Pantheon Res Regulatory News (PANR)

31st March 2023

Pantheon Resources plcInterim Results (unaudited) for the six months ended 31 December 2022

Pantheon Resources plc ("Pantheon" or "the Company"), the AIM-quoted oil and gas exploration and production company with 100% working interests in several conventional projects on the North Slope of Alaska, announces its interim results for the six months ended 31 December 2022 (the "Period"), together with operational highlights for the half year and the period beyond.

HIGHLIGHTS

Operational

· Drilling and long term production testing of the Alkaid #2 well - confirmed discovery

· Confirmed better than expected reservoir deliverability; very positive for future development

· Flow data and hydrocarbon mix adversely impacted by fracking intercepting a gas cap

· Future Alkaid wells to be positioned slightly deeper within the >400ft section to avoid the gas cap

· SLB (previously Schlumberger) completion of first module of project review and estimated Pantheon's projects to contain 17.8 billion barrels of oil in place

· Receipt of a report by the independent experts at Baker Hughes AHS ('Advanced Hydrocarbon Stratigraphy') titled "Pantheon Great Bear Theta West 1 well: Characterization of a World Class Petroleum System Using AHS's Cuttings' Volatiles Stratigraphy."

· Recent appointment of independent non-executive director, Mr David Hobbs, +40 years' experience

· Strengthening of operational team - recent appointment of Tony Beilman, +40 years drilling, completions and production experience

· Wood Mackenzie ('WoodMac') report Pantheon's Theta West #1 well as "the fourth largest discovery well globally in 2022".  Consistent with Pantheon's own assessment WoodMac characterise Theta West as a contingent resource requiring additional drilling and testing before potentially being considered commercial.

 Financial

· Loss for the period $1.6 million (2021: $4.4 million). Impacted by $4.8 million net credit from mark to market revaluation of derivative component and interest expenses on the Convertible Bond

· G&A slightly higher at $3.7 million (2021: $3.2 million) reflecting the growth in the operational activity

· Cash on hand 31 December 2022: $16.3 million (2021: $92.7 million)

· Cash on hand 30 March 2023: $10.8 million

Jay Cheatham, CEO of Pantheon Resources, said: 

"The period to 31 December 2022 and beyond has continued to be one of great achievement for our Company with an enormous volume of work having been undertaken, further supporting our confidence in our projects. Globally recognised WoodMac referred to Theta West #1 as being the fourth largest discovery well of 2022. Importantly, it is the only onshore well in the top four. AHS Baker Hughes also referred to Theta West #1 as a 'World Class Petroleum System.' We should all be very proud of these achievements. As I stated last year, which I repeat again, Pantheon's projects have the potential to be a nationally significant oil resource in a safe jurisdiction onshore USA.

"We do understand that Pantheon's share price has suffered, as a result of a number of factors including the results at Alkaid which represents less than 4% of our resource, social media mistruths, a lower oil price, and rising interest rates.. I reiterate again to shareholders that we see great potential in the Alkaid project. We know the flow test result was impacted because our fracks intercepted a gas cap. We will adjust for this in future wells by positioning them a little deeper and would expect to see significant improvement. Alkaid #2 was designed as a test well to gain data to optimise future wells. This is industry standard practice - at Prudhoe Bay, America's largest oilfield and only 20 miles north of us, the initial wells were dry holes! Alkaid was anything but a dry hole; far from it, our modelling points to Alkaid being a potential commercial development."

Further information:

Notes to Editors

Pantheon Resources plc is an AIM listed Oil & Gas company focused on several large projects located on the North Slope of Alaska ("ANS"), onshore USA where it has a 100% working interest in 153,000 highly prospective acres with potential for multi billion barrels of oil recoverable. A major differentiator to other ANS projects is its close proximity to transport and pipeline infrastructure which offers a significant competitive advantage to Pantheon, allowing for materially lower capital costs and much quicker development times. The Group's stated objective is to create material value for its stakeholders through oil exploration, appraisal and development activities in high impact, highly prospective conventional assets, in the USA; a highly established region for energy production with infrastructure, skilled personnel and low sovereign risk. All operations are onshore USA, with drilling costs materially below that of offshore wells.

For further information on Pantheon Resources plc, see the website at: www.pantheonresources.com

STATEMENT FOR THE SIX MONTHS ENDED 31 DECEMBER 2022

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The period 1 July 2022 and beyond has seen Pantheon continue to progress its projects across its large Alaskan portfolio spanning 153,000 acres, which management estimate to contain over 20 billion barrels of oil in place and more than 2 billion recoverable barrels of oil. At the same time, the macro energy environment we faced during the first half of 2022 faded somewhat in the last half year and into 2023 in reaction to global macroeconomic and geopolitical events. Supply chain issues impacted operations at Alkaid #2 materially, as did high cost inflation which was particularly impacted by extremely high diesel prices (although these have since eased), service provider and material costs.

