LNG Project Development Cycle Reference (2)
LNG Project Development Cycle Reference (2)
This is a power point presentation of GLOBAL LNG FUNDAMENTALS materials from the US DOE and USAID (see link at the references section at the bottom of this presentation)
Prepared by
MARCIAL OCAMPO
Energy and Power Technology Selection and Project Finance Modeling Expert
To download this presentation with tables and charts, click on the link below
Table of Contents
Hydrogen from LNG
Hydrogen Production: Natural Gas Reforming
Natural gas reforming is an advanced and mature production process that builds upon the existing natural gas pipeline delivery infrastructure. Today, 95% of the hydrogen produced in the United States is made by natural gas reforming in large central plants. This is an important technology pathway for near-term hydrogen production.
How Does It Work?
Natural gas contains methane (CH4) that can be used to produce hydrogen with thermal processes, such as steam-methane reformation and partial oxidation.
https://www.energy.gov/eere/fuelcells/hydrogen-production-natural-gasreforming
Steam-Methane Reforming
Most hydrogen produced today in the United States is made via steam-methane reforming, a mature production process in which high-temperature steam (700°C– 1,000°C) is used to produce hydrogen from a methane source, such as natural gas.
In steam-methane reforming, methane reacts with steam under 3–25 bar pressure (1 bar = 14.5 psi) in the presence of a catalyst to produce hydrogen, carbon monoxide, and a relatively small amount of carbon dioxide. Steam reforming is endothermic—that is, heat must be supplied to the process for the reaction to proceed.
Subsequently, in what is called the "water-gas shift reaction," the carbon monoxide and steam are reacted using a catalyst to produce carbon dioxide and more hydrogen.
In a final process step called "pressure-swing adsorption," carbon dioxide and other impurities are removed from the gas stream, leaving essentially pure hydrogen. Steam reforming can also be used to produce hydrogen from other fuels, such as ethanol, propane, or even gasoline.
https://www.energy.gov/eere/fuelcells/hydrogen-production-naturalgas-reforming
Partial Oxidation
In partial oxidation, the methane and other hydrocarbons in natural gas react with a limited amount of oxygen (typically from air) that is not enough to completely oxidize the hydrocarbons to carbon dioxide and water. With less than the stoichiometric amount of oxygen available, the reaction products contain primarily hydrogen and carbon monoxide (and nitrogen, if the reaction is carried out with air rather than pure oxygen), and a relatively small amount of carbon dioxide and other compounds. Subsequently, in a water-gas shift reaction, the carbon monoxide reacts with water to form carbon dioxide and more hydrogen.
Partial oxidation is an exothermic process—it gives off heat. The process is, typically, much faster than steam reforming and requires a smaller reactor vessel. As can be seen in chemical reactions of partial oxidation, this process initially produces less hydrogen per unit of the input fuel than is obtained by steam reforming of the same fuel.
Why Is This Pathway Being Considered?
Reforming low-cost natural gas can provide hydrogen today for fuel cell electric vehicles (FCEVs) as well as other applications. Over the long term, DOE expects that hydrogen production from natural gas will be augmented with production from renewable, nuclear, coal (with carbon capture and storage), and other low-carbon, domestic energy resources. Cheap electricity can electrolyze water into H2 and O2.
Petroleum use and emissions are lower than for gasoline-powered internal combustion engine vehicles. The only product from an FCEV tailpipe is water vapor but even with the upstream process of producing hydrogen from natural gas as well as delivering and storing it for use in FCEVs, the total greenhouse gas emissions are cut in half and petroleum is reduced over 90% compared to today's gasoline vehicles.
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LNG Supply Industry / Utility
Global Gas Market
There are three main global gas markets:
Supply and Demand Balance
In 2016 global LNG trade accounted for 258 million metric tonnes per annum (MTPA). Also in 2016, there were 34 countries importing LNG and 19 countries that export LNG.
In terms of the global supply balance for LNG, the key features of the last few years have been:
These 4 factors have created a short-to-medium term situation of LNG oversupply which is depressing spot and medium term prices for gas that has not already been contracted.
A major portion of the LNG market has long-term contracts indexed to oil prices and oil prices have also dropped significantly.
All these factors have created a difficult environment to develop greenfield LNG export facilities but has increased demand and markets for LNG
For excess LNG that has not been contracted long term, prices in most key consuming markets, such as Europe or Asia, have fallen from a high of $10 to $15 per million British thermal units (MMBtu) to below $5/MMBtu.
While this price remains above the marginal cost of production for some projects, it typically falls well short of the whole-life costing of an LNG project, once amortization of capital and loan repayments are taken into account.
For a gas/LNG project developer/investor or host government, one of the main challenges is to determine when a rebalancing of gas markets might take place, as this would have implications on LNG price projections and a project's economic viability.
Opinions vary on when, and in what manner LNG global markets will rebalance to phase output and delay completion or LNG liquefaction terminals, It appears likely that the market will continue to be oversupplied at least into the early 2020s.
If development plans proceed, based on the completion dates and FID decisions, the oversupply could continue through the next decade.
The charts below indicate two possible realignment scenarios, based on a prompt (short term) market realignment, or a longer term oversupply. The red bars represent the amount of global LNG oversupply in MTPA.
[chart 1]
Shipping and Logistics Consideration
The LNG shipping market is also experiencing some overbuilding in LNG carrier capacity. Some shippers have also suffered due to technology changes that substantially improved the fuel efficiency and reduced the operating costs of more modern ships, making older ships less competitive.
LNG carriers trended towards a 125,000 cubic meter standard in the 1980s. Later, economies of scale and newer technology gave rise to increased ship sizes of 160,000 to 180,000 cubic meters, with the newest generation of Qatari ships being 216,000 to 266,000 cubic meters.
The largest ships can carry around 6 billion cubic feet of gas or around 10% of U.S. daily gas production.
A new build LNG carrier might cost around $200 million to $250 million, which would typically require a charter rate of about $80,000 to $100,000 per day to support capital and operating costs.
Spot charter rates in the industry are currently only at around a third or a quarter of these levels, so ships without long-term charter arrangements are struggling to find economically viable short-term charters.
