BP p.l.c. (BP): PESTLE Analysis [Nov-2025 Updated]

You're looking for a clear, actionable breakdown of the forces shaping BP p.l.c. right now, and honestly, the landscape is shifting faster than ever. As an analyst who's watched this sector for two decades, I can tell you the PESTLE framework is the best way to map near-term risks and opportunities as BP pivots from an oil major to an Integrated Energy Company (IEC). The tension is clear: their 2025 capital expenditure (CapEx) is targeted at around $16 billion, with roughly $5.5 billion earmarked for low-carbon energy, meaning they defintely need the oil profits to fund the clean future. That tightrope walk is where all the pressure points lie-let's map them out.

BP p.l.c. (BP) - PESTLE Analysis: Political factors

You're navigating a political landscape that is more fragmented and volatile than at any point in the last two decades. For BP, this means the core political risk isn't just about taxes or regulation; it's about the fundamental tension between energy security and climate goals, a dynamic that directly impacts your capital allocation decisions for 2025 and beyond. Every major government is now pulling in two directions at once, so you need to be prepared for policy whiplash.

Increased government pressure for energy security post-geopolitical conflicts.

The geopolitical conflicts in Ukraine and the Middle East have fundamentally reshaped national energy policy, making security a primary concern again. BP's own 2025 Energy Outlook highlighted this, noting that heightened tensions have intensified demands around national energy security, leading to a potential preference for domestically produced energy over imports.

This pressure creates a near-term opportunity for BP to maximize production from existing, politically stable assets, but it also accelerates the long-term shift towards 'electrostates'-nations prioritizing domestic low-carbon energy and electrification. This is a short-term tailwind for oil and gas that masks a long-term structural headwind. You must treat this as a temporary, high-price environment, not a permanent reversal of the energy transition.

US and EU regulatory push for Carbon Border Adjustment Mechanisms (CBAMs).

The European Union's Carbon Border Adjustment Mechanism (CBAM) is the most immediate regulatory threat, currently in its transitional phase until the end of 2025 and set for definitive application starting January 2026. While CBAM initially targets carbon-intensive imports like steel, aluminum, and fertilizers-key inputs for BP's operations and products-it signals a global move toward carbon pricing at the border that will eventually impact the entire value chain.

In the US, the political momentum is building, with legislative proposals like the Foreign Pollution Fee Act (reintroduced in April 2025) and the Clean Competition Act. The Foreign Pollution Fee Act alone is estimated to have an upper-bound revenue potential of up to $198.1 billion over a five-year period (2026-2030), demonstrating the sheer scale of the potential new tax burden on carbon-intensive imports. This regulatory environment forces BP to prioritize low-carbon intensity production globally to maintain competitiveness in the EU and preemptively prepare for a US mechanism.

Risk of nationalization or higher royalties in key oil-producing nations.

The risk of fiscal instability-higher royalties, windfall taxes, or outright nationalization-remains elevated, particularly in a high-price environment where producing countries feel emboldened. A mere 7% of the world's estimated oil and gas reserves are in countries that allow private international companies free rein, with 65% controlled by state-owned entities. This imbalance means BP's bargaining power is structurally weak in most major producing regions.

For BP, this risk is concrete in regions like West Africa, where you operate the Greater Tortue Ahmeyim (GTA) development. Changes to production sharing agreements (PSAs) or royalty rates in nations like Ghana and Equatorial Guinea, often triggered by government transitions or policy shifts, directly impact the financial returns of these capital-intensive projects. The quick math is: high oil prices increase the probability of a government demanding a larger slice of the pie.

UK election cycles creating uncertainty on North Sea oil and gas licensing.

The UK's political environment, BP's home market, is defined by regulatory uncertainty following the recent election. The current government has pledged not to issue new licenses for new fields but has committed to maintaining existing fields.

However, the new, stricter environmental regulations introduced in June 2025 require project approvals to account for downstream emissions-the carbon impact from the final use of the extracted fuel, not just the extraction process. This policy shift has already led to legal challenges and reassessments for key North Sea projects. The industry body, Offshore Energies UK (OEUK), warns that a policy-driven decline could lead the UK to import up to 80% of its oil and gas needs within this decade, a clear national security concern the government will struggle to ignore. BP's Murlach oil field, coming online in 2025-2026, is one of the few projects providing a short-term boost, but the long-term outlook for new North Sea exploration is defintely compromised.

