STRATEGIC EVALUATION CENTRAL TO LNG PROJECT FORMATION

July 3, 1995
David Nissen , Poten & Partners Inc., New York Robert N. DiNapoli , Merlin Associates, Atlanta C.C. Yost , Merlin Associates, Houston

David Nissen,
Poten & Partners Inc.,
New York


Robert N. DiNapoli,
Merlin Associates,
Atlanta


C.C. Yost,
Merlin Associates,
Houston

An efficient-scale, grassroots LNG facility of about 6 million metric tons/year capacity requires a prestart-up outlay of $5 billion or more for the supply facilities - production, feedgas pipeline, liquefaction, and shipping. The demand side of the LNG chain requires a similar outlay, counting the import-regasification terminal and a combination of 5 gigawatts or more of electric power generation or the equivalent in city gas and industrial gas-using facilities.

LNG differs from crude oil and oil products in scale and frontloading of projects, the relatively large cost of transportation and terminalling, and the relatively small magnitude of trade. As a consequence, there exist no well-developed commodity markets for free-on-board (fob) or delivered LNG. A new LNG supply project is dedicated to its buyers. Indeed, the buyers' revenue commitment is the project's only bankable asset, the facilities and reserves being essentially worthless without an assured market. Symmetrically, an LNG buyer, especially in isolated Asian gas and electricity markets, must dedicate import and end-user facilities and service commitments to the specific LNG supply project.

For the buyer to make this commitment, the supply venture's capability and commitment must be credible: to complete the project and to deliver the LNG reliably over the 20+ years required to recover capital committed on both sides. This requirement has technical, economic, and business dimensions.

On the technical and economic sides, adequate quantity and deliverability of the resource and reliable, cost-effective facilities design must be demonstrated. Because of the magnitude and duration of the commitment, the cost and effort required go well beyond those of a typical oil project.

BUSINESS STRUCTURE

Perhaps even more important is the business structure of the project. This has two parts: first, a supply venture to own and form the project, and, second, the project as a whole, comprising the key participants and commitments.

The supply venture must include energy company sponsors with the requisite project management, LNG technology, and marketing capabilities, in addition to suitable resources. But there is more. An LNG project is of national significance to both exporting and importing countries for its strategic role in their energy systems as well as its procurement and revenue consequences.

A successful LNG supply venture typically involves both host and buyer country representation to facilitate the negotiation of the terms of LNG sale and purchase agreement (SPA) and host country sovereign terms; to coordinate procurement, lending, project management, and operations; and to provide a long-term alignment of interests.

PROJECT FORMATION

The supply venture must then form a consistent set of commitments between the key project participants: the venture, the engineering-procurement-construction (EPC) contractors, shipowners, lenders, buyers, and the host and buyer countries, whose support for the sale and purchase contract, sovereign terms, and financing is critical.

A successful LNG project can be considered as two complementary chains: a physical chain of jointly designed and optimized facilities delivering the resource to the end-user, and a chain of business ventures with interlocking operating commitments, jointly determined revenue allocation or transfer pricing, and jointly contingent financing.

An LNG trade is inherently international, moving remote, low-value gas to a high-value market and almost inevitably crossing borders. No single sovereign or regulatory authority can enforce cost recovery through the chain. As a consequence, each business segment in the chain, with its financing and its operating and revenue entitlements and obligations, must be a viable business entity.

The formation of these complementary chains is an expensive and lengthy process. Expenditures of several hundred million dollars may be required over several years to delineate the resource; specify upstream, liquefaction, and shipping facility designs; and negotiate key agreements. The key agreements that form the project comprise the supply venture structure together with agreed sovereign terms, the principal EPC contracts, acquisition of ships or transportation, the LNG SPA, and financing for each segment.

Once these agreements are in place, however, the "business" is largely over. What remains are 4-5 years of construction and 20+ years of operation of the project.

Throughout the formation process the prospective project participants are continually evaluating the prospects and alternatives for the project as a whole and for their participation in it. This requires an integrated understanding of the design, cost, market, financial, and fiscal structures of the project. Since analyses of aspects of the project are highly detailed, it is easy in this process to lose the forest for the trees. This is a great danger since informed commitment by all the key parties is essential to LNG project success.

