Pantheon Resources Plc

Pantheon Resources Plc, through its subsidiaries, engages in the exploration and production of oil and gas in the United States. Its primary assets are the Greater Alkaid project that covers 22,804 acres located in Alaska; and the Talitha project covering an area of approximately 44,463 acres. The company was incorporated in 2005 and is headquartered in London, the United Kingdom.

Operations

Idea

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Projects

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Greater Alkaid

The Alkaid #1well was drilled in 2015 adjacent to the Dalton Highway and Trans Alaska Pipeline System (TAPS) - the primary transportation highway and major export pipeline (TAPS) on the Alaska North Slope respectively. Drilling of the well was terminated prior to the well reaching target depth for environmental reasons; the nearby Sag River flooded which ultimately led to the Dalton Highway being closed to all traffic for a number of weeks. As a result Alkaid was comprehensively logged but no production testing was conducted at that time due to the urgency to conclude operations and demobilize all equipment prior to advancement of the flood. Importantly, the well had encountered 400 feet of gross pay when operations were concluded, however, promisingly, there was no oil water contact encountered and this the Company believes potential exists for several hundred feet of additional gross pay. Activities recommenced at Alkaid in 2019 with Pantheon successfully production testing the Primary Zone of Interest which is contained within the same Brookian section that has proven so successful in the recent drilling campaigns of other operators regionally. The recent oil discovery at Talitha #A in the Shelf Margin Deltaic formation has also upgraded the potential for the Shelf Margin Deltaic to be oil bearing on the Greater Alkaid structure as well.

ALKAID #1 PAY INTERVALS

Data acquired from the Alkaid well included extensive sidewall coring, formation imaging logs and the oil reservoir flow test. A number of expert consulting firms performed detailed petrophysical analysis with all confirming similar results, thereby providing increased confidence on the potential of this project. The Alkaid well encountered 400 feet of gross pay with 240 feet of net oil pay and no water contact, testing high quality 35 deg API light oil. This result upgraded the adjoining Phecda segment which is now mapped with Alkaid to be part of one large ‘Greater Alkaid’ structure. The Alkaid well tested an average 100 bopd via a small “through-tubing single frac”. Only 6 ft of the 240 ft net pay interval was perforated, accessing only a fraction of ultimate well productivity. Pantheon estimates that horizontal development wells could potentially produce as much as 2000 bopd with recoveries of 1.5-2.5 million barrels per well. Primary recovery is conservatively estimated at 10-15% yielding 90-135 million barrels of recoverable oil from the estimated 900 million barrels of oil in place (“OIP”) but could be significantly higher with optimally located and designed wells. In order to maximize Alaskan Tax credits at the time, the Alkaid well was located a State mandated minimum distance from the nearest well and hence only penetrated the of the structure. Recent high tech seismic imaging clearly indicates that better reservoir can be expected in the heart of the accumulation, hence recoveries are expected to improve materially. The successful application of secondary recovery techniques could further increase ultimate recoveries, adding major upside potential to this project. The Company plans to use an early production unit (EPU) as part of a pilot testing operation to yield early cashflow as well as acquiring valuable production data to assist future development planning. Ultimately a Central Processing Unit (CPU) with full facilities will be needed to fully exploit the resource potential. Pantheon’s Alaskan projects will utilize unconventional oil production technologies applied to conventional oil reservoirs in order to maximize reserves and production which has now become standard operating procedure across the entire Alaska North Slope (“ANS”). The industry has transferred these technologies into Alaskato develop this higher quality oil in stratigraphic Brookian sections containing billions of barrels of recently discovered oil. The Greater Alkaid oil accumulation sits underneath and adjacent to the TAPS pipeline and the Dalton Highway making it uniquely ideal for year-round “Phased Development”, minimizing cost and offering early production potential with significant advantages to other remote oil field developments on the ANS.

Independent Expert report completed in 2020 on the Greater Alkaid oil accumulation ascribed 76.5 million barrels of certified recoverable reserves with a calculated NPV (10) of $595m for this singular project (at the then prevailing realized oil price of $55/Bbl held flat). This estimate discounted certain parts of the field by 50% and hence is considered by the Company to represent a conservative estimate. A single development well is planned for 2022 that will be completed as a pilot test producer which could yield early cashflow and near-term payback. Being onshore and adjacent to established infrastructure provides opportunities for phased development to manage cash flow and risk associated with development. The ultimate development concept model will involve a Central Processing Facility adjacent the highway and Trans Alaska Pipeline with approximately 44 wells targeting with peak production of circa 30,000 barrels of oil per day. A phased development means a bulk of capex could be funded through production revenue hence yielding high IRR’s. Expected development of Talitha will leverage off the Greater Alkaid infrastructure, hence improving economic returns. A major benefit of Alkaid over other projects on the Alaska North Slope is that wells can be rapidly brought onto production after testing by trucking the oil to Pump Station #1, about 20 miles north of Alkaid. Alkaid's location, underneath and adjacent to the Dalton Highway and the Trans Alaska Pipeline System allows the placement of a drill pad next to the Dalton Highway which offers the ability for year-round activity as well as other material advantages.