Global pushback against new fossil fuel exploration subsidies.

The political rhetoric on phasing out fossil fuel subsidies is strong, but the reality is that the G7 group of nations missed its self-imposed 2025 deadline to eliminate inefficient subsidies. In fact, G7 fossil fuel subsidies hit a record high of $282 billion in 2023 (the latest surge data available), up from $71 billion in 2016. The US alone subsidizes its domestic fossil fuel industry by nearly $31 billion per year.

This creates a policy gap: governments are simultaneously pushing for climate action while supporting production. The 2025 Production Gap Report shows governments plan to produce 120% more fossil fuels by 2030 than is compatible with the 1.5°C warming target. This political failure to align action with rhetoric means BP can still rely on implicit or explicit government support for existing operations, but new exploration projects face massive, coordinated political pushback and public scrutiny.

Here's the quick math on the subsidy disconnect:

Next Step: Finance and Legal teams should draft a comprehensive risk matrix by the end of the quarter, mapping all key BP assets against the projected $198.1 billion US CBAM revenue potential and the UK's downstream emissions regulation to quantify the worst-case financial impact.

BP p.l.c. (BP) - PESTLE Analysis: Economic factors

Crude oil price volatility, with 2025 forecasts hovering near $85 per barrel

The core economic risk for BP remains the volatile price of crude oil, which directly drives the company's upstream (exploration and production) profitability. While the price environment has been generally supportive, 2025 forecasts show continued uncertainty. For instance, the U.S. Energy Information Administration (EIA) projected the Brent crude oil spot price to average around $85.71 per barrel for the full year 2025. This is a strong price, but it masks significant quarter-to-quarter swings, with the EIA forecasting a drop to around $83 per barrel in the fourth quarter of 2025. Goldman Sachs Research, for its part, forecasts Brent to trade in a range of $70-$85 per barrel for 2025, averaging about $76 per barrel. This wide range means that a $15 per barrel swing in the average price can translate into billions of dollars of difference in BP's annual underlying replacement cost (RC) profit. The market is highly sensitive to geopolitical tensions and OPEC+ production policy, which is why we're seeing this volatility. One clean one-liner: Oil price volatility is the single biggest determinant of BP's near-term earnings.

High global inflation increasing the cost of major capital projects (CapEx)

Persistent global inflation, particularly in the cost of materials and services, is eroding the margins on BP's major capital projects (CapEx). This is a critical challenge for the company's disciplined investment strategy, which aims for a CapEx of around $14.5 billion in 2025. The energy sector is seeing cost pressures from import tariffs and supply chain disruptions. For example, tariffs on key materials like steel and aluminum are expected to add a 2% to 5% increase to the cost of offshore projects. This cost creep directly impacts the internal rate of return (IRR) for new developments, potentially pushing marginal projects into uneconomical territory. The inflationary environment also affects BP's underlying operating expenditure, which totaled $16.248 billion for the first nine months of 2025.

Interest rate hikes raising the cost of financing the low-carbon transition

The shift to a higher interest rate environment has significantly increased the cost of capital for BP's low-carbon energy portfolio, forcing a strategic reset. The company revised its capital expenditure guidance for low-carbon energy, with a new focus on capital-light platforms. BP now expects to spend around $2 billion in total out to 2027 on low-carbon CapEx, a significant reduction from the prior guidance that aimed for $3-5 billion annually by 2025. Higher interest rates disproportionately affect renewable energy projects, which are typically debt-financed against long-term power purchasing agreements. The math is simple: a 2% increase in the risk-free interest rate can push up the levelized cost of electricity (LCOE) for a renewables project by as much as 20%, compared to only 11% for a combined cycle gas plant. This makes the economics of new solar and offshore wind projects defintely harder to justify against BP's strict investment criteria.

