Economic Feasibility of LNG Business: An Integrated Model and Case Study Analysis

Abstract

Liquefied natural gas (LNG), recognized as the fossil fuel with the lowest carbon emission intensity, is a crucial transitional energy source in the global shift towards low-carbon energy. As the natural gas industry undergoes rapid expansion, the complexity of investment business models has increased significantly. Optimizing the combination of various segments within the value chain has become standard practice, making it essential to control risks and enhance economic benefits in these multifaceted scenarios. This paper introduces an integrated economic model encompassing upstream, liquefaction, shipping, regasification, and consumption, suitable for both upstream and downstream integration. The model offers a comprehensive analysis of the primary business models and key factors across each segment of the value chain. By constructing a robust economic evaluation framework, the study aims to provide a holistic approach to understanding the economic feasibility of LNG projects. Two detailed case studies are conducted to demonstrate the application and effectiveness of the proposed model, highlighting its capability to guide investment decisions, support risk management, and optimize asset portfolios. The integrated economic model developed in this study serves as a valuable tool for stakeholders in the LNG industry. It not only facilitates informed investment decision-making but also enhances the strategic management of risks and resources. By leveraging this model, investors and managers can better navigate the complexities of the LNG business, ensuring sustainable and economically viable operations.

1. Introduction

The concepts of “carbon reduction” and “carbon neutrality” have become a global consensus, and the imperative of energy transition is evident. As one of the fossil fuels with the lowest carbon dioxide emission intensity, natural gas has emerged as a crucial bridge fuel [1]. It shows significant flexibility, and its demand is expected to increase stably in the medium term of the future. The major international oil companies are consistently increasing their share of natural gas assets, with the average percentage of natural gas production rising from 33.94% in 2000 to 42.44% in 2023, according to Wood Mackenzie. They are strategically positioning themselves in global upstream gas fields, liquefaction plants, and gasification terminals. Among them, Shell, ExxonMobil, Chevron, TotalEnergies, and BP hold liquefaction capacity that ranks among the top ten globally. The liquefied natural gas (LNG) industry is gaining increasing significance for oil and gas enterprises, and vertical integration emerges as a potent strategy to enhance economic advantages and mitigate risks for players in the LNG business [2,3,4,5].

Many scholars have studied the cost parameters of each segment in the LNG industry. Songhurst [6,7] conducted a detailed study on global LNG plant investment and operating costs, which facilitates LNG cost benchmarking analysis. Steuer [8] compared the competitiveness of LNG supply based on cost comparisons in the upstream, liquefaction, and shipping segments. Raj et al. [9] and Dai et al. [10] conducted technical and economic evaluations of LNG shipping costs from the Canadian West Coast to the Asia–Pacific region and from Russia to Northeast Asia via the Arctic route. Agarwal [11] studied the capital expenditure of LNG gasification terminals in different regions globally.

In the area of economic and environmental effect study, Langshaw [12] compared the comprehensive benefits of LNG and diesel heavy-duty trucks from wellhead to wheel, considering the costs of vehicle use and monetized greenhouse gas emission. Zhang et al. [13] assessed the technical, economic, and carbon dioxide emission aspects of the supply chain of imported LNG to China.

For the integration study of the LNG business, Ruester and Neumann [14] analyzed the factors that push firms towards enhanced vertical integration in the LNG industry and found that firms are more integrated in the presence of elevated transaction costs related to specific infrastructure investments and environmental uncertainty. Al-Saadoon and Nsa [15] studied the economic feasibility of an LNG project throughout the value chain, including liquefaction, shipping, and regasification stages, but some assumptions used may not apply to the current complicated LNG business. Tcvetkov et al. [16] conducted a technical and economic evaluation of integrated schemes involving small-scale LNG and power plants in the Russian region. Fioriti et al. [17] conducted a synergistic technical and economic benefit evaluation for integrated schemes of LNG terminals and power plants. Wyllie [18] systematically studied five technological schemes for the integrated development of LNG and power plants, comparing and evaluating the levelized cost of electricity (LCOE). Strantzali et al. [19] explored the viability of using LNG for sustainable electricity production in small-scale insular systems, emphasizing the benefits of reduced environmental emissions and lower operational costs with a multicriteria evaluation model. Lee et al. [20] formulated a comprehensive conceptual design for a supply chain involving pressurized liquefied natural gas (PLNG), encompassing stages of marine production, transportation, and utilization, and calculated the life cycle cost (LCC) of the entire chain to evaluate its economic viability.

Currently, most scholars’ research focuses on evaluating individual segments of the LNG business. These studies do not fully integrate the various segments of the industry chain, nor do they consider the synergistic benefits between segments. As a result, they fail to support the integration and optimization of the industry chain through modeling and calculations. As the LNG industry evolves, three dominant commercial structures—integrated, merchant, and tolling—prevail [21]. The landscape of the LNG business is becoming increasingly flexible and intricate, and companies could participate in various segments of the LNG value chain, either in whole or in part. There is no comprehensive economic evaluation framework or model capable of addressing the current complex business models and diverse participation across different segments of the LNG value chain.