ALKAID #1

Pay from Top SMD(B) to TD

Pantheon was awarded a unit over Alkaid where it submitted a First Plan of Exploration ("POE") in November 2020 outlining its proposed activities in relation to the unit. These include a commitment to the reprocessing of approximately 50 square miles of 3D seismic as well as engagement of 3rd party specialists to produce an engineering study on a conceptual 'hot-tap' into the Trans Alaska Pipeline System ("TAPS"). There are no firm drilling commitments, however the POE proposes the drilling of two wells from gravel pads located adjacent to the Dalton Highway to allow year-round activity. Under the POE, drilling and long-term production testing on the first of these wells, the Alkaid #2 well, is targeted for Spring/Summer 2022. Dependent upon the results of Alkaid#2, the POE anticipates the drilling and testing of the Alkaid#3 well thereafter. GBP is a large exploration leaseholder where it controls over 250,000 acres, most of it contiguous, south of the giant Prudhoe Bay and Kuparuk oil fields which are the largest oil fields in North America. This acreage is covered by 3D seismic and contains several existing discoveries and a host of world class exploration prospects. Pantheon has a 100% interest in all of its projects.

Talitha

The Talitha #A well was drilled in 2021 and was an appraisal of a conventional oil accumulation discovered by a well named Pipeline State #1 drilled by Arco Alaska in 1988. Pipeline State #1 was designed to drill to 13,000 feet (“ft”) depth but stopped short of this, just below the Kuparuk formation. The well encountered several oil-bearing intervals as well as strong oil shows throughout an extensive section and did observe oil to surface from several Brookian zones whilst drilling. Promisingly, several cores taken from the well confirmed the presence of oil. No reservoir flow tests were performed as at the time as the objective of the well had been to find a lookalike for the prodigious Kuparuk River oilfield. This activity occurred in 1988 when oil prices had plunged to around WTI $15-$20/bbl and the Trans Alaska Pipeline System (“TAPS”) was running at full capacity, hence there was little incentive to continue the evaluation of the discovery at that time. Moreover, at that time 3D seismic imaging was in its infancy, drilling and completion technologies as well as oil extraction techniques were not nearly as advanced as they are today. Had today’s techniques been available in the 1980’s, it is possible that the Pipeline State #1 well may well have initiated the new field development Pantheon envisions today. High resolution 3D seismic acquired in 2013 indicated the potential for an exceptionally large oil accumulation across multiple zones which structurally conform to the oil encountered at Pipeline State #1 which led to the drilling of the Talitha #A well in 2021 which confirmed oil in several zones. Independent experts at AHS Baker Hughes conducted a ‘Volatiles Analysis Service’ (“VAS”) at Talitha #A and confirmed the presence of oil in all cuttings taken over a 3,700 ft section within the wellbore. The recent operations in early 2022 at the Talitha project involved testing several of those oil-bearing zones in the Talitha #A well bore.

TALITHA A PAY INTERVALS

There are several distinct stratigraphic oil zones and possibly more that have been identified at Talitha which have been defined using advanced seismic petrophysics, a technology which integrates petrophysics, geophysics and geology. Advances such as horizontal drilling and reservoir stimulation now enable economic development of these type of reservoirs, which were previously considered uneconomic. This integrated approach has proven to be successful on the Alaska North Slope (ANS) and resulted in an exploration revival of the ANS which now boasts some of the largest onshore conventional oil discoveries in the world.

The Talitha #A well, drilled by Pantheon, is located approximately eight miles west of the Dalton Highway and TAPS and four miles from the Pipeline State #1 well and confirmed the presence of movable light oil in all of the objective horizons. Talitha #A has been announced by Pantheon as a new discovery of oil with over a billion barrels of recoverable oil potential across the multiple stacked (primary and secondary) objectives. These zones are comprised of Brookian reservoirs (primary targets) and the deeper Kuparuk reservoir (secondary target).

Most of the recent larger oil discoveries by other operators on the ANS have been drilled some distance from existing infrastructure which will require extremely high preproduction expenditure and exceedingly long lead times to any production. These recent discoveries by other operators remain several years away from producing any oil and cashflow. Talitha’s closer proximity to the Dalton Highway and TAPS will be immediately appraised and if successful, the objective is to progress it to development via phased modular production facilities reducing the need for substantial upfront capital expenditure, hence allowing production to ramp up as early cashflow is reinvested to grow production.

The Talitha #A well reached a total depth of c. 10,456 ft and drilled through the Shelf Margin Deltaic sequence along with several other targets including (a) the Slope Fan System, (b) the Basin Floor Fan, both within the Brookian section, as well as (c) the deeper Kuparuk formation. Data collected during drilling indicated five potentially productive zones in the (from deepest to shallowest) (i) Kuparuk, (ii) Lower Basin Floor, (iii) Upper Basin Floor Fan sequences, (iv) Slope Fan and (v) Shelf Margin Deltaic horizons. The Company was only able to test the deepest of these zones, the Kuparuk Formation in 2021 as it experienced operational issues that led to a delayed testing operation and eventual suspension of the testing at the onset of the warmer Spring weather. Recent testing operations in 2022 focussed on the three shallow Brookian zones, namely the Lower Basin Floor Fan, the Slope System and the Shelf Margin Deltaic which are all normally pressured and were secured behind casing. The shallow zones are all geologically independent of the Kuparuk, have all confirmed the presence of potentially significant quantities of light oil, and were flow tested as part of the recent program.

