Serica Announces Results for the 6M Ended 30 June 2021

Source: www.gulfoilandgas.com 10/28/2021, Location: Europe

Serica Energy plc announced its financial results for the six months ended 30 June 2021.

Mitch Flegg, Serica's CEO stated:
“In the current environment Serica’s focus on gas production and investment in new projects is expected to generate very significant returns for shareholders and help support further investment.

In the first half of the year, we continued to pursue our strategy of capital investment in our assets. This has allowed us to recomplete the Rhum R3 well and bring it into production in August and to drill the Columbus development well which is now ready to produce. Serica’s production is over 80% gas and we are delighted that we are already seeing the benefits of our investment strategy in the second half through increasing production levels at a time of record high wholesale gas prices.

We expect first production from Columbus in Q4 this year and then Serica’s share of receipts under the BKR Net Cash Flow Sharing mechanism increases from 60% to 100% on 1 January 2022. Later in 2022 we intend to drill the North Eigg well which, if successful, will enhance gas reserves in the BKR area and potentially extend the life of Bruce and related infrastructure.

Serica is currently responsible for around 5% of UK gas production and our role in enhancing and extending the life of that production and helping to maintain forward supply during a period of energy transition, is essential to meet UK energy needs.”

First Half Performance
• Gross profit of £46.0 million (1H 2020: loss of £19.8 million) and cash flow from operations of £63.8 million (1H 2020: £19.3 million).
• Group 1H average production of 18,900 boe per day net to Serica compared to 21,600 boe per day for 1H 2020 after extended field maintenance shut-ins during H1 following last year’s COVID-19 related deferrals.
• Rhum R3 well workover completed and commenced production in late August 2021. Columbus production well drilled and tied into the export system ready for first production in Q4.
• Capital investment of £43.0 million (2020: £26.6 million) all funded from internal cash resources.

Financial Highlights
• Closing cash balance up at £92.0 million (31 December 2020: £89.3 million) despite significant capex spend.
• Average realised sales price of US$43.30 per boe (1H 2020: US$15.20 per boe) before net hedging gains/losses.
• Average operating cost of US$16.05 per boe for 1H 2021 (1H 2020: US$15.12 per boe) reflected lower production in the period - underlying costs reduced by 10% during 1H 2021 (2020: 10%).
• Operating profit of £5.5 million (1H 2020: loss of £12.7 million) after £30.3 million of unrealized hedging provisions.
• Profit before tax of £2.2 million (1H 2020: £20.4 million). Profit after tax of £1.3 million (1H 2020: £12.4 million) after non-cash deferred tax provision of £0.9 million (1H 2020: £8.0 million).

Operational
• 10% reduction in operating costs during 1H 2021 builds on similar reduction already achieved during 2020. This translates into a reduction in operating costs per boe as new production volumes delivered from R3 and Columbus during 2H 2021.
• The Rhum R3 well workover adds more than 4,000 boe/d to Serica’s share of Rhum gas production capacity.
• Columbus well drilled to measured depth of 17,600ft and flowed predominantly gas at over 8,000 boe/d gross (Serica 50%).

Environmental, Social and Governance
• Additional Rhum R3 production utilises existing facilities reducing BKR emissions intensity and operating cost per boe.
• Single Columbus well also uses existing offtake infrastructure, limiting additional emissions and cost per boe.
• Such investment boosts domestic low emission gas supplies and reduces need for higher emission imports thus supporting the UK’s energy transition.
• We continue to seek further opportunities to reduce the carbon intensity of our production and deliver our ESG objectives.
• Andy Bell has joined the Board as CFO on 3 September and today we announce the appointment of Richard Rose as a Non-Executive Director.

Outlook
• New production from Rhum R3 and Columbus well timed to benefit from the unprecedented rise in gas prices from 2020 lows.
• In view of the extraordinary volatility in global gas markets over the past 18 months we will maintain a prudent hedging programme whilst retaining material upside – over 80% of projected oil and gas volumes unhedged.
• 2020 dividend of 3.5 pence per share (2019: 3 pence per share) paid in July. The level of dividend for 2021 will be reviewed in light of the strong gas price trends currently unfolding in the second half of this year.
• Serica’s share of receipts retained under the BKR Net Cash Flow Sharing mechanism increases from 60% to 100% on 1 January 2022.