Also, LNG sellers are passing on cost/revenue pressures created by the gas oversupply to shippers. For example, charterers are now typically paying only for the loaded leg of a journey, perhaps augmented by a small fee or bonus for the return ballast (empty) leg of the trip.
The depressed shipping market does have some spin-offs for the gas/LNG development industry. Relatively new LNG carriers (even post 2000), which have a limited prospect of finding viable future long-term charters, are becoming available for conversion to other types of floating facility.
Conversion to a floating storage and regasification unit (FSRU) would be the easiest and quickest conversion to carry out. More recently and less frequently, ships have become a candidate for conversion to a floating liquefaction (FLNG) facility.
FLNG conversion usually requires more structural alteration of the hull, given the significant additional tonnage of equipment on the topside, but the advantages of an existing hull/cryogenic storage facility can represent a significant cost saving.
Countries may want to capitalize on short-to-medium term low-cost LNG to provide an initial gas stream for power projects. Governments could promote local market development using converted LNG carriers as floating storage and import terminals.
Later, as domestic markets develop and natural gas development projects are implemented, countries could replace or supplement LNG imports with indigenously-produced gas. Possible options include a variety of configurations with combinations of LNG storage, regasification, and/or ship-mounted power generation.
Some proposed configurations even include water desalination in a coordinated package. In light of these shipping market dynamics, engineering solutions for gas and LNG projects include a much wider spectrum of options than in the past.
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LNG Value Chain
The below graphic provides a depiction of the LNG value chain.
[chart 2]
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Domestic Gas Value Chain
The domestic gas value chain begins with production, and proceeds to processing and treatment. Processing and treatment remove impurities and petroleum liquids that can be sold separately where available in commercial quantities (for petrochemicals, cooking gas, and so on.) The gas can then be compressed into a pipeline for transmission, distribution, and sale to consumers. In many countries, the gas aggregator, which is in many cases the national gas company, markets the gas to customers and operates the infrastructure.
Many national governments mandate the allocation of gas to the domestic market as this allows the development of local industries, including use as a feedstock and as fuel for power generation. Small markets will take time to develop and for the initial years of market development the most likely customers for domestic gas are power plants and existing and planned large industries.
Hand in hand with the development of gas-fired generation, appropriate wholesale and retail market rules and institutions are a critical feature assisting in the formation of a viable domestic gas monetization plan. Unlike an LNG take-or-pay contract with one or several large customers, the integrity of the systems to collect bill payments from potentially thousands or millions of end-users in the domestic market can be a key challenge for credit risk management
The below diagram shows some of the domestic uses of natural gas.
[chart 3]
LNG Pricing
As opposed to crude oil, LNG does not feature a harmonized global price. In contracts, the price of LNG is segmented into regional markets:
LNG Reference Market Price
Price Indexation
Crude Oil Prices
Oil Indexed Price Formula
Spot and Short-Term Markets
Netback Pricing
Price Review or Price Re-openers
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LNG Reference Market Price – European Market
In Europe, this same trend was first established in the UK, following gas market deregulation in the mid-1990s, and the emergence of National Balancing Point (NBP) pricing, which, though similar to Henry Hub, is not a physical place.
In Continental Europe, the so-called Title Transfer Facility (TTF) has now become an equally dependable mechanism for long-term pricing, though Southern Europe is still transitioning to a mechanism of gason-gas pricing, as new hubs start to emerge.
LNG Reference Market Price – Asia Pacific Market
The first signs that a new pricing basis was emerging for the Asia-Pacific region occurred in the early 2010s with the signing of Henry Hub-based LNG tolling contracts. At the time, buying gas in the U.S. and paying a tolling fee to put it through one of the emerging LNG liquefaction facilities, represented a lower landed price in Japan and other SE Asian countries, compared to traditionally oil-priced gas.
A number of attempts are being made to establish a pricing index for the Asia-Pacific market, including the so-called JKM index (Japan-KoreaMarker) and also the Singapore Gas Exchange (SGX) spot price index known as SLiNG, which is intended to represent an exchange-traded futures market for LNG based on gas being traded at or around the Singapore LNG facilities. At the time of writing, no index exists that is considered sufficiently dependable for use on long-term contract pricing in Asia.
LNG Reference Market Price – North American Market
The historical rationale for gas reference pricing emerged from the development of a liquids wholesale market in the U.S., with exchange-traded futures contracts to support a pricing mechanism that was not vulnerable to undue influence from a single buyer or seller, and was derived from a transparent, market-based mechanism.
Historically, natural gas prices were fixed by the government, but in 1992, the Federal Energy Regulatory Commission (FERC) issued its Order 636. Prices were decontrolled and interstate natural gas pipeline companies were required to split-off any nonregulated merchant (sales) functions from their regulated transportation functions.
This unbundling of gas contract pricing and transportation contract pricing meant that exchange-traded gas contracts, based on Henry Hub and other secondary hubs, were established, and the industry moved to market-based indices for pricing purposes.
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Price Indexation
Natural gas may be sold indexed to the price of certain alternative fuels such as crude oil, coal and fuel oil. The natural gas feedstock prices into the LNG plants are sometimes indexed on the full revenue stream of the LNG plant including LPG and propane plus (other gas liquids), as in the case of the 2009 amendment of the NLNG contract in Nigeria. Such a pricing mechanism is markedly different from the one found in traded gas markets, where price is determined solely by gas demand and supply at market areas or “hubs.”
In the United Kingdom, around 60% of the gas is sold at the National Balancing Point (NBP) price and the rest at an oil index price based on old long-term contracts. The oil-indexed and hub-priced contracts co-exist.
On the European continent, the case is different. Oil-indexed contracts dominate, with hardly any hub-priced long-term contracts. The continental markets are mainly supplied on a long-term take-or-pay basis. However, a number of short-to-medium contracts do exist which are either fully or partially hub-priced.
Crude Oil Prices
Different crude oil prices are used for the oil index in LNG long-term contracts such as:
Oil Indexed Price Formula
Approximately 70% of world LNG trade is priced using a competing fuels index, generally based on crude oil or fuel oil, and referred to as “oil price indexation” or “oil-linked pricing."