BASIN FLOOR FAN

Testing operations on the Lower Basin Floor Fan ("BFF") involved perforating three separate 10 ft intervals over 370 ft out of 600 ft of gross section, at 9405 to 9415 ft, 9205 to 9215 ft and 9045 to 9055 ft. These three intervals were individually stimulated, and successfully flow tested, producing high quality c. 35 to 39 degree API oil and averaging 73 barrels of oil per day ("BOPD") over a three day test period.

On the final day of testing, the well was flowing at a sustained rate of approximately 40 BOPD. Encouragingly, the bottom hole pressure is near to the reservoir pressure, thus providing an indication of the production potential of this portion of the oil accumulation, which is at the distal limits of the field. Future development wells would all be drilled horizontally and stimulated with multiple stage fracs, meaning that flow rates are expected to be many times higher.

The Company was greatly encouraged by the test results given the optimal location for any development of the BFF will be in a structurally higher position where better reservoir properties can be expected and, in a location, similar to which is presently being drilled and tested at Theta West, 10.5 miles to the north west, where the BFF is the primary objective.  

SLOPE FAN SYSTEM

Testing operations on the Slope Fan System (“SFS”) which is immediately above the BFF involved perforating two separate five ft intervals at 8160 to 8165 ft and 7855 to 7860 ft, within two distinct c. 50 ft sand bodies or 'lobes'. The two intervals were stimulated, and flow tested together, producing high quality c. 35 to 38 degree API oil and averaging 45 BOPD over a three day test period. On the final day of testing, the well was flowing at a sustained rate of approximately 32 BOPD from this combined 10 ft of perforations which again is highly encouraging given production wells on the Alaska North Slope are drilled horizontally, which would typically result in materially higher flow rates.

This is the first indication of producible oil in the Slope Fan System on Pantheon's acreage and has significant implications for future resource and recoverable oil estimates. The two SFS lobes are in two distinct trapping systems and suggest very good reservoir properties. The Company's initial analysis suggests that the deeper of the two lobes extends below the Alkaid Deep anomaly and will be assessed in the upcoming Alkaid #2 well, planned for summer 2022.

The Company has not previously provided guidance on potential resource for the SFS but is now greatly encouraged by these results and will provide an estimate of resource and recoverable oil in due course.

SHELF MARGIN DELTAIC

The Shelf Margin Deltaic testing was the last test in the shallowest zone of the Talitha #A well bore. The Company had to suspend testing of the Shelf Margin Deltaic (“SMD”) horizon due to suspected blockages in the well bore. The well was perforated in the SMD from 6,965 ft to 6,975 ft and was successfully fracture stimulated. Immediately after the fracture stimulation, the test was suspended by a blizzard on the North Slope which shut down all operations for health and safety reasons. Flow testing operations resumed three days later.

Once flow testing commenced and before the well stopped flowing after a short period of time, only 45% of the fracture fluid was produced, with no formation water and small amounts of light high quality 34 degree API oil. Other than the small amounts of oil, no reservoir fluids were produced. The consensus among the Company and external consultants is that there is a blockage preventing any additional reservoir fluid from entering the well bore. Based on all the data, which includes a full suite of logs, sidewall cores, extensive Volatiles Analysis Service (“VAS”) work undertaken by AHS/Baker Hughes over the past 12 months, and the testing of the lower zones this year, the Company’s expectation for the SMD is that it should produce better than the two lower zones already tested; the Basin Floor Fan and Slope Fan System horizons, where the Company achieved excellent results.  

Pantheon decided to suspend operations at Talitha with a possible return to testing after the program on Theta West or return next season. The main priority for the remainder of the current winter season is to allow sufficient time to satisfactorily test the BFF at Theta West. The shortage of testing equipment had necessitated the movement of the Coil Tubing Unit and test equipment from Talitha to Theta West. This consequently limits the amount of time available for remedial work at Talitha.

Regardless of the operational challenges, the company believes the potential of the SMD is undiminished and it plans further operations on the SMD at Talitha to remediate the issue either this season, time permitting, or next. Despite the blockage encountered in the SMD, the Talitha well has been a great success for Pantheon, confirming the presence of movable, high quality light oil in both the Slope Fan System and the Basin Floor Fan, which has very significant implications for our acreage. The next well in the programme is an Alkaid appraisal/production well in the summer of 2022 which will penetrate the SMD as well several other potential oil zones, hence additional data will be gathered on the SMD. The plan at Alkaid is to drill a horizontal lateral wellbore on the best oil zone and, if successful, put on a long-term production test.

Pantheon is extremely encouraged by the analysis and initial results of the shallower zones in the Talitha #A well. The reservoir qualities are in line with expectations, the oil appears to be lighter than expected and an additional significant zone has been discovered in Talitha #A, significantly increasing the total resource potential.