Merlin Associates and Poten & Partners Inc. have collaborated for several years in developing a system for strategic evaluation of LNG Projects. This includes 1) assessment of project costs based on explicit design and empirical engineering cost data, and 2) assessment of project economics based on a cost-of-service (COS) evaluation incorporating detailed specification of the time structure of outlays, revenues, and sovereign payments as represented in standard corporate capital budgeting project evaluation methods.

In this article we describe this LNG project evaluation system and show its application to typical tasks:

  • Project cost of service and participant shares.
  • LNG Project competition.
  • Alternative project structures.
  • Market competition for LNG-supplied electric power generation.

LNG PROJECT COSTS

An assessment of total project costs requires review of facility requirements, capital cost estimating methodology, and operating costs.

FACILITY REQUIREMENTS

The facility capital cost estimates must reflect, to the maximum extent possible, all known physical requirements of the project.

Key project-specific and site-specific factors which influence capital investment, and which should be identified to the limits of available data, include location of gas fields (on or offshore), maximum recoverable reserves and expected reservoir fluid production qualities, recoverable condensate production, construction labor sourcing and procurement philosophy, harbor and marine requirements, and the extent of temporary and permanent support infrastructure needed. A realistic appraisal of these factors is particularly important for a comparative economic analysis where differences in project/site-specific factors can possibly compensate for more obvious differences in project capacity or shipping distance.

Forward capital investment must also be estimated to account for known expenditures made during the operating life of the project to maintain contractual production rates. Expenditures of this type most often involve additional production facilities and drilling additional gas wells to maintain feedgas production as deliverability declines with time. The estimate also covers expenditures for facility optimization and major maintenance replacements.

For an economic comparison of alternative LNG supply sources, the economic analysis (COS) is conveniently done on an ex-ship basis for LNG delivered to alternative import markets. Physical elements of the supply chain included in the analysis are: gas production, pipeline transmission, gas liquefaction, storage and loading, and LNG shipping.

  • Gas production and transmission.

Facility requirements include drilling, production and gas recovery, and related wellhead gas treating. For offshore production these facilities are installed on one or more platforms at significantly higher costs than for onshore systems. Gas and any associated condensate are transported from the production site to the LNG plant via one or more dedicated pipelines.

For LNG projects with a reasonable chance of development over the near term, the scope and design of gas production and pipeline supply facilities should not differ greatly from similar facilities in use for large gas supply projects. Exceptions may be the Natuna project, where the bulk of the CO2 that makes up 70% of the reservoir gas must be removed and reinjected offshore, and the Alaska North Slope and Sakhalin Island projects requiring pipelines to move the feed gas from the arctic production site to an ice-free, export liquefaction plant location.

  • Liquefaction plants.

The liquefaction plant cost estimates are based on liquefaction trains with capacities on the scale of 3 million tons/year using the well-proven Air Products & Chemical Inc. propane-precooled, mixed refrigerant (C3-MR) process. Gas turbines are assumed as drivers for all refrigerant compressors and electric power generators. All utility and process support systems and plant buildings required for a totally green-field installation are included.

Storage and loading facilities are provided for LNG product and any recovered gas liquids. Harbor and mooring facilities are provided for handling 125,000-135,000 cu m capacity LNG carriers. Other marine facilities provided include a construction/small-boat harbor to receive equipment and materials and related ship-handling services such as tug boats and navigational aids.

Estimates of LNG plant costs also include allowances for a temporary construction camp and related infrastructure for on-site housing of the construction labor force and permanent housing and related community support facilities for the permanent plant operating personnel.

  • LNG shipping.

The analysis assumes the use of 125,000 cu rn capacity ships. Future use of ships of up to 165,000 cu m capacity may reduce shipping costs, particularly for long voyages or large-volume trades. No LNG ships larger than 137,500 cu rn capacity, however, have been built to date.

COST ESTIMATING METHODOLOGY

Capital cost estimates for the gas production and liquefaction segments of the delivery chain are developed from Merlin Associates' extensive database of actual costs of most of the recent base-load LNG projects. The database comprises a comprehensive listing of all major plant equipment, a breakdown of bulk material items in terms of piping, electrical, instrumentation, etc.; major supply-and-erect subcontracts for such items as storage tanks, loading jetty, buildings, etc.; and field labor requirements for erection of all plant equipment. It allows realistic cost estimates of new projects to be developed depending on the level of project detail available and completeness of the known facility basis of design.