In the Asia-Pacific region, LNG contracts are typically based on the historical linkage to JCC. This is due to the fact that at the time that LNG trade began, Japanese power generation was heavily dependent on oil so early LNG contracts were linked to JCC in order to negate the risk of price competition with oil. The formula used in most of the Asia LNG contracts that were developed in the late 1970s and early 1980s can be expressed by:
PLNG = α x Pcrude + β Where:
PLNG = price of LNG in U.S.$/mmBtu (U.S.$/GJ x 1.055) α = crude linkage slope
Pcrude = price of crude oil in U.S.$/barrel β = constant in U.S. $mmBtu (U.S.$GJ x 1.055)
Spot and Short-Term Markets
In recent years, LNG markets have seen the emergence of a growing spot and short-term LNG market, which generally includes spot contracts (for immediate delivery) and contracts of less than four years.
Short-term and spot trade allows divertible or uncommitted LNG to go to the highest value market in response to changing market conditions.
The short-term and spot market began to emerge in the late 1990s-early 2000s. The LNG spot and short-term market grew from virtually zero before 1990, to 1% in 1992, to 8% in 2002.
In 2006, nine countries were active spot LNG exporters and 13 countries were spot LNG importers. By the end of 2011, 21 countries were active spot LNG exporters and 25 countries were spot LNG importers
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Netback Pricing
The concept of "netback" pricing is particularly important for producing countries because netbacks allow the countries to understand the varying value of LNG in different destination markets.
Netbacks are calculated taking the net revenues from downstream sales of LNG/natural gas in the destination market, less all costs associated with bringing the commodity to market, including pipeline transportation at the destination, regasification, marine transport and, possibly liquefaction, and production, depending on the starting point of the netback.
There is no single formula for determining the netback price as it depends on specifics of the deal and is determined on a case-by-case basis, depending on the start and delivery point of the LNG sales contract and the particular destination market involved.
The starting point for calculating a netback price can be at the well, at the inlet to a liquefaction plant, or at the exit of the liquefaction plant. The delivery point of the LNG sales contract can be at the liquefaction facility (a free on board (FOB) sale, or a costs, insurance and freight (CIF sale)), or at the destination market (a delivered at terminal (DAT) sale, or a delivered at place (DAP) sale).
The terms DAT and DAP have replaced the term delivered-ex-ship
(DES), although some parties continue to use the DES reference term.
To determine costs in netback pricing, the following terms are relevant:
The calculation of marine transportation and regasification costs are specific to the ship and receiving terminal to be used.
Price Review or Price Re-openers
The trigger event or conditions entitling a party to invoke the clause must be defined. Usually, this is a change of circumstances beyond the control of the parties.
The elements of the price mechanism which are subject to review must be defined and usually include:
[chart 4]
If a requesting party has satisfied the trigger event or criterion, then there is the challenge of determining which benchmark should be applied to determine the revised price mechanism and often the buyer’s and seller’s view of the relevant market differ significantly.
If the parties cannot agree on a revised price mechanism, then the parties should consider referral of the matter to a third-party or arbitration.
However, many LNG contracts contain “meet and discuss” price review clauses that do not allow for such referral, leaving the parties without recourse unless some specific recourse is specified.
For example, the parties could provide that if the parties are unable to agree on the revised price mechanism, then the seller has the right, upon written notice, to terminate the long-term LNG SPA.
LNG and Gas Contracts
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Production Sharing Contract (PSC) v. Licenses
The way in which the upstream contractual arrangements are configured is a complex matter, the basics of which are summarized as follows.
The four contractual structures that have been adopted comprise:
Preliminary Agreements
The negotiation process for the LNG sale and purchase agreement (SPA) can often be quite lengthy and detailed. Some sort of preliminary document between the parties can include:
Domestic Gas Sales Agreements
The domestic Gas Sales Agreement (GSA) follows the typical pipeline gas sales agreement format, with the following key points:
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The LNG Sale and Purchase Agreement (SPA) is the keystone of the LNG project bridging the liquefaction plant to the receiving regasification terminal.
There is no worldwide accepted model contract for a SPA, with most major LNG sellers and LNG buyers having their own preferred form(s) of contract.
Most LNG SPAs have become lengthy and very detailed documents. However, the main points of an LNG SPA can be summarized below:
Term - LNG SPAs are long-term contracts with terms of 20-25 years. These long-term contracts were needed by both the seller and the buyer to justify the significant investments required by the liquefaction project and by the receiving terminal and the natural gas end-users.
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Miscellaneous Agreements
There are a number of other key agreements that might be necessary for an LNG project, depending on the structure selected. The following is a representative list:
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LNG Import Projects
LNG Technology
Virtually all operating large scale liquefaction facilities use liquefaction process technology developed by U.S. companies. The production of LNG from natural gas is based on three main processes: gas treating, dehydration, and liquefaction. Treating results in the removal of impurities from the raw gas and these comprise entrained particulate matter, moisture, mercury, and acid gases such as H2S and CO2. The chilling or liquefaction process is the conversion of the treated and dehydrated gas into liquid by refrigeration of the gas down to a temperature of about -162°C (240°F).
There are two main commercially available processes for liquefaction:
The most common liquefaction process currently used for land-based LNG plants is the APCI-C3MR. The feed natural gas stream is essentially precooled with a propane refrigerant and the liquefaction is completed with a mixed refrigerant which is a mix of nitrogen (N2), ethane (C2), methane (C1), and propane (C3).
The C3MR technology is well-known and has high efficiency, ease of operation and reliability, with the use of readily available refrigerant streams. However, the use of propane as a key refrigerant requires some risk mitigation. Propane is highly explosive, is heavier than air, and accumulates in low-lying areas - presenting an explosion risk if there is a leak. The hazardous properties of Propane drive some of the plant design by requiring that refrigerant storage tanks be located at some distance from the main processes.
LNG Technology has generally followed an evolutionary path rather than one of radical, rapid changes.