An enormous volume of high-quality data has been collected from drilling Talitha #A which has both de-risked these zones for future drilling, and increased confidence of their commercial viability. The Basin Floor Fan zone encountered more reservoir than expected. The Upper BFF is an additional zone with that was penetrated in Talitha #A. The Slope Fan System was proven oil productive and better than expectations. The SMD was not as well developed as anticipated at Talitha #A. Pantheon now interprets that the SMD extends across the Alkaid project where the zone is proven oil bearing, and better developed as it extends southeast across the Dalton Highway. This significantly increases the resource potential near the highway and pipeline. The discovery of oil in these formations enhances the prospectivity of other adjoining potential oil-bearing structures that will form part of a future drilling programme. The Company believes that it can “see” light oil in reservoir within its 3D seismic.

The SMD was the primary interval of focus utilized to define the Talitha Production Unit which covers 44,373 acres. The SMD could be classed as analogous in stratigraphic setting to the large Pikka/Horseshoe discovery to the west which is also described as a SMD play. The SMD play now extends into the Alkaid Unit to the northeast lying directly above the tested Alkaid discovery. New mapping also extends the play due east and underneath the Dalton Highway and TAPS.

KUPARUK

The third and deepest oil formation is the Kuparuk formation. The Kuparuk formation is a prolific regional producer just north of Pantheon’s leases where there is a giant oilfield named the Kuparuk Field, holding an estimated oil in place of 14 billion barrels of oil. Oil was discovered in the Kuparuk formation at the Pipeline State #1 well in 1988 but much deeper than the established Kuparuk oil fields to the north. The Pipeline State well encountered 47 ft of net oil pay in the Kuparuk but was never tested. The Talitha #A well was drilled “up dip” from Pipeline State and encountered thicker and better reservoir rocks. The well encountered ± 60 ft of well-developed sand with high resistivity readings and very strong gas chromatograph indications of oil. The presence of oil in reservoir was independently confirmed by VAS. Talitha #A demonstrated the key elements of a proven hydrocarbon system in the Kuparuk formation with the presence of movable high-quality (± 42 degree API) oil, however during testing the well-produced oil intermittently along with solution gas and formation water with lower salinity than anticipated. High quality light oil flowed intermittently at rates up to 100 BOPD as test encountered several operational issues and is believed to exhibit ‘oil wettability’ characteristics, which will be addressed in future wells through the application of different drilling products and techniques. The Kuparuk horizon at this location was over pressured which was both unexpected and unlike any known Kuparuk well regionally, causing challenges in testing. The Kuparuk at Talitha #A is some 800 ft downdip from its ideal 'updip' position and was recognized, predrill, as a secondary target but important stratigraphic play test. The Talitha #A well location was selected as the optimal location for the shallower Shelf Margin Deltaic horizon, the primary target of the well.

Our technical team prioritised testing the Kuparuk formation and ultimately recommended deferring plans to test the shallower horizon during the 2021 drilling season because the well logs of the Kuparuk indicated excellent reservoir, comparable to reservoirs in highly productive nearby Kuparuk fields. Based upon the well logs and regional analogues, the test results were a surprise, and more work will be needed to understand the Kuparuk reservoir at this location. Comprehensive analysis of the VAS and wireline data from these zones over the forthcoming months will enable the Company to fully optimize its testing programme for next season, as well as enabling lengthier flow tests.

Before drilling Talitha #A, Pantheon completed an internal analysis of the Kuparuk Formation in late 2020 where it estimated the Kuparuk formation, on a 100% basis, has the potential to contain 1.4 billion barrels of oil in place and a Prospective Recoverable Resource of 341 million barrels of oil as a most likely case.  A standalone development concept would be significantly enhanced if this development is combined with the discovered resources the shallower section at Talitha and Alkaid.

Theta West

Pantheon has recently completed drilling of the Theta West#1 well, confirming the discovery of light sweet crude oil, which will now be subject to an extensive production testing operations. Theta West is Pantheon’s largest appraisal project, which the Company believes has the potential to be one of the largest hydrocarbon pore volume plays currently being exploited on the ANS outside of the giant Prudhoe Bay Oilfield. This type of geological play and its volumetric size, if successful, is comparable to deepwater offshore Gulf of Mexico, West Africa and recent discoveries offshore Guyana. It is defined as a giant Basin Floor Fan with multibillion barrel oil potential.

Pantheon recognised this large geological play several years ago and leveraged its proprietary 3D seismic and analytical methodologies over the past few years to strategically secure a dominant position in the Theta West play fairway, prior to the drilling of Talitha #A in 2021. The drilling of Talitha #A confirmed the Theta West structure as oil bearing on the distil flanks of the field which was followed up with the recent Theta West #1 appraisal well structurally higher i.e., “up dip” in a better geologic location some 10.5 miles from Talitha.  There are currently three wells that have penetrated and encountered oil in the Basin Floor Fan (“BFF”) complex - Pipeline State #1, Talitha #1 and Theta West #1.

