THE NEW ENERGY PLAYBOOK FOR EMERGING MARKETS The Complete Guide — Ten Principles from the Virtual Energy Summit

This is the complete edition of the New Energy Playbook for Emerging Markets, combining both instalments published following the inaugural Virtual Energy Summit in May 2026. It distils ten principles from nine sessions featuring some of the most experienced energy practitioners working across Africa, Latin America, and the Caribbean.

It is written for project developers, policymakers, utility executives, traders, and financiers who are working on the frontlines of energy development in West Africa, Southern Africa, and the Caribbean. Every principle here was drawn from lived experience. Every one of them can be implemented.

INTRODUCTION

The question is no longer what emerging markets need in terms of energy. The demand is undeniable. The resources — gas, solar, wind, hydro — are abundant. The populations across Sub-Saharan Africa, West Africa, Southern Africa, and the Caribbean who need reliable power are not hypothetical. They are real, and their economies are being constrained every single day by its absence.

The question this playbook addresses is how. How do you finance it? How do you structure it? How do you move from ambition to construction in markets where the regulatory environment is still developing? How do you attract capital in a market where infrastructure is fragmented and demand is scattered?

In May 2026, the Virtual Energy Summit brought together nine of the most experienced energy practitioners working across Africa and the Caribbean to answer exactly those questions. What follows is a distillation of the key principles from those conversations, drawn from every session and synthesised into a single practical framework.

This is not theory. Every principle here was drawn from lived experience — and every one of them can be implemented.

PART ONE: STRATEGIC FOUNDATIONS
How to Think About Emerging Market Energy Development

PRINCIPLE 1: DESIGN THE ENERGY MIX AROUND WHAT THE ECONOMY ACTUALLY NEEDS
Philip Julien · Kenesjay Green

One of the most persistent mistakes in emerging market energy planning is allowing ideology to drive the energy mix rather than engineering reality. The result is plans that look good in policy documents but cannot sustain industrial load.

Philip Julien of Kenesjay Green, who has spent more than two decades developing energy projects across Trinidad and Tobago and the wider Caribbean, put it plainly: the fundamental challenge is demand. Not the existence of it, but the fragmentation of it. Across the Caribbean, diesel procurement happens island by island, company by company, with no coordination and therefore no scale. The result is a market that cannot access the pricing or the supply structures that scale would unlock.

His answer is regional demand aggregation — drawing a circle around the Caribbean and treating the aggregated demand as a single market. The same logic applies to West Africa and Southern Africa. Industrial zones in southeastern Nigeria, power pools across the ECOWAS region, and anchor demand from utilities in Southern Africa all represent aggregation opportunities that remain significantly underexploited.

Julien also made a point that deserves emphasis: the most underutilised asset in many emerging markets is existing infrastructure. Terminals, storage facilities, pipelines, and power stations built for one purpose can often be repurposed for another — faster, cheaper, and with lower execution risk than new-build alternatives. Before reaching for a greenfield solution, ask what already exists that can be adapted.

What This Means in Practice

Before investing in new infrastructure, map your existing demand. Identify the industrial anchor loads, the utility offtakers, and the commercial consumers in your region. Model what the aggregated demand looks like. Then design the energy mix — gas, solar, storage, LNG — around that demand profile, not around what is easiest to finance in isolation. The energy mix that works is the one that serves what the economy actually consumes, reliably, at a price that supports growth.

PRINCIPLE 2: GAS-TO-POWER IS EXECUTABLE — BUT ONLY WITH THE RIGHT PARTNERS AND THE RIGHT PLAN
Cheikh Dieng · Senelec

Gas-to-power is consistently cited as the critical pathway to energy security across emerging markets. The challenge is that most discussions treat it as a destination rather than a process. Cheikh Dieng, Director General of Senelec in Senegal, has navigated that process from inside one of West Africa's leading utilities — and his experience points to three non-negotiables.

The first is long-term planning. Senelec's approach to LNG procurement is anchored in three specific goals: lower the cost of electricity, ensure LNG purchases beat the cost of the HFO it replaces, and negotiate an LNG purchase price below TTF — the European benchmark. These are not aspirational targets. They are hard commercial tests that any proposed supply arrangement must pass. The discipline behind them reflects a fundamental truth: with fuel accounting for approximately 70% of the cost of electricity, every dollar per MMBtu in the LNG purchase price directly determines whether the energy transition is affordable for end users.

