A flash blog today as I’m in the smoke seeing the movers and shakers…

Challenger Energy Group

Challenger has provided the following activity update and work programme guidance.

Highlights

·    Given the current strong oil price environment, the Trinidad business unit is profitable at current production levels of 350 to 400 bopd

·    Near-term upside potential from production enhancing work presently underway, that is aiming to boost production, with resulting cashflow benefits

·    Balance of the 2022 work programme being finalised, including infill drilling and EOR programs in Trinidad and pilot well testing in Suriname, in support of further increasing production and cashflow

·    Appointed new Country Head in Trinidad with robust technical and production management expertise

·    Company to enter Q2 2022 substantially debt free and with cash reserves available to support ongoing operations and investment in the planned production growth focused work programme

Oil Price and Financial Performance

To date, this year, the Company has benefitted from more favourable oil prices compared to 2021. In the year 2022 to date, the Company has realised an average crude sales price of US$76.50 per barrel compared to US$60.00 per barrel for the full year 2021.

The Company’s crude production is sold to Heritage Petroleum Company Limited (“Heritage”), the Trinidadian state-owned oil company, at an approximate 10% to 12% discount to the West Texas Intermediate (“WTI”) crude benchmark price. The Company does not currently use any hedging instruments in relation to its oil sales so is making full gain of the current pricing regime.

Should the WTI benchmark continue to range between US$100.00 per barrel and US$120.00 per barrel as it has in recent weeks, the Company would expect to see realised prices in the range of US$90.00 and US$105.00 per barrel (assuming the discount to the WTI benchmark is consistent with the Company’s recent past sales to Heritage).

At realised prices within this range and based on current production levels (i.e., before any increased impact from near-term production enhancement / growth initiatives, or the broader 2022 work programme) the Company expects that its business in Trinidad will generate free-cash from operations for the 2022 calendar year.

The Company would be able to direct some or all of this free-cash toward offsetting a portion of the Company’s ongoing corporate overhead. As previously advised, the Company’s ongoing corporate overhead has been substantially reduced following the recent restructuring and recapitalisation process, and is currently less than US$200,000 per month. Indicative netback calculations are included in the ‘Illustrative Economic Outcomes’ presented below.

Illustrative Economic Outcomes

The table below sets out indicative high-level potential economic outcomes for the Company’s Trinidad business unit, on a per month basis, at each of 350, 400 and 600 bopd production levels, and assuming a range of realised oil price outcomes. This should not be read as Company forecasts, but is provided for illustrative purposes only.

US$000 unless stated otherwise

At US$75 per barrel

At US$90 per barrel

At US$105 per barrel

350 bopd

400 bopd

600 bopd

350 bopd

400 bopd

600 bopd

350 bopd

400 bopd

600 bopd

Gross Oil Sales p/m1

800

900

1,350

960

1,080

1,620

1,120

1,260

1,890

CEG Sales Revenue p/m2

575

680

1,130

690

810

1,350

790

930

1,560

Deductions p/m3

(200)

(240)

(390)

(240)

(280)

(460)

(290)

(340)

(550)

SPT p/m4

(75)

(90)

(160)

(100)

(170)

(210)

Operating Costs p/m5

Approximately 300 per month

Operating Netback p/m

75

140

440

75

140

430

100

170

500

Annualised Netback p/a

0.9m

1.6m

5.2m

0.9m

1.6m

5.2m

1.2m

2.0m

6.0m

Refer to footnotes at the end of this announcement.

 

Near-Term Production Enhancement Activities

A programme of well recompletions at five identified wells has been approved by the Board and commenced. This will be complemented by targeted workovers at other identified offline and / or underperforming wells across the Company’s producing fields. The necessary government permits for all of the planned works have been obtained, and it is expected that this work will be completed by the end of May 2022. In performing the recompletions, the Company will re-enter existing wells and perforate new sand reservoir horizons, potentially resulting in an immediate increase in oil production from the wells subject to recompletion.

The Company is targeting a 10% or more increase in aggregate total production from these activities, with any incremental production able to be monetised immediately and thereby benefit from current strong oil prices.

These near-term production enhancing activities will be supplemented by a package of well equipment and infrastructure purchases and upgrades (utilities, road and facilities) with the objective of maintaining and increasing production integrity, thereby improving field performance and reliability. This includes additional downhole pumps and well swabbing equipment, an increased capacity circulation pump to improve workover pace and efficiency, in-field generator sets to protect against frequent grid power outages, and road upgrades to improve year-round field access and rig cycle time. This program of purchases and upgrades is expected to be completed by the end of Q2 2022.