Since the start of 2021 Serica has benefitted from a much-improved economic environment, most notably oil and gas prices which have recovered from the very low levels seen last year. Serica’s production is over 80% gas and so the recent exceptional rise in wholesale gas prices has a particularly material impact. Market gas prices averaged over 56p per therm in the first half of 2021 which is some three times higher than the corresponding period in 2020 and are averaging close to 150p per therm for September 2021. Prices have strengthened even further in the second half, coinciding with second half increases in Serica’s gas production as new projects (R3 and Columbus) come on-line.

As a result of increased oil and gas prices in the first half, Serica’s sales revenue for the six-month period was £100.8 million compared to £46.0 million for the corresponding period in 2020, notwithstanding reduced first half production levels to accommodate planned maintenance programmes. Gross profit was £46.0 million compared to a gross loss of £19.8 million in the same period in 2020.

Production net to Serica for the period averaged 18,900 boe/d (1H 2020: 21,600 boe/d) and was impacted by the planned maintenance outage for the Forties Pipeline System and additional work designed to catch up on work programmes deferred from last year by COVID-19 restrictions. Production for the second half of the year will be much improved as the impact of R3 and Columbus is seen, and the full year guidance is now set at between 23,000 and 25,000 boe/d. The outlook for the second half of this year is particularly encouraging as gas prices have strengthened to new record highs. We are already seeing the benefits of these increases in July and August sales revenues with September revenues boosted further still by increasing gas production.

Significantly improved net cash inflow from 1H operations (£63.8 million compared with £19.3 million in 1H 2020), combined with strong cash balances, has allowed the Company to successfully continue its growth strategy of investment in projects designed to enhance and extend future production profiles. The work on the R3 well intervention project overcame complex technical issues and was successfully concluded. A well test was performed which demonstrated that the well can deliver at gross production rates in excess of 10,000 boe/d1. The well has subsequently been put into production. The Columbus development well was also drilled to a measured depth of 17,600ft with a horizontal section of over a mile in length. The completion equipment has been successfully installed into the well and a flow test was performed and resulted in a stabilized gross flow rate of over 8,000 boe/d2. The well has now been hooked up and first production is expected in Q4 2021.

Both of these capital projects optimize the use of existing equipment thus minimizing their environmental impact. Columbus is tied into the Arran pipeline that runs into the Shearwater platform and so the additional pipeline and processing equipment associated with the well are minimal. R3 was drilled and tied into Bruce in 2006 and we carried out the essential work to bring it back into service and do the job it was designed to do. Both projects will increase our gas production into the UK, providing much needed domestic gas during the energy transition. That both are being brought into production at a time of severe gas shortages in the UK and unprecedented gas prices will have a material impact on the second half, providing strong support for our ongoing investment programme aimed at maximizing existing resources and extending infrastructure life.

On our Bruce platform we continue to drive down our emissions and are on track to achieve a 20% reduction in such emissions compared to 2018 figures3. Our 2021 flare volumes remain low, maintaining a 65% reduction since 2018, due to best practice and improved operating procedures. We continue to look for improvements and have installed Artificial Intelligence software to track performance and identify further emissions savings. R3 production puts us in a strong position to lower the carbon intensity of Bruce going into 2022 as the platform runs more efficiently.

Our growth strategy will continue into 2022 as we drill the North Eigg exploration well. This is an exciting opportunity targeting a large gas prospect close to existing Serica infrastructure and lying within the BKR area. In the case of success at North Eigg we believe that it would be possible to develop the resources in a carbon neutral manner.

Serica continues to benefit from having no debt, significant cash reserves, limited decommissioning liabilities and from gas being a material part of our portfolio. This enabled the payment of an increased dividend of 3.5p per share in July this year and it is our intention to remain a regular dividend payer.

Last year our gas price hedging programme played an important part in sustaining our financial stability during a very challenging period. This allowed us to initiate a dividend policy in 2020 whilst also maintaining our capital investment programme through 2020 and 2021. This year the unprecedented and continuing surge in gas prices has required significant accounting provisions based upon future-period hedge valuations. This is reflected in our first half reported profit which is net of a £30.3 million non-cash hedge provision against £3.3 million in the prior year first half. It is important to recognize that this provision will only be realised if gas prices continue to maintain their current very high levels but in those circumstances the Company will be benefitting enormously from the high prices as around 80% of the Company’s projected oil and gas production is unhedged. In view of the extraordinary scale of gas price volatility seen over the past eighteen months, with unprecedented lows quickly followed by unprecedented highs, we believe it important to maintain a prudent price hedging programme within sensible cost constraints whilst retaining material upside exposure.

Our financial strength positions us well to take advantage of the opportunities to expand our portfolio through M&A (Mergers & Acquisition) activity. However, extreme price volatility makes transactions aimed at utilising the Company’s skills, extending infrastructure life through new investment and building on synergies difficult to execute.