With the inconsistent price system in different gas markets and the flexibility of the business model, conducting an economic feasibility study for the LNG business proves significantly more challenging compared to that of oil assets. Due to a lack of understanding of the entire overseas natural gas value chain, some oil and gas companies, particularly national oil companies (NOCs), have faced significant losses in some acquisitions. When investing in certain segments of the overseas natural gas value chain, such as upstream assets, they tend to focus on the evaluation of underground resources using conventional oil and gas asset assessment methods. This approach often overlooks the limitations and risks of natural gas pipelines, the regional characteristics of natural gas markets, and the complexity of upstream and downstream cooperation within the industry. These alarming acquisition failures highlight the shortcomings of traditional evaluation methods and warrant serious reflection. There is a need for a comprehensive evaluation framework that can accommodate the complexities of the current LNG business model.

This article aims to construct an integrated model encompassing upstream, liquefaction, shipping, regasification, and consumption (e.g., power plants) to conduct a meticulous analysis of the LNG business, including both comprehensive and segmented feasibility studies. It enhances risk analysis of the interconnections and combinations within the LNG industry chain, providing refined decision-making support for investments and ultimately optimizing economic benefits.

2. Upstream and Liquification

2.1. Upstream Sector

In the upstream sector, natural gas is developed and produced from gas fields. Ownership and fiscal structures of upstream fields are typically determined by local governments, granting rights to specific parties for exploration and exploitation of oil and gas reserves in designated blocks. Upstream pipelines transport gas from the developed fields to liquefaction plants. Pipeline ownership typically rests with the upstream producers, who may construct and own the pipeline through the same joint venture (JV) or different entities they establish. If multiple gas fields use the same pipeline, there might be an independent pipeline company charging a tariff. Additionally, as natural gas pipelines are strategic assets with monopolistic characteristics, some countries regulate these pipelines or acquire them through government ownership to ensure open access to any new producer and fair pricing [22]. While most natural gas is allocated for LNG production, there may still be a portion designated for local dry gas sales, which is known as domestic market obligation (DMO) [23]. The DMO depends on the requirements and regulations of the local government. Like other oil and gas field projects, upstream investment in gas fields includes drilling, processing facilities, etc. The upstream project typically applies to a production-sharing contract or royalty and tax system, with costs including capital expenditure (CAPEX), operating expenditure (OPEX), general and administrative expense (G&A), and government take [24,25].

In the royalty and tax system (referred to as concession agreements), the government and companies do not directly share the profit of oil/gas. Instead, foreign companies typically pay a fixed percentage of their revenue to the resource country, regardless of costs. The basic fiscal structure of the royalty and tax system is established by national laws and regulations. This regime is widely used in developed countries, such as the UK, Australia, and Norway.

Production sharing contracts (PSCs) are the predominant fiscal framework in the upstream natural gas sector. Under a PSC, foreign companies do not own the natural gas resources. Instead, they enter into agreements with the host country’s government or its national oil company. The foreign company provides funding and technology for exploration and development. The produced natural gas is then divided between the government and the foreign company, with the government typically receiving a substantial share. PSCs stipulate that the initial share of the upstream gas production is allocated to the government in the form of royalties. After this allocation, the remaining production is used for “cost recovery”, allowing investors to recover their incurred costs, although there may be limits on the amount that can be recovered annually. The residual production, termed “profit gas”, is then shared between the government and the investor. Finally, the investor must pay income tax and any other stipulated additional profit taxes on their share of the profit gas.

2.2. Liquification Plant

There are generally three options for the commercial structure of liquefaction plant owners: integrated, tolling, and merchant structure [26,27,28]. Figure 1 illustrates the contractual relationships between gas field producers, liquefaction plants, and LNG buyers under different LNG business models. The distinctions among the three different business models are as follows:

In the integrated structure, the natural gas producer functions as both the owner of upstream facilities and the liquefaction plant [26,27,28]. Revenues are derived from one or more LNG sales and purchase agreements (SPA), and the creditworthiness of LNG buyers facilitates financing for both upstream production and LNG liquefaction projects. In most scenarios employing the integrated structure, both upstream production and liquefaction segments fall under the scope of the upstream tax system, leading to the consolidation of revenues and costs. However, in cases where different tax systems are applicable to upstream extraction and LNG plants, transfer pricing between upstream and liquefaction facilities becomes necessary. This ensures the equitable calculation of income for tax purposes, subject to the oversight of local governments. Examples of LNG liquefaction projects utilizing an integrated structure include Qatar’s Qatargas and RasGas projects, Russia’s Sakhalin, Norway’s Snøhvit, Australia’s Northwest Shelf, Darwin LNG, and Indonesia’s Tangguh project, etc.