Strong US dollar impacting repatriated profits from international operations

BP, a UK-domiciled company, reports its financial results in US Dollars (USD), making its consolidated earnings vulnerable to foreign exchange fluctuations. While the dollar's performance has been mixed in 2025, a strong USD against other currencies, particularly those in emerging markets where BP has significant operations, creates a translation risk. For instance, the nominal trade-weighted dollar strengthened by 9.0% over the four quarters through December 2024, appreciating against emerging market economy currencies by 10.3%. When BP converts profits earned in local currencies (like the Euro or Brazilian Real) back into USD for its financial statements, a stronger dollar reduces the reported value of those repatriated profits. This currency headwind can obscure strong operational performance in local markets, leading to a lower reported underlying RC profit, which was $2.210 billion for the third quarter of 2025.

Increased competition from national oil companies (NOCs) in emerging markets

Competition from National Oil Companies (NOCs) is intensifying, particularly as these state-backed entities leverage their vast reserves and lower cost of capital to gain market share. This is not just a threat in emerging markets, but globally. Saudi Aramco, for example, is the world's largest oil producer and had a market capitalization of $1.8 trillion in January 2025. Other Gulf NOCs, such as Abu Dhabi National Oil Company (ADNOC), are actively pursuing strategic international acquisitions in the global oil and gas value chain, including in Liquefied Natural Gas (LNG), a key growth area for BP. These NOCs often have a greater cost competitiveness, meaning that in a scenario of falling global demand, the burden is disproportionately borne by non-OPEC+ producers like BP, which must maintain shareholder returns.

Here's a quick snapshot of the competitive landscape and key economic metrics:

Next Step: Review the current hedging strategy for foreign exchange exposure, focusing on currencies where the dollar showed the greatest appreciation in 2024/2025. Finance: draft a memo on FX exposure by end of the week.

BP p.l.c. (BP) - PESTLE Analysis: Social factors

Growing consumer and investor demand for transparent ESG (Environmental, Social, and Governance) reporting.

You are operating in an environment where capital allocation is increasingly tied to clear, verifiable ESG performance, not just promises. The key pressure point for BP in the 2025 fiscal year is the demand for transparency around the company's energy transition strategy. This isn't just a moral issue; it's a financial one, as large institutional investors use ESG metrics to manage long-term risk.

A clear sign of this demand is the push for a 'Say on Climate' vote at the 2025 Annual General Meeting (AGM). A coalition of 48 institutional investors, who collectively manage approximately £5 trillion in assets, formally urged BP to allow shareholders to vote on its climate strategy. This is a direct response to BP's strategic pivot, which saw the company remove its previous target for an absolute 20% to 30% reduction in Scope 3 emissions by 2030, replacing it with a less stringent goal to reduce the carbon intensity of its energy products by up to 10% over the same period. That shift is why investors are demanding more accountability.

Here is a quick view of BP's current public-facing sustainability aims for its operations:

• Net Zero Operations (Scope 1 and 2): Target a 20% reduction in absolute emissions by 2025 against the 2019 baseline.
• Net Zero Sales (Average Lifecycle Carbon Intensity): Aim for an 8-10% reduction by 2030 against the 2019 baseline.
• Methane Intensity: Maintain 'near-zero' intensity across operated producing assets.

Talent war for specialized engineers in renewables and hydrogen technology.

The energy transition has created a fierce global competition for a very specific set of skills, and BP is fighting a talent war on two fronts: retaining its top-tier oil and gas engineers while aggressively hiring for its low-carbon pivot. This is a zero-sum game for specialized talent. The competition is driving up compensation across the board in the clean energy sector.

For example, in the US market as of mid-2025, a mid-level Hydrogen Engineer typically earns around $115,000 per year, while an experienced professional in this field can make $121,500 or more. Energy Storage Engineers-critical for BP's solar and wind projects-are seeing median salaries between $90,000 and $145,000. This competition is quantifiable: 48% of renewable energy workers reported a pay raise in 2025, with 21% receiving increases exceeding 5%. BP is actively trying to build its future workforce, investing in its low-carbon energy business (which includes hydrogen) with an allocation of $1.6 billion in 2024.

BP's challenge is to make its transition roles competitive against pure-play renewable companies and technology firms, which are also poaching talent. That's a defintely expensive proposition.

Public perception risk from past environmental incidents still influencing brand trust.

The shadow of the Deepwater Horizon oil spill in 2010 remains a significant social factor, despite the passage of time. While BP has spent years and billions on recovery and reputation management, the incident is permanently embedded in the public consciousness as a symbol of corporate environmental catastrophe. The financial cost was staggering, including a record-breaking settlement with the U.S. government of $20 billion in environmental fines and penalties.