The total anticipated cost of the above activities, purchases and upgrades is, in aggregate, approximately US$0.5 million, with rapid payback expected across the full range of activities.

2022 Work Programme

In addition to the above-noted near-term production enhancement activities, Mr. Sohan Ojah-Maharaj, the newly appointed Trinidad Country Head, will lead the operations team in finalising of the work programme for the remainder of 2022, focusing on production growth. Highlights of the upcoming work programme are expected to include:

·    an additional infill production well at South Erin (consistent with licence obligations), currently scheduled to be drilled in Q4 2022 with an estimated cost of less than US$1.5 million and targeting an additional 50 bopd of production;

·    drilling an initial pilot production well in Suriname which is currently scheduled for Q3 2022. On completion the well will be put on an extended well test (EWT). The cost of the well and associated extended test is expected to be approximately US$0.7 million and will target an additional 20 bopd of production. The EWT is aimed at establishing the proof of concept for a broader field development which, in a success case, could result in production in excess of 500 bopd for the Company with favourable economics; and

·    deployment of enhanced oil recovery (“EOR”) techniques, including both waterflood and CO2 injection, at the Goudron and Inniss-Trinity fields (consistent with licence obligations). This work is scheduled to commence in Q2 2022 and will run through the remainder of this year. The estimated cost of the initial EOR programme is US$1.2 million in aggregate and targets an additional 50 to100 bopd of production.

The Company’s objective is to exit 2022 with a stable production run-rate of approximately 600 bopd, which is expected to provide a springboard toward the Company’s targeted stable production base of more than 1,000 bopd by the end of 2024. Based on the outcomes of its production focused work programme during 2022, the Company would also expect to undertake a review of its reserves / resources in the first half of 2023.

M&A

As was noted in the Notice of Extraordinary General Meeting sent to shareholders on 9 February 2022, in addition to work designed to enhance and grow organic production from existing fields, the Company intends to pursue value-based, production accretive acquisition opportunities, as well as seek monetisation opportunities for exploration assets.

To this end, management has intensified its focus on a number of potentially complementary opportunities in Trinidad, as well as various farm-out type opportunities. At this time, the Company is engaging in initial discussions and early-stage due diligence, and will provide updates, as applicable, in due course.

Creditor Restructuring

The majority of payments due under the previously announced creditor settlement agreements were paid as required during February 2022. A small number are due for payment in March 2022, and which are all expected to be made on time, in line with the description of creditor settlements as set out in the Notice of Extraordinary General Meeting sent to shareholders on 9 February 2022.

As a result of these payments, the Company will have substantially eliminated all residual debts and payables associated with the drilling of the Perseverance-1 well. In addition, the non-recourse liabilities of the Company’s various subsidiaries in Trinidad and Tobago have been reduced to less than US$2.5 million, an amount considerably lower than the approximate US$8 million inherited as part of the acquisition of Columbus Energy Resources PLC in August 2020. The Company expects that these remaining subsidiary-level liabilities will be gradually discharged in the ordinary course of business over the coming 12-18 months using operations derived income.

The Company therefore expects to commence Q2 2022 debt and liability free at the corporate level, with subsidiary company liabilities significantly reduced and managed in the ordinary course of business. The Company’s cash reserves will be applied toward general working capital and supporting a work programme through 2022 and 2023 which is focused on production growth, as previously described.

No Russian Exposure

The Company has no exposure to Russian oil production, and recently enacted sanctions have had no impact on the Company’s business or operations.

Corporate Presentation

Additional information is set out in a new corporate presentation that was released on 16 March 2022, which is available on the Company’s website (www.cegplc.com).

Eytan Uliel, Chief Executive Officer of Challenger Energy said:

“With our restructuring and recapitalisation process now complete, full attention is on growing the core business, through building production and generating cashflow. The higher oil price environment creates an even greater imperative to increase production and maximise every barrel of oil sold, and to that end we are immediately moving forward with some ‘low-hanging fruit’ operational items. The aim of this work is to stabilise and offset natural decline of baseline production, and then add 10% or more of new production, which can be readily monetised. Thereafter, we can begin to roll out our 2022 work programme, which will see drilling and EOR deployment across the fields, as we work towards achieving our overall sustainable production growth and cashflow targets. I look forward to keeping shareholders appraised of our progress.”

After a tricky couple of years I see this as the first sign of moving on from Eytan Uliel and his newly formed management team. He is right to identify the short to medium term as the place to start and he has the warm wind of high current oil price behind him with which to start the journey. 