During the period we have made proposals to acquire significant asset packages but to date we have not secured a deal at a price that is attractive to us. We will not overpay in order to secure a quick deal, but we continue to work on a number of opportunities to grow the Company.

At the end of this year, the BKR net cash flow sharing arrangements come to an end after four years during which the Company has been able to enhance the performance of the assets materially from all aspects and from which all of our partners have benefitted.

We are proud of this performance. Under these arrangements we shared the net cash flow with the vendors of the relevant assets with Serica receiving 40% of the relevant net cash flow from the BKR assets in 2018, rising to 50% in 2019 and 60% in 2020 and 2021. At the end of this year we enter a new phase for the Company when we will be retaining 100% of the net cash flow.

Finally, I would like to thank the staff and management of the Company and our contractors and to congratulate them all on the significant achievements this year. The constraints imposed by the ongoing Covid-19 pandemic have added significant complexity to all of our operations and logistics. The achievements of 2021 are a demonstration of Serica’s outstanding operating capability.

REVIEW OF OPERATIONS

UK Operations
UK Production
Northern North Sea: Bruce Field – Blocks 9/8a, 9/9b and 9/9c, Serica 98% and operator Serica is operator of the Bruce facilities which consist of three bridge-linked platforms, wells, pipelines and subsea infrastructure. The platforms contain living quarters, reception, compression, power generation, processing and export facilities and a drilling platform that is currently mothballed. The offshore team is supported onshore from the Serica technical headquarters in Aberdeen.

The Bruce field is produced through a combination of platform wells and subsea wells tied back to the platform, with a total of over 20 wells producing from multiple reservoirs and compartments. Bruce production is predominantly gas, which is rich in natural gas liquids (“NGL’s”), plus condensate. Gas is exported through the Frigg pipeline to the St Fergus terminal, where it is separated into sales gas and NGL’s. Condensate is exported through the Forties Pipeline System to Grangemouth where it is sold as Forties blend oil.

As with the rest of the UK and the offshore industry, we have continued to manage the impact of the COVID-19 outbreak. We continue to enforce our travel policies, including PCR testing prior to mobilization, social distancing, repeat testing and the option of home working for all office-based staff. As of the date of writing, Serica has experienced no interruption in production due to the COVID-19 outbreak though the associated reduced personnel levels on the platform caused some deferral of planned programmes which we are working to catch up this year. We continue to monitor the ongoing situation and are constantly working with our medical advisors to minimize risk to our staff.

During May and June, we executed the planned platform outage which was timed to align with maintenance on the Forties pipeline system. This outage had been delayed since summer 2020 due to COVID. The work was carried out safely within the COVID restrictions and delivered the planned scopes on budget including additional work delayed from 2020. It is intended to carry out further well work during 2H to sustain field production levels.

The commute undertaken by our workers is one of the more unusual ways to get to work and at the platform itself, the helideck is a key to being able to perform this operation safely at all times and in all weathers. This year we have accomplished the complete strip down, recoat and return to service of the helideck using a technology that saved time (operating within a restricted helideck is logistically challenging) and reduced the waste generated from the activity.

The ongoing work of efficiently running Bruce has confirmed our latest projected field life to 2030. As before, further extensions are possible depending on the operating environment and sustaining robust late life field economics.

Bruce field production in 1H 2021 averaged in excess of 6,800 boe/d (1H 2020: 9,300 boe/d) of exported oil and gas net to Serica.

The latest independent report of reserves, compiled by RISC Advisory, estimated 2P reserves of 15.7 million boe net to Serica as of 1 January 2021 (2020: 22.2 million boe).

Northern North Sea: Keith Field – Block 9/8a, Serica 100% and operator
Keith is a small oil field produced via one subsea well tied back to the Bruce facilities and requires very little maintenance. Keith produces at a relatively low rate but contributes to oil export from Bruce at minimal additional cost. In the first half of the year we undertook two platform based well interventions which have returned the field to service at limited rates. Further interventions are planned during the remainder of 2021 to improve these rates.

No 2P reserves were included in the most recent reserves report pending successful reinstatement of full production.

Northern North Sea: Rhum Field – Block 3/29a, Serica 50% and operator
The Rhum field is a gas condensate field which has been producing from two subsea wells, R1 and R2, tied into the Bruce facilities through a 44km pipeline. Rhum production is separated into gas and oil and exported to St Fergus and Grangemouth respectively along with Bruce and Keith production. Both wells are capable of producing at high rates approaching 12,000 boe/d gross of which some 95% is gas. Average Rhum production from the two wells in 1H 2021 was approximately 10,400 boe/d net to Serica after the extended summer maintenance shut-in (1H 2020: 9,900 boe/d).