The integrated business structure could optimize operational efficiency through improved handovers and coordination across segments along the industrial chain. However, it lacks flexibility in terms of ownership, as some upstream participants may not find LNG liquefaction ventures appealing. Additionally, when confronted with new third-party gas sources, expanding integrated project structures becomes more challenging.

In the tolling structure, upstream gas fields and liquefaction projects are separate entities. The liquefaction project company does not own the rights to natural gas or LNG but provides liquefaction services based on one or more long-term liquefaction tolling agreements [26,27,28]. Revenue for LNG liquefaction projects comes from liquefaction service fees paid by customers (upstream developers or downstream buyers). Since the function of liquefaction project companies does not include commodity trading, they do not bear the risks associated with gas and LNG supply, costs, and pricing. The creditworthiness of tolling customers supports financing for liquefaction projects.

In this structure, LNG liquefaction plant investors pay for the capital and operating costs of the plant, but ownership of the produced LNG remains with the upstream natural gas producers. The owners of liquefaction plants charge a certain processing fee based on volume. After paying the processing fees to convert natural gas into LNG, upstream owners then sell the LNG to the export market. LNG liquefaction projects using the tolling business model include Trinidad Train 4, Egypt’s Damietta, Indonesia’s Bontang, and the United States’ Freeport LNG, Cameron LNG, and Cove Point facilities, etc.

Merchant structure is like tolling structure; upstream producers and liquefaction project companies are separate entities. What is different is that liquefaction project companies purchase natural gas from upstream companies and sell LNG to the export market, which means they must bear the risks associated with gas and LNG supply, costs, and pricing. Revenue for liquefaction projects comes from LNG sales, with costs including liquefaction and natural gas procurement [26,27,28]. Liquefaction project companies can purchase gas from multiple local gas suppliers. The creditworthiness of LNG buyers and natural gas producers supports financing for liquefaction projects. LNG liquefaction projects using the merchant structure include Trinidad Trains 1, 2, and 3, Angola LNG, Nigeria LNG, Equatorial Guinea LNG, and Malaysia LNG.

To facilitate cost comparisons within the industry, the common practice is to employ the liquefaction unit CAPEX, calculated as the plant’s capital expenditure in millions of USD per capacity in a million tons per year. As shown in Figure 2, the X-axis represents the final investment decision (FID) time of the project, and the Y-axis represents the liquefaction unit CAPEX. The size of the bubble corresponds to the capacity of each project, and different colors refer to the location or country of the project. From 2000 to 2013, the liquefaction unit CAPEX witnessed a significant surge from about 300 USD/ton to 1500 USD/ton, despite the upstream capital cost index (UCCI, index comes from S&P) experiencing a mere 131% increase. Notably, Australian projects incurred exceptionally high costs due to their intricate nature, remote locations, and construction in areas known for some of the world’s highest costs. These high-cost projects received FID during a period of elevated oil and gas prices, and most of them surpassed initial CAPEX forecasts. Furthermore, Australia grapples with significantly higher labor expenses compared to the industry average. In contrast, the other two leading LNG producers, Qatar and the United States, boast lower cost levels, benefiting from mature conditions that contribute to cost savings. The United States experienced a surge in LNG projects following the shale gas boom, with over 20 projects reaching FID from 2012 to 2023, with relatively stable unit CAPEX. In 2021, Qatar initiated the mega project North Field East (NFE) with a capacity of 32 million tons per year, featuring a unit CAPEX of approximately 530 USD/ton.

3. Mid and Downstream

3.1. LNG Shipping

For LNG producers, shipping is not just a crucial component but a strategic decision point that can offer significant competitive advantages when managed effectively [26]. This requires specialized knowledge and experience, with comprehensive evaluations from commercial, legal, financial, and risk management perspectives. Financial modeling and sensitivity analysis are critical for refining shipping plans and ensuring the economic viability of projects.

The entry barrier for LNG shipping is high due to professional requirements for asset management and operations [30]. Each LNG vessel costs around USD 200 million, necessitating reputable partners, stable agreements, and a reliable LNG value chain for project financing. Technically, the safe operation of LNG fleets requires experienced management and skilled crews. The sector is consolidating among specialized shipowners like MOL (51 vessels), NYK (47 vessels), and Maran Gas (40 vessels).

LNG buyers and sellers often lease LNG ships from professional shipowners but may also consider self-ownership [31,32]. Building their own fleet can enhance industry chain revenue, provide asset portfolio flexibility, optimize routes, and improve shipping capacity reliability. Companies with large LNG projects or global assets, such as Shell, BP, and Qatargas, often own fleets of self-operated LNG vessels, some of which are self-built or long-term leases.

