But data indicates we have at least 50 years of O&G reserves left. While the most optimistic (or pessimistic, depending on who you are) estimates indicate oil demand may peak in 2025, most estimates suggest we’ll have to wait until 2035. Either way, it’s unlikely O&G issuers’ cashflows are going to be impacted by a drop in demand or a fall in supply in the short term.

So why don’t issuers keep drilling indefinitely while churning out huge profits?

Government Policy

As the UK government looks to achieve its Nationally Defined Contributions, the climate action plan required to achieve the goals of the Paris Agreement, policymakers are turning their attention towards the O&G sector.

The new Labour government has planned to prioritise the UK’s green energy transition and net zero policy. Labour's climate and energy plan, led by Secretary of State Energy Security and Net Zero Ed Miliband, includes:

• Zero carbon electricity, banning new internal combustion vehicles by 2030, reducing end-user demand for oil and gas
• A new national wealth fund and 'Great British Energy' company to boost public/private sector investment into green energy projects. Labour seeks £3 of private investment for every £1 of public investment

Additionally, the Labour government announced that it would not issue any new licences to explore North Sea oil fields. Details are yet to be set in stone. Still, assuming Labour stays broadly true to this commitment, the impact will likely reduce future production volume in the North Sea, which in turn will reduce cash generation and delay deleveraging timelines.

EBITDAX and exploration activity

Exploration expenditure includes costs related to searching for potential new oil and gas reserves. A critical yet expensive activity for companies looking to maintain or grow production levels and subsequent reserves.

Exploration expenditures are inherently risky; unsuccessful exploration can lead to significant financial losses, and depending on accounting practices, exploration costs may be capitalised or expensed, leading to incomparable reported financial performance across companies.

Looking into Harbour Energy’s reporting as an example, we find two line items, “Exploration and Evaluation Expenditure and New Ventures” and “Exploration Costs Written-Off”:

• Exploration and evaluation expenditure and new ventures encompass all costs associated with the exploration and evaluation of potential oil and gas reserves, such as geological and geophysical studies, drilling of exploration wells, and acquiring licenses and/or permits. These expenditures are typically capitalised on the balance sheet, reflecting the potential future economic benefits from successful exploration
• Exploration costs written off represent the other side of the coin, referring to costs incurred during exploration but later deemed unrecoverable, reflected as expenses to the income statement. This commonly occurs when explorations have not led to commercially viable reserves

EBITDAX (standard EBITDA plus exploration costs) is a financial metric commonly used by O&G credits to provide a clearer picture of operational performance. Adding back exploration expenses into EBITDAX can smoothen a company’s operational performance, as these costs can fluctuate dramatically YoY.

Exploration activity often correlates to the underlying oil price, as the risk-to-return profile for exploration improves during peak oil markets. As the price of oil increases, more reserves can be determined as proven and probable (2P) — typically signifying at least 90% of the resource is recoverable by “economically profitable” means. Effectively, the present value of the extractable resources must exceed the all-in cost of harvesting it.

A company with significant exploration expenditures may report lower (or sometimes negative) net cash flows despite otherwise healthy operational performance from existing assets due to higher exploration expenditures. The use of EBITDAX allows an O&G credit to omit the expensive process of exploration to focus on the operating segment of the business.

Later down the line, high exploration expenses (if successful) can lead to future periods of higher cash generation as the business transitions from an “exploration phase” to a “harvesting phase”.

Source: Harbour Energy Financial Reports

Overall, if the issuance of new North Sea drilling licenses ends, this could significantly impact future exploration activities without diversification into alternative jurisdictions, thereby affecting exploration expense and EBITDAX. As new exploration opportunities dry up, companies will incur fewer costs, leading to a reduction in the adjustments made to EBITDAX for those expenses. This could make cash flows appear more stable in the short term, as exploration costs shrink, yet it may also lead to longer-term challenges for revenue growth and reserve replenishment.

Reserve based lending

Reserve-based lending (RBL) facilities offer unique access to credit commonly utilised by O&G firms. The facility enables a credit to borrow against the future value of its 2P reserves.

The facility offers additional working capital flexibility for exploration, development, and production activities — exercises that later feed into the expansion or resupply of the 2P reserves the facility is borrowed against.

Lenders calculate the maximum facility size based on the estimated future revenues achievable from reserves via third-party assessments and discounted cash flow models. An example report from Tullow can be read here.

Facilities are periodically reviewed (typically semi-annually) to adjust for changes in reserve estimates, commodity prices and production volumes. During this process, we could begin to see the impact of blocked new North Sea drilling licenses.

As reserves are exhausted and new exploration does not occur (due to the inability to win a license to extract discovered assets), activity will decline, leading to lower 2P reserve volumes. During a redetermination, such a decline would likely result in a reduction in the borrowing base, restricting working capital headroom. In extreme cases, if the borrowing base falls below the outstanding loan balance, the company may be required to repay part of the loan early.

Energy Profits Levy

The Energy Profits Levy (EPL) is a windfall tax introduced in May 2022 by the previous Conservative government, targeting the extraordinary profits made by O&G companies due to soaring global energy prices — exacerbated by the war in Ukraine. The levy was originally set at 25% and later raised to 35% in January 2023.