Over the last 30 years, the size of LNG plants has grown from 2 MTPA to as much as 7.8 MTPA (size of the large Qatar trains), with attendant economies of scale - though specialized equipment and materials and large required gas reserves for the 7.8 MTPA size make facilities of this size difficult to replicate.
The current standard size is about 5 MTPA. The size increase has resulted from the availability of large size gas turbines for refrigerant service.
The evolutionary approach has benefited the industry. The well-established LNG technology has given LNG EPC bidders the confidence to bid on a lump sum turnkey basis, increasing the execution certainty of the companies developing LNG plant projects.
Innovative technology continues to appear on this evolutionary track; the recent use of aero-derivative turbines in LNG plants is an example. Use of aero-derivative turbines reduces plant fuel consumption by about 10% and improves plant up-time by about 2% through avoidance of the longer maintenance cycles associated with frame industrial turbines.
Modularized LNG plants have been utilized in selective locations in recent years. They require earlier and more complete engineering during the EPC phase for the use of the fabrication yard in the module fabrication. Any delays in the engineering and procurement work can be very disruptive to the module fabrication work, so some additional execution risk is introduced.
Large modules can also be difficult to offload and transport.
Schedule Estimate
With the gas resources already defined, the estimated time for execution of an LNG export project could range from 6 - 10 years, assuming no interruptions. As expected, many unforeseen developments can occur during project implementation which can impact the schedule. Contingencies are normally factored into the indicated schedule range. Schedule discipline should be maintained throughout the project. Schedule recovery options should be identified to mitigate delays.
Change management must also be employed to minimize changes since any changes will impact the schedule and almost always add cost. It is important to optimize the engineering, procurement and construction schedules to minimize the number of critical path items for the project.
Delays in the overall project schedule result in liquidated damages for the contractor (giving the contractor incentive to complete the project on time). It is a requirement for the EPC contractor to develop a level 4 project schedule (Primavera) as a guide throughout the project.
The following chart depicts an example of a project schedule:
[chart 5]
LNG Project Development
Progressing an LNG project from inception to final investment decision (FID) requires three main work streams that run in parallel:
An LNG export project typically comprises the following developmental phases:
In each phase below, the project developer will work to provide increasing definition in the description and cost of the facilities, and the execution schedule with a goal of achieving a high definition of costs (+/- 10-15%) by the time of awarding the EPC contract.
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Project economics, calculated for each phase based on the latest cost estimates, schedule, and the LNG pricing outlook, would be a key factor in determining whether the project is economically viable to move on to the next phase.
FEED
After the in-house screening and evaluation and contractor led pre-FEED, which covers optimization of various plant equipment and configuration options, the basic scheme is selected for the FEED in order to provide better scope definition to the EPC contract bidders. The FEED process takes approximately 12-18 months to complete and results in a FEED package.
Two of the key outputs from the FEED are the cost estimate and schedule projection. Estimated FEED cost for an LNG plant can range from U.S. $40-80 million depending on size and complexity.
Company personnel required for the FEED are in the order of 20-30 full-time persons.
The better the definition of the project at the FEED stage, the better the definition for project cost and schedule.
LNG project cost estimates after the pre-FEED stage generally have a contingency (uncertainty in the estimate) in the order of 30-40%.
After the FEED, the contingency level is reduced to about 15-25%.
The EPC contract will generally have a contingency of about 10-15% to cover changes that result from gathering more information and doing progressively more design work.
EPC Contractor Bidding and Selection
EPC contract bidding for a greenfield project is almost always done on a competitive basis. The number of contractors that are experienced and qualified to carry out an LNG project is limited, on the order of 6 or 7 companies.
The number of qualified bidders is often further reduced by the practice of forming consortiums for bidding on the EPC work, which can reduce the number of separate bidding companies or groups to only 3 or 4.
Usually, one company acts as the lead for the consortium. Competitive bidding is highly important for obtaining a competitively-priced proposal.
One method employed to increase the competitive intensity is to utilize a competitive FEED approach, whereby two well-qualified bidding consortiums are selected to conduct separate FEEDs, with a commitment from each to submit lump sum bids as the price of admission to such a limited competitive bidding slate. Prior experiences with this bidding strategy indicate that it can potentially save 10-20% on the price of the EPC bid.
The bidders are typically provided a period of around 4-6 months to prepare and submit their bids after receipt of the company's FEED package. The EPC bidders submit their bids in 2 packages. Unpriced proposal or technical proposal - that describes in detail all important technical and project execution aspects of the bid, including major equipment specifications and performance sheets (e.g., for refrigerant gas turbines, refrigerant compressors, main cryogenic heat exchanger or cold boxes, fired heaters, waste heat recovery units, LNG storage tanks, LNG jetty and berth including LNG vapor recovery facilities at the berth).
The unpriced proposal bid also includes a complete detailed project execution plan, including a detailed EPC Schedule. The execution plan will address (1) the early site work; (2) the plan for the temporary facilities (construction camp, roads, construction material offloading facility (MOF), and site preparation); (3) the plan for site mobilization of construction personnel and the arrival of concrete batch plants, and the delivery schedule of the major equipment to the site and its installation.
The company evaluation of the unpriced proposal requires about 2 months. As part of the unpriced proposal, each bidder is required to provide a schedule guarantee and performance guarantees for LNG capacity and fuel consumption.
Priced proposals - Approved EPC bidders are then requested to submit priced proposals. These submittals include a lump sum price and an EPC completion schedule guarantee. Plant performance guarantees and the schedule completion guarantee are each backed by a schedule of liquidated damages (escalating penalties) in the event of nonperformance.
The Priced Proposals are evaluated and the price adjustments from the unpriced proposal evaluations are applied. The overall evaluation is then assessed, and a recommendation prepared for EPC contract award. This process may require going back to the EPC contractors for some final clarifications, but generally, this priced evaluation can be accomplished within 1 to 2 months.
The EPC award to the successful EPC contractor is not made until the other necessary conditions for the final investment decision (FID) have been achieved and the FID decision taken.
These other conditions include
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Final Investment Decision (FID)
The EPC contractor is required to provide a project execution plan (PEP), which shall include the detailed engineering specifications, the procurement plan; the construction plan; health, safety, and environment (HSE) plan; as well as quality assurance, project management, and project control aspects.