LNG transport vessels are categorized as project-specific ships (project ships) and spot ships, with varying daily rental rates. Most global LNG fleet vessels are project ships tied to specific LNG projects, with shipowners signing long-term charter contracts with project parties for stable vessel rentals and returns. These vessels have the following distinct features:

• Fixed long-term leases typically spanning 15 to 25 years.
• Concurrent execution of charter, construction, and financing contracts.
• Daily rental capital portion based on a fixed return on investment.
• Operating cost portion based on actual verified costs, agreed upon annually.

Recently, traders have signed long-term project charter contracts for LNG ships to ensure a stable supply [33,34,35,36]. This has led many shipowners to withdraw from the spot ship market due to the high and secure rates of these contracts. Traditionally, LNG project companies leased “project ships” for LNG transport needs, with vessels often owned by the LNG project itself. However, recent trends show a shift towards independent shipowners, reflecting increased diversity and competitiveness in LNG vessel ownership. Major shipowners are exploring joint ownership and investment opportunities, with many LNG ships now held by joint ventures involving multiple shipowners and some oil and gas companies becoming equity shareholders in these joint ventures.

International oil companies have strengthened control over LNG transportation by establishing LNG fleets, which are core assets in the industry [33,34,35,36]. Owning a dedicated fleet enhances autonomy, optimizes vessel scheduling, and increases trade flexibility. For example, Shell, originally a trading and transportation company, currently operates a world-class fleet of 64 LNG vessels with 13 new orders in progress.

Oil companies or LNG exporters typically establish separate subsidiaries for shipping operations, contributing to transparency in accounting and financial management, along with legal and tax advantages. Companies like QatarEnergy, BP, Shell, and Venture Global operate large-scale LNG fleets through such subsidiaries. A long-term charter agreement between the parent company and the shipping subsidiary ensures structured leasing akin to external shipping companies.

LNG shipping operates under distinct fiscal and tax regimes compared to upstream operations. Tax obligations for vessel owners vary by jurisdiction of registration, operations, and lease agreement terms. Common taxes include income tax, withholding tax, value-added tax, and special shipping taxes. Contract terms specify responsibilities for tariffs and port fees/taxes.

3.2. Regasification

LNG regasification terminals are a critical step in connecting the upstream and downstream markets of the oil and gas industry, which serve as the endpoints for LNG import and export operations and as starting points for downstream activities, such as power generation and retail [37].

Like the LNG plant, there are also three options for the commercial structure of regasification terminal owners: integrated, tolling, and merchant structure. In the tolling model, investors own or lease and operate the regasification facilities, charging fees for LNG regasification. In the merchant model, investors own or lease and operate the regasification facilities, purchase LNG in the open market and sell the natural gas, earning the margin between the LNG price and the domestic natural gas price. In the integrated business structure, the LNG regasification terminal may be part of an upstream integrated project or a comprehensive downstream project, which includes regasification facilities, downstream pipelines, and natural gas power generation.

Currently, Shell owns 10 regasification terminals, mainly located in North America and Europe. In recent years, Shell has intensified its efforts in the Asian market to meet changing market demands. This includes developing and expanding the Hazira regasification terminal in India, pursuing floating storage and regasification unit (FSRU) projects in Pakistan (Port Qasim) and the Philippines (Batangas), and developing an onshore regasification project in Myanmar. In China, Shell, in partnership with Guanghui Energy, has established the Jiangsu Qidong regasification terminal to receive and distribute LNG.

International oil companies’ regasification terminal projects are generally not tied to specific upstream projects. These terminals, as essential channels for importing LNG via maritime routes, can theoretically connect with global upstream LNG resources without being bound to a single project. Shell, Total, and BP package their LNG production resources into asset portfolios, optimizing shipping routes for their own fleets to connect with global regasification terminal resources. This asset configuration allows for more flexible LNG cargo turnover and more competitive pricing.

Regasification facilities can be constructed either as onshore LNG terminals or as offshore FSRUs. Traditionally, onshore LNG terminals have been preferred due to their high economies of scale, low operating costs, ease of expansion, and high degree of localization. However, in recent years, FSRU technology has emerged as a more flexible alternative to traditional onshore terminals [38]. FSRUs offer moderate scale, lower costs, quick deployment, and ease of relocation after contract termination. Typically, FSRUs have a lease period of about 10 to 12 years, covering facility costs and operation expenses.

The investment cost for constructing a 180,000 cubic meter capacity onshore regasification terminal is approximately USD 750 million, with an operating cost of about USD 100,000 per day. The service fees for global regasification terminals vary significantly, and in China, they range from CNY 0.18 to 0.35 per cubic meter (about 0.73 to 1.42 USD/MCF). The total capital expenditure for an FSRU is about 60% of that for an onshore solution, around USD 450 million (with costs for small or retrofitted FSRUs being under USD 300 million). Operating costs are USD 20,000 to USD 30,000 per day, and FSRUs are mostly used on long-term leases with daily rental fees of approximately USD 180,000.