The second is partner quality. Dieng is unequivocal that a strong partner brings more than capital. They bring operational capability, institutional knowledge, and a genuine long-term stake in the project's success. The warning signs of the wrong partner are well-known in this sector even if rarely stated plainly: partners who close the deal and disengage, who do not invest in local capacity, and who prioritise short-term returns over the operational health of the asset. In markets where you are building institutions as much as infrastructure, partners who understand only one of those things are a risk, not an asset.

The third is the willingness to adapt. LNG pricing dynamics, shipping logistics, the interface between terminal infrastructure and grid management — these are not things you fully understand before you are operating in them. The markets advancing fastest in gas-to-power are those that treat each iteration as information rather than failure, and that invest in the commercial and technical capacity to improve continuously.

What This Means in Practice

Before entering any gas-to-power project, define your commercial tests. What is the HFO price you are replacing? What is the maximum delivered LNG cost at which the project remains viable for end users? What is your benchmark — TTF, JKM, Henry Hub — and at what premium over that benchmark does the economics of the project break down? These are not questions for the financing stage. They are questions for the concept stage, and they should drive every subsequent commercial decision.

PRINCIPLE 3: AFRICA NEEDS SPEED — BUT SPEED REQUIRES TRANSMISSION AND DISTRIBUTION FIRST
Chinenye Nwosu · Shell Nigeria

Chinenye Nwosu delivered what may be the most urgent argument of the summit: Africa is behind on energy, and the gap is growing in some markets because demand is rising faster than supply.

The numbers make the case. The modern energy minimum for economic development is 1,000 kilowatt hours per capita per annum. West Africa is tracking below 500. The consequences are not abstract — businesses running on diesel generators, hospitals without reliable power, industrial investment bypassing the continent because the energy infrastructure cannot support it. Every day that gap persists, there is a compounding economic and human cost.

Nwosu's response to that gap is deliberate: speed over perfection. Not recklessness, but urgency. The perfect regulatory framework that takes twelve years to develop while millions live without power is not a victory. Progress that is imperfect but functional, and that can be improved iteratively, serves people better than perfection that never arrives.

But the most practically important point she made was about where to prioritise investment. Nigeria has approximately 13,000 megawatts of installed power generation capacity. Less than half of it reaches the distribution network. The bottleneck is not generation — it is transmission and distribution. Building more generation capacity into a system where the T&D infrastructure cannot carry what already exists is not a solution. It is a misallocation of capital.

The West African Power Pool was established specifically to develop transmission infrastructure that can move excess generation capacity between countries — connecting landlocked nations like Mali and Burkina Faso to generation capacity in coastal states like Nigeria and Ghana. The work needs to accelerate.

Nwosu also made an argument about talent that the sector needs to hear. African talent in the diaspora — engineers, project managers, financiers, operators — represents an underdeployed strategic asset. The barrier to deploying them is not willingness. It is structural: immigration frameworks, compensation structures, and institutional cultures that do not yet treat diaspora expertise as the strategic resource it is. Companies and governments serious about closing the energy gap need to close this gap too.

What This Means in Practice

Before your next project, prioritise an honest assessment of your transmission and distribution infrastructure. Where are the gaps between generation capacity and delivered power? That gap is your first investment priority — not more generation. On talent: implement local content requirements that go beyond box-ticking. Build mentorship structures. Ensure your local talent is in every room, not just the rooms designated for local content compliance.

PRINCIPLE 4: THE TRUE COST OF LNG IS DELIVERED — NOT CONTRACTED
Ina Arneson · Fearnleys

One of the most consistent blind spots in LNG project planning across emerging markets is the failure to model the full delivered cost of LNG accurately. Ina Arneson of Fearnleys, one of the world's leading LNG shipbroking firms, provided the data that puts this in context.

The LNG market has grown significantly over the past two decades and is forecast to continue growing — with emerging market demand playing an increasingly important role in absorbing global supply. More supply, from more export locations, heading to more distant import markets, is the structural direction of the market. What that means for emerging market buyers is longer trade routes, more tonne-miles, greater freight costs, and a shipping market that needs to keep pace through new fleet investment.

The practical implication is significant. The shipping cost on a US Gulf to Asia voyage — the kind of route increasingly relevant to Southern and West African LNG buyers — is approximately three times the shipping cost on a US Gulf to Europe voyage. On some trade routes, freight can represent a material share of the total delivered cost. Getting this wrong in a financial model does not just affect project returns — it can make a project commercially unviable at the point of delivery.