This levy, in addition to the existing ring fence corporation tax (30%) and supplementary charge (10%), brings the total headline tax rate on O&G profits to an eye-watering 75%.

Looking forward, the levy paid on UK oil and gas production profits is set to increase from 35% to 38% as of 1 November 2024, as per a government announcement in July 2024, pushing the new total headline tax rate to 78%.

The levy seeks to capture extraordinary windfall profits while maintaining incentives for continued investment in the UK's energy sector. As such, actual tax levels paid had two main workarounds via investment allowances:

1. A 29% capex investment allowance, abolished by the Labour Party in July 2024 for qualifying expenditure incurred on or after 1 November 2024
2. A 80% decarbonisation investment allowance, which currently remains in place

The EPL was initially set to expire by 31 December 2025 but was extended until March 2029 and then again to March 2030, the year the current parliament is due to finish.

Although a 3% increase to the tax rate may not seem too impactful at first glance, multiple HY issuers have already reported suffering from the existing 35% levy:

• EnQuest: In its FY 23 results statement, the company’s management team reported that the EPL impacted EnQuest’s ability to access capital, with the biggest reduction coming from a downsized borrowing base within the Group’s RBL facility, leading it to repay borrowings ahead of schedule as a safety measure
• Harbour Energy: In its 2023 annual report, it reported that the EPL led to a reduction in cash flow and impacted the availability of debt, as well as weighing on its share price. It has also caused the company to scale back activities in certain areas and undertake a review of its UK organisation (more info below). As of H1 24, Harbour Energy reported an effective tax rate after investment allowances and M&A costs of 85%

Source: H1 24 Results presentation

• Ithaca Energy: In its 2023 annual report, it reported that statutory profit was impacted by a $557.9m pre-tax impairment charge following its decision not to proceed with drilling on its Harrier field as a direct result of the EPL

It’s worth noting the EPL could end sooner if oil and gas prices fall below the thresholds set out in the Energy Security Investment Mechanism (ESIM). The threshold prices for oil and gas are $71.40 per barrel and £0.54 per therm respectively, based on a 20-year average to the end of 2022. Brent crude trades at $73.97 at the time of writing, down 6.1% YTD.

UK Emissions Trading Scheme (ETS)

O&G issuers will also likely face gradually increasing costs from the UK’s ETS. The UK ETS is a cap and trade system that limits an issuer’s emissions, which gradually falls over time. Issuers exceeding the limit must purchase carbon emissions allowances to avoid fines.

Harbour Energy reported costs associated with the UK ETS of $5.8m in 2023 and $4.2m in 2022. However, EnQuest and Ithaca Energy, which also have high exposure to the UK, did not report expenses related to the UK ETS.

To minimise costs, it’s vital that companies manage carbon price fluctuation via hedging and participation in auctions so that they pay a lower price for carbon credits when they inevitably exceed ETS limits. However, a safer strategy over the long term would be to reduce emissions and remain under ETS limits.

Environmental Impact Assessments

Following a Supreme Court decision in August which required regulators to consider the impact of burning oil and gas, scope 3 emissions, in the Environmental Impact Assessment (EIA) for new projects, the government announced it would start consulting on new environmental guidance for oil and gas firms attempting to extract fossil fuels from the North Sea. The extent to which the guidance, which has not yet been released, will impact firms is unclear. However, it's possible that developers who fail to fully reflect the project's impact in their EIAs may open the door to legal challenges.

The decision came the same day the UK government announced it would not fight a legal challenge against the decision to block the Rosebank and Jackdaw North Sea oil and gas developments. The government's decision does not mean the licences for Jackdaw and Rosebank have been withdrawn. However, if the legal challenge is successful, operators must resubmit environmental assessments, creating more delays and additional costs. Ithaca Energy, a joint owner of the Rosebank field, would likely face significant costs.

Decommissioning

The growing emphasis on ESG responsibilities, coupled with a focus on the energy transition, is making decommissioning obligations increasingly important for both issuers and investors alike.

Decommissioning expenditure refers to the costs of shutting down oil and gas installations at the end of their productive lives. This can include removal of infrastructure, site remediation, and environmental restoration. Typically, companies fund the decommissioning of assets constructed decades ago with cash flow from current operations.

A common limitation of decommissioning provisions comes from underestimating future decommissioning costs. The UK’s Oil and Gas Authority (OGA) found that actual costs often exceed initial estimates due to unforeseen complexities and inflationary pressure.

For example, Ithaca Energy reported changes in decommissioning estimates of $48.8m for development and production assets during the six months ending 30 June 2024, along with an additional $157.2m in FY 23.

Additionally, decommissioning is often a long-term process. Financial reports may not adequately reflect the immediate financial health of a company. In theory, costs should be covered by current cash flow, as older assets are phased out and replaced with new ones. However, total costs have steadily grown as oil companies have systematically deferred obligations.

The decision of the Labour government to no longer issue new drilling licenses may make it more challenging for issuers to fund future decommissioning costs with revenue from new assets.