For situations where full project design detail is available, a PC-based, generic LNG costing model allows direct adjustment of the U.S. Gulf of Mexico model costing basis to actual site-specific conditions with a high degree of accuracy (on the order of 10%).1

Comparative project analysis, such as the analysis described in this article, however, involves multiple projects, and the estimates are developed at a point in time when design detail is not fully available. Under these circumstances, historical database costs are used to develop a lower quality, engineering-factor type of estimate for a more generalized basis of design considering project trade volume, facility processing requirements, and site-specific factors. A detailed plant equipment list is generated for the assumed basis of design from which estimates of bulk materials supply-and-erect subcontracts, and construction labor requirements are developed with appropriate adjustments for site-specific labor man-hour rates and productivities.

The current Merlin costing methodology represents a significant improvement over cost data we published in the 1970s and 1980s. 3 4 5 The earlier data provided a means for estimating LNG project capital costs and project economics based on technology and cost data appropriate for the time period. The limited extent and level of cost detail available at the time, however, necessitated use of a more generalized and lower quality estimating methodology.

LNG project facility costs are stated in unescalated, Jan. 1, 1995, U.S. dollars consistent with standard engineering-based cost-estimating methodology. The costs represent "quoted" costs for equipment, materials, and services on the specified order day (Jan. 1, 1995) with payment and delivery under a normal order schedule. Commitments for equipment, materials, and services are in fact made throughout the entire construction period, so that the commitment profile must be escalated to yield costs in money of the day. Further, the expenditure profile for escalated outlays is developed to evaluate finance during construction.

Estimates of capital costs for new LNG ships are obtained from published shipyard quotes for recent new buildings of 125,000 cu m capacity ships. The number of ships required for a given trade is calculated assuming typical, existing, ship-operating parameters.

OPERATING COSTS

Annual operating costs for the gas production, pipeline delivery, and liquefaction segments of the supply chain are based on fixed percentages of the installed facility investments. The percentages are based on estimates of site-specific facility staff and pay rates, maintenance needs, and related administration and support staff costs derived from similar gas supply and LNG projects currently in operation. Where appropriate, adjustments are made to account for local labor conditions and government hiring policies.

Ship-operating costs are based on steam turbine propulsion burning boil-off vapors, supplemented with bunker fuel. Annual operating costs account for port charges, canal tolling charges where appropriate, administration and crew costs, maintenance and stores, and hull insurance.

LNG PROJECT COS

Comparisons of LNG projects with other energy supplies, and evaluations of project competition and alternative project structures, require a summary measure representing project cost and financial and fiscal requirements.

COS

The COS of a project is defined as the levelized minimum unit-output revenue or minimum price required to provide for capital recovery, cover operating and forward capital costs, and pay the sovereign take (taxes, royalties, and production sharing). Our approach accommodates a very general treatment of revenue and expenditure profiles and escalation and a very general treatment of sovereign take. It is structured to be consistent with any generally accepted, corporate capital-budgeting, project-evaluation methodology.

SEGMENT ANALYSIS

Our analysis is typically applied to the LNG (or gas pipeline) chain." In calculating the COS for each segment, the key question is how to treat the required return, since segments will have different debt structures and equity participation. For project evaluation for a sponsor, we adopt the sponsor's capital-budgeting methodology.

For competitive analysis we proceed consistently with the basic principles of corporate finance. Financially, an LNG project is a claim on a stream of revenues, generally prices, together with a commitment to a stream of outlays. The outlays are front-loaded or predictable, and start-up capital requirements are largely locked in through near fixed-price EPC and ship-procurement contracts prior to commitment. Since the assets in the chain are totally dedicated to the buyers, the correct rate of return for discounting free cash flow for the chain assets as a whole is significantly determined by the credit-worthiness and market variability of the buyers' revenue commitments.

Debt and debt service commitments anywhere in the chain "leverage" the returns to equity elsewhere in the chain as determined by the transfer pricing or revenue sharing specified in the chain business structure. We specify a required return for the whole-chain

assets and model the leverage effect of debt finance in the chain on each segment's required return and sovereign take obligation.