I have every confidence that both short term initiatives to increase revenue and the longer haul of restructuring and repositioning will be found so this may be an interesting time to join the team and see what that journey brings, boring it will not be… 

Petrofac

RESULTS FOR THE YEAR ENDED 31 DECEMBER 2021

Significant progress on 2021 strategic objectives

  • Long term capital structure in place following capital raise and comprehensive refinancing
  • Business performance net profit of US$35 million(1)(2)
  • Reported net loss of US$(195) million(2) post impairments and separately disclosed items
  • Group order intake of US$2.2 billion(4)
  • Achieved targeted cost savings of US$250 million
  • Net debt of US$144 million(7) and liquidity of US$705 million(8)
  • Backlog of US$4.0 billion, of which Russia is 0.6%
  • Recently reinstated to ADNOC’s bidding list for all upcoming tenders
  • Well positioned with a Group pipeline of US$37 billion for award in 2022, of which $7 billion is in New Energies

 

 Year ended 31 December 2021Year ended 31 December 2020 (restated)(3)
US$mBusiness performanceSeparately disclosed itemsReportedBusiness performanceSeparately disclosed itemsReported
Revenue3,057n/a3,0574,081n/a4,081
EBITDA104n/an/a211n/an/a
Net profit / (loss)(2)35(230)(195)50(242)(192)

DIVISIONAL HIGHLIGHTS

Engineering & Construction (E&C)

E&C demonstrated its ability to deliver for clients across the portfolio in difficult circumstances, but financial performance continued to be materially impacted by COVID-19. As expected, revenue decreased as a result of the lower backlog and pandemic-related project delays.

Net profit margins were impacted by cost increases related to the COVID-19 disruption, including the recognition of full-life losses on a small number of contracts. The challenges on these mature projects have been resolved and are not expected to have an impact in 2022.  Margins were further reduced by the write down announced on 11 March, as a result of the progress made in closing out claims in relation to two historical projects.

Cost inflation had limited impact on E&C’s relatively mature portfolio, with procurement largely complete, and we do not expect inflation to present a headwind for margins going forward. Furthermore, having adapted to the new operating environment, clients have started to show more flexibility in settling claims related to COVID-19 and we have now resolved commercial positions on a large number of our projects.

Margins were supported by management actions to reduce costs and by $29 million of tax provision releases in the year.

The contraction in capital spending by clients, initially triggered by the decline in oil and gas prices and the COVID-19 pandemic in 2020, continued into 2021 in our addressable markets. As a result, new order intake in the year was US$1.2 billion (2020: US$0.7 billion), comprising EPC contracts in Oman, Libya and Lithuania and other net variation orders. As the year progressed, the market showed signs of recovery and over 90% of order intake was secured in the second half of the year.

E&C financial results for the 12 months ended 31 December 2021 (1)(2)

  • Revenue down 36% to US$2.0 billion
  • EBIT down to US$(14) million
  • EBIT margin down 3.3 ppts to (0.7)%
  • Net profit margin down 1.6 ppts to 0.4%
  • Net profit of US$8 million
  • US$1.2 billion of new order intake

Asset Solutions (AS)

Business unit previously known as “Engineering & Production Services”

AS delivered a strong financial performance in the year with significant growth in both revenue and margins. Revenue increased across each of its service lines (Asset Operations, Asset Developments and Wells & Decommissioning). Engineering, procurement and construction activity on our Asset Developments projects portfolio progressed well, overcoming challenges presented by the COVID-19 pandemic and with strong delivery on several projects in the MENA region.

Net margins increased significantly due to higher revenues, a lower overhead ratio, high contract margins on some projects, higher income from associates and tax provision releases.

The volume of work in new energies (carbon capture and storage, hydrogen, waste-to-value and offshore wind) increased markedly, with AS executing 16 contracts, predominantly Pre-FEED and FEED studies, up from two contracts in 2020. We further strengthened our position in these sectors through strategic alliances with technology partners and developers, including with Protium for green hydrogen and with Storegga and Co2Capsol for carbon capture and storage. In 2022 we formed an alliance with Seawind Ocean Technology to strengthen our position in the floating offshore wind sector.