Arneson also highlighted a structural tension in the current market: the fleet has grown substantially while LNG volumes have been constrained by geopolitical disruption, leaving parts of the fleet underutilised. Near-term, that creates some relief on freight rates. But the order book remains substantial, and by the end of the decade, the market is expected to tighten as the wave of new liquefaction projects from the US, Qatar, and Canada comes online and shipping demand grows.

What This Means in Practice

Model your delivered cost from day one. Do not use a single shipping cost estimate — model a range based on vessel type, route, and season. For projects where the volume justifies it, consider term charter arrangements that lock in shipping availability and reduce rate volatility. Engage your shipping advisor at the concept stage, not the financing stage. The cost of delivered LNG is shaped as much by what happens between the export terminal and your regasification facility as by what you negotiate in the supply contract.

PRINCIPLE 5: CAPITAL FOLLOWS BANKABILITY — NOT AMBITION
Paul Eardley-Taylor · Standard Bank

Paul Eardley-Taylor, Head of Gas at Standard Bank and principal adviser to the Zululand Energy Terminal in Richards Bay, provided the most operationally specific account of how capital decisions are made in emerging market energy — and two principles from his session are essential reading for every project developer in this space.

The first is that a bank's presence in a country is a prerequisite, not a given. A strong project in a country where a lender has no banking presence, no on-the-ground relationships, and no existing counterparty network cannot be financed by that lender regardless of the project's quality. This is not a theoretical risk constraint — it is a practical operational limit. The implication for developers is that building relationships with the right financial institutions, in the right markets, years before you are ready to present a project, is not optional. It is part of the development process.

The second is the distinction between projects with externalised commodity revenues and those whose revenues stay in the domestic market. If your project's revenues are denominated in hard currency — LNG sold on global markets, oil at international benchmarks — your lenders are largely indifferent to the domestic regulatory environment beyond the basics. But if your project sells into a domestic market — electricity, pipeline gas — then everything matters: the tariff regime, the cost recovery mechanism, the creditworthiness of the offtaker, and crucially, what happens at the end of the project's contracted life.

South Africa's gas cliff is the cautionary tale. The country accessed a Mozambican gas field in 2002 through a laissez-faire arrangement driven by a private company. No domestic gas allocations were mandated. No end-of-life planning was done. The field is declining, with the supply running out between 2028 and 2030. The answer — LNG imports, anchored by projects like the Zululand Energy Terminal — is now being assembled under time pressure that would not exist if the planning had been done twenty years ago.

What This Means in Practice

If your project is a domestic market project, address the revenue question from day one. What is the tariff structure? Who is the offtaker and what is their creditworthiness? What happens at the end of the contracted term? These are not questions for the financing process — they are questions for the project concept. Lenders will ask them. Get to the answers before they do.

PRINCIPLE 6: PROCESS DISCIPLINE IS THE DEVELOPER'S COMPETITIVE ADVANTAGE
Matt Norman

Matthew Norman, who has delivered energy infrastructure projects across both emerging and established markets through the full project lifecycle, made an argument that sounds simple and is consistently underestimated: work the process.

The foundational contracts — grid connection, land tenure, water supply, export logistics — are the things that determine whether a project can be financed, not the engineering of the project itself. These are also the things that developers under time pressure most commonly defer. The pattern is predictable: a developer with a strong concept, good technology, and willing investors arrives at the financing stage only to find that the lenders have identified gaps in the foundational infrastructure frameworks that should have been addressed eighteen months earlier.

Norman's point about technology is equally important. The narrative that emerging markets are resistant to new technology is not supported by evidence. Nigeria had one of the world's first large-scale LNG plants. Libya was an early LNG adopter. The appetite for new technology exists. What is required is early stakeholder engagement, transparent technology selection, and assurance that the technology provider can support the solution in the specific operating environment. These are solvable problems — but they have to be solved in the concept phase, not at financial close.

What This Means in Practice

Map your project risks at the concept stage, not the feasibility stage. For every external dependency — grid, land, water, regulatory approval, offtake — ask: what is the process by which I get from where I am today to having a robust, bankable agreement in place? Then work that process. Engage stakeholders early. Do not wait for the regulatory environment to be perfect before you begin. Use the engagement to help shape where the regulation lands. And remember: the banks will find everything you have not addressed. Get there first.