ANALYSES

Following are four examples of the analyses provided by our system.

PROJECT STAKEHOLDER ANALYSIS

Fig. 1 (45884 bytes) shows the breakout of COS by segment, and the allocation of the COS to capital recovery, operating and forward capital cost, sovereign take, and loss. By specifying a market price, this analysis can be extended to show stakeholder shares of the project's net-back revenues to each segment.

COMPETITIVE ANALYSIS

Fig. 2 (42671 bytes) shows a typical competitive analysis. For five representative projects, we have calculated the COS for ex-ship LNG delivery into Japan.

To show difference attributable to costs, we have specified a common generic structure for sovereign terms across projects. A complete competitive analysis would account for specific sovereign terms as well.

PROJECT STRUCTURE

LNG projects are structured to pay some segments on a cost-based or charter basis, while taking the residual revenue allocation (the "merchant" function) elsewhere in the chain. Shipping is always paid under some kind of long term charter or transportation agreement. For the remainder of the chain there are alternatives, largely determined by the resource and capability endowments of the sponsors and the host country sovereign fiscal structure.

  • In the Australia North West Shelf project, the upstream and liquefaction facility are jointly owned by an unincorporated venture.

  • In Indonesia, the liquefaction facility is government-owned, debt-financed, and compensated on a cost basis. The residual revenue is pushed upstream to the production sharing concession, where it is subject to production sharing terms.

  • In Malaysia and Brunei, the upstream and liquefaction project are separate ventures with separate ownership, and LNG sales revenue is shared.

  • In the Mideast, a variety of structures is developing. However, in one project the feedgas is paid essentially on a fee basis (with some share of "excess" downstream profits), and the liquefaction project is the residual revenue claimant.

Fig. 3 (42161 bytes) shows analysis of netbacks and costs under these alternative project structures.

LNG COMPETITION

In Fig. 4 (109077 bytes) we apply the cost of service analysis to interfuel competition in the growing market for independent electric power production. Here we specify representative imported LNG and coal prices, and import terminal and electric generation facility costs and efficiencies. COS in cents per kilowatt-hour is calculated for LNG, unscrubbed coal, and scrubbed coal-fired generation at a range of available plant load factors.

The panel on the right presents the "gas premium" calculation, showing how much ex-ship LNG could be paid and still compete with unscrubbed and scrubbed coal-fired generation.

PROJECT CHALLENGES

A sponsor or buyer for a prospective LNG project faces a massive financial and institutional commitment to an enterprise requiring a dedicated effort and informed commitment by all the key players.

Successful project formation requires a shared, coherent understanding of costs and rewards through the LNG chain. The LNG project evaluation system developed by Merlin Associates and Poten & Partners and described in this article carefully and systematically integrates engineering-based cost assessment with the business and financial structure of the project.

It has proved to be an effective tool for strategic assessment of project structure and competition during the project formation process.

REFERENCES

1. Merlin Associates, Poten & Partners Inc., "New LNG Trades: Cost and Competition," 1991.

2. DiNapoli, R.N., Yost, C.C., "A Generic Model for Estimating LNG Plant Capital Cost," presented at Symposium on Liquefied Natural Gas, AIChE, Houston, April 1991.

3. DiNapoli, R.N., "Evolution on LNG Project Costs and Estimation Techniques for New Projects," presented at LNG 8 Conference, Los Angeles, June 1986.

4. DiNapoli, R.N., "LNG costs reflect changes in economy and technology," OGJ, Apr. 4,1983, pp 138 143.

5. DiNapoli, R.N., "Estimating cost for baseload LNG plants," OGJ, Nov. 17,1975, pp 58-60.

6. DiNapoli, R.N., "Economics of LNG projects," OGJ, Feb. 20, 1984, pp 47-50.

7. Nissen, D., "Economics Accounts of the Resource Firm," Energy Models and Studies, Benjamin Lev, ed., Studies in Management Science and Systems, Vol. 9, North-Holland, 1983, also in Oil and Gas Supply Modeling: Proceedings of a DOE/NBC Symposium, Saul Gass, ed., NBS Special Publication 631, 369410,1983.

8. Nissen, D., "Economic Accounting for Project Value," Proceedings of the 8th Annual North American Conference of the International Association of Energy Economists, MIT Press, Boston 1987.