It is noteworthy that the cost of constructing a new FSRU is approximately 50% to 60% of that of an onshore terminal, and the construction time is only half as long [38,39]. However, investors may face challenges in site selection and permit applications, which need to be addressed through agreements with local stakeholders. FSRUs offer significant advantages in terms of shorter construction cycles, lower investment, and minimal land use, making them ideal for quickly meeting the natural gas needs of small markets and enabling new markets to rapidly integrate into the global LNG trade. However, for large markets with long-term stable LNG demand, onshore regasification terminals are often more advantageous. Onshore infrastructure can support larger storage tanks and regasification capacities and can be expanded as needed. Onshore projects also have lower maintenance costs and reduced risk of malfunctions and weather disruptions compared to FSRUs.

3.3. Gas Consumption in Power Plant

One key use of natural gas is converting it into electricity with efficient gas turbines. In combined cycle gas power generation, high-temperature exhaust gases from burning natural gas drive a gas turbine for primary power [40]. These exhaust gases then heat water to produce steam, which drives a steam turbine for secondary power. In the 1990s, low natural gas prices and advancements in combined cycle technology boosted demand for natural gas power generation in Europe and the United States, leading to the construction of numerous plants. In the 2000s, Japan and South Korea significantly increased LNG imports, primarily for natural gas power generation. Recently, due to its high thermal efficiency and relatively low emissions, natural gas is considered the cleanest fuel for power generation. Today, combined cycle gas power generation technology is highly mature and widely used in large-scale commercial operations globally.

A vertically integrated power company covers generation, transmission, and distribution components; however, oil companies that are interested in natural gas power generation may take the independent power producer (IPP) model as a primary consideration. Power plants are one of the most capital-intensive and inflexible segments in the downstream natural gas value chain. The stable operation of the entire value chain often depends on long-term purchase and sale agreements [41]. Compared to other types of power plants, natural gas power plants face more challenges, such as long-term take-or-pay fuel supply contracts and the need for large-scale investments.

To fulfill the obligations of a take-or-pay fuel supply contract, an IPP must ensure it has enough electricity generation to meet its contractual requirements throughout the term of its gas purchase agreement. This necessitates signing long-term power purchase agreements (PPAs) with grid companies and must align with the gas supply agreements [42]. To guarantee the annual minimum take-or-pay gas volume, the IPP must enter into long-term natural gas sales agreements with strict monthly, weekly, and daily gas volume requirements and reflect it in the IPP’s grid dispatch agreement. The power plant pays the costs of LNG, including its transportation and gasification fees, and these costs fluctuate within a certain range based on international oil price indices. Consequently, the PPA between the power plant and the grid company must include a long-term, 15–25-year take-or-pay commitment corresponding to the minimum gas volume promised by the power plant.

4. Materials and Methods

Considering the characteristics of the LNG industry, this study identifies key elements at each stage and evaluates the benefits of the upstream, midstream, and downstream segments, as depicted in Figure 3. The integrated model incorporates over 25 parameters across five stages and includes options for fiscal regimes, LNG plant structures, LNG delivery, and pricing to accommodate different commercial scenarios. This comprehensive approach links different segments through free-on-board (FOB) price, delivered ex-ship (DES) price, and domestic gate price, facilitating an integrated benefit analysis for the entire LNG value chain.

To better integrate with actual LNG project operations and make our models more practical, we divided them into two types: upstream integrated model and downstream integrated model.

4.1. Upstream Integrated Model Framework

The upstream integrated model encompasses various possible combinations of upstream natural gas production, gas pipelines, LNG plants, and LNG shipping. The primary stakeholders include upstream investors, LNG liquefaction plant owners, the host country’s government, and the local oil company.

The primary objective of upstream investors is to attain the anticipated return on investment while astutely managing geological, operational, political, and market risks. The government of the host country and the local oil company aim to ensure the project’s economic feasibility and continued attraction of investors while maximizing the country’s benefits in a situation of limited and depleting resources over time. For cash flow modeling of a gas field producer, the approach is the same as the traditional upstream asset evaluation method. Revenue distribution should refer to the applicable tax code, concession agreement, or production-sharing contract. Figure 4 illustrates the different revenue distributions under a royalty and tax system or a production-sharing contract.