Engineering
The EPC contractor uses the FEED work as the starting point to carry out detailed engineering and design needed for construction, utilizing appropriate design specifications, material specifications, and construction specifications. In addition, detailed engineering requires the application of a safety-in-design process, a safety-in-review process (HAZID), and a hazardous operations plan (HAZOP).
Procurement
EPC contractors generally have fairly complete databases detailing cost and delivery schedules for major equipment that they have compiled prior to submitting their bids.
Consideration should be given to ordering materials and equipment in advance, where warranted, to maintain or improve schedules. Some major equipment, such as the refrigerant turbines, can generally be ordered in advance with a schedule of cancellation costs and charges. Engineering work and procurement work should be done in the same office to ensure full coordination.
Construction
This part of the EPC phase typically takes 4 to 6 years. It is performed at the plant site, except for those plants that are modularized or floating (i.e., have their main equipment placed inside modules that are fabricated in offsite fabrication yards such as those in Korea or China).
During the first 16 months, EPC contractor focus is on Engineering and Procurement in the contractor's home office. Meanwhile, initial mobilization on the plant site is focusing on site clearance and road construction.
After 16 to 20 months, the majority of project activities shift from the home office to the site. Approximately 5,000 to 8,000 workers may be required. Initial activities include:
With the availability of the construction camps, the mobilization of large numbers of workers can occur. Equipment delivery on site occurs between the 30th to 45th months. Then installation of equipment and running piping on pipe racks can begin.
Commissioning of plant equipment can begin between the 12th and 18th months before start-up. The first major equipment to be commissioned and started up is the power generation system.
After the plant is mechanically complete, and after equipment commissioning is completed, the plant is ready for the introduction of the natural gas feedstock. Start-up can range from two to as long as six months or more if there are problems. Typically, it takes about six months for the plant to ramp up to its full capacity.
After the plant is operating at full capacity and operations are stable, the plant performance and acceptance tests are conducted by the company jointly with the contractor. Plant LNG capacity is measured by a plant performance test conducted within a specified time after startup (typically on the order of 6 months).
Any deficiencies found that are covered under the guarantee provided by the contractor, must be corrected by the contractor before the company accepts the plant as complete and final payment is released.
Import Commercial Structuring
Project structuring is a critical element of a successful LNG import project. Given the magnitude of the required capital investment and the length of the period of commercial operations, the risks associated with each import project and the functions for the project participants need to be carefully defined and allocated in order to allow debt to be paid off and to generate sufficient returns for investors.
Structuring an import project correctly from its inception is important in order to anticipate project risks over time, to avoid misalignments between stakeholders, and other risks to the project's success.
The structure chosen for each LNG import project will have ramifications for the allocation of the project's risks and the roles of the various project participants. It will also have an impact on whether the project is able to attract further equity investors, if needed, and raise debt funding from financiers. The structure can impact project agreement pricing and financing costs because the allocation of risk generally involves a rate-of-return or pricing tradeoff.
Choosing a Commercial Structure
As with LNG export projects, three basic forms of commercial structures have emerged for LNG import projects - tolling, merchant and integrated. There are hybrid variations of these three models and the potential exists for further changes in the future, but these three structures are the basic prevailing structures currently being used for LNG import projects.
Tolling Commercial Structure
The user or users of the LNG import terminal are different entities than the owner of the LNG import terminal. The LNG terminal company need not buy LNG or sell natural gas, but rather provides regasification services (without taking title to the natural gas or LNG) under one or more long-term terminal use agreements. The LNG terminal company revenues are derived from tariff payments paid to the LNG terminal company by the terminal users.
The payments typically take the form of a two-part tariff:
The following chart shows the Colling Commercial Structure
[chart 6]
Merchant Commercial Structure
The LNG supplier and the natural gas marketing or distribution company are different entities than the owner of the LNG import terminal. The LNG import project company purchases LNG from the LNG supplier under a long-term LNG sale and purchase agreement, and sells re-gasified LNG to the natural gas marketing or distribution company, or directly to a power station, under a long-term natural gas sale and purchase agreement. The LNG import project revenues are derived from the amount by which the revenues from natural gas sales exceed the sum of the cost of regasification (including debt service) and LNG procurement costs. Because the LNG supplier is a different entity than the owner of the LNG import project, there may be more than one supplier of LNG to the LNG import project company, and because the natural gas marketing or distribution company is a different entity than the owner of the LNG import terminal, there may be more than one purchaser of natural gas from the LNG import project company.
India's Petronet Dahej and Kochi LNG import projects, and Shell's Hazira LNG import project in India. The merchant commercial structure for LNG import projects is illustrated in the diagram below.
The following chart shows the Merchant Commercial Structure
[chart 7]
Integrated Commercial Structure ("Merchant +")
The project development for this structure is the same as under the Merchant Structure, except that the terminal is owned by an entity that undertakes a wider role in the LNG chain; e.g. a power plant (TEPCO) or a gas distribution company (Tokyo Gas) or the LNG export company (eg. RasGas for the Adriatic LNG Terminal).
The ultimate commodity sold may be the product of the company; thus gas, power or steel, as in the case of Tokyo Gas, TEPCO or Pohang Iron and Steel Company (Posco), respectively. As with the development under the
Merchant Structure, a FEED package is developed, sent out for bid, and an EPC contract award is made to the successful bidder after all commercial agreements and permits are in place and a FID has been taken.
The owner of the LNG import facilities is also either the LNG supplier or the natural gas marketing or distribution company (or perhaps a power producer).
The project revenues for both commercial functions are integrated into one entity such that there is no need for an LNG SPA for delivery at the terminal with respect to integrated structures that combine the LNG supply and import terminal functions.
There is no need for a natural gas sale and purchase agreement for delivery at the tailgate of the terminal with respect to integrated structures that combine the import terminal and natural gas marketing or distribution functions (and perhaps the associated power producer function). There is typically no other user of the LNG import terminal.
Examples of the integrated commercial structure for LNG import projects are reflected in the diagrams below.