Pantheon continued advancing its high-impact projects on the Alaska North Slope from the exploration phase to appraisal and development planning. The long term production test at Alkaid #2 was an important milestone in our passage to becoming an oil development and production company. Over that period, Pantheon produced and sold oil from its successful production test at Alkaid #2.

Pantheon's operational ambitions over 2023 and beyond are to test the Shelf Margin Deltaic ("SMD") which we believe has the potential to contain 2.6 billion barrels of OIP and a P50 Contingent Resource (recoverable) of 404 million barrels oil ("mmbo") in the Alaskan late spring/summer, prior to shifting our efforts into evaluating our 1.7 billion barrel discovered resource at Theta West as well as assessing the various discovered horizons at Talitha. Completion of these activities will require additional capital and in this regard Pantheon has prioritised the opening its data room in the near term to commence the process of finding a suitable farmout partner, or to otherwise raise capital to fund operations. Activities at Theta West and Talitha will include additional drilling and testing to increase our contingent resources with an aim to ultimately transition these resources to reserves allowing investors and the industry to recognize a higher valuation for the discoveries which have now been ranked amongst the largest in the world by several global research organizations. This is a credit to our team which have done a tremendous job in discovering this large resource and now working hard to unlock its value and deliver a commercial outcome for our shareholders.

Opening of Data Room

Pantheon has engaged SLB (nee Schlumberger) to manage and operate Pantheon's data room which is expected to open in the near term. In December 2022, SLB completed phase 1 of the project which included preparation of dynamic and static models over Pantheon's projects which they estimate to contain over 17 billion barrels of oil in place and which will form an important component of the data room. The purpose of the data room is to attract a potential farm in partner into one or more of Pantheon's projects, all of which Pantheon has a 100% working interest in. Pantheon is seeking a 'pay to earn' type arrangement (which may or may not include an additional up-front cash payment) where any potential farminee would fund a mutually agreed drilling/activity programme in exchange for a working interest in either a specific asset (for example, Alkaid) or across the entire portfolio. Pantheon recognizes the benefit in actively exploiting its portfolio which, in a success case, has the potential to create very significant value for shareholders given the large size of its projects. Historically at an industry level, Pantheon has maintained a low profile to protect its competitive advantage (Pantheon has sole access to c.1000 square miles of high quality 3D seismic) while prosecuting its acreage strategy. Pantheon has now successfully executed its acreage strategy and as such intends to increase the profile of the Company within both industry and in the investment community.

Alkaid #2 Drilling, Completion and Flow Testing

After more than a decade of exploration and appraisal on the North Slope of Alaska, Pantheon/Great Bear drilled and completed a pilot production test at its Alkaid oil accumulation. The Alkaid location was selected for this first test because of the positive test result from the nearby Alkaid #1 in 2019 coupled with the low cost location from which to drill and run a long term production test, being immediately adjacent to the highway. The Alkaid ZOI, being the deeper horizon and having flowed previously in the Alkaid #1 well, was the logical primary objective because we would subsequently be able to come up the hole to test the independent and five times larger SMD resource in the same wellbore where we expect to encounter high quality reservoir. A successful long term production test at Alkaid had the objective of proving the production capability and characteristics for the reservoir to allow for field development planning and as a tool for potential future debt financing. The Alkaid #2 well bore reached a measured depth of 14,300' including a 5,300' horizontal section which was all oil bearing. This lateral was successfully fracture stimulated with 30 frac stages, including the placement of +/- 8 million pounds of sand proppant. Production testing operations at Alkaid #2 commenced in October. Initially, frac sand production was higher than expected which necessitated a cleanout. Due to the lack of availability of a workover rig, a thru tubing coiled tubing cleanout procedure was undertaken which successfully cleared all but c.1000ft of the wellbore blockage. The Company used this hiatus to transition from temporary flow back facilities into its larger permanent facilities.

After returning to production in December, Pantheon reported production at a rate of over 500 barrels per day (bpd) of hydrocarbon liquids including oil, condensate and natural gas liquids (NGLs), as well as c2.5 mmcfpd natural gas, from approximately 4,000 ft of clean lateral wellbore. At this time, much discussion centred around the value of liquids produced at Alkaid #2. When separated and sold, condensate and NGLs are estimated to achieve 80% - 90%, or potentially higher, of ANS crude oil price (ANS crude typically trades at a premium to WTI oil). All liquids produced on the North Slope are blended and sent through the Trans Alaska Pipeline System (TAPS) to Valdez and on to market as ANS crude. The crude oil produced and sold during this time period averaged c.$87/Bbl.