The Theta West #1 reached a total depth at 8,450 feet (“ft”) having drilled through both the Upper Basin Floor Fan ("UBFF") and Lower Basin Floor Fan ("LBFF") target horizons, which are both Brookian age, and having encountered approximately 1,160 gross ft of hydrocarbon bearing reservoir across both horizons combined. Data received so far suggests the reservoir quality to be superior to the downdip Talitha #A, with high quality light oil encountered across the entire section.

The UBFF was encountered between 6,800 and 7,000 ft, and the LBFF was encountered between 7,450 and 8,410 ft depth. The top of the UBFF is located approximately 150 ft higher than pre-drill estimates. Well bore conditions in the shallower sections above the primary objective, combined with the extremely cold weather, have prevented the Company from conducting wireline operations in the open hole. However, the Company undertook Logging While Drilling ("LWD") operations which included resistivity, gamma ray, neutron density, formation density along with gas chromatography readings during drilling, which has provided excellent quality data, indicating the presence of hydrocarbons in the targeted horizons some 1,500 ft structurally higher (updip) from the Talitha #A well, 10.5 miles to the southeast.

Samples analysed to date by AHS/Baker Hughes, who were contracted to undertake Volatiles Analyses ("VAS"), has also confirmed the presence of light oil within the UBFF and the top portion of the LBFF, consistent with the LWD data. AHS/Baker Hughes is yet to complete analysis of the lower portion of the LBFF. Company estimates of the resource potential of Theta West #A (pre-drill) on a 100% basis were 12.1 billion barrels of Oil in Place and a P50 Contingent Resource (Recoverable) of 1.41 billion barrels of oil on Pantheon’s acreage as a most likely case under primary recovery. This will be reviewed and updated post the testing operation and more detailed evaluation.

The Theta West BFF was also penetrated in the Pipeline State #1 well drilled in 1988, substantially downdip from Talitha #A, and was also oil bearing. The Talitha #A well penetrated the two separate reservoirs within the BFF in a structurally down dip location, over eight miles from the crest of the trap to the northwest. At the Talitha #A site, the LBFF is 600 ft thick with approximately 50% net sand to gross rock interval ratio. The LBFF was successfully tested at Talitha #A where three separate 10 ft intervals were perforated over 370 ft out of 600 ft of gross section, at 9405 to 9415 ft, 9205 to 9215 ft and 9045 to 9055 ft. These three intervals were individually stimulated and flow tested, producing high quality c. 35 to 39 degree API oil and averaging 73 barrels of oil per day over a three day test period, before flowing at a sustained rate of approximately 40 BOPD on the final day of testing.

As predicted, the current Theta West #1 well reservoir target interval was substantially thicker at its (updip) crest and substantially shallower in depth than at Talitha #A with increased porosity and permeability. The shallow drilling location of Theta West presents a simple low-cost drilling operation for a major resource. The Theta West project covers approximately 100,000 acres controlled by Pantheon. Theta West represents a major opportunity for Pantheon to pursue the appraisal and development of what management believes  is a truly world class project in an excellent location.

The Theta West BFF is part of the Brookian deepwater fan systems, which include the Slope Fan system, and lie below the Shelf Margin Deltaic and above the Kuparuk Formation in depth, all of which were proven as oil-bearing in the discovery well at Talitha #A and Pipeline State #1. The original interpretation was that this was a series of discrete fan systems, however, more recent analysis has indicated that the fan systems previously identified as discrete pay zones could, in fact, be part of one large continuous section that extends several thousand feet and has the potential to lie within a “super trap”.

Strategy

Onshore hydrocarbon exploration and production on the North Slope of Alaska is Pantheon’s strategy, where our expertise and competitive advantage lie. Our lean organisation with tight cost controls is committed to maximising the potential returns to shareholders through carefully targeted exploration and appraisal in proven areas.

Onshore Alaska is part of a sophisticated free market economy in the USA where the rule of law and encouragement of free enterprise are both deeply ingrained. Our location, immediately underneath and adjacent to established and underutilized Trans Alaska Pipeline System (TAPS) and transport infrastructure yields huge advantages. We can bring on stream any oil discoveries to market more quickly and cost-effectively than other projects on the North Slope of Alaska.

Despite being a small exploration and appraisal company, we have the benefit of over 10 years in-depth proprietary knowledge of the geology, resulting from over US$200m invested on Pantheon’s Alaskan acreage to date. The board of Pantheon believes that its low cost, narrow focus (“prove up and sell”) strategy offers investors a unique and attractive opportunity to participate in high impact, risk managed drilling which offers significant potential. We have over 1,000 square miles of proprietary 3D seismic as well as a significant acreage position spanning four projects. The anticipated award of two production units in late 2020 by the State of Alaska over the Greater Alkaid and Talitha projects (which encompass nearly 70,000 acres combined) will be a crucial milestone for our company.

Next year’s drilling will test prospects that are extremely large with commensurate economic potential compared to our current market capitalization. Any commercial discoveries of hydrocarbons from this drilling will transform the scale and reach of the company. Our strategy is to monetize the assets by a sale or other means at the appropriate time.