Upstream integrated structure:??????????????????????????????Downstream integrated structure:
[chart 8]????????????????????????????????????????????????????????????????????[chart 9]
Hybrid Structures
Hybrid structures combining some of the attributes of tolling, merchant, and integrated models may be used to tailor LNG import
projects to the characteristics and needs of particular host governments and project participants.
For example, hybrid merchant-tolling structures may be used to allow the LNG import project company to take title to the LNG and sell natural gas, but receive fixed monthly reservation charges regardless of whether their customers utilize regasification services and actually import LNG.
Driving Factors in Choice of Structure
There are a number of key driving factors that influence the choice of an LNG import project structure for the host government, the investors, the natural gas buyer(s), the project lenders and the other project stakeholders:
Legal regime and taxes: The host country legal regime and local taxes often have a major impact on project structure. regime. The tax rates may differ for LNG importing, terminal operation, and natural gas marketing and distribution.
Governance: A poorly governed structure in any of the LNG supply, terminal ownership and operation, or natural gas distribution components of the LNG import chain can lead to conflicts among the parties and impact the efficiency and reliability of the LNG import project.
Efficient use of project facilities: The LNG import project structure should encourage efficient use of all project facilities and activities by the project owners and by third parties. In determining the optimal project structure for LNG imports, consideration should be given to the costs and benefits of sharing common facilities, open access to third parties for spare capacity, and reduction of unnecessary facilities and their related costs.
Flexibility in Ownership: Some of the participants in the commodity chain may not be interested in owning an interest in the LNG terminal company. The choice of a particular structure can enable different levels of ownership in companies performing different components of the LNG import chain.
Desire for Limited Recourse Financing: Utilizing an LNG import project tolling structure should facilitate project financing by shifting commodity merchant functions and risks away from the terminal company.
Operational Efficiencies: The integrated structure offers operational efficiencies because only one operator is involved in construction, operating and scheduling activities. The operational inefficiencies of having two operators may be overcome through transparency and coordination between the operators.
Regulations: The choice of project structure will affect the required regulations.
LNG and Gas transfer prices: The LNG transfer price is the price of LNG sold by the LNG supplier or suppliers to the terminal company in a merchant structure. The natural gas transfer price is the price of natural gas sold by the terminal company to the natural gas buyer or buyers in a merchant structure. These are often contentious commercial points. In addition, each segment of the gas value chain may fall under a different tax regime such that the prices may need to comply with an arm’s length standard to comply with tax transfer pricing laws and regulations.
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Commercial Agreements
LNG import projects require different types of contracts at different stages in the LNG import value chain.
LNG Sale and Purchase Agreement (SPA)
An LNG SPA will not be needed in the integrated LNG import commercial structure, which includes the upstream and/or liquefaction developer, or in an integrated tolling LNG import commercial structure. In these structures, the user of the LNG import project already has title to LNG. In the merchant LNG import commercial structure, or the integrated LNG import commercial structure, which includes the downstream user of the LNG, an LNG SPA is required by the project company.
Facilities Use Agreement
An agreement is needed between the user of the terminal and the terminal project company for the use of the terminal. The key terms to focus on are: the nature and quantity of services to be used; how services can be performed for other customers and what happens in the event of a conflict between customers; the terminal fees and charges for the services ; fuel and lost or unaccounted-for gas; scheduling for LNG receipts; term; LNG vessel requirements, berthing and unloading details; receipt and storage of LNG and redelivery of re-gasified LNG; invoicing and payment; liabilities; taxes; insurance; and curtailment of services.
Operations and Maintenance (O&M) Agreement
The terminal owner may elect to engage a third party to actually operate and maintain the terminal. The Operations and Maintenance Agreement (O&M) should include: the services and scope of the services to be provided; the standard of performance; the term of the agreement; the responsibilities and liabilities of the operator and the terminal owner; budgets and necessary costs; payments and incentives to the operator; employees, including local employees, and services, including local services, to be used by operator; rights to suspend and terminate early; and owner's rights to monitor and inspect.
Natural Gas Sales Agreement (GSA)
The key terms to focus on are: the commitment of the buyer to purchase natural gas and whether there is a take-or-pay obligation; price and payment terms; ability of the buyer to withhold payment or dispute invoices; what constitutes force majeure for the buyer; liability for natural gas that is off-specification; and the LNG import project's liability for delivery shortfalls.
A GSA is not needed in the integrated LNG import commercial structure, which includes the downstream user of the LNG because the LNG import terminal user is using, instead of selling, the natural gas.
Port Use Agreement
LNG import terminals often fall under the jurisdiction of a particular port and are subject to the port's port use agreement. Where the terminal is considered its own port, the terminal will adopt its own port use agreement. The port use agreement is a set of rules and requirements applicable to all vessels using the port and address a variety of operational and other topics, including responsibility for damages and other liabilities. The LNG import terminal is then responsible for ensuring that each LNG vessel calling at the terminal agrees to comply with the port use agreement.
Power Purchase Agreement
An LNG import project will be bundled with a power generation option. In such situations, the output of the LNG import project may include electricity. In these situations, a Power Purchase Agreement will be required. To better understand Power Purchase Agreements, please refer to publication Understanding Power Purchase Agreements at the following link:
https://cldp.doc.gov/sites/default/files/Understanding_Power_Purchase _Agre ements.pdf
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Financing Import Terminals and FSRUs
Onshore LNG import terminals can be financed in a similar manner to liquefaction facilities, typically on a project finance basis. The main difference between land-based regasification terminals and liquefaction facilities is one of scale and cost.
Liquefaction facilities cost multiples of billions of dollars, while land-based regasification terminals typically cost to the order of $500 million or more, depending on their regasification capacity, the amount of storage included, and the associated infrastructure that is needed. FSRUs are gaining ground over land-based terminals because they cost less to build.
For onshore import terminals, project finance structures are often used and the lenders to the project generally come from the same sectors that appear on liquefaction projects. The project company may raise the financing from international commercial banks, local banks, development banks, and export credit agencies, etc.
Given that LNG import facilities will earn money in local currency, they will be more likely to attract domestic bank participation, if they are sufficiently liquid.