In order to maximise data, Alkaid #2 was then shut in awaiting the arrival of the Nordic Calista #2 workover rig to pull the tubing and then clean out the remaining 1000 ft of blocked wellbore with a larger coiled tubing unit (CTU). During this shut in period extensive analysis was carried out to understand the much higher than anticipated gas production. Pantheon along with SLB (previously known as Schlumberger) now believe Alkaid #2 was drilled near a small gas cap which was not clearly visible from available seismic resolution and fracked into that gas cap. Gas production is now estimated as a combination of free gas from the gas cap along with gas from solution. The nearby Alkaid #1 well, tested in 2019 had a producing gas oil ratio (GOR) many times less than that of Alkaid #2 despite being in the same reservoir, suggesting an anomalous result. Pantheon will drill future development wells deeper to avoid the gas cap which should result in a lower GOR consistent with what we saw at Alkaid #1.

Post the cleanout of the sand blockage in the final 1,000ft (c.20%) of the wellbore, Alkaid #2 returned to production with flow rates only marginally higher than pre-cleanout, suggesting that despite the sand blockage, the final 1,000ft was likely connected and already contributing to the main wellbore through the fractures communicating with each other. The well soon returned to production along the pre cleanout decline profile. The initial 30 day Production (IP30) production rate is calculated at c.505 barrels per day (BPD) of marketable liquid hydrocarbons consisting of c.180 BOPD oil, c.325 BPD of condensate and NGLs, along with c.2,300 mcfpd natural gas after shrinkage. Encouragingly, the quantum of liquid and gas production flowing without artificial lift from Alkaid #2 demonstrates the good deliverability of the reservoir, which is a significant de-risking event for Alkaid development. The well has now flowed for c.90 days including the initial start up, and the reservoir engineering team has determined we have collected sufficient data to determine decline rates, a primary objective of the long term test. Given also the greater than forecast gas being produced, we have not sought an extension from the State of Alaska for a second 90 day flaring permit and have proactively shut in Alkaid#2. 

In January, for illustrative purposes, Pantheon stress tested the Alkaid development model using an estimated development well drilling cost of $19.5 million, which for conservatism modelled in a 50% increase over the then Company estimate of $13 million. The Company has continued to analyse and review this figure and currently estimates development drilling costs in the region of +/- $13.5 million per well. Applying $13.5 million well cost, assuming a 10,000ft lateral and no improvement in individual well productivity, our modelled Alkaid development economics yield a c.20% IRR at an $80 ANS crude price. This indicates that without including the benefit of any expected improvement in hydrocarbon liquid flow from deeper and down dip completions, Alkaid is modelled as economic even as a stand-alone development. However, in practice, Alkaid is unlikely to ever be a stand-alone development because of the other oil accumulations, such as the SMD, in and around the Alkaid structure that were not included in the economics and will be evaluated as part of our future activities mentioned above. The ability to share infrastructure between projects significantly enhances modelled field economics.

Alkaid represents less than 4% of Pantheon's resource base, is not representative of Pantheon's other discoveries and is Pantheon's first production test well in a new geological play type. As is typical for first time operations in new fields, there is a learning curve with any first well that will be optimized over subsequent wells to yield the best results.

Commissioning of Independent Expert Reports

Pantheon has commissioned Netherland Sewell & Associates (NSAI), a worldwide leader in petroleum property analysis and one of the most respected names in independent reserves reporting, to undertake two independent expert reports (Competent Persons Report) over each of the Company's Theta West and Alkaid projects. Additionally, SLB (nee Schlumberger) is updating the dynamic reservoir models across Pantheon's portfolio to incorporate into the NSAI report. The SLB and NSAI work will run in parallel to the farmout process providing investors and financiers an independent assessment of the resources.

Strengthening Board and Technical Team

Pantheon announced the appointment of David Hobbs as an independent non-executive Director.

David is an outstanding addition to our team, bringing great experience and technical knowledge to Pantheon. David graduated as a Petroleum Engineer from Imperial College in 1984, initially working at British Gas as a drilling engineer before moving into commercial and business development roles at Monument Oil & Gas and Hardy Oil and Gas, two UK listed international independent E&P companies. He joined Cambridge Energy Research Associates (CERA), now part of S&P Global, ending up as Chief Energy Strategist, advising Government officials, senior executives and Boards of Directors across the energy sector. He also spent six years as part of the leadership team establishing the King Abdullah Petroleum Studies and Research Center (KAPSARC) in Riyadh, Saudi Arabia. David is an adjunct professor at the University of Calgary.