Team

Phillip Gobe, Non Executive Chairman

Phillip Gobe has over 40 years’ experience in the oil and gas business both in the USA and internationally. He is also Chairman (and former CEO) of ProPetro, a Texas-based oil field services provider in the pressure pumping space, which includes hydraulic fracturing services and cementing, as well as completion services including wireline. Phillip has held senior positions in Energy Partners Ltd (President & COO), Nuevo Energy Co. (COO), Vastar Resources (COO) and several senior positions with Atlantic Richfield Company, including a role as Operations Manager of Prudhoe Bay in Alaska, the largest oilfield in the USA. Throughout his career Phillip has successfully overseen several corporate exits at substantial premiums to pre-deal valuations. Phillip also has a background in drilling, human resources and health and safety. He is currently a non-executive director of the S&P 500 company, Pioneer Natural Resources and was previously a director of Scientific Drilling International Inc, the USA’s fifth largest provider of directional drilling and measurement equipment and operational services. Phillip acts as Chairman of Pantheon’s Remuneration and Nominations Committee, Audit Committee and Conflicts Committee. Phillip is also a member of the Companies Anti-Corruption and Bribery Committee.

Jay Cheatham, Chief Executive Officer

Jay Cheatham has more than 50 years' experience in all aspects of the petroleum business. He has extensive international experience in both oil and natural gas, primarily for ARCO. At ARCO, Jay held a series of senior appointments. These include Senior Vice President and District Manager (ARCO eastern District) with direct responsibility for Gulf Coast US operations and exploration and President of ARCO International where he had responsibility for all exploration and production outside the US Jay's most recent appointment was as President and CEO of Rolls-Royce Power Ventures, where he had the key responsibility for restructuring the Company. 

Jay also has considerable financial skills in addition to his corporate and operational expertise. He has acted as Chief Financial Officer for ARCO's US oil and natural gas company (ARCO Oil & Gas). Moreover, he has an understanding of the capital markets through his past position as CEO to the Petrogen Fund, a private equity fund. 

Jay is a member of the Company’s Remuneration and Nominations Committee, Audit Committee, Conflicts Committee and Anti-Corruption and Bribery Committee.

Justin Hondris, Director, Finance and Corporate Development

Justin Hondris has over 15 years’ experience in public company management in the upstream oil and gas sector and has wide ranging experience in corporate finance, private equity and capital markets in the UK and abroad. Prior to Pantheon, Justin was involved in the private equity sector where he gained valuable experience in both investment and exit strategies for growth companies.

He is responsible for the financial, legal, administrative and corporate development functions of the company. 

Justin acts as Chairman of Pantheon’s Anti-Corruption and Bribery Committee and is a member of the Remuneration and Nominations Committee and the Conflicts Committee.

Robert (Bob) Rosenthal, Technical Director

Bob Rosenthal has over 40 years' experience in the oil and gas industry globally as an Exploration Geologist and Geophysicist. He has held various senior exploration positions and spent a large part of his career at Exxon and at BP, where he gained key relevant regional experience in the geology of North Slope of Alaska and of Texas. Since 1999, Bob has run his own successful consulting business and has led the exploration efforts of a number of private and public companies.

Jeremy Brest, Non-executive Director

Jeremy has more than 25 years’ experience in investment banking and financial advisory. Jeremy is the founder of Framework Capital Solutions, a boutique Singapore-based advisory firm specializing in structuring and execution of private transactions. Prior to founding Framework, Jeremy was the head of structuring for Indonesia at Credit Suisse and a derivatives trader at Goldman Sachs.

Jeremy is a member of the Company’s Audit Committee, Remuneration and Nominations Committee, Conflicts Committee and Anti-Corruption and Bribery Committee.

Market

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Financials

Most recent

Cash flow

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Full-year results

Profit and loss

Profit and loss

	2021	2022
	$	$
Continuing operations
Administration expenses	(5,034,361)	(7,430,653)
Share Based payments expense	(3,211,038)	(8,256,575)
Operating loss	(8,245,400)	(15,687,228)
Convertible Bond - Interest Expense	-	(4,640,537)
Convertible Bond - Revaluation of Derivative Liability	-	4,310,773
Interest receivable	4,234	42,674
Loss before taxation	(8,241,165)	(15,974,318)
Taxation	1,573,094	2,022,334
Loss for the year from Continuing Operations after Taxation	(6,668,071)	(13,951,984)
Loss for the year from discontinued operations	(54,415)	-
Loss for the year	(6,722,487)	(13,951,984)
Other comprehensive income for the year Exchange differences from translating foreign operations	1,503,199	(741,484)
Total comprehensive loss for the year	(5,219,288)	(14,693,468)
Loss per share from continuing operations:
Basic and diluted loss per share	(1.17)¢	(1.93)¢