During late 2020 and 1H 2021, intervention work has been successfully undertaken on the third well, R3. The well originally encountered technical issues while it was being completed in 2006 and had remained shut-in ever since. We removed the hydrate that had formed whilst the well was being completed and also recovered equipment which had been stuck downhole during the original operations. However, the process of removing the original 5½ inch completion equipment and replacing it with 7 inch completion equipment proved to be far more complicated than had been anticipated due to the poor condition of the existing equipment and consequently these operations extended until June with the rig being released in early July 2021. A diving support vessel (“DSV”) was then deployed to install the subsea control equipment and the well was brought into production on 23 August.

The well has demonstrated a capability to add more than 4,000 boe per day net to Serica’s share of Rhum production. This is enabling us to accelerate field production, increase resilience by reducing dependency on the other two wells and is expected to bring additional reserves into the economic category. Further work will continue in the coming weeks to optimize and stabilize production.

The latest independent report of reserves, compiled by RISC Advisory, estimated 2P reserves of 35.1 million boe net to Serica as at 1 January 2021 (2020: 28.7 million boe).

Central North Sea: Erskine Field – Blocks 23/26a (Area B) and 23/26b (Area B), Serica 18%
Serica holds a non-operated interest in Erskine, a gas condensate field located in the UK Central North Sea. Serica’s co-venturers are Ithaca Energy 50% (operator) and Harbour 32%.

The Erskine field is produced through five wells from the Erskine normally unattended installation, with gas and liquids transported via a multiphase pipeline and processed on the Lomond platform which is 100% owned and operated by Harbour. Then condensate is exported down the Forties Pipeline System via the CATS riser platform at Everest and gas is exported via the CATS pipeline to the terminal at Teesside.

Erskine was shut down in May as part of the Lomond platform outage with the timing linked to the Forties pipeline shutdown. During the outage a significant programme of maintenance and upgrade was carried out including the change out of the engine powering the export compressor and its associated control system. The extent of work on Erskine and the Lomond platform followed COVID-related restrictions during 2020 when only reduced maintenance was possible. Erskine production restarted in midAugust.

The regular pigging program on the condensate export line has continued and no indications of wax build-up have been seen.

Erskine production levels in 1H 2021 prior to the outage averaged 2,400 boe/d net and 1,600 boe/d for the period as a whole (1H 2020: 2,360 boe/d net).

The latest independent report of reserves, compiled by RISC Advisory, estimated 2P reserves of 3.1 million boe net to Serica as of 1 January 2021 (2020: 4.1 million boe). UK Development
Central North Sea: Columbus Development – Blocks 23/16f and 23/21a (part), Serica 50%
Serica is operator with partners Tailwind Mistral Limited (25%) and Waldorf Production Limited (25%). Columbus is located in the Eastern Central Graben, UK Central North Sea and the reservoir is located within the Forties Sandstone. Columbus has been designated as a development within the Lomond Field Area; it is however independent of Lomond, having separate development consent, export route and licence terms.

The development comprises a single subsea well drilled to a total depth of 17,600ft with a 5,600ft horizontal section through the reservoir, connected to the Arran-Shearwater pipeline. Columbus production will be exported through the pipeline along with Arran field production. The Arran export pipeline was approved at a similar time to Columbus and has now been constructed, installed and tied into the Shearwater platform. When production from Arran and Columbus reaches the Shearwater facilities, it will be separated into gas and liquids and exported via the SEGAL line to St Fergus and Forties Pipeline System to Cruden Bay respectively.

Planning for the development began as soon as FDP approval was received in October 2018. Since that time, Serica has worked closely with Shell, the operator of the Arran field, to ensure effective construction and operation of the two developments. The Columbus horizontal development well and all four Arran development wells have been drilled, completed and tied into the export system.

A flow test on the Columbus well achieved a stabilised flow rate of 38.0 mmscf/day of gas and 1,560 bbls/d of condensate through a 56/64ths inch choke (over 8,000 boe/d). This rate was at the upper end of the pre-drill range of expected outcomes and was constrained by the surface well test equipment on board the Maersk Resilient HeavyDuty Jack-Up drilling rig.

Columbus will start-up immediately after the Arran Field wells have been brought online, stabilized and tested; initial production is now expected in Q4 2021 at anticipated gross rates of around 7,000 boe/d of which 75% is expected to be gas.