Pantheon has also enhanced its technical and operational team with the addition of Tony Beilman. Tony has over 40 years' experience in the industry starting his career at Phillips Petroleum. Tony specializes in drilling and completions especially in horizontal well bores, with an emphasis on fracture stimulation. Tony also co-founded a drilling and production company and his wealth of experience is undoubtedly going to improve Pantheon's operational execution.

We enthusiastically welcome both David and Tony to the team.

Financial & Corporate

The interim results show a loss for the period of $1.6m (2021: $4.4m) which is lower than the comparative interim period, largely impacted by a $4.8m net credit which resulted from the combined mark to market revaluation of the derivative component of the unsecured Convertible Bond and interest charges on the debt component. General and administration expenses of $3.7m (2021: $3.2m) were slightly higher than the prior year reflecting the growth of the Company. Revenue generated during the period was $0.5m (2021: $Nil), resulting from oil sales during testing of the Alkaid #2 well. Due to the disproportionate start up commissioning and operations costs, there was a gross loss of $0.6m (2021: Nil) on operations.

At 31 December 2022, cash and cash equivalents amounted to $16.3m (2021: $92.7m). As previously announced, the Company had a successful operational campaign since 1 July 2021, encountering oil in all three wells drilled and/or tested/testing by the Group including Theta West #1, Talitha #A and Alkaid #2. The data and analysis from drilling and testing activities resulted in material increases to Company estimates for both Oil in Place and recoverable resource. The Company has sufficient working capital to continue operations to the end of 2023, however as previously reported, intends to complete either a farmout and/or other funding arrangement in the first half of 2023 to have sufficient resources for the 2023/24 drilling and testing campaign, the additional acreage purchases and ongoing working capital. The Company's data room is anticipated to open shortly to formally commence the process of seeking an appropriate farmout partner.

Supporting farmout efforts, the Company has commissioned Netherland Sewell & Associates to undertake an independent expert report over the Company's Theta West and Alkaid projects. Additionally, SLB is updating the dynamic reservoir models across Pantheon's portfolio as part of the second phase of their work. These reports will run in parallel to the farmout process as well as providing investors and financiers an independent assessment of the resources. 

In 2021 the Company issued $55 million senior unsecured convertible bonds (the "Convertible Bonds"). The Convertible Bonds carry a coupon of 4.0% per annum and are repayable in equal quarterly instalments (the "Amortisations") over the 5 year term of the Convertible Bond. Such Amortisations are payable in cash or shares at the Company's option. As at 31 December, 2022 the principal outstanding on the bond was $39.2m ($36.75m as of the date of publication of this report). A summary of the key terms of the Convertible Bond can be found at Note 5.

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

FOR THE PERIOD ENDED 31 DECEMBER 2022

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CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE PERIOD ENDED 31 DECEMBER 2022

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CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

AS AT 31 DECEMBER 2022

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CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE PERIOD ENDED 31 DECEMBER 2022

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RECONCILIATION OF OPERATING LOSS TO NET CASH OUTFLOW FROM OPERATING ACTIVITIES

NOTES TO THE FINANCIAL INFORMATION

FOR THE PERIOD ENDED 31 DECEMBER 2022

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1. Accounting policies

A summary of the principal accounting policies, all of which have been applied consistently throughout the period, is set out below.

1.1. Basis of preparation

This financial information has been prepared on a going concern basis using the historical cost convention and in accordance with the International Financial Reporting Standards as adopted by the European Union ("EU") ("IFRS"), including IFRS 6 'Exploration for and Evaluation of Mineral Resources', and in accordance with the provisions of the Companies Act 2006.

This interim report has been prepared on a basis consistent with the Group's expected accounting policies for the year ending 30 June 2023. These accounting policies are the same as those set out in the Group's Annual Report and Financial Statements for the year ended 30 June 2022, which are available from the registered office or the company's website (www.pantheonresources.com).

The Group financial information is presented in US Dollars and is unaudited. The interim financial information does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. The comparative figures for the year ended 30 June 2022 have been taken from the Group's statutory accounts for that financial year, which have been reported on by the Group's auditors and delivered to the Registrar of Companies. 

1.2. Basis of consolidation

Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date that control ceases. The purchase method of accounting is used to account for the acquisition of subsidiaries by the Group. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued, and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any minority interest. The excess of the cost of acquisition over the fair value of the Group's share of the identifiable net assets acquired is recorded as goodwill. Goodwill arising on acquisitions is capitalised and subject to impairment review, both annually and when there are indications that the carrying value may not be recoverable.