PRINCIPLE 7: HONOUR YOUR CONTRACTS — EVEN WHEN IT IS EXPENSIVE
Vierlier Quan-Vie · VQV Consulting

Vierlier Quan-Vie of VQV Consulting, who served as Vice President of Commercial at the National Gas Company of Trinidad and Tobago, closed the summit's strategic session with the principle that sits underneath every commercial strategy in this sector: contract sanctity.

When supply is constrained — and it will be, at some point in every energy market — the question of who gets priority is answered by your contracts. Not by the current spot price. Not by political pressure. Not by who is offering the highest margin. By the obligations you have already committed to. Markets that give in to the temptation to breach less profitable contracts in favour of higher-priced alternatives destroy their long-term credibility with suppliers, lenders, and partners. The reputational damage compounds over years and manifests in the form of risk premiums, restricted access to capital, and the flight of investment to more predictable environments.

Quan-Vie drew on Trinidad's experience to make a second, related point: the value of being present across the full gas value chain. The National Gas Company of Trinidad has equity in upstream production, in LNG facilities, in petrochemical supply, and in domestic distribution. That cross-sector participation means it can see the whole system — not just the margin of any individual transaction — and make decisions on the basis of national energy security and long-term commercial health rather than short-term optimisation of a single segment.

Her final principle was one of the most actionable of the summit: international pricing for domestic industry, where possible, creates the incentive for domestic market prioritisation. When domestic energy is priced at international benchmarks, producers and developers have a financial reason to serve the home market. When it is artificially suppressed, the incentive structure inverts — and export becomes the commercially rational choice, draining supply from the domestic economy.

What This Means in Practice

Build your contracts for the full life cycle of the project, not just the period of current market conditions. Include price reopeners. Build in optionality for supply flexibility between domestic and international markets. And price your domestic contracts at commercially sustainable levels — not to maximise short-term revenue, but to ensure the incentive structure keeps supply in country and investment flowing.

PART TWO: FROM STRATEGY TO MARKET
The Commercial and Operational Realities of LNG in Frontier Economies

Part One answered the question of how to think about emerging market energy development. Part Two answers a harder question: how do you actually do it in the market?

Because there is a gap — a significant and consistently underestimated gap — between understanding the strategic logic of LNG for emerging markets and being operationally, commercially, and contractually ready to participate in that market. That gap has derailed more projects than poor planning or inadequate financing combined. It is the gap between the conference room and the trading floor, between the feasibility study and the first cargo.

PRINCIPLE 8: OPERATIONAL READINESS IS NOT OPTIONAL — IT IS THE ENTRY TICKET
Ian Belmore & Fiona Ferglind · Oil Brokerage

The most consistent and costly mistake that new LNG market participants make — across Africa, Latin America, and the Caribbean — is arriving at the market before they are ready to operate in it. Ian Belmore and Fiona Ferglind of Oil Brokerage, who between them cover LNG trading, market execution, and risk management across global physical and financial markets, gave a frank account of what this looks like from the broker's side of the table.

The picture is familiar to anyone who has worked in commodity trading: a company with genuine demand, genuine intent, and genuine commercial interest approaches the market — and then discovers that the infrastructure of participation does not exist. No exchange membership. No credit lines with counterparties. No standby letter of credit facility from an A-rated bank. No KYC documentation completed. No Master Sale and Purchase Agreement negotiated with any counterparty in the market. No trained traders who understand the difference between LNG and the oil products they previously managed.

The result, as Belmore described it, is a tick list of noes. And those noes do not just delay a trade — they can cost significant sums in a market where a single cargo can be worth hundreds of millions of dollars and where an unhedged exposure of even a few days can generate material losses.

The LNG market has specific operational requirements that differ fundamentally from other commodity markets. Documentary letters of credit — the standard instrument in oil trading — do not work in LNG physical markets, because the volume of a cargo changes during transit as boil-off gas is used for propulsion. The delivered volume is not what was loaded. This makes the standard conditions of a documentary LC practically impossible to satisfy for suppliers, who consequently demand standby letters of credit instead. SBLCs require 110% cash collateral from the issuing bank, must come from an A-rated institution, and represent a far higher collateral burden than most companies entering the LNG market from oil or domestic gas backgrounds have planned for.