The good news is that BP's reputation has largely recovered from its lowest point. Public opinion polling shows the company's net favorability ratings improved from a low of -52 points in 2010 to +19 points by 2025. Still, the market value tells a different story: BP's stock price has never fully bounced back to its pre-spill level of $59-$60. This demonstrates a lingering risk premium applied by the market, which reflects the public's and investors' long-term memory of the disaster.

Increased shareholder activism demanding faster emissions reduction targets.

Shareholder activism is no longer solely about financial returns; it's now deeply focused on climate risk and the pace of the energy transition. The dissent at BP's 2025 AGM was historically significant, signaling a loss of confidence in the board's strategic direction.

Key actions and investor dissent in 2025 include:

Shift to electric vehicles (EVs) reducing long-term demand for gasoline and diesel.

The electrification of transport is a fundamental social shift that directly threatens BP's core retail and refining business. This is a long-term structural risk that is already showing near-term impacts. The global fleet of electric vehicles is growing exponentially, and this directly translates to displaced oil demand for gasoline and diesel.

The International Energy Agency (IEA) projects that global EV sales will climb from over 17 million in 2024 to 20 million in 2025, with EVs making up a quarter of worldwide vehicle purchases this year. This trend is expected to accelerate, leading to a substantial reduction in BP's traditional fuel market. By 2030, EVs are forecast to displace over 5 million barrels of oil per day (mb/d) of diesel and gasoline globally. This will hit BP's downstream (refining and marketing) segment hard.

The shift is also moving into heavy-duty transport, which is a major consumer of diesel. In China, battery-powered trucks accounted for 22 percent of new heavy truck sales in the first half of 2025, up significantly from 9.2 percent in the same period a year earlier. This means the demand shock is not confined to passenger cars. BP needs to accelerate its retail strategy to focus on EV charging infrastructure to capture the energy sales that will be lost from gasoline and diesel.

BP p.l.c. (BP) - PESTLE Analysis: Technological factors

Rapid advancements in Carbon Capture, Utilization, and Storage (CCUS) reducing emissions costs.

You see the immediate challenge: how do you decarbonize massive industrial operations without shutting them down? The answer, for now, is CCUS (Carbon Capture, Utilization, and Storage). BP is making big, tangible bets here, moving the technology from pilot to industrial scale to drive down the effective cost of emissions reduction. The focus is on developing large-scale hubs that can serve multiple industrial emitters.

A prime example is the Tangguh Ubadari, CCUS, Compression (UCC) project in Indonesia, a $7 billion investment with partners. This project is designed to sequester a staggering 15 million tonnes of CO2 in its initial phase, demonstrating CCUS as a tool for enhanced gas recovery, not just a pure cost center. We are seeing the technology mature, with BP deploying specialized solutions like OASE blue gas treatment technology and Sorbead® Adsorption Technology for dehydrating captured CO2. This is defintely a core area for the company's dual strategy.

• Sequestering CO2 from gas production.
• Developing 5-7 high-graded CCUS projects this decade.
• Advancing major hubs like the Northern Endurance Partnership.

Breakthroughs in green hydrogen production lowering the levelized cost of energy.

The race to make green hydrogen cost-competitive is all about the electrolyzer-the machine that splits water using renewable electricity. BP is actively investing in startups, like a $12.5 million Series A round, to accelerate the development of low-cost electrolyzer technology. This is a direct play to lower the levelized cost of energy (LCOE) for hydrogen, making it an economically viable alternative to natural gas in industrial and transport sectors.

The company's strategy is shifting from broad, early-stage exploration to focused asset construction, primarily in Europe. The Lingen green hydrogen project in Germany, for instance, is a major step. It will use a 100MW electrolyzer system to produce 11,000 tons of green hydrogen annually, showing a clear path to commercial scale. Also, the joint venture with Iberdrola in Spain for a 25MW green hydrogen plant represents a focused investment exceeding €70 million ($72.2 million). Here's the quick math: scaling up electrolyzer capacity is the only way to get the production costs down. The total 2025 investment in the low-carbon portfolio, including hydrogen, is about $1.6 billion.