Inter-company transactions, balances and unrealised gains on transactions between group companies are eliminated. All the companies over which the Company has control apply, where appropriate, the same accounting policies as the Company.

1.3. Foreign currency translation

(i) Functional and presentational currency

The financial statements are presented in US Dollars ("$"), which is the functional currency of the Company and is the Group's presentation currency.

(ii) Transactions and balances

Transactions in foreign currencies are translated into US dollars at the average exchange rate for the year. Monetary assets and liabilities denominated in foreign currencies are translated at the rate of exchange ruling at the balance sheet date. The resulting exchange gain or loss is dealt with in the income statement.

The assets, liabilities and the results of the foreign subsidiary undertakings are translated into US dollars at the rates of exchange ruling at the year end. Exchange differences resulting from the retranslation of net investments in subsidiary undertakings are treated as movements on reserves.

1.4. Cash and cash equivalents

The company considers all highly liquid investments, with a maturity of 90 days or less to be cash equivalents, carried at the lower of cost or market value.

1.5. Going concern

The interim report has been prepared on the going concern basis, which contemplates the continuity of normal business activity and the realisation of assets and the settlement of liabilities in the normal course of business.

At 31 December 2022, cash and cash equivalents amounted to $16.3m (2021: $92.7m). As previously announced, the Company had a successful operational campaign since 1 July 2021, encountering oil in all three wells drilled and/or tested/testing by the Group including Theta West #1, Talitha #A and Alkaid #2. The data and analysis from drilling and testing activities resulted in material increases to Company estimates for both Oil in Place and recoverable resource. The Company has sufficient working capital to continue operations to the end of 2023 however as previously disclosed, the Company intends to complete either a farmout and/or other funding arrangements in the first half of 2023 to have sufficient resources for the anticipated 2023/24 drilling and testing campaign, the additional acreage purchases, and ongoing working capital. The Company is confident of achieving one or both of these objectives. The Company's data room is expected to open in the near term to formally commence the process of seeking an appropriate farmout partner.

Supporting farmout efforts, the Company has commissioned Netherland Sewell & Associates to undertake an independent expert report over the Company's Theta West and Alkaid projects. Additionally, SLB is updating the dynamic reservoir models across Pantheon's portfolio as part of the second phase of their work. These reports will run in parallel to the farmout process as well as providing investors and financiers an independent assessment of the resources. 

1.6. Revenue

The Group is engaged in the business of extracting oil and gas. Revenue from contracts with customers is recognised in accordance with IFRS15 Revenue from Contacts with Customers, at an amount that reflects the consideration to which the Group expects to be entitled in exchange for those goods.

Contract balances

A contract asset is the right to consideration in exchange for goods transferred to the customer. If the Group performs by transferring goods to a customer before the customer pays consideration or before payment is due, a contract asset is recognised for the earned consideration that is conditional. The Group does not have any contract assets as performance and a right to consideration occurs within a short period of time and all rights to consideration are unconditional.

Interest revenue is recognised on a proportional basis taking into account the interest rates applicable to the financial assets.

1.7. Deferred taxation

Deferred tax is provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the balance sheet date and expected to apply when the related deferred tax is realised, or the deferred liability is settled.

Deferred tax assets are recognised to the extent that it is probable that the future taxable profit will be available against which the temporary differences can be utilized.

1.8. Exploration and evaluation costs and developed oil and gas properties

The Group follows the 'successful efforts' method of accounting for exploration and evaluation costs. At the point of production, all costs associated with oil, gas and mineral exploration and investments are classified into and capitalised on a 'cash generating unit' ("CGU") basis, in accordance with IAS 36. Costs incurred include appropriate technical and administrative expenses but not general corporate overheads. If an exploration project is successful, the related expenditures will be transferred to Developed Oil and Gas Properties and amortised over the estimated life of the commercial reserves on a 'unit of production' basis.

The recoverability of all exploration and evaluation costs is dependent upon the discovery of economically recoverable reserves, the ability of the Group to obtain necessary financing to complete the development of the reserves and future profitable production or proceeds from the disposition thereof. All balance sheet carrying values are reviewed for indicators of impairment at least twice yearly. The prospect acreage is classified into discrete "prospects" or CGU's. When production commences the accumulated costs for the specific CGU is transferred from intangible fixed assets to tangible fixed assets i.e., 'Developed Oil & Gas Properties' or 'Production Facilities and Equipment', as appropriate. Amounts recorded for these assets represent historical costs and are not intended to reflect present or future values.