The latest independent report of reserves, compiled by RISC Advisory, estimated 2P reserves of 7.1 million boe net to Serica as at 1 January 2021 (2020: 6.7 million boe).

UK Exploration
North Eigg and South Eigg – Blocks 3/24c and 3/29c, Serica Energy (UK) Limited 100% and operator
In December 2019, Serica was awarded the P2501 Licence as part of an out of round application; this comprises Blocks 3/24c and 3/29c and contains the North Eigg and South Eigg prospects. The official start date for the licence was 1 January 2020. The work programme involves reprocessing seismic and drilling an exploration well within three years of the start of the licence. The North Eigg prospect has been high-graded for drilling, being clearly visible on 3D seismic data and sharing many similarities with the nearby Rhum field, operated by Serica.

Work has started on planning the exploration well, which is expected to be high temperature and high pressure. A tendering process has been held for long-lead items and negotiations are under way to secure a drilling rig.

In the event of a commercial discovery, Serica would seek a fast-track route to develop the field, potentially via a subsea tie-back to the Serica operated and 98% owned Bruce facilities, which are to the south of the prospect. As well as providing Serica with potentially significant additional reserves, a tie-back to the Bruce platform would reduce combined unit operating costs and extend the economic life of this strategic North Sea infrastructure. The use of existing offtake facilities would also significantly restrict additional carbon emissions. The Company takes its ESG responsibilities very seriously and is therefore undertaking conceptual design studies aimed at identifying ways that such a development could be undertaken while working within the framework of the North Sea Transition Deal agreed between the industry and government to expedite the energy transition.

Skerryvore and Ruvaal– Blocks 30/12c (part), 30/13c (split), 30/17h, 30/18c and 30/19c (part), Serica Energy (UK) Limited: 20% working interest, operator Parkmead
The Skerryvore and Ruvaal prospects lie in the Central North Sea, 60km south of the Erskine field. Potential for both sandstone and chalk reservoirs has been identified.

Over 500km2 of 3D seismic data was purchased over the licence areas. However, the company contracted to reprocess the data, enhancing it prior to interpretation, was unable to deliver the dataset in the agreed timescale. That meant it was not possible to undertake the necessary work programme in time to make a drill or drop decision by the end of the initial three-year term, in September 2021. An extension application was therefore submitted to the Oil and Gas Authority and a drill or drop decision is now due by September 2022.

Licence Awards in the UK 32nd licensing round
In December 2020 Serica was formally awarded four new blocks in the UK 32nd licensing round. Blocks 3/25b, 3/30, 4/26 and 9/5a are in the vicinity of the Bruce hub and include several leads which, if successful, could be tied back to Serica’s existing infrastructure. The work programme does not include any commitment wells but is designed to mature these leads to drill-ready status.

FINANCIAL REVIEW
Field revenues and costs are booked for Serica’s full equity interests and included within gross profits. Under the BKR deals, amounts are due to the asset vendors for net cash flow sharing (40% in 2020 and 2021) and certain other deferred payments. Estimates of these amounts were included within the fair value upon acquisition and subsequent changes are included as ‘Change in fair value of BKR financial liability’ within profit before tax for each reported period. Such variations are driven principally by changes in commodity sales prices, costs and production volumes.

1H 2021 RESULTS
During 1H 2021 Serica generated a gross profit of £46.0 million (1H 2020 – loss of £19.8 million) and cash flow from operations of £63.8 million (1H 2020 – £19.3 million). At the operating profit level this was reduced to £5.5 million (1H 2020 – loss of £12.7 million) after non-cash provisions for unrealised hedging losses of £30.3 million (1H 2020 – £3.3 million). Profit after tax for the period was £1.3 million compared to £12.4 million for 1H 2020.

The strong recovery in gas prices during this period boosted gross profit and cash flow from operations. However, even greater increases in forward gas pricing, particularly through to the end of next winter, have also caused significant non-cash accounting provisions, resulting from the Group’s hedging position, which have reduced profits at the operating level. Such provisions are calculated based upon forward market gas prices at the balance sheet date and consequently reflect the impact of the recent exceptionally high future gas pricing on the settlement of pricing hedges in future periods. They do not, however, factor in the benefits that would be realised from gas sales should actual prices for those future periods match such futures market pricing.

The increase in market gas prices from the summer period last year, already strong during H1 2021, has continued upwards since 30 June. Serica applies swaps and equivalent fixed pricing to a maximum 25% of projected gas production volumes which represents approximately 20% of total production once oil and other liquids are taken into account. It therefore stands to benefit from 80% or more of this exceptional price upside from gas and oil prices.