Those who fail to address these liabilities risk facing reputational harm and financial losses.

9fin’s analysis shows that EnQuest, Ithaca Energy and Harbour Energy have extremely high decommissioning liabilities and are also the most reliant on the North Sea, meaning they are most at risk of failing to cover costs with new assets.

The combination of high decommissioning costs and increasingly stringent UK regulation means that issuers continuing to drill should look to reduce their exposure to the UK and move towards countries with less stringent regulation, e.g. West Africa, where taxes are lower, and the countries do not currently have emissions trading schemes in place.

boped: Barrels of oil equivalent per day

Issuers, such as Tullow and Energean, have managed to do this successfully. However, moving away from the UK to regions like South-East Asia and West Africa could lead to an increase in downside risk for lenders, such as physical climate risk, including extreme weather events. In line with good practice, both have conducted scenario analysis to understand these risks. However, such moves can also lead to an increase in political risk.

In February 2023, Tullow’s Ghana unit filed for arbitration on two tax charges ttotalling$387m from local authorities. The charges cover the period from 2010-2020 and are separate from a previous tax dispute and taxes Tullow has already paid in Ghana. The arbitration protects Tullow from enforcement action on Ghana's claims.

In addition to political and climate risks, lenders may face difficulty enforcing on assets located outside the UK, which could amplify losses if a borrower defaults.

While Harbour Energy’s exposure in terms of output remained high in 2023, its acquisition of Wintershall DEA’s asset portfolio means that it has now added significant positions in Norway, Germany, Argentina and Mexico, reducing its exposure to the UK. The issuer was upgraded to IG following the acquisition, which Fitch stated was due to its “enlarged size, improved geographical and asset diversification and higher reserves post-acquisition”, indicating that increased diversification away from UK operations helped to reduce credit risk.

EnQuest has one drilling site in Malaysia but hasn’t announced robust plans to reduce exposure to the North Sea. Capex for the North Sea represented 93% of capital expenditure in FY 23.

Ithaca Energy’s strategy is centred on the North Sea, and it has not reported plans to diversify geographically.

Cost of capital

An ever-growing number of asset managers are joining initiatives, such as GFANZ, which encourage members to commit to achieving climate-related objectives. In the case of GFANZ, members commit to setting interim targets and credibly reaching net-zero carbon emissions by 2050. Although GFANZ doesn’t force members to take a specific position on O&G investments, it recommends members “establish and apply policies and conditions on priority sectors and activities, such as thermal coal, oil and gas, and deforestation”.

This has led many financial institutions to make pledges related to O&G. Natwest, for example, has pledged to stop lending and underwriting to all major oil and gas producers unless they have a credible transition plan aligned with the Paris Agreement. Meanwhile, Danske Bank committed to restricting investment to companies with viable transition plans for 85% of assets. However, some members, like Munich RE, have withdrawn their membership, indicating not all financial institutions share the same approach to tackling climate change.

The International Energy Agency’s (IEA) 1.5C-aligned pathway entails the immediate cessation of all new upstream oil and gas projects, indicating that O&G should no longer invest in new drilling sites to be aligned with the goals of the Paris Agreement. It’s generally considered that viable transition plans should also include scope 1-3 emissions targets. Despite this, none of the HY issuers examined by 9fin meet these criteria:

In its FY 23 results statement, EnQuest reported that factors such as climate change, other ESG concerns, oil price volatility and geopolitical risks have impacted investors’ and insurers’ acceptable levels of oil and gas sector exposure, with the availability of capital reducing while the cost of capital has increased.

Since O&G issuers tend to be highly leveraged, the cost of capital can play an important role in a company’s long-term success. If the HY issuers mentioned above fail to align with investors’ strategies, they may face limited access to new forms of capital in the future.

Capex

Some companies may keep generating cash by shifting oil and gas operations to countries with looser regulations, but stricter policies are spreading, and Africa’s climate exposure could push its oil-producing nations to eventually follow suit. Additionally, regulations like the EU’s Carbon Border Adjustment Mechanism, which places a tariff on carbon-intensive products imported into the EU, are expected to extend crude petroleum by 2023.

Issuers that are planning to decarbonise their operations should begin to invest in fewer emissions-intensive revenue streams, such as carbon capture and storage (CCS) and renewable energy assets, to keep cashflows resilient during the transition.

CCS involves the capture of CO2 emissions from industrial processes, such as steel and cement production, and storing it deep underground. Depleted oil and gas reserves can be used for CCS, allowing the O&G sector to potentially benefit from a technology vital for the energy transition.

Issuers that invest sooner rather than later may benefit from government subsidies incentivising investment. In October 2024, the UK government announced plans to allocate £22bn in subsidies for carbon capture over the next 25 years. Although it’s unclear whether HY issuers will be eligible for the subsidies, EnQuest has already received £1.74m in funding from the UK Government to progress a 50 MW green hydrogen project at one of its oil terminals.

In July 2024, the new labour government also announced £1.5bn of funding for clean energy to be spent over the next year. Industry will bid for a share of the funding through the government’s sixth renewable auction.

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