1.9 Impairment of exploration costs and developed oil and gas properties, depreciation of assets, plug & abandonment and goodwill

In accordance with IFRS 6 'Exploration for and Evaluation of Mineral Resources' (IFRS 6), exploration and evaluation assets are reviewed for indicators of impairment. Should indicators of impairment be identified an impairment test is performed.

In accordance with IAS 36, the Group is required to perform an "impairment test" on assets when an assessment of specific facts and circumstances indicate there may be an indication of impairment, specifically to ensure that the assets are carried at no more than their recoverable amount. Where an impairment test is required, any impairment loss is measured, presented and disclosed in accordance with IAS 36.

Exploration and evaluation costs

All exploration and evaluation assets relate to the Group's Alaskan operations. The Alaskan leasehold assets were fair valued as at the date of acquisition of Great Bear and the carrying value at 31 December 2022 represents the cost of acquisition (plus the fair value adjustment, in accordance with IFRS) and any capitalised costs incurred subsequent to the acquisition.

Decommissioning Charges

Decommissioning costs will be incurred by the Group at the end of the operating life of some of the Group's facilities and properties. The Group assesses its decommissioning provision at each reporting date. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing, extent and amount of expenditure may also change - for example, in response to changes in reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The provision at reporting date represents management's best estimate of the present value of the future decommissioning costs required.

For all wells the Group has adopted a Decommissioning Policy in which all decommissioning costs are recognise immediately when a well is either completed, abandoned, suspended or a decision taken that the well will likely be plugged and abandoned in due course. For completed or suspended wells, the decommissioning charge is recorded against the capitalised amount and subsequently depleted over the useful life of well using unit of production method.

1.10 Financial instruments

Recognition and derecognition 

Financial assets and financial liabilities are recognised when the Group becomes a party to the contractual provisions of the financial instrument. 

Financial assets, if/where applicable, are derecognised when the contractual rights to the cash flows from the financial asset expire, or when the financial asset and substantially all the risks and rewards are transferred. 

A financial liability is derecognised when it is extinguished, discharged, cancelled or expires. 

Classification and measurement of financial liabilities 

The Group's financial liabilities include borrowings (convertible bond debt), trade and other payables and embedded derivative financial instruments. 

Financial liabilities are initially measured at fair value, and, where applicable, adjusted for transaction costs unless the Group designated a financial liability at fair value through profit or loss. 

Subsequently, financial liabilities are measured at amortised cost using the effective interest method except for derivatives and financial liabilities designated which are carried subsequently at fair value with gains or losses recognised in profit or loss. 

All interest-related charges and, if applicable, changes in an instrument's fair value that are reported in profit or loss are included within finance costs or fair value gains/(losses) on derivative financial instruments. 

Embedded derivative financial instruments 

A borrowing arrangement structured as a convertible bond repayable in stock over 20 quarterly instalments, in addition to the right of the lender to voluntarily convert part or all of the outstanding principal prior to the maturity date of the bond, has embedded in it a derivative. This is considered to be a separable embedded derivative of a loan instrument. 

At the date of issue, the fair value of the embedded derivative is estimated using Monte Carlo analysis, by considering the derivative as a series of individual components with modelling of the fixed and floating legs to determine a repayment schedule and derive a net present value. 

This amount is recognised separately as a financial liability or financial asset and measured at fair value through the income statement. The residual amount of the loan is then recorded as a liability on an amortised cost basis using the effective interest method until extinguished upon conversion or at the instrument's maturity date. 

2. Loss per share

The calculation above for the loss per share has been calculated by dividing the loss for the period from continuing operations, by the weighted average number of ordinary shares in issue of 764,186,409 (December 2021: 676,479,991; June 2022: 724,563,153). As the Group recorded a loss for the period, the diluted loss per share has been made to equal the basic loss per share.

3. Non-current assets

In January 2019, the Group acquired 100% of the share capital of Great Bear Petroleum Ventures I LLC and Great Bear Petroleum Ventures II LLC companies (collectively, "Great Bear"). The principal assets of Great Bear are leases with the rights to explore for hydrocarbons in the State of Alaska. At the period end the exploration and evaluation assets all relate to the Alaskan operation; Alaskan assets $274.3m (December 2021: $195.7m).

Exploration and evaluation assets are constantly reviewed for indicators of impairment. If an indicator of impairment is found an impairment test is required, where the carrying value of the asset is compared with its recoverable amount. The recoverable amount is the higher of the assets fair value less costs to sell and value in use. The directors are satisfied that no impairments are required for the current period end.

Property, plant and equipment

4. Share Capital

During the period, in September and December 2022, the company elected to meet its quarterly Convertible Bond amortisation obligations by issuing a total of 6,077,187 ordinary shares.