Owners of LNG liquefaction plants may include international oil companies, local oil companies, international gas buyers, infrastructure companies, or local power companies. They seek to ensure the ongoing profitability of the LNG project itself. In an integrated structure, the LNG liquefaction plant and gas field producer function as a unified entity. Consequently, CAPEX, OPEX, and cash flow modeling are consolidated and typically follow the upstream fiscal regime. In a tolling structure, tolling fees are determined based on the LNG liquefaction plant’s target rate of return. This calculation considers CAPEX during the construction period, OPEX, and taxes during the operational period to achieve the desired internal rate of return (IRR), as shown in Equation (1). The tolling fee is typically divided into CAPEX and OPEX components. “T1” is the calculated tolling fee related to CAPEX, while the OPEX component is determined by annual incurred OPEX. Taxes here refer to potential income tax and other applicable taxes. “N” denotes the evaluation period, “r” represents the target IRR, and “Q” refers to LNG production.

$$\sum _{n=1}^{n=N}\frac{(T1\times Q+OPEX)-CAPEX-OPEX-tax}{{(1+r)}^n}=0$$

(1)

In a merchant structure, the cash flow of an LNG liquefaction plant is determined not only by costs but also by the prices of feed gas and exported LNG, as shown in Equation (2). “N” denotes the evaluation period, and “r” represents the calculated IRR. “P1” and “Q1” refer to the LNG export price and production volume, respectively, while “P2” and “Q2” refer to the feed gas price and volume. Taxes include potential income tax and other applicable taxes.

$$\sum _{n=1}^{n=N}\frac{P1\times Q1-P2\times Q2-CAPEX-OPEX-tax}{{(1+r)}^n}=0$$

(2)

The LNG shipping segment can also be included. Typically, LNG shipping operations align with long-term LNG purchase and sale agreements, involving voyages between specific loading and unloading ports for durations of 15–20 years. When the upstream and liquefaction segments are owned by different entities, LNG shipping may be operated by either the upstream investor or the liquefaction plant owner. LNG shipping cost is mainly determined by the charter daily rate, ship capacity, BOG (boil-off gas) rate, and voyage days, as shown in Equation (1). “C” refers to the charter daily rate. “D1” and “D2” represent the number of days for the loaded and ballast voyages, respectively. “F” stands for fuel oil costs, and “G” stands for port charges. “V” denotes the capacity of the LNG vessel, “L” is the loading rate, and “B” is the BOG rate. The converter here is the factor that converts liquid volume units (m³) to calorific value units (MMBTU).

$$Unit Cost (US\$/MMBTU)=\frac{C\times \left(D1+D2\right)+F+G}{V\times \left[L-B\ast \left(D1+D2\right)\right]\times converter}$$

(3)

Given the diverse stakeholders and project participation structures, the economic model has the following main flexibility settings:

• Establishing the equity percentage and carry options for foreign and local oil companies.
• Adjusting the government’s revenue structure through financial and tax terms.
• Comprehensive or individual evaluation of the economic benefits of LNG liquefaction projects under different participation structures.
• Comprehensive or individual assessment of the economic impact of LNG shipping segments.

4.2. Downstream Integrated Model Framework

This economic model for a downstream natural gas integration project is based on several key assumptions to predict the behavior of participants and potential project benefits. The model assumes that LNG suppliers consistently provide the minimum quantity of LNG to buyers. Buyers and power plants must adhere to “take-or-pay” obligations to LNG suppliers, ensuring immediate payment upon purchase.

The model aims to evaluate various LNG-to-power structures, analyzing costs, revenues, and risks to provide a comprehensive understanding of the responsibilities and benefits for all participants. It summarizes project returns, expenses, and taxes under different scenarios, allocating these to investors and government utilities.

In a tolling or merchant structure, cash flow modeling for regasification is quite like that of a liquefaction plant, as shown in Equations (1) and (2). The primary difference between regasification and a liquefaction plant is whether the process involves converting gas to LNG or LNG to gas. For natural gas power plants, revenue is determined by grid electricity prices, while costs depend on plant investments and operational expenses. Among operational costs, natural gas procurement costs are paramount. Depending on the commercial structure, this could encompass pipeline transportation fees, gasification costs, shipping expenses, and the purchasing price of LNG from liquefaction plants.

In terms of pricing, the economic model assumes independent pricing at each stage of the value chain, including LNG DES price, regasification exit price, gas sale price to power plant, and electricity price. These prices are typically contractually determined using formulas to mitigate risks, often linking them to global market factors and reflecting different energy contents and standards. For instance, LNG prices might be indexed to major gas markets like Henry Hub or tied to widely traded oil benchmarks like Brent.

Electricity pricing mechanisms vary by country and are influenced by specific conditions and policies. Traditionally, vertically integrated monopolies balance asset portfolios to ensure stable pricing and affordability. In liberalized markets, prices are set via spot prices or long-term power purchase agreements, with generators bidding based on marginal costs. To compare different power sources, the LCOE is a useful metric, considering production, capital cost and fiscal terms.