Getting on to an exchange — ICE or CME for financial products — requires credit limits to be established, collateral to be posted, and clearing arrangements to be in place. None of this happens quickly. KYC processes alone can take weeks to months with each counterparty. Master Sale and Purchase Agreements, which are the standard contractual framework for LNG trades, need to be negotiated individually with the twenty to thirty counterparties you will realistically need access to in order to trade effectively. The contracts are increasingly standardised — which helps — but the process of getting them in place is not fast.

Belmore and Ferglind's advice to new market entrants is consistently the same: start on the financial side. The futures and financial derivatives markets — JKM, TTF, Henry Hub — are accessible through exchanges, provide anonymity, require less counterparty-specific infrastructure, and allow participants to learn the market, understand the pricing dynamics, and build a track record without the exposure of the full physical market. Two to three years of financial market participation before moving into physical trading is not excessive caution — it is the route map that the market's most successful new entrants have followed.

For participants in West Africa, Southern Africa, and the Caribbean who cannot afford two to three years of preparation because the demand need is imminent, the answer is not to skip the preparation — it is to partner with an established market participant who can provide market access while you build your own infrastructure in parallel. The margin cost of that partnership is real. The cost of unpreparedness in a live trade is far higher.

What This Means in Practice

Before approaching the LNG market as a buyer, developer, or trader, complete a systematic audit of your operational readiness. Do you have an A-rated banking relationship capable of issuing SBLCs? Are your exchange memberships and clearing arrangements in place? Have you completed KYC with your key target counterparties? Do your traders understand LNG-specific price indices — JKM, TTF, Henry Hub — and the basis relationships between them? Do you have the internal systems to manage hedging positions in real time? If the answer to any of these is no, address it before you approach the market, not after.

PRINCIPLE 9: THE TRUE COST OF LNG IS DELIVERED — AND SHIPPING IS THE VARIABLE NOBODY MODELS CORRECTLY
Ina Arneson · Fearnleys

Ina Arneson of Fearnleys presented the data that every LNG buyer in emerging markets needs to see before they sign a supply contract, and that most of them never do.

The shipping cost is not a rounding error. On the US Gulf to Japan and Korea route — the kind of long-haul voyage increasingly relevant to Southern African and Asian emerging market buyers — the shipping cost runs to approximately three times the cost of the equivalent voyage from the US Gulf to Northwest Europe. On these extended routes, freight can represent a significant and highly variable component of the total delivered cost of LNG. Model it wrong at the feasibility stage and your project economics may not survive contact with the actual market.

The complexity goes beyond the headline charter rate. The type of vessel matters significantly to the delivered cost calculation. A modern two-stroke LNG carrier — the XDF, ME-GI, or ME-GA — has lower fuel consumption, lower boil-off rates, and larger cargo capacity than the older Tri-Fuel Diesel Electric vessels that still make up a portion of the global fleet. On paper, the day rate for a modern two-stroke vessel is higher than for an older TFDE. In practice, the delivered cost in dollars per MMBtu is often lower for the modern vessel, because the efficiency advantages more than offset the higher day rate. The headline charter rate, in other words, rarely tells you what you actually need to know. The shipping cost per unit of cargo delivered is what matters — and calculating it correctly requires modelling vessel type, voyage distance, boil-off rates, fuel consumption, and canal routing simultaneously.

On canal routing: the Panama Canal, which would offer the most direct westbound route for US LNG heading to Asian buyers, is not reliably accessible. Pre-booked slots require high company rankings with the Panama Canal Authority built over years of transit history. Auction slots involve unpredictable waiting times. The Suez Canal has been closed to LNG carriers since 2024 due to geopolitical tensions. Cape of Good Hope — the longest route but the most predictable — has become the default for much of the LNG trade, adding substantially to voyage distances and therefore to freight costs for buyers at the end of those routes.

The global LNG fleet has grown substantially and is, at this moment, structurally oversupplied. New build deliveries set records in 2024 and 2025 is expected to be another record year. The order book stands at approximately 293 vessels through to 2031, with the bulk delivering in 2026, 2027, and 2028. Simultaneously, older vessels are leaving the fleet younger than historical norms — ships that would previously have traded for 35 to 40 years are now being scrapped or converted at 21 and 22 years, reflecting charterers' strong preference for modern, efficient tonnage.