Balance sheet

Balance sheet

	2021 $	2022 $
ASSETS
Non-current assets
Exploration & evaluation assets	188,954,719	237,722,294
Property, plant and equipment	30,308	91,691
	188,985,027	237,813,985
Current assets Trade and other receivables	109,876	2,498,447
Cash and cash equivalents	5,663,477	57,784,121
	5,773,353	60,282,568
Total assets	194,758,380	298,096,553
LIABILITIES Current liabilities
Convertible Bond – Debt	-	10,001,704
Trade and other payables	1,107,090	6,377,986
Provisions	1,250,000	5,285,440
Lease Liabilities	32,788	60,297
Other Liabilities	-	1,964,441
Deferred tax liability	3,705,737	1,683,403
	6,095,615	25,373,271
Non-current liabilities
Lease Liabilities	-	30,004
Convertible Bond – Debt	-	20,474,664
Convertible Bond – Derivative	-	12,816,226
	-	33,320,894
Total liabilities	6,095,615	58,694,166
Net assets	188,662,765	239,402,388
EQUITY
Capital and reserves
Share capital	9,739,203	10,720,459
Share premium	208,683,936	264,879,196
Retained losses	(36,331,398)	(48,466,591)
Currency reserve	1,234,562	493,078
Share based payment reserve	5,336,462	11,776,246
Shareholders’ equity	188,662,765	239,402,388

Cash flow

Cash flow

	2021 $	2022 $
Net outflow from operating activities	(3,098,495)	(941,506)
Cash flows from investing activities
Interest received	4,295	42,674
Funds used for drilling, exploration and leases	(24,973,399)	(45,267,175)
Advance for Performance Bond	-	(2,400,000)
Property, plant and equipment	-	(3,368)
Net cash outflow from investing activities	(24,969,105)	(47,627,869)
Cash flows from financing activities
Proceeds from share issues	30,181,084	46,739,796
Issue costs paid in cash	(1,197,275)	(994,694)
Proceeds from Convertible Bond	-	55,000,000
Repayment of borrowing and leasing liabilities	(55,698)	(55,083)
Net cash inflow from financing activities	28,928,111	100,690,020
Increase in cash & cash equivalents	860,511	52,120,645
Cash and cash equivalents at the beginning of the year	4,802,965	5,663,476
Cash and cash equivalents at the end of the year	5,663,476	57,784,121

Risks

As with any investment, investing in Pantheon Resources Plc carries a level of risk. Overall, based on the Pantheon Resources Plc's adjusted beta (i.e. ccc), the degree of risk associated with an investment in Pantheon Resources Plc is 'ccc'.

Here, to estimate the adjusted beta, we used the iShares MSCI World ETF to represent the market portfolio; and in terms of the time period and frequency of observations, we used five years of monthly data (i.e. 60 observations in total), which is supported by a study and is the most common choice. The beta value in a future period has been found to be on average closer to the mean value of 1.0, and because valuation is forward-looking, it is logical to adjust the raw beta so it more/most accurately predicts a future beta. In addition, here, we have assumed that for an investment to be considered 'medium' risk, it must have a beta value of between 0.5 and 1.5. Further information about the beta ratings can be found in the appendix section of this report.

The key risks can be found below. For us, currently, the biggest risk to the valuation of the company relates to ccc.

The group may be unable to meet its lease obligations

In general, the group's properties are held under oil and gas leases. The terms of the group's leases often provide for yearly rental payments. Such yearly rentals may vary depending upon the particular lease and whether the group has commenced activities in the property. If the group defaults on its lease payments, its leases may be automatically terminated. If the group is unable to make these payments and its leases are terminated, there could be a material adverse effect on its business, financial condition and results of operations. Managing the lease position is of material importance for the group, and management devote considerable time to lease management, budgeting and planning, consulting with the State of Alaska where required. In 2020 Pantheon was awarded Units on the Alkaid and Talitha projects and has been an active participant in the annual lease sales over recent years, significantly strengthening Pantheon’s lease portfolio. The 40,000 leases successfully bid for in the November 2022 have a 10-year life, $10 per acre rentals and low royalties of between 12.5% – 16.7% to the State of Alaska.

The group may be unable to renew and/or extend its leases once they expire 

The group's lease agreements contain terms whereby the lease may be terminated if the group does not fulfil certain obligations. These obligations include conducting exploration and/or production activities. If the group is unable to satisfy these conditions on a timely basis, it may lose its rights in these properties. In addition, given that it may not be able to renew certain leases unless it begins exploration or production activities within specific timeframes, the group may be required to invest significant funds at timetables not optimal in order to meet the capital requirements as per the terms of the leases. If the group is unable to meet its obligations under the terms of its leases, there could be a material adverse effect on its business, financial condition and results of operations. To mitigate this risk the group has successfully applied for and been granted unitization for the leases that comprise its Talitha and Alkaid projects. Unitization recognizes that the group has established, to the State’s satisfaction, that all or part of multiple potential hydrocarbon accumulations are included in the unit areas to allow the leases to potentially be held beyond the initial lease term. Most of Pantheon’s lease position is now covered by these units or leases of between c.7 years or more of remaining life. Management has materially reduced the risk of lease expiry.

The group's operations require it to obtain licensing, planning permissions and other consents

The development of its current and future leases may be dependent upon the receipt of planning permission from the appropriate local authorities, as well as other necessary consents, such as environmental permits and regulatory consents. Obtaining the necessary consents and approvals may be costly, and they may not be granted, may be withdrawn or made subject to limitations and conditions. Certain permits and consents may also become contentious in the future, which may lead to these not being granted or withdrawn.  The failure to gain such permissions or gain such permissions on terms or at a cost acceptable to the group, may limit the group in its ability to develop and extract value from its leases and could have a material adverse effect on its business, results of operations, financial conditions and prospects. To manage the risk, the group employs experienced and qualified personnel who have successfully obtained licenses and permits in the past, and who maintain working relationships with regulatory agencies.