In September 2022 the Company received instructions to exercise a total of 4,525,000 share options. The new ordinary shares have a nominal value of £0.01. Total proceeds to the Company for the exercised options was $1,756,018.

As at 31 December, 2022 the company had on issue 778,307,724 shares.

As at 31 December, 2022 the Company also has the following options and warrants:

· 4,825,000 share options and 4,803,921 warrants; all with a £0.30 exercise price and all expiring September 2024. The warrants are identical to the share options except are convertible into non-voting shares on a 1:1 basis.

· 7,000,000 share options with an exercise price of £0.27, expiring July 2030.

· 12,430,000 share options with an exercise price of £0.33, expiring January 2031.

· 21,380,000 share options with an exercise price of £0.67, expiring January 2032.

5. Unsecured Convertible Bond

In December 2021, the Company issued $55 million face value of senior unsecured convertible bonds to a fund advised by Heights Capital Ireland LLC, a global equity and equity-linked focused investor. At the date of publication of this report the remaining principal outstanding was $36.75m.

The Convertible Bonds have a maturity of 5 years, a coupon of 4.0% per annum and are repayable in 20 quarterly repayments ("amortisations") of principal and interest over the 5 year term of the convertible bond. Such quarterly amortisations are repayable at the Company's option, in either cash at face value, or in ordinary shares ("stock") at the lower of the conversion price (presently USD$1.032 per share) or a 10% discount to volume weighted average price ("VWAP") in the 10 or 3 day trading period prior to election date. Additionally, the bondholder has the option to partially convert the convertible bond at their discretion. A full summary of the terms of Convertible Bonds is detailed in the Company's RNS dated 7 December, 2021.

The bond agreement contains embedded derivatives in conjunction with an ordinary bond. As a result, and in accordance with the accounting standards, the convertible bonds are shown in the Consolidated Statement of Financial Position, in two separate components, namely Convertible Bond - Debt and Convertible Bond - Derivative. At the time of initial recognition (Dec 2021) the $55m bonds were split, $39,175,363 for the Debt Component and $15,824,637 for the Derivative Component.

In order to value the derivative component, Pantheon engages an independent third party expert valuation specialist group to perform the valuations bi-annually, who determined that the valuation of the instrument required a Monte-Carlo simulation of share price outcomes over the 5 year life to determine the ultimate value of the conversion option. This produced a calculated Effective Interest Rate ("EIR") of 20.41%. For the 6 month period ended 31 December 2022, the third party expert valuation group performed their Monte-Carlo simulation and valuation calculations to determine the new value for the equity component to be $3,587,629. The resulting movement was posted to the consolidated statement of comprehensive income to the account "Revaluation of derivative liability". These amounts will be revalued every balance date with the differences being accounted for on a mark to market basis.

For the 6 month interim period to 31 December 2022, two quarterly repayments (amortisations) were made, and in both cases ordinary shares were issued in full settlement. Subsequent to year end, in March 2023, an additional quarterly repayment (amortisation) was made, and in all cases ordinary shares were issued in full settlement.

At 31 December 2022 the Unsecured Convertible Bond is shown in the Consolidated Statement of Financial Position in the following categories;

6. Approval by Directors

The interim report for the six months ended 31 December 2022 was approved by the Directors on the 30th of March 2023.

7. Availability of Interim Report

The interim report will be made available shortly on the Company's website (www.pantheonresources.com), with further copies available on request from the Company's registered office.

8. Contingent liability

Pursuant to IAS37, a contingent liability is either: (1) a possible obligation arising from past events whose existence will be confirmed only by the occurrence or non-occurrence of some uncertain future event not wholly within the entity's control, or (2) a present obligation that arises from a past event but is not recognized because either: (i) it is not probable that an outflow of resources embodying economic benefits will be required to settle the obligation, or (ii) the amount of the obligation cannot be measured with sufficient reliability.

Kinder Morgan Treating L.P. ("Kinder Morgan") initiated a dispute over an East Texas gas treating agreement between Kinder Morgan and Vision Operating Company, LLC ("VOC"). VOC ceased making payments to the service provider in July 2019. The service provider subsequently issued a demand to VOC and, in February 2021, served Pantheon Resources plc with a petition, seeking to recover not less than $3.35m in respect of this VOC contract. Pantheon held ownership of less than 0.1% of VOC via a 66.6% interest in Vision Resources LLC. Both Vision Resources LLC and VOC filed for Chapter 7 Bankruptcy in the United States Bankruptcy Court for the Southern District of Texas Houston Division in April 2020

No Pantheon entity is a signatory to the gas treating agreement and none are named in the agreement. Pantheon has taken legal advice on the matter and believes it has no liability to the service provider. Accordingly, Pantheon does not consider a provision should be included with the final statements and will contest any claim made.

