evolution of long-term lng sales contracts

8/11/2019 Evolution of Long-Term LNG Sales Contracts

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During the 40+ year history of the LNG industry,

customs and practices have developed with regard to

documenting long-term LNG sales (SPAs). Although

the foundational approach to SPAs has, in general,

remained unaffected since the first contracts of the

early 1960s, market changes, fresh challenges and new

players are resulting in approaches to contractual terms

that may differ from the traditional LNG way. While

clearly much can be learned from past LNG precedent,

present circum-stances may necessitate a different

course than in past SPAs. This article will review

common alternative drafting and risk-sharing

approaches as well as changes to contracting practices

for representative Asian and Atlantic-basin SPAs, with an emphasis on

contractual and legal issues rather

than purely commercial concerns. In

preparation of this article, the author

examined many, but not all, of the SPAs

signed during the relevant period,

including: 3 from the 1960s; 11 from

the 1970s; 9 from the 1980s; 17 from

the 1990s; and 21 since 2000. These

SPAs are from 14 existing or planned

exporting nations (and 2 nations whichhoped to do so but the projects were cancelled) and 9

existing or planned importing nations. Given the task

of reviewing four decades of experience and the

necessary brevity of this article despite the intricacy of

the subject matter, the following is intended to be an

overview, rather than a comprehensive discussion, on

the evolution of certain key SPA issues.

1960s

Compared to the 14 long-term SPAs executed in 2004,

relatively few SPAs were signed in the 1960s. In fact,

long-term sales were limited during this decade to

Alaskan sales to Japan and Algerian sales to the United

Kingdom and France.

The LNG lawyer of today would first

notice the brevity of SPAs of the 1960s.1

These SPAs were 20 to 30 page

documents with guiding contractual

principles rather than the detailed

(sometimes overly) clauses we now see.

In these initial contracts, perhaps due

to the fact that financing was not

provided by third parties, no real trend

was established with respect to the

choice of law. The choice of contractual

law was wide,2 from Algerian law to Japanese law to no

choice of law at all (relying instead on empowering the

arbitrators to act as amiables compositeurs and

thereby permitting the arbitrators to decide the dispute

according to the legal principles they believe to be just,

without being limited to any particular national law).

Arbitration of disputes, rather than litigation, by three

arbitrators was already the norm, with the International

Chamber of Commerce rules applying and the place of

arbitration being Geneva, Zurich or Tokyo.

In these early days of the LNG industry, not all SPAs were

stated in terms of take-or-pay; instead, the simple

obligation to purchase the quantity appears to have been

Evolution of Long-Term LNG Sales Contracts:

Trends and Issues

Philip R. Weems, Partner, King & Spalding LLP

1 For a discussion of principles guiding the choice of contractual structures for LNG export projects and further background on terms of SPAs, see Weems, "Overview of Issues Common

to Structuring, Negotiating and Documenting LNG Projects," International Energy Law and Taxation Review (Issue 8, 2000) (available at

www.kslaw.com/practice_areas/energy/publications.asp).

2 The choice of law under the oldest SPA (signed on December 12, 1961 between British Gas Methane Limited and Compagnie Algerienne de Methane Liquide) is not known. This SPA

expired in 1979.


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the only necessary requirement:

The annual contract quantity of LNG which

Sellers agree to sell and deliver to Buyers, and

which Buyers agree to receive and pay for under

this Agreement for each contract year is [____]

billion Btus. [C]argoes of LNG shall be

delivered and received during each contract year

at rates and intervals and volumes which are

reasonably equal and constant.

The term of SPAs was 15 years in two instances and 25

years in the other. It was not unusual for the term of the

contract to be extended at Buyers election if an event of

force majeure prevented the delivery of the minimum

contract quantity. As these contracts pre-dated the 1973

Oil Crisis, pricing was relatively fixed. The following

illustrates the three methods of pricing in these early

agreements: $0.52 per MMBTU delivered ex ship.