This near-term oversupply means that freight rates, absent the current geopolitical disruption from the Hormuz Strait closure, would be soft. That is generally positive for emerging market buyers accessing LNG for the first time. But the medium-term picture tightens. The wave of new liquefaction capacity — over 80 million tonnes under construction, predominantly from the US, Qatar, and Canada — will generate substantially more LNG volumes by the end of the decade. More volume, heading to more markets over longer distances, will absorb shipping capacity and push freight rates upward. The buyers who will be most exposed to that tightening are those who have not secured term charter arrangements while the market is soft.

What This Means in Practice

Integrate shipping costs into your LNG project economics from day one — not at the point of supply contract negotiation. Use delivered cost modelling that accounts for vessel type, voyage route, canal access assumptions, and seasonal rate variations. Build a range of scenarios rather than a point estimate. For projects where volume justifies it, engage a shipping advisor at the concept stage — not when you are approaching financial close. And consider whether term charter coverage, while the market is structurally soft, gives you a freight cost certainty that materially de-risks your project economics over the life of the supply arrangement.

PRINCIPLE 10: AGGREGATION IS INFRASTRUCTURE — WITHOUT IT, THE MARKET CANNOT FUNCTION
Evans Mabaso · PetroSA

Evans Mabaso, General Manager of Chemicals and Fuels at PetroSA, gave the most operationally grounded account of the LNG transition of any session at the summit — because South Africa is not planning a transition. It is living one, under time pressure, with the gas cliff accelerating and the infrastructure to manage it still under construction.

His account of PetroSA's experience trying to bring LNG to its Gas to Liquids refinery at Mossel Bay is one of the most instructive case studies in the limits of LNG economics at the individual project level. The GTL plant requires feedstock at approximately $3 per MMBtu to operate at commercially viable margins. LNG delivered to Mossel Bay was pricing at $8 per MMBtu. The gap — $5 per MMBtu on every molecule consumed in a large industrial process — is not manageable through operational efficiency alone. The response was not to abandon LNG but to fundamentally reconsider what the plant produces — moving from fuels, which cannot absorb the higher feedstock cost, toward higher value chemicals that can. It is an instructive example of the business model adaptation that the LNG transition is demanding from industrial operators across the continent.

But the deeper implication of Mabaso's account is structural. The reason the economics at Mossel Bay are so challenging is that PetroSA, as an individual industrial consumer, cannot achieve the scale required to access LNG at competitive delivered costs. The infrastructure — regasification terminal, storage, distribution — has to be built specifically for that demand centre, and the fixed cost of that infrastructure, amortised over a single consumer's volume, is prohibitive. This is the fundamental challenge of fragmented demand, and it is not unique to South Africa. It applies across Southern Africa, West Africa, and the Caribbean wherever industrial demand for LNG exists but is spread across geographically dispersed consumers without a shared infrastructure model.

The answer Mabaso identified — and it is the right answer — is aggregation. Not demand aggregation in the abstract sense of combining multiple buyers into a single commercial arrangement, but aggregation as physical and institutional infrastructure. Industrial energy hubs — shared regasification and distribution infrastructure that serves multiple consumers from a single import point. Modular LNG distribution systems that can serve demand centres too small to justify standalone infrastructure. And critically, an anchor load large enough to justify the fixed infrastructure investment and to bring the per-unit cost down to a level that the broader market can absorb.

In the South African context, Mabaso is clear that the anchor load has to be power generation. Eskom, the state-owned electricity utility, represents the scale of demand that makes the infrastructure economics work. Every other industrial consumer — chemicals, mining, manufacturing, refining — then connects into infrastructure justified by the power sector anchor, at a delivered cost that the Eskom-scale volumes have made viable. The sequencing matters: power generation first, industrial market development second, domestic gas exploration as the long-term complement to imported LNG.

The public-private partnership dimension of this model is also important. State-owned entities — Eskom, PetroSA, or a designated gas aggregator — provide the anchor demand, the institutional credibility with suppliers, and the policy alignment that makes long-term supply contracts achievable. Private sector participants bring the capital, the commercial speed, and the operational capability. Neither can solve this alone. The PPP structure is not a governance preference — it is a commercial necessity in a market of this complexity.