Serica has already been benefitting from the current high prices during Q3 to-date and the Rhum R3 well, following first production from on 23 August, is now making an increasing contribution to overall BKR volumes. The Company expects to benefit further as Columbus production starts in Q4 2021. It remains the Company’s strategy to protect commodity pricing for a proportion of its future production and we will continue to build hedge protection, typically spread over the forward twelve to eighteen month period, where market pricing supports this.

Sales revenues
Total product sales volumes for the half year comprised approximately 153 million therms of gas (1H 2020: 177 million therms), 365,000 lifted barrels of oil (1H 2020: 534,000 barrels) and 24,200 metric tonnes of NGLs (1H 2020: 32,100 metric tonnes).

These generated total 1H 2021 product sales revenue of £100.8 million (1H 2020: £46.0 million) consisting of BKR revenues of £89.3 million (1H 2020: £37.7 million) and Erskine revenues of £11.5 million (1H 2020: £8.3 million). This represented average sales prices, net of system fees, of 50 pence per therm (1H 2020: 14 pence per therm), US$65.0 per barrel (1H 2020: US$41.4 per barrel) and £284 per metric tonne (1H 2020: £144 per metric tonne) respectively. This gave a combined realised sales price for lifted volumes of US$43.30 per barrel of oil equivalent (1H 2020: US$15.20 per boe).

Gross profit
The gross profit for 1H 2021 of £46.0 million (1H 2021: gross loss of £19.8 million) was after overall cost of sales of £54.9 million (1H 2021: £65.7 million). This comprised £40.1 million of operating costs (1H 2020: £45.8 million) and £15.3 million of non-cash depletion charges (1H 2020: £18.7 million) partially offset by a £0.5 million credit representing a small increase during the period of the opening liquids underlift position (1H 2020: charge of £1.2 million). Reductions in both operating costs and depletion charges reflected lower production volumes plus operating cost savings. Operating costs comprise costs of production, processing, transportation and insurance and averaged approximately US$16.05 per boe (1H 2020: US$15.12). An overall reduction in operating costs of some 10% was achieved during the period. The increase in operating costs per barrel reflected the impact of lower production volumes and the strengthening of the US$ against the GB£ and does not reflect an increase in the underlying trend.

Operating profit before BKR fair value adjustment, net finance revenue and tax The operating profit for 1H 2021 was £5.5 million compared to an operating loss of £12.7 million for 1H 2020. This included £36.0 million of net commodity price hedging losses (1H 2020: gain of £8.3 million) comprising realised hedging losses of £5.7 million (1H 2020: gains of £11.7 million) and unrealised hedging losses of £30.3 million (1H 2020: losses of £3.3 million). The unrealised losses reflected the surge in future gas prices at the close of 1H 2021 and will only become fully realised should actual prices for 2H 2021, 2022 and 1H 2023 reach those levels.

Administrative expenses of £3.0 million compared to £2.8 million for 1H 2020 whilst share-based payments were £0.9 million (1H 2020: £0.7 million) and currency losses were £0.6 million (1H 2020: gains of £2.5 million) largely arising on US$ holdings.

Profit before taxation and profit for the period after taxation
Profit before taxation was £2.2 million (1H 2020: £20.4 million) after an increase in fair value of the BKR financial liability of £3.1 million (1H 2020: decrease of £33.0 million) plus net finance costs of £0.2 million (1H 2020: net finance revenue of £0.1 million). Net finance costs/revenue represent the discount unwind on decommissioning provisions less interest earned on cash deposits.

The fair value loss of £3.1 million arose following an upwards revision of the fair value of the balance sheet financial liability relating to remaining consideration projected to be paid under the BKR agreements. The fair value of this liability is re-assessed at each financial period end. The fair value loss in 1H 2021 reflected higher sales prices largely offset by lower volumes and increased costs. 2H 2021 is the last period to which net cash flow sharing applies and Serica will retain 100% of net cash flow from the BKR fields thereafter.

The 1H 2021 taxation charge of £0.9 million (1H 2020: £8.0 million) solely comprised a non-cash deferred tax element as the Company continued to benefit from accumulated losses carried forward from previous years. It is nonetheless required to make provision for deferred taxes in recognition of future periods when all losses have been utilised and cash payments commence. It is anticipated that remaining tax losses carried forward will be utilised during 2H 2021.

Overall, this generated a profit after taxation for the first six months of 2021 of £1.3 million compared to a profit after taxation of £12.4 million for 1H 2020.