A price based on (a) the value of the

natural gas (determined based on the value of heavy fuel

No. 2 from certain Mediterranean and Atlantic refineries

and based on wholesale coal prices as published by the

French Institute of Statistics); plus (b) the cost of

liquefaction (pursuant to a separate liquefaction

agreement) and indirect taxes.

$0.305 FOB, escalated annually for

certain U.S. inflation.

The most-favored nation pricing concept found its way

immediately into Japanese contracts through clauses

requiring that if in the future another [LNG] project is

placed into operation to supply Japan under similar

conditions such as volume, distance, liquefaction, and

ocean transportation techniques, contract term and so

forth, sellers will hold a discussion with Buyers

concerning the price and shall endeavor to find a

solution satisfactory to all parties concerned.

Noting that each party has the obligation to act in dueregard for appropriate safety precautions, one SPA

introduced the following concept of liability in relation

to LNG tankers:

While the LNG tanker is [at berth at Buyers

terminal], Buyers shall indemnify Seller for

any injuries or damages they may suffer as a

result of the negligence, or willful and malicious

acts of Buyers, their agents, employees,

contractors and suppliers of labor and materials

and their employees while performing services

for Buyers.

A mirror indemnity of Buyer for sellers negligence, etc.

was likewise included.

Additional observations regarding SPAs of the 1960s are

as follows: In one contract, there was an obligation

to use best efforts to obtain government approvals

within 60 days; otherwise, either party could terminate

the SPA with no liability.

Few specifics are included regarding the

facilities to be constructed by either seller or Buyer.

In one contract, the port charges payable

by Buyer for use of sellers loading port are frozen for the

term (25 years) at the rate existing on July 15, 1969.

Two SPAs are silent on demurrage (withone simply stating that Sellers and Buyers shall

cooperate in their efforts to unload an LNG tanker within

17 hours after docking) while one SPA includes a

demurrage rate fixed at $24,000 per day.

In one contract, if a default in the

performance of any obligation under the SPA occurs and

is not remedied in 60 days, the non-defaulting party is

entitled to terminate the contract.

In general, seller bears the risk of taxes

imposed by the export country while buyer bears the risk

of taxes imposed by the importing country; but in oneSPA if any new income or product related taxes are

imposed on seller, buyer is obligated to reimburse seller

for 75% of the amount of taxes payable, provided that

such recovery is not prohibited by law.

In one contract, force majeure is deemed

to include serious accidental damage to the principal

pipelines leading from the regasification facilities and to

the principal pipeline systems transporting gas to

buyers Principal Customer (defined as any customer

who buys at least 10% of the annual contract quantity

sold under the SPA). However, whenever the force

majeure event ceases, the quantities of LNG not

delivered due to force majeure must be sold or purchased

as make-up quantities in the shortest possible time.

Each SPA is silent on (i) damages

payable in the event of a failure to purchase or sell; (ii)

obligations with regard to off-spec LNG; and (iii)

financial security to be provided by either seller or buyer.


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Element based on crude oil export prices and a

Transportation Element (with the LNG Element having

a minimum LNG price of $0.99 per MMBTU [escalating

at an agreed rate] and the Transportation Element being

$0.30 per MMBTU [escalating based on changes in

sellers actual cost of transportation payable to its

transporter]).

$0.63 FOB, adjusted for changes in a

basket of currencies but not to be less than a stated

minimum price.

The higher of the base price (set initially

at $1.30 FOB) or a Floor Price, with monthly

adjustments to the base price based on changes in

certain fuel oils and semi-annual adjustments to the

Floor Price based on changes in a basket of European

exchange rates.

The higher of the base price (set initially

at $1.50 FOB) or a Floor Price (escalating at an agreedrate), with semi-annual adjustments to the base price to

be based on crude oil export prices and on U.S. inflation.

These different approaches to pricing were obviously

influenced by major changes in oil pricing from 1973

onward. Uncertainty about pricing in the buyers market

led to the adoption of perhaps the first LNG price review

clause (governed by the laws of the United Kingdom).