5. Results and Discussion

5.1. Case 1: Upstream Integrated LNG Project

The A project (real name omitted for confidentiality) is a large-scale integrated natural gas project with an international oil company (IOC) with 80% interest and a local company with 20% interest. It comprises an offshore production facility and an onshore LNG plant with an annual capacity of 9.5 million tons, aiming to fully develop the natural gas resources of the A gas field with approximately 21 Tcf of recoverable natural gas resources. The project is expected to use a floating production storage and offloading (FPSO) unit for initial processing and condensate separation. Subsequently, the raw gas will be transported via a subsea pipeline to an onshore LNG facility. The total CAPEX for the entire project is estimated to exceed USD 20 billion. We anticipate that the project will reach the FID in 2026 and commence LNG production in 2031.

The offshore gas field is planned to supply about 1200 MMCFD of raw gas to a newly constructed onshore LNG plant, with up to 150 MMCFD of pipeline gas designated for local customers. The project will also produce up to 28,000 barrels per day of condensate. Plans include the construction of five gathering hubs, each capable of connecting four wells. Over the project’s lifecycle, 19 to 21 development wells are expected to be drilled, and the expected recoverable reserves per well are estimated at 110 million barrels of oil equivalent. The total CAPEX for the offshore gas field is projected to be around USD 9.45 billion. A subsea pipeline, approximately 180 km long and 34 inches in diameter, will transport the LNG feed gas to the onshore LNG plant, with an estimated CAPEX of around USD 1 billion. The project will establish an LNG facility with an annual production capacity of 9.5 million tons with CAPEX of about USD 11 billion, equating to approximately USD 1167 per ton of capacity. In addition, the CAPEX related to the carbon capture and storage (CCS) component is estimated to be around USD 1.3 billion.

The project operates under a PSC fiscal structure, enabling a cost recovery mechanism. Its contract spans approximately 30 years. The First Tranche Petroleum (FTP) is set at 15%, shared between the contractor and the government. Following FTP, the contractor recovers all depreciated capital and operating costs through production. The remaining production, termed Equity to be Split (ETBS) post FTP and cost recovery, is divided as per percentages outlined in the PSC between the state and contractor. Post-tax profit sharing for oil and gas stands at 50:50, with an income tax rate of 40%.

We conceptualize a comprehensive natural gas integrated project functioning under a PSC regime, incorporating upstream gas fields, CCS, export pipelines, and an LNG plant. However, we possess the flexibility to fine-tune parameters within an Excel model to assess diverse development scenarios economically. For example, the operator could prioritize upstream operations exclusively while covering tolling fees for an independent LNG plant (LNG processing fee). Our assumptions encompass an average price of USD 4.2 per mcf for LNG feed gas, a long-term average of USD 9.3 per mcf for LNG off-take, and a domestic price of USD 6 per mcf for local pipeline gas (in real terms). Additionally, we assume that carbon capture and storage facilities do not generate revenue.

With the assumption above, the unit technical cost of project A is 6.23 USD/MCF, and the LNG plant cost accounts for more than half of that, as shown in

Table 1. Unit cost of LNG production.

Unit Cost (USD/MCF)	Capex	Opex	Total
Gas Field	1.95	0.47	2.43
CCS	0.28	0.06	0.33
Pipeline	0.25	0.06	0.31
LNG Plant	2.55	0.62	3.16
Total	5.02	1.21	6.23

. Internal Rate of Return (IRR) and Net Present Value (NPV) of IOC in this project are 11.4% and 1313 MMUSD, as shown in

Table 2. Economic results of upstream integrated project A.

Gov./Investor	Acc. Net Cashflow	NPV	IRR	Payback Period	PI Ratio
Discount rate	0%	10%
Project net cashflow	77,518	8409
Investor cashflow	36,888	1641	11.4%	10.2	1.10
IOC cashflow	11.4%	1313	11.4%	10.2	1.10
Local Company Cashflow	11.4%	328	11.4%	10.2	1.10
Gov. take	40,630	6768

and Figure 5. The A project exhibits high sensitivity to natural gas prices, moderate sensitivity to upstream gas fields and LNG plant capital expenditures, and low sensitivity to LNG feed gas prices, as shown in Figure 6 and Figure 7. The potential delay of the onstream date is a crucial factor for investors, and the additional costs associated with CCS will further constrain their profits, as shown in Figure 8 and Figure 9.

5.2. Case 2: Downstream Integrated LNG Project

Project B is a fully integrated LNG-to-power project where an international company purchases LNG, operates regasification stations, natural gas pipelines, and power plants, and sells electricity to the grid.

Table 3. Key assumptions of project B in different segments.

	LNG Trade	Regasification		Gas Pipeline		Power Plant
Ownership	IOC	IOC		IOC		IOC
Newly built or lease	N.A.	Newly built		Newly built		Newly built
Capex	N.A.	525	MMUSD	309	MMUSD	3257	MMUSD
Capacity	N.A.	3.6	Million ton	3.5	Million ton	3428	MW

outlines the key parameters for each segment in the value chain, assuming LNG prices at 7.4 USD/MMBTU and electricity grid prices at 98.0 USD/MWh.