GROUP BALANCE SHEET
The balance sheet at 30 June 2021 demonstrates Serica’s continuing resilience during a period of significant capital expenditures. This has allowed the Company to fund Rhum R3 well work and the Columbus development programme from its cash resources without recourse to borrowing and also to declare a cash dividend, subsequently paid in July, of £9.4 million, increased from the prior year dividend of £8.0 million.

Exploration and evaluation assets of £1.6 million showed an increase from £1.0 million at the end of 2020 reflecting exploration activities on UK licences (primarily North Eigg) during the period.

Total property, plant and equipment increased from £311.1 million at year end 2020 to £338.1 million at 30 June 2021 after booked expenditure on Columbus and Rhum during 1H 2021 of £42.4 million, partly offset by depletion charges of £15.3 million (1H 2020: £18.7 million). Depletion charges represent the allocation of field capital costs over the estimated producing life of each field and principally comprise costs of asset acquisitions. An inventories balance of £5.0 million at 30 June 2021 showed a small increase from £4.6 million at the end of 2020. Trade and other receivables increased from £41.3 million at the end of 2020 to £42.5 million at 30 June 2021.

Cash balances of £92.0 million at 30 June 2021 showed an increase from £89.3 million held at 31 December 2020 and reflected cash flow from operations partially offset by cash capital expenditures of £43.0 million and BKR acquisition outflows of £18.0 million during the period.

Current trade and other payables of £44.0 million at 30 June 2021 increased significantly from a closing 2020 balance of £31.1 million. This reflected significant payments on the R3 and Columbus capital projects pending settlement in Q3. This will be followed by proportionate recovery from partners and also, in the case of R3, under the net cash flow sharing arrangements.

The derivative financial liability of £9.7 million at year end 2020 had increased significantly to £40.0 million at 30 June 2021. This represents the valuation of gas price hedges in place at the respective period ends and the consequent amounts projected to be payable based upon futures pricing prevailing at those points. Period end June 2021 reflected very strong futures pricing which, should this be realised, would deliver greatly increased gas sales revenues during 2H 2021, 2022 and 1H 2023.

The dividend payable of £9.4 million at 30 June 2021 (31 December 2020: £nil) represents the final cash dividend for 2020 of 3.5 pence per share approved at the annual general meeting on 24 June 2021 and paid in July.

Financial liabilities of £47.6 million (31 December 2020: £53.6 million) included within current liabilities and £39.9 million (31 December 2020: £48.8 million) included within non-current liabilities comprise total remaining amounts projected to be paid under the BKR acquisition agreements.

The current financial liability comprises amounts estimated to fall due over the final six months of the net cash flow sharing arrangements, a fixed payment of £16 million contingent upon a successful outcome of the Rhum R3 well work and contingent consideration in respect of Rhum field performance during 2021. Amounts due under the net cash flow sharing arrangements are based on forward projections of production volumes and sales prices. Actual payments will be calculated on volumes and prices achieved in 2H 2021.

The non-current financial liability comprises deferred consideration in respect of BKR decommissioning and oil linefill. Under arrangements for those BKR field interests acquired from BP, Total E&P and BHP, decommissioning liabilities were retained by the vendors with Serica liable to pay deferred consideration equivalent to 30% of the actual costs of decommissioning net of tax recovered by them.

The overall reduction in financial liabilities of £14.9 million during 1H 2021 comprised cash amounts of £18.0 million paid in the period partially offset by £3.1 million charged through the income statement due to higher than previously forecast net cash flow sharing payments in respect of 1H 2021 plus a re-assessment of the estimated fair value of projected remaining payments as at 30 June 2021.

Non-current provisions of £23.0 million have been made in respect of decommissioning liabilities for the Bruce and Keith interests acquired from Marubeni (31 December 2020: £22.8 million). These were not subject to the same deferred consideration arrangements as applied for those field interests acquired from BP, Total E&P and BHP described above. No provision is included for decommissioning liabilities related to the Erskine facilities as these liabilities are retained by BP up to a cap which is not projected to be exceeded. The deferred tax liability of £81.5 million at 30 June 2021 has increased from £80.6 million at year end 2020 and reflects accounting provisions that will be released in future periods, partially offsetting actual tax charges once the Group’s tax losses have been fully utilised and Serica commences cash tax payments.

Overall net assets have decreased from £199.8 million at year end 2020 to £192.8 million at 30 June 2021 after recognising a liability for the dividend of £9.4 million paid in July 2021.