For import terminals, funding risk will still be mitigated via the use of long-term contracts, but, in this case, the LNG that comes into the receiving terminal will be sold as gas to power operations and other end-users. Similar due diligence procedures and financing processes will apply.
FSRU Financing
For FSRUs, different financing considerations apply because they are typically chartered to the importing entity from a shipping company and the shipping company will raise the financing. This has the advantage of reducing upfront project expenditure. The project company will, however, have to take a view on whether the life of the charter would make a fixed import terminal more cost effective.
When the first FSRUs started up in 2005, there was a pain barrier to go through as lenders had to assess the technology risk, which was not new, per se, but compressed into a smaller space and floating. But the industry now has a good track record and financiers see FSRUs as secure earners because they are usually on long-term or medium-term charters that allow for debt servicing across long-term repayment profiles.
While there are only a small number of companies that offer FSRU units for charter – which currently include Excelerate Energy, Golar LNG, Hoegh LNG, Exmar, BW Gas and MOL (and Gazprom which had one unit on order in 2016), others are looking to break into the sector.
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Financing LNG-to-Power
The LNG-to-power sector, where LNG import projects are typically based on FSRUs coupled with power generation facilities, is creating considerable interest. Independent power projects have a long history of successfully attracting funds using project finance structures. This implies that off-take is guaranteed by the government, a government entity or a creditworthy utility and their steady earnings over long periods – power purchase agreements can span out beyond 20 years – allowing for debt servicing over long payback horizons.
This approach can be applied to LNG-to-power, although given the extra components, a number of structures could be used. A single project entity could develop the power and gas operations and raise funding as one entity.
Separate project entities could develop the power and gas facilities, and the gas could be bought from the LNG providers and re-gasified via a tolling contract. Funds could be raised separately or as a single financing with the gas and power entities both taking the borrowers’ role. In a third possibility, gas is sold directly to the power company and the financing is raised by each entity separately.
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New and Emerging LNG/CNG Markets
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LNG by Truck / LNG by Rail
A number of concepts have emerged in recent years relating to the shipment of LNG either by rail or road tanker to supply remote centers of demand, particularly in instances where local transmission and distribution pipelines are impractical or too time-consuming to complete.
One of the better-known applications of LNG by rail is Japan’s JAPEX LNG Satellite System, which transports LNG by rail and tank trucks to reach gas consumers in regions not served by a gas pipeline network. One of the industry’s first, JAPEX has been using rail to supply imported LNG since 2000 and by tank trucks since 1984.
A trial program in Alaska, which started in 2016, is the first example of LNG by rail in the U.S. It involves moving rail-mounted standard ISO containers, each carrying 12,500kg (625 MMBtu) of LNG. The program is designed to enable Fairbanks, which is in Central Alaska near Anchorage, some 300 miles away, to benefit from LNG derived from local gas production.
Small-Scale LNG
Although LNG has historically been transported in bulk, typically in gas carriers of more than 100,000 cubic meters, there are a number of emerging applications which involve much smaller quantities of LNG, both in respect of production and demand. Anti-flaring regulations, as well as more practical and efficient smaller-scale technologies, have meant that small-scale LNG solutions are now widely available.
China is the largest market where widespread small-scale LNG applications have found success, with over 500 LNG filling stations for trucks and buses and a widespread fleet of LNG-powered ferries and other marine applications. The source of LNG in China is typically smaller liquefaction plants built on the gas transmission system, rather than directly supplied by coastal LNG import terminals.
There are over 60 such small-scale liquefaction plants in China, producing approximately 20MTPA of LNG in total, which is the equivalent of more than one large LNG liquefaction facility. In this way, although development has been gradual, incremental small scale modular development could eventually create sufficient gas demand to underpin one or more of the major gas discoveries currently under evaluation.
Emerging LNG Marine Transportation Options
For most of the 50 years since the establishment of transoceanic LNG transportation, the size of gas carriers has grown from the 25,000 cubic meters that applied to the first commercial LNG exports from Algeria, through to 260,000 cubic meters which reflect the latest Q-max LNG carriers used to transport LNG from Ras Laffan.
Small-scale LNG carriers, which are similar in size to the 25,000 cubic meter ships used in the 1960s in the early days of LNG, are also becoming popular for the purposes of reloading LNG from regasification terminals, or for smaller offtake volumes from LNG liquefaction terminals.
The availability of these modularized bunker/coastal LNG barges and smaller scale conventional LNG carriers significantly improves the opportunity to develop niche markets, such as coastal power stations or floating power barges, and road tanker operations.
Peaking and Storage
As gas markets develop, gas supply will need to be available to meet the peak demand in the gas distribution system. In this mode, companies will need to have the ability to take natural gas from storage or off the gas distribution network. Peak-shaving LNG facilities liquefy and store natural gas when supply exceeds demand in the pipeline network for eventual regasification during peak demand periods. The storage tank volumes in these facilities can be very large, capable of storing 1.0 to 2.0 BCF of natural gas.
Most well-developed gas transmission infrastructure, such as in North America and Europe, has some degree of LNG-based peak shaving to address relatively shortterm changes in gas demand, often as a result of hot or cool weather, in addition to seasonal storage applications which typically do not involve LNG facilities. LNG may also be transported by truck to nearby power stations that have small regas modules. The array of LNG peak-shaving facilities within the natural gas distribution network may result in other forms of LNG application, including vehicular usage.
Mid-Scale Virtual Pipeline Projects
Much of the population in less-developed countries lives in the countryside in small communities, and connecting these communities in the traditional way using transmission pipelines would be too expensive.
The virtual pipeline, filled either by compressed natural gas (CNG) or small-scale LNG, can be the solution to bring natural gas to these communities, through the installation of small Autonomous Gas Units (GAU).
CNG is a low-cost alternative for the transport of small to average gas volumes over moderate distances (+/-2000 km) where the volumes are too small for LNG or too far to transport by pipeline. The gas is compressed to around 250 bar and can be transported to small villages or used to supply natural gas for local vehicles.
CNG is compressed into mobile tube trailers for onward delivery to customer locations, and the facility also has dispensing points for filling Natural Gas Vehicles (NGV) utilizing CNG as a primary or alternate fuel.