Asset Solutions financial results for the 12 months ended 31 December 2021 (1)(2)

  • Revenue up 19% to US$1.1 billion
  • EBIT up 48% to US$74 million
  • EBIT margin up 1.3 ppts to 6.7%
  • Net profit up 115% to US$86 million
  • Net profit margin up 3.4 ppts to 7.7%
  • Underlying net profit margin, excluding tax provision releases, up 1.2 ppts to 5.5%
  • US$1.0 billion of awards, representing a book-to-bill of just over 0.9x

Integrated Energy Services (IES)

Following the disposal of the Mexico assets in 2020, IES financial results in the year reflected the performance of its sole remaining asset, Block PM304 in Malaysia. Production declined due to the unplanned outage in the main Cendor field, partly offset by the start of production from the East Cendor development in June. On a like-for-like basis, revenue increased as higher oil prices more than offset lower production.

IES financial results for the 12 months ended 31 December 2021 (1)(2)

  • Revenue down 55% to US$50 million (up 19% on a like-for-like basis)
    • Disposal of Mexico assets in 2020
    • Average realised oil price(6) up 92% to US$75/boe
    • Net equity production down 35% to 640 kboe on a like-for-like basis
  • EBITDA down 46% to US$21 million (up 40% on a like-for-like basis)
  • Net loss decreased to US$5 million (2020: US$18 million loss or US$14 million on a like-for-like basis), with lower EBITDA and higher tax mitigated by lower interest and depreciation

As a result of East Cendor coming on stream part way through the year, the exit rate net production was 2.9 kboe/d compared with an average of 1.8 kboe/d for the full year. Production in 2022 is expected to benefit from the return of production from the main Cendor field in the second half of the year (c.0.9 kboed).

SEPARATELY DISCLOSED ITEMS

The reported net loss(2) of US$195 million (2020 restated(3): US$192 million) was caused by separately disclosed items and certain re-measurements of US$230 million (2020 restated(3): US$242 million). These were primarily:

 

  • US$106 million penalty imposed by the UK courts in connection with the conclusion of the SFO investigation, which was paid earlier this year
  • US$28 million of costs in relation to the Group’s refinancing related costs
  • A non-cash impairment charge of US$58 million following a review of the carrying amount of the investment in Block PM304 in Malaysia based on increased uncertainty in respect of securing an extension for the Production Sharing Contract beyond the current term, which expires in 2026. This comprises:
    • a US$15 million impairment charge of the carrying amount of the investment; and
    • a US$43 million write-down of the associated deferred tax asset based the shorter recoverability period

Consistent with previous periods, all COVID-19 related costs are treated as business performance.

CASH FLOW, NET DEBT AND LIQUIDITY

In November 2021, we concluded a capital raise and comprehensive refinancing to create a long term capital structure. This included a capital raise of US$275 million(10), US$600 million of senior secured notes due 2026 and a new US$180 million two-year revolving credit facility. An existing US$90 million bilateral term loan was repaid and replaced with a new US$50 million term loan, maturing in October 2023. As part of the refinancing, we repaid our £300m Covid Corporate Financing Facility, which was due to mature on 31 January 2022.

Free cash outflow of US$281 million (2020 restated(3): US$123 million), principally reflected the impact of lower EBITDA, a working capital outflow, payment of end of service employment benefits provided for in the prior year, and the cash impact of other separately disclosed items. This was largely offset by net proceeds from the capital raise, resulting in a modest increase in net debt, which was US$144 million at year end (2020: US$116 million). Liquidity at 31 December 2021 was US$0.7 billion(8).

DIVIDEND

In April 2020, the Board cancelled the payment of the final 2019 dividend in response to the COVID-19 pandemic and the fall in oil and gas prices. The Board recognises the importance of dividends to shareholders and expects to reinstate the dividend policy in due course, once the company’s performance has improved. Under the terms of the new debt facilities, the company will be permitted to pay dividends from 1 January 2023, subject to the satisfaction of certain covenant tests.

ORDER BACKLOG

The Group’s backlog decreased 20% to US$4.0 billion at 31 December 2021 (2020: US$5.0 billion), reflecting progress delivered on the existing project portfolio and low new order intake in E&C as clients continued to maintain capital discipline and delay new contract awards in response to the COVID-19 pandemic. While the E&C backlog declined from the prior year, strong order intake in the second half resulted in a 14% increase from the 30 June 2021 position.

The Group has minimal current exposure to Russia, which represented 0.6% of Group backlog at 31 December 2021.

 

 31 December 202131 December 2020
 US$ billionUS$ billion
Engineering & Construction2.43.3
Asset Solutions1.61.7
Group backlog4.05.0

OUTLOOK

The market outlook is improving and the recovery in energy prices is supportive of increased capital spending by clients in all our addressable markets. E&C has a US$30 billion pipeline of opportunities scheduled for award by the end of 2022 and whilst we expect industry awards will remain low in the near term, current client engagement provides confidence that the pace will increase materially in the second half of the year and beyond. Furthermore, our reinstatement to bidding in the UAE provides significant growth potential, particularly from 2023 when ADNOC is expected to award a number of material contracts. We are well positioned with a competitive cost structure, an enhanced low-carbon bid strategy and a strict commitment to bidding discipline in order to return to sector-leading margins in the medium term.