The increase in share capital from £181.6 million to £181.7 million arose from shares issued following the exercise of share options and shares issued under an employee share scheme, whilst the increase in other reserves from £19.7 million to £20.6 million arose from share-based payments related to share option awards.

CASH BALANCES AND FUTURE COMMITMENTS

Current cash position and price hedging
At 30 June 2021 the Group held cash and cash equivalents of £92.0 million (31 December 2020: £89.3 million). This is after capital investments during the period of £43.0 million plus monthly net cash flow sharing payments and other BKR consideration totalling £17.0 million and £1.0 million respectively. Amounts due under the net cash flow sharing arrangements are set at 40% of BKR net operating cash flows for 2021 and then zero thereafter. Of the total cash, £16.4 million was held in a restricted account supporting letters of credit to secure decommissioning liabilities (£6.4 million) and security (£10.0 million) related to gas price swaps.

At 30 June 2021 Serica held gas price swaps covering 192,500 therms per day for H2 2021 at an average price of 39 pence per therm. For 2022, it held gas price swaps covering 300,000 therms per day for H1 and 225,000 therms per day for H2 at average prices of 45 pence per therm and 42 pence per therm respectively. For H1 2023 it held gas price swaps covering 125,000 therms per day at an average price of 48 pence per therm. At 30 June 2021 cash margin calls of £10.7 million had been paid to hedge counterparties as security against settlement of future hedge instruments (31 December 2020: £1.8 million) and is not included in 30 June 2021 cash totals.

In Q3 2021 to date, Serica has obtained additional gas price swaps covering 12,500 therms per day for 2H 2021, 50,000 therms per day for 2022 and 25,000 therms per day for 2023 at average prices of 94, 66 and 51 pence per therm respectively.

Field and other capital commitments
There are no existing capital commitments on the Erskine producing field and net production revenues are expected to cover all ongoing field expenditures. Serica’s share of decommissioning costs relating to its 18% Erskine field interest will be met by BP up to a level of £31.3 million, adjusted for inflation, and Serica’s current estimate of such costs is below this level.

There are no significant existing capital commitments on the BKR producing fields other than an estimated £2.0 million net to Serica outstanding as at 30 June 2021 on the Rhum R3 well work, which was completed in August 2021. Potential further programmes to enhance current production profiles and extend field life are under consideration. Net revenues from Serica’s share of income from the BKR fields, after net cash flow sharing payments, is expected to cover Serica’s retained share of ongoing field expenditures as well as other contingent or deferred consideration due under the respective BKR acquisition agreements set out below.

The Columbus development well has been completed with first gas expected in Q4 2021. Total development expenditure net to Serica’s share outstanding at 30 June 2021 is estimated at approximately £4.5 million.

The Group’s only significant exploration commitment is a well on the North Eigg prospect to be drilled within three years of the 1 January 2020 licence award.

BKR asset acquisitions
On 30 November 2018 Serica completed the four BKR acquisitions. The following elements of consideration were outstanding at 30 June 2021:
• A contingent payment of £16.0 million is due to BP Exploration Operating Company (“BPEOC”) upon bringing the Rhum R3 well onto production and achieving a minimum cumulative 90 days of gas production at a defined level. This is expected to be settled in 2022.
• A contingent payment of up to £7.7 million is due to BPEOC based upon Rhum 2021 average field production and commodity sales prices in the year. The payment made in respect of 2019 was £2.6 million whilst the payment calculated in respect of 2020 and made in Q1 2021 was £1.0 million. There will be a final calculation of the combined average performance covering years 2019 to 2021 and applied to the total potential consideration for the three years of up to £23.1 million. Any difference between this calculation and cumulative payments to-date will then be settled.
• In addition, Serica will pay contingent cash consideration to BPEOC, Total E&P and BHP calculated as 40% of 2H 2021 net cash flows resulting from the respective field interests acquired from those companies. Such amounts will be paid by Serica pre-tax on a monthly basis and then offset by Serica against its own tax liabilities.
• BPEOC, Total E&P and BHP will retain liability, in respect of the field interests Serica acquired from each of them, for all the costs of decommissioning those facilities that existed at the date of completion. Serica will pay deferred consideration equal to 30% of actual future decommissioning costs, reduced by the tax relief that each of BPEOC, Total E&P and BHP receives on such costs. Staged prepayments against such projected amounts will commence in 2022 and be spread over the remaining years before cessation of field production.
• Serica will pay to each of BPEOC, Total E&P and BHP, deferred consideration equal to 90% of their respective shares of the realized value of oil in the Bruce pipeline at the end of field life.


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