Digitization and AI optimizing upstream oil and gas production efficiency.

BP's traditional oil and gas business is benefiting immensely from digitization and AI, which is crucial for funding the energy transition. The company is leveraging its existing digital foundation to drive significant operational gains. In February 2025, BP announced an increase in annual oil and gas spending to around $10 billion, explicitly linking this capital allocation to AI-driven efficiencies.

The results are concrete. AI has boosted upstream reliability to nearly 97%, the highest level in two decades. In the U.S. onshore arm, BPX Energy, AI tools have helped achieve a 30% productivity improvement in completions and a 15% improvement in drilling over the past year. This isn't just about speed; it's about safety and precision. AI is predicting drilling 'kicks' (dangerous influxes of formation fluid) with 98% accuracy and reducing well planning time by 90%. That's a massive capital efficiency gain.

Development of advanced biofuels offering a lower-carbon transport fuel alternative.

Advanced biofuels are the immediate solution for hard-to-abate sectors like aviation and shipping, where electrification is years away. BP is focusing on 'drop-in' fuels that work in existing infrastructure. The partnership with Johnson Matthey to co-develop the Fischer-Tropsch (FT) CANS™ technology is specifically aimed at producing Sustainable Aviation Fuel (SAF). This is a strategic move to capture market share in a high-demand sector.

The company is already a significant player. BP currently produces about 10,000 barrels per day of biofuels through co-processing at its refineries. Plus, the full acquisition of BP Bunge Bioenergia in Brazil gives them a top-three position in sugarcane bioethanol production, with a capacity of around 50,000 barrels a day of ethanol equivalent. For road transport and heating, BP's Archaea Energy subsidiary started up nine new Renewable Natural Gas (RNG) plants in 2024, adding capacity for over 10 million MMBtus per year. Biofuels are a bridge, but a very profitable one.

Need to scale battery storage technology for intermittent renewable power.

The biggest technical hurdle for renewable power is intermittency-the sun doesn't always shine, and the wind doesn't always blow. This makes battery energy storage systems (BESS) a critical technology for BP's power and renewables portfolio. The company is on track to have developed 20 GW of renewable power capacity by the end of 2025. Scaling this capacity mandates a corresponding increase in storage.

BP's agreement to acquire the remaining 50.03% interest in Lightsource bp, a leading developer of utility-scale solar and battery storage assets, is a clear signal of their commitment to scaling this technology. The industry standard is rapidly moving towards larger-capacity systems, with the 5 MWh container format becoming the norm, which helps lower the capital expenditure (capex) per unit of energy stored. What this estimate hides, though, is the intense competition and supply chain risk, especially with rising protectionism in the US market potentially increasing storage capex by about 10%. Still, the investment is disciplined: total capital expenditure for 2025 is expected to be around $14.5 billion, with only $1.5-2 billion p.a. allocated to the transition growth engines like storage and hydrogen.

BP p.l.c. (BP) - PESTLE Analysis: Legal factors

Ongoing climate litigation risk, including shareholder lawsuits over transition strategy

You need to be acutely aware that BP's legal risk profile is now dominated by climate litigation, especially from shareholders challenging the company's recent strategic pivot. This isn't just about environmental groups anymore; it's about fiduciary duty.

BP's move in early 2025 to fundamentally reset its strategy-increasing investment in oil and gas to $10 billion per year while cutting investment in energy transition businesses by more than $5 billion annually-has created a clear legal vulnerability. This shift directly led to a major investor rebellion at the April 2025 Annual General Meeting (AGM), where approximately 24.3% of shareholders voted against the re-election of the Chair, Helge Lund. That's a huge signal of legal and governance risk.

The core of the shareholder lawsuits revolves around the misalignment of the new targets with previous climate commitments. BP's revised 2030 oil and gas production target is now a range from 2.3 to 2.5 million barrels of oil equivalent (mmboe) per day, a significant increase from its original net-zero plan. Forty-eight institutional investors, including major firms, formally called for a 'Say on Climate' vote at the 2025 AGM, demanding accountability for the strategic change. This legal pressure means every capital allocation decision is now under intense scrutiny for its long-term liability.