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SPA, Negotiation, Commercial Risks
The following diagram depicts the relationships between the project sponsors and the financiers and the cash flows:
[chart 10]
Debt to equity ratio: As a result of the large cost of LNG projects, they are typically highly leveraged. A target of 70:30 debt to equity ratio is the norm. Limited recourse to project sponsors: LNG project finance is essentially based on “limited recourse” finance, which means that the loan is given to a Special Purpose Vehicle (SPV) instead of the project sponsors. As a result, lenders rather than sponsors assume the lion's share of risk associated with the project.
Public-Private Partnerships (PPP) in higher-risk countries: LNG projects always require government support, this is for political reasons, risk mitigation, regulatory framework matters, interactions with communities, and contract stability and enforcement. Often the government (national or regional) is a shareholder in the project.
Special Purpose Vehicle: In order to successfully implement a project finance transaction, project sponsors typically establish a special purpose vehicle (SPV) that allows banks, export credit agencies (ECAs) and other entities to lend money directly to the project company instead of to the individual project sponsors.
Offshore ventures: In some instances, the project developers also create an offshore account that will receive cash inflows from lenders, equity from shareholders, and LNG sales revenues. Debt will be serviced from this offshore account.
Loan tenor/payback period: Debt is provided by a syndicate of lenders. The tenor terms are based on a debt service coverage ratio which can be determined using financial models. The loans are priced at a margin applied above the base rate, which is often the London interbank offered rate.
Long-term sales-and-purchase agreements: Firm long-term agreements among LNG exporters and importers are generally required for up to 80% of the project's capacity. They typically cover contract periods of about 15 to 25 years, thus exceeding the anticipated loan payback period - normally in the range of 7 to 15 years.
Inputs from ECAs and MDBs: The lengthy and thorough due diligence process involved in a project finance transaction, is well suited to ECA and MDB involvement. Since the mid-1990s, MDBs and ECAs have played a growing role in structuring LNG projects. They can finance them through direct loans, political risk coverage or loan guarantees.
Risk mitigation: A key advantage of project finance is that it allows developers to mitigate the risks associated with politically or economically unstable environments. Such projects face a risk of expropriation, political turmoil, labor strikes, land rights issues, and other unforeseen disruptions. Debt recovery and default rates: Experience has proven that the use of project finance for liquefaction projects has resulted in remarkably low default levels.
Project financing can have its drawbacks. Because banks lend to a project company, with limited recourse to the actual project sponsors, the due diligence requirements take time and money. While these drawbacks are significant, liquefaction project sponsors have historically found project finance advantages outweigh its drawbacks.
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Available Funding Sources
LNG projects raise funding from a variety of private and public funding sources.
International commercial banks: Commercial banks have historically been the main providers of funding to liquefaction projects. As projects grew in size due to the need for economies of scale, and thus became more expensive to construct, banks were unable to provide all of the debt required.
Domestic banks: Domestic banks can be a lot smaller than the international commercial banks which appear frequently on global LNG project finance transactions. They may also have limited access to dollars. However, in some project finance transactions, a separate tranche of loans can be provided in the local currency to allow local lenders to supply funding to the project.
?Islamic banks: These banks are governed by Shari'a law and can also provide funding to LNG projects. The Islamic bank funding would be in a separate tranche, which would have its own Shari'a compliant structure.?These funds would still sit within the debt side of the project financing structure. Islamic banks are mostly, but not exclusively, tapped for funding in countries where common law is Shari'a-based. Export credit agencies (ECAs): Export credit agencies became important providers of funding as liquefaction projects grew in size and cost and more sources of funding were required. But after the global financial crisis that affected international commercial banks, they took on an even greater role.
Development Banks: Some development banks come in early to structure projects - such as the IFC, regional development banks or the EIB. Their roles can include equity participation, due diligence, benchmarking against international best practices, lending and syndication, as well as offering risk coverage guarantees.
The World Bank Group negative pledge clause: When providing loans for infrastructure development projects, instead of taking a lien over the state’s assets, the World Bank protects its interests via a broadly-worded negative pledge clause.
Sponsor co-loans: These can be tapped for large projects where the funding needs are considerable. Sponsors, in this case, act as debt providers and receive a margin payment for their loans in the same manner as banks. They typically rank pari passu, on equal footing, with the other debt providers.
Other providers, debt, and equity: Projects can also raise financing via other means. They can issue bonds, which can sit within the debt side of the project finance structure and rank on an equal footing with other lenders in terms of payback. However, bond investors do not relish construction risk exposure, so bonds are often offered post-construction and are mostly used to refinance bank debt.
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Risk Management and LNG Business
Managing risk is important for each organization involved in an LNG project to understand. The host government, local community, project developer, EPC contractor, upstream developer, LNG buyer and financier(s) all have risks they need to understand, manage and mitigate. Risks are generally not eliminated by the decisions that are made, but rather are shared between these institutions.
LNG Investment and Risk: Key risk models recognize the intricacies of LNG investment and will also consider risks. In today's changing price environment, hedging and managing long-term price risk has become a more complex and challenging part of project implementation.
LNG Risk Structure: The primary goals for corporations investing in LNG are to cost-effectively build, or expand, LNG trains, improve export or import capacity, provide least-cost environmentally and technically sound LNG facilities that generate an economically-viable product streams (LNG, LPG , condensate) for maximum investor return.
LNG Risk Management Methodologies: Methods and tools for portfolio and risk management are locally defined to deliver increased capital efficiency and greater resistance against strategic, operational and market risks. This stage avoids disputes through a proactive and comprehensive framework for managing risks and claims. Risk review supports the project stakeholders' need to understand their tolerance of risk in terms of safety, environmental, financial, reputation, and performance risk in order that risk limits can be appropriately defined and decision-making processes informed.
Types of Risk in LNG (LNG risk register)
Example of a Risk Matrix
[chart 11]
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References
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THANK YOU
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Marcial Ocampo
Energy and Power Technology Selection Expert
And
Project Finance Modeling Expert
OMT ENERGY ENTERPRISES