PetroSA itself has signalled its interest in taking on the gas aggregator role. The logic is sound: PetroSA has operated natural gas infrastructure in South Africa for decades, understands the industrial demand base, has the technical capability to manage an LNG supply chain, and sits at the intersection of government policy and commercial operation in a way that a private aggregator could not replicate. Whether PetroSA, Eskom, or a dedicated new entity ultimately performs this function, the function itself is non-negotiable. Without an aggregator providing the pooled demand, the contractual counterparty, and the shared infrastructure, the South African LNG market will remain fragmented, expensive, and structurally unable to attract the long-term supply relationships it needs.

What This Means in Practice

For developers and policymakers in West Africa, Southern Africa, and the Caribbean: before designing an LNG supply solution for your market, map the aggregated demand. Who are the anchor loads — utilities, large industrial consumers, port facilities — whose volume justifies the infrastructure investment? Build the model around them first. Then design the shared infrastructure that allows smaller consumers to connect into a system the anchors have made viable. The aggregator function — whether performed by a state entity, a private company, or a joint venture — needs to be identified and structured before supply negotiations begin, not after. Suppliers negotiate with counterparties, not with markets. The aggregator is the counterparty.

THE PLAYBOOK IN FULL

Ten principles. Nine practitioners. One consistent thread across all of them: the gap between emerging market energy potential and emerging market energy reality is not a resource gap, a demand gap, or a technology gap. It is an execution gap.

The Ten Principles

1. Design the energy mix around what the economy actually needs — Philip Julien, Kenesjay Green
2. Gas-to-power is executable — but only with the right partners and the right plan — Cheikh Dieng, Senelec
3. Africa needs speed — but speed requires transmission and distribution first — Chinenye Nwosu, Shell Nigeria
4. The true cost of LNG is delivered — not contracted — Ina Arneson, Fearnleys
5. Capital follows bankability — not ambition — Paul Eardley-Taylor, Standard Bank
6. Process discipline is the developer's competitive advantage — Matt Norman
7. Honour your contracts — even when it is expensive — Vierlier Quan-Vie, VQV Consulting
8. Operational readiness is not optional — it is the entry ticket — Ian Belmore & Fiona Ferglind, Oil Brokerage
9. The true cost of LNG is delivered — and shipping is the variable nobody models correctly — Ina Arneson, Fearnleys
10. Aggregation is infrastructure — without it, the market cannot function — Evans Mabaso, PetroSA

The strategic principles tell you how to think: design the energy mix around what the economy needs, execute gas-to-power with long-term discipline and strong partners, prioritise transmission and distribution, model the full delivered cost of LNG, make your project bankable before you approach capital, and honour your contracts when conditions are difficult.

The commercial principles tell you how to act: arrive at the market operationally ready, model shipping as a primary cost variable not a secondary consideration, and build the aggregation infrastructure that makes the economics of LNG viable for individual participants who cannot achieve scale alone.

None of these principles is new. All of them are documented in the experience of markets that have navigated this transition before — Trinidad and Tobago, Malaysia, Qatar, Namibia, Indonesia. What is new is the urgency. The demand in West Africa, Southern Africa, and the Caribbean is not waiting. The gas cliff in South Africa is accelerating. The LNG supply available from the US Gulf is growing. The shipping market is, for the moment, soft. The window exists. The playbook is written.

What happens next is determined by what the practitioners, developers, policymakers, and financiers who work in these markets do with it.

To access the full Virtual Energy Summit replay — including all nine speaker sessions from which this playbook is drawn — join Solomon Peter Plus at members.solomonpeter.com. 

About the Author

Zavier Danielle is Director of Solomon Peter Group and host of the Virtual Energy Summit. With over 18 years of international experience across LNG origination, trading, and marketing, she brings practitioner-level expertise to every conversation she facilitates and every framework she builds. Her career spans the full LNG commercial spectrum — from marketing analytics, front office risk and treasury at Gazprom Marketing and Trading in London and Singapore, to LNG marketing at QatarEnergy where she led and supported the negotiation and execution of more than 30 MSPAs and 28 SPAs across East of Suez and African markets. At Solomon Peter Group, she has led LNG market entry origination across Africa, the Caribbean, and Latin America, and has established SPA and MSPA frameworks for frontier LNG markets that had no prior commercial infrastructure. She has spoken at LNG Congress and Africa Oil Week on market development strategy. The New Energy Playbook is not an observer's account of these markets. It is written by someone who has negotiated inside them.

Solomon Peter Group provides strategic advisory and market development services across energy infrastructure in Africa, Latin America, and the Caribbean.

+44(0)207-666-3143 · members.solomonpeter.com