E&C has US$1.3 billion of backlog scheduled for execution in 2022. It has now reached commercial agreements with a large number of clients on ongoing projects and is expected to deliver EBIT margins(9) of at least 2.5% in 2022.

Asset Solutions has a healthy US$7 billion pipeline of opportunities scheduled for award by the end of 2022. Bidding activity is elevated as clients seek to capitalise on the supportive macro environment to increase production and extend the life of assets.

Asset Solutions has US$0.9 billion of backlog scheduled for execution in 2022 and revenue is expected to continue to increase. EBIT margins(9) are expected to be slightly lower at 5-6% due to the conclusion of certain high margin projects in 2021 as well as increased investment in New Energies capability to position the Group for growth in this market.

The combined US$37 billion Group pipeline for 2022 includes US$6.8 billion of New Energies opportunities, comprising projects in offshore wind, carbon capture and storage, hydrogen and waste-to-value. Approximately a quarter by value relates to offshore wind opportunities, which are more mature and expected to be awarded on schedule in 2022. In other sectors, we are strengthening our position through early-stage engineering studies and alliances with technology partners.

While revenue and margins will inevitably remain subdued in the near term, we are confident that we will start to rebuild the backlog in 2022 and deliver strong growth thereafter. Our medium-term ambition is to deliver revenues of US$4-5 billion, including c.US$1 billion from New Energies, with a sector leading 6-8% EBIT margin and a return to a net cash position. Delivery of these medium-term objectives will create significant value for Petrofac shareholders.

Sami Iskander, Petrofac’s Group Chief Executive, commented:

“Our 2021 results demonstrate a resilient performance thanks to the hard work and perseverance of our people and a renewed focus on service quality, bringing us closer to our clients. We continued to manage the challenges of COVID-19 while delivering our significant cost reduction targets to enhance our competitiveness. Our relatively mature portfolio has shielded us from the current inflationary environment.

“Significant strategic progress made in 2021 under our plan to rebalance, reshape and rebuild Petrofac saw us resolve the SFO investigation and establish a long-term capital structure for the Group. Furthermore, we recently achieved a significant milestone through our reinstatement to ADNOC’s bidding list, which is a major step forward as we look towards rebuilding the backlog. We are now in a stronger position, having created the right environment to pursue future growth.

“Looking forward, we are focused on securing the backlog that will deliver profitable growth whilst retaining a strict approach to bidding discipline. While clients continue to prioritise cash preservation over new investments, we expect the increasingly supportive energy price environment to improve the outlook for awards as the year progresses. Market fundamentals are strong in our traditional markets, particularly in the MENA region where Petrofac has a leading position, and in New Energies, underpinning the medium-term performance objectives that we are confident will drive significant shareholder value over the coming years.”

The past years with the accompanying ‘discomfort’ on a number of fronts have led some to consider what Petrofac’s future really is. Indeed from the SFO through Covid one could easily have either given up the ghost or at the very least considered that the company might accept life as a smaller, less dynamic player.

It is perfectly clear, just from listening to the new management on the conference call that this is just not what is going to happen, indeed right from the start the repositioning of the company under the ‘rebalance, reshape and rebuild’ banner indicates that in a number of key areas but with a keen eye on the capital structure. Indeed the rightsizing of the organisation with those $250m of cost savings show that PFC will be a downsized company but from this level and with 2022 being an inflection point for growth properly kicking in in 2023. 

Accordingly it is worth taking a look at the bidding pipeline which stands at some $37bn and growing although interestingly ‘not at all costs’. With the increase in oil prices countries that have been seriously underinvested in recent years this pipeline should increase and with the recent news that ADNOC is back on the list being not the only positive (the current list doesn’t include Russia, KSA or Iraq) as it includes a decent mix of geographies and of course in new energies.

Stripped of significant costs which the management are not going to bulk up any time soon, and being realistic of how long this is going to take is very grown up and I like this team a good deal even without the important benefit of spending time together. ( I had hoped that this meeting would have been in person like others!) The shares at 111.9p are still almost at the bottom on a years view with the low of 94p a year ago but well off the near 200p from October’s false start, with this presentation I would think that the company have made an excellent case for buying the shares, this is some lock away for a rainy day stock indeed.