Figure 10 exhibits the detailed breakdown cost and profit, and the total unit cost of project B is 10.68 USD/MMBTU, with LNG purchase costs comprising most of it. As shown in

Table 4. Main economic evaluation results of project B.

	NPV (MMUSD)	IRR (%)	CAPEX (MMUSD)	OPEX (MMUSD/Year)	Net Cashflow (MMUSD)	Tax (MMUSD)
Regasification	−52	6.6%	525	84	620	289
Gas pipeline	175	15.3%	309	18	1023	423
Power plant	1838	15.0%	3257	130	10,821	4482
Total	1962	14.0%	4090	233	12,464	5194

and Figure 11, the IRR and NPV for the IOC in this project are 14.0% and 1962 MMUSD, respectively. Project B demonstrates a high sensitivity to electricity grid prices, moderate sensitivity to LNG purchase costs for regasification stations, and low sensitivity to terminal CAPEX, power plant CAPEX, and the price of natural gas entering power plants, as shown in Figure 12 and Figure 13.

The model not only calculates returns and benefits across the LNG-to-power value chain but also identifies and quantifies risks associated with different commercial structures.

• Infrastructure Risks: Design capacity issues from unrealistic demand forecasts, construction delays or cost overruns, and the availability of necessary supporting infrastructure.
• Operational Risks: Operational schedules and maintenance.
• Market Risks: Misalignment between LNG sales, regasification, and end-user demand, as well as price risks from unaligned consumer gas prices.

To mitigate risks, LNG agreements often require buyers to commit to minimum LNG quantities, ensuring operational continuity and financial stability. Similar “take-or-pay” obligations are imposed on downstream gas customers to manage fluctuating demand. Long-term contracts impose minimum supply obligations on sellers, ensuring reliability. Fee-based regasification plants and pipelines may require minimum throughput commitments, with penalties for shortfalls to cover proportional operational and capital costs. The model’s risk allocation mechanisms are essential for comprehensive commercial risk assessment.

5.3. Discussion

Compared to the previous scholars’ research, the model and methods proposed in this paper offer superior advantages. The evaluation method proposed by Al-Saadoon [15] is limited to certain LNG projects with integrated structures and lacks flexibility in upstream fiscal regimes, as well as value chain participation scenarios. Similarly, the methods developed by Tcvetkov [16], Fioriti [17], and Wyllie [18] are tailored to specific types of LNG-to-power plant projects, with Tcvetkov’s research being exclusively focused on the Russian region. Strantzali’s study addresses small-scale LNG supply issues, concentrating on the maritime transport segment only and lacking a comprehensive industry chain assessment [19]. Meanwhile, Lee’s research focuses on pressurized liquefied natural gas (PLNG) technology, integrating only the Floating Liquefied Natural Gas Unit (FLNG) and an LNG Shuttle-and-Regasification Vessel (SRV), thus limiting its application to LNG business evaluation [20].

The economic evaluation model and framework proposed in this paper for the LNG value chain effectively handle diverse business combinations across different chain segments, providing a comprehensive view of costs and revenues. Unlike traditional evaluation methods, this model offers enhanced scope and adaptability, either upstream, like case 1, or downstream, like case 2. Its holistic approach to analyzing the value chain assists enterprises in identifying potential upstream and downstream collaboration opportunities, thereby mitigating risks through integrated chain processes.

This model and framework not only enable the economic valuation of assets but also support quantitative economic assessments that address the real-world business challenges encountered by enterprises investing in various chain segments. By integrating detailed cost–benefit analyses with strategic insights, it facilitates informed decision-making and strategic planning. Moreover, it enhances the understanding of operational dynamics and optimizes resource allocation across the entire LNG value chain, fostering sustainable growth and competitive advantage.

However, the method and model proposed in this paper have some limitations and can be improved in the future. They do not dynamically track the location and shipping routes of LNG ships, which is essential for optimizing shipping and sales strategies. Furthermore, the model lacks optimization methods or algorithms, reducing its practical applicability.

6. Conclusions

Compared to crude oil, LNG has higher production and global transportation costs and more challenging investment risks. Traditional evaluation and management methods for oil and gas projects are no longer adequate for the current complex LNG business models.

This paper provides a comprehensive analysis of the business models and key factors across all segments of the LNG industry, including upstream, liquefaction, shipping, regasification, and consumption. It develops an economic evaluation framework applicable to various combinations of industry chain segments. For common commercial scenarios, models for both upstream and downstream integrated projects are established, followed by case analyses.

The integrated economic model for LNG business developed in this paper considers factors across all segments of the industry chain, enabling comprehensive economic evaluations for complex multi-segment business models. It also enhances the risk analysis of linkages and combinations within the LNG industry chain, optimizing the profitability of gas projects. This model offers significant practical value, aiding LNG investors in making informed investment decisions and optimizing their portfolios, thereby achieving better profitability.