Stricter methane emissions regulations in the US and EU requiring new monitoring tech

New methane regulations in both the US and the EU are imposing a hard legal requirement for new operational technology, and that means capital expenditure. These rules are non-negotiable for a global player like BP that is subject to both the US Environmental Protection Agency (EPA) regulations and the forthcoming EU Methane Regulation.

The EU rules, which will soon come into full force, require operators to stop routine flaring, limit venting, and implement advanced monitoring using technologies like satellites. BP is already ahead of some peers, reporting a methane intensity of 0.07% in 2024 (methane emissions as a percentage of total gas to market) and aiming for a 50% cut in the coming years. To achieve this, the company is deploying drone-mounted measurements and advanced predictive algorithms, which are high-cost compliance items.

In the US, where BP has invested $150 billion since 2005, the company has expressed concern that the proposed methane fee program could lead to an inefficient allocation of capital if the rules don't properly incentivize the most effective, portfolio-wide abatement opportunities. The cost of compliance is less about a single fine and more about the ongoing, embedded operational expense for new leak detection and repair (LDAR) systems.

New EU taxonomy rules restricting what can be labeled as 'sustainable' investment

The EU Taxonomy Regulation is the legal definition of what counts as an environmentally sustainable economic activity, and it's creating a major headache for reporting. Large companies, including BP, are required to report on their Taxonomy alignment for the 2024 reporting period in 2025 under the Corporate Sustainability Reporting Directive (CSRD).

This regulation is designed to prevent greenwashing, but its complexity is high. For example, the European Commission is working on an 'Omnibus I' package of amendments to simplify reporting templates, with some entities having the option not to apply them to years beginning in 2025. The legal risk here is twofold:

• Disclosure Risk: Misstating Taxonomy-aligned revenue or CapEx can lead to regulatory action and investor backlash.
• Strategic Risk: The new rules make it harder for BP to market its scaled-back green investments as 'sustainable,' especially after cutting its renewable energy investment by over $5 billion.

This regulatory environment is forcing a stark clarity on BP's portfolio, making it impossible to use vague language about its transition efforts.

Compliance costs for new global anti-bribery and corruption standards

The global regulatory landscape for anti-bribery and corruption (ABC) is tightening in 2025, which translates directly into higher compliance spending, even if the exact figure is not publicly itemized. BP operates in high-risk jurisdictions, making its adherence to both the US Foreign Corrupt Practices Act (FCPA) and the UK Bribery Act 2010 a perpetual, material risk.

Two major developments drive this cost increase:

• The UK's new Failure to Prevent Fraud Offence, which is set to take effect in September 2025, significantly expands corporate liability beyond the Bribery Act.
• The finalization of the EU Anti-Corruption Directive, which will mandate a more stringent, unified approach across EU member states.

While BP does not disclose a specific ABC compliance budget, these costs are embedded in its Selling, General & Administrative (SG&A) expenses, which were $17.022 billion for the twelve months ending September 30, 2025. The need for continuous, risk-based counterparty due diligence (CDD) on new partners, suppliers, and agents, plus mandatory training for high-risk employees, is a permanent, rising cost of doing business globally. For perspective, the company's non-audit assurance fees-a proxy for some governance compliance-were $4 million in 2024. That's defintely going up as new compliance systems are deployed.

Complex permitting processes for large-scale offshore wind and solar projects

Permitting complexity and political risk have become a major legal barrier to BP's transition strategy, particularly in the US offshore wind market. The sheer length and uncertainty of the federal and state permitting processes have forced the company to make a dramatic exit from a key growth area in 2025.

The most concrete example is the 2.5 GW Beacon Wind project off the coast of Massachusetts. In February 2025, BP formally withdrew its application to connect the project to the grid in New York waters, citing a challenging regulatory environment and a pause in federal consenting. The complexity proved fatal: in October 2025, the BP-Jera joint venture announced it would largely close its US offshore wind operations, concluding there was no viable path to the project's development in the present environment. This isn't just a delay; it's a full write-down of the time and legal capital spent on a major project.

Here's the quick math on the legal and strategic cost of permitting failure:

The permitting process, which involves environmental impact assessments, grid connection approvals, and local opposition lawsuits, is now a primary bottleneck that requires massive upfront legal and lobbying spend with no guarantee of success.

BP p.l.c. (BP) - PESTLE Analysis: Environmental factors

BP's target to reduce operational emissions by around 25% by 2025 (vs. 2019).