In, July 2021, the court dismissed Kinder Morgan's claims against Pantheon Resources plc. Kinder Morgan has also asserted the same claims against two subsidiaries, Pantheon Oil & Gas, LP and Pantheon East Texas, LLC. Pantheon Oil & Gas, LP and Pantheon East Texas, LLC are contesting these claims.

9. Subsequent events

Alkaid #2 production test well - operations

In January 2023 Pantheon confirmed that the Nordic Calista #2 rig would mobilize to the Alkaid #2 location to undertake a cleanout of the estimated c.1,000ft sand blockage in the horizontal wellbore. The commencement of these operations was repeatedly delayed due to poor weather and a number of electrical and hydraulic issues with the rig, which were subsequently resolved. The cleanout of the wellbore was successfully completed, however post cleanout the flow rates were only marginally higher than pre-cleanout flow rates suggesting that the sand blockage affected final 1,000ft of the wellbore had likely already been connected and contributing to the main wellbore, probably through the fractures having been connected and in communication with each other. The IP30 (average flow over 30 days) production rate was calculated at c.505 barrels per day ("BPD") of liquid hydrocarbons consisting of c.180 BOPD oil, c.325 BPD of condensate and natural gas liquids ("NGLs"), along with c.2,300 mcfpd natural gas, after shrinkage. Very importantly, this quantum of liquid and gas production was flowing without artificial lift demonstrating better than expected reservoir deliverability, which is positive and considered a significant de-risking event for future Alkaid development.

It is believed that the Alkaid #2 well most likely fracked into a gas cap which resulted in a much higher gas oil ratio ("GOR") than encountered at the nearby Alkaid #1 well in the same reservoir. Analysis suggests that future wells should be drilled a little deeper to avoid the gas cap and thus should have the potential to produce a much improved GOR with a superior outcome. Alkaid #2 was always designed as a production test well whose primary objective was to gather information to assist in understanding the productive capability of the reservoir and to assist in modelling and engineering future development scenarios and commerciality. The decline rate at Alkaid #2 has provided sufficient data to accurately model well performance and given the significantly greater than expected gas production at Alkaid #2, likely as a result of the intercepted gas cap, Pantheon has elected to not apply to the State of Alaska for an extension of its gas flaring permit and thus has concluded its flow testing operations of the zone of interest at Alkaid #2. The wellbore will now be prepared for the future testing of the shallower shelf margin deltaic ("SMD") in the vertical section of the wellbore.

During drilling to target depth, Alkaid #2 penetrated the shallower SMD reservoir, which management estimates contains over 400 million barrels of oil ("mmbo") recoverable resource, over five times larger than the Alkaid reservoir and with superior reservoir quality. The addition of these resources to any potential Alkaid development will significantly boost economic returns. Testing of oil and gas wells is always sequenced from deepest to shallowest horizons, hence why SMD testing would always follow Alkaid testing.

Appointment of Independent non executive director

Pantheon announced the appointment of David Hobbs as an Independent Non-Executive Director, effective 22 March 2023. Mr Hobbs is a Petroleum Engineer with over 20 years experience in upstream oil and gas and 20 years experience in strategy and energy policy.

Payment of quarterly amortization of convertible loan

In March 2023, Pantheon announced that it elected to pay (i) the quarterly principal repayment of US$2.45 million and (ii) the interest payment of US$0.392 million (collectively, the "Quarterly Repayment") in respect of its senior unsecured convertible bonds due 2026 (the "Convertible Bonds"), through the issuance of 9,257,328 new shares.

Issuance of 290,000 ordinary shares

In February 2023, Phillip Gobe, non-executive Chairman and a person discharging managerial responsibility (PDMR) in the Company, was issued and allotted 290,000 Ordinary Shares as a result of the conversion of 100% of his previously granted 290,000 Restricted Stock Units ("RSUs"). Following the completion of this allotment.

Other key appointments

Pantheon has appointed Tony Beilman, a petroleun engineer with over 40 years experience in drilling, production and completions to the team. Tony's appointment significantly strengthens Pantheon's operational capability.

Other key events

Pantheon as contracted SLB (nee Schlumberger ) to continue work on Phase 2 of the reservoir dynamic model across the entire acreage and four reservoirs within Pantheon's portfolio, and to manage the data room present for prospective farminees.

Commissioning of Independent Expert Reports on Theta West and Alkaid

Pantheon has formally appointed Netherland Sewell & Associates, an independent and highly reputable resource reporting firm, for the preparation of Independent Experts Reports over its Theta West and Alkaid projects.

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