Political conditions and government regulations could change and have a material effect on the group's results of operations

Although political conditions in the Northern Slope Borough, the State of Alaska and the United States federal government are generally stable, changes may occur in their political, fiscal and/or legal systems, which might adversely affect the group's operations. The group's strategy has been formulated in the light of the current regulatory environment and probable future changes to the regulatory regime. In 2021 the federal government has adopted a more cautionary position with respect to operations on federal land, notably with respect to ConocoPhillips’ Willow project. Pantheon’s projects are all located on state, not federal land, and so has not been impacted by such politics.

Although the group believes that its activities are currently carried out in accordance with all applicable rules and regulations, no assurance can be given that new rules, laws and regulations will not be enacted, or that existing or future rules and regulations will not be applied in a manner which could serve to limit or curtail exploration or development of the group's business or have an otherwise negative impact on its activities. Amendments to existing rules, laws and regulations governing the group's operations and activities, or increases in or more stringent enforcement, implementation or interpretation thereof, could have a material adverse impact on the group's business, results of operations and financial condition.

Future legal proceedings could adversely affect the group's business, results of operations or financial condition

The group may face legal proceedings that may result in the group having to pay material damages and/or other remedies. While the group would assess the merits of each legal proceeding and defend the group accordingly, it may be required to incur significant expenses or devote significant resources to defend against such legal proceedings. In addition, legal proceedings are also difficult to predict, which may force the group to enter into settlement arrangements even in the absence of any culpability from its part. 

Furthermore, the adverse publicity surrounding legal proceedings may negatively affect the group's relation with local communities, government and non-government organizations, which could also impact the group's activities. As a result, legal proceedings could have a material adverse effect on the group's business, financial condition, results of operations and prospects. To manage this risk the group consults legal counsel when it faces potential legal proceedings. The board and management consult legal counsel when conducting activities or entering into agreements that are viewed to have the potential to give rise to material legal proceedings.

Failure to manage relationships with local communities, environmental groups and non-government organizations could adversely affect the group's future growth potential

The activities of oil and gas companies often face scrutiny from the public and receive negative publicity. Although the group's operations are not located in or near large communities, the group's ability to further expand its operation may be hindered by communities that may regard oil and gas activities as detrimental to their environmental, economic or social circumstances. Furthermore, oil and gas companies are also increasingly facing scrutiny by environmental groups regarding the effect operations may have on the animal life in the region. Negative reaction to its operations could have a material adverse impact on the cost, profitability, ability to finance or even the viability of an operation. Such events could give rise to material reputational damage. 

These disputes are not always predictable and may cause disruption to projects or operations. Failure to manage relationships with local communities, environmental groups and non-governmental organisations may adversely affect the group's reputation, as well as its ability to commence production projects in certain locations, which could in turn affect its long-term prospects and the group's business, financial condition and results of operations. The group’s current leased acreage is not in the immediate vicinity of any local community. To manage this risk the group ensures it conducts operations in a legal and responsible manner and complies with rules and regulations.

Any change to government regulation/administrative practices may have a negative impact on the group's ability to operate and its future profitability

The business of oil and gas exploration and development is subject to substantial regulation under federal, state, local laws relating to the exploration for and the development of upgrading, marketing, pricing, taxation, and transportation of oil and gas and related products and other matters. Amendments to current laws and regulations governing operations and activities of oil and gas exploration and development operations could have a material adverse impact on the group's business. In addition, there can be no assurance that tax laws, royalty regulations and government incentive programs related to the group's oil and gas properties and the oil and gas industry generally, will not be changed in a manner which may adversely affect the group's prospects and cause delays, inability to explore and develop or abandonment of these interests.

Furthermore, permits, leases, licenses and approvals are required from a variety of regulatory authorities at various stages of exploration and development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be granted in respect of the group's activities or, if granted, will not be cancelled, or will be renewed upon expiry. There is no assurance that such permits, leases, licenses and approvals will not contain terms and provisions which may adversely affect the group's exploration and development activities. If any of the forgoing were to occur, it could have a material adverse effect on the group's business, financial condition and results of operations. To manage the risk, the group employs experienced personnel and contractors who have successfully obtained licenses and permits in the past, and who maintain working relationships with regulatory agencies and monitor changes that could impact the group. 

COVID, Supply chain and inflationary risk

The impact of the Covid-19 pandemic on global supply chains is a well-documented phenomenon which has affected many industries globally, including the oil and gas sector. This has been exacerbated by the Russia/Ukraine conflict and the high oil and gas prices which resulted in high demand for equipment, service providers and materials. Additionally, services and materials costs have experienced very high inflation. As a result, the lead times, availability and costs for the equipment and consumables required for drilling in Alaska have increased over the last 12 months. To manage this risk it is important that key equipment and materials are ordered on a timely basis so as to minimise the potential for supply chain disruption to drilling operations, and that well operations are carefully planned, to try to minimise cost inflation where possible.