You need to know where BP stands on its core climate commitment because it's a direct measure of transition risk. BP's original target was to achieve a 20% reduction in operational Scope 1 and Scope 2 greenhouse gas (GHG) emissions by the end of 2025, using a 2019 baseline of 54.4 MtCO2e (million tonnes of carbon dioxide equivalent).

The company has actually surpassed this 2025 goal early, which is a major positive for the Environmental factor. By the end of 2024, BP had achieved a 38% reduction in its combined Scope 1 and 2 operational emissions compared to 2019 levels. This reduction, driven by divestments and sustainable emission reduction (SER) projects, means the 2025 target is already in the rearview mirror. The absolute Scope 1 and 2 emissions were reported at 32.1 MtCO2e in 2023. That's a strong operational achievement.

Increased physical risks to assets from extreme weather events (e.g., hurricanes).

Physical climate risks-like hurricanes, floods, and extreme heat-are a growing financial threat to any global energy company, especially one with extensive coastal and offshore infrastructure. BP explicitly includes these as principal risks related to safety and operations.

To manage this, BP tests its strategy's resilience against various climate-related scenarios, including those consistent with a 1.5°C global temperature rise. Their analysis indicates that for their strategic resilience to be jeopardized out to 2030, a significant portion of their combined oil and gas portfolio would need to be either permanently or temporarily shut in due to physical events. More concretely, BP's investment criteria for all projects exceeding specific GHG emission thresholds include an internal carbon price, which was set at $135/teCO2e in 2023. That price is a clear financial signal to project developers that the cost of carbon-and by extension, the risk of non-compliance or environmental impact-is material.

Water scarcity issues impacting refining and upstream operations in arid regions.

Water is the next big commodity risk, particularly in arid regions where BP operates. The company has made reducing its net freshwater use in stressed catchments a key sustainability aim. They are making progress, but the exposure remains a concern.

In 2024, BP reported a 15% fall in freshwater withdrawals and a 17% fall in freshwater consumption compared to its 2020 baseline (which was 96.4 million m³ and 55.9 million m³ per year, respectively). Critically, the percentage of freshwater withdrawals at major operating sites coming from regions with high or extremely high water stress dropped significantly to just 11% in 2024, down from 73% in 2023. This dramatic shift was due to efficiency projects and a reclassification of one refinery's water stress level, but it shows active management is working.

Need to manage the decommissioning of aging North Sea oil and gas infrastructure.

The North Sea is a mature basin, and the cost of decommissioning (dismantling and cleaning up old platforms and wells) is a massive, near-term liability for the entire industry. This isn't a transition risk; it's a fixed, unavoidable cost.

Operators on the UK Continental Shelf (UKCS) spent a record £2.4 billion on decommissioning activities in 2024 alone. Looking ahead, the total forecast cost of fully decommissioning the remaining UKCS scope from 2025 onwards stands at a staggering £44 billion (in 2024 constant prices). The industry is estimated to commit about £27 billion to this work between 2023 and 2032. For BP, managing this liability includes retaining decommissioning liabilities for certain assets it has sold, like those transferred to Enquest, to facilitate the deal. Well plugging and abandonment (P&A) is the single largest cost component, forecast to make up about 50% of total decommissioning expenditure. That's where the focus needs to be for cost control.

Pressure to accelerate biodiversity protection across all operational sites.

The pressure to move beyond simply mitigating harm to achieving a Net Positive Impact (NPI) on nature is intensifying, especially from institutional investors. BP's strategy is to aim for NPI on all new in-scope projects, which is a significant commitment.

The company is backing this up with concrete, site-specific action:

• Aiming for Net Positive Impact on all new in-scope projects.
• Developing biodiversity enhancement plans for all major operating sites in biodiversity sensitive areas (work continued in 2024).
• Committing to support three more biodiversity restoration projects in the US and Brazil starting in 2025.
• Creating over 470 acres of new wetland just outside a refinery perimeter as a local enhancement project.

This focus is a direct response to the Taskforce on Nature-related Financial Disclosures (TNFD) framework, which BP is actively monitoring as a Forum member. You defintely want to see this kind of proactive, quantifiable commitment in a PESTLE analysis.