This clause (i) required the parties to meet every four

years; (ii) required the parties to adapt the price in a

reasonable and fair manner to the economiccircumstances then prevailing on the imported Natural

Gas market and on the market for other imported energy

supplies competing with this product in the East Coast

and Gulf Coast areas of the [U.S.] within the framework

of long term contracts; (iii) provided for arbitration to

determine the price revision if the parties could not

reach agreement in 90 days; and (iv) provided that no

arbitration award on price revision would become

effective until approved by governmental authorities

having jurisdiction in the countries of the parties.

As had been the practice in the 1960s, specific remedies

applicable to non-performance were not included (aside

from the ability in one contract to terminate the contract

if non-performance is not remedied in 60 days).

Therefore, remedies for seller non-performance were

based to a great extent on the underlying choice of law

(such as the Uniform Commercial Code Article 2 when

New York law was chosen). A 1970 SPA confirmed the

view of take-or-pay as sel lers exclusive remedy by

stating that in respect of non-fulfillment by any Buyer

of its obligations to take delivery of LNG hereunder,

Seller shall rely solely on the remedy afforded by [the

clause requiring buyer to pay the shortfall at the contract

price].

Although the 1973 Pertamina - Pacific Lighting SPA

ensured that the obligations to sell and purchase LNG

were not effective until satisfaction of certain conditions

precedent, the maximum 30 month period to obtain U.S.

approval to import LNG and to obtain financing of

Pacific Lightings import facilities proved, in hindsight,

to be a major underestimation. In fact, it was not until

1981 that Pacific Lighting abandoned its hope to obtain

California approval of the siting of the import terminal.

In another Indonesian contract, although no conditions

precedent were included, seller obtained the right to

terminate the SPA if it was unable to obtain, within six

months, firm and binding commitments from Japanese

lenders on terms satisfactory to Seller, for financing of

construction of [the port and liquefaction facilities].

Destination restrictions were common, reinforced often

through the requirement that ships be dedicated to

trading between seller and buyer. Limited rights to alter

the receiving terminal were incorporated into a few SPAs,

such as the following provision:

The scheduled port of destination is the port of

Boston (Massachusetts) where Buyer has now atits disposal the required facilities. However,

Buyer shall have the right to designate any safe

port on the East Coast of the United States of

America, subject to the designation being

notified to Seller in writing at least 15 days prior

to the scheduled date of delivery; provided,

however, that all required authorizations and

permits, and any delay which may result

therefrom, shall be the responsibility of the

Buyer; provided also that the sales price stated

shall be adjusted in such case to take intoaccount the variations in the length of the

voyage and any additional costs which would be

incurred as a result therefrom.

Additional observations regarding SPAs of the 1970s are

as follows:

A distinguishing characteristic between

force majeure under some Asian SPAs and those from


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other regions was introduced in 1973 with one Asian

contract deeming force majeure to include [t]he reserves

of natural gas in [certain named fields] which can

economically be produced for purposes of this Contract

have been fully depleted.

In one instance under an ex ship SPA, even

if the buyer was excused from purchasing LNG due to a

buyer force majeure, the buyer was nonetheless obliged to

pay certain transportation costs incurred by seller during

the force majeure.

Tax risks continued to be divided based on

the concept that seller bears the risk of taxes imposed by

the export country while buyer bears the risk of taxes by

the importing country. In one instance, buyers agreed to

an equal sharing of sellers increased natural gas or freight

taxes outside of the importing country, provided seller had

exercised reasonable diligence to avoid the increase or

new imposition of taxes.

Not all SPAs included the obligation to pay

demurrage if loading (or unloading) of a particular cargo

was delayed. Furthermore, in other agreements, cargoes

loaded/unloaded quickly over the year were netted against

cargoes loaded/delayed over the same year, in order to

determine any demurrage payable.

Scheduling of deliveries was to be at rates

and intervals reasonably equal and constant throughout

the year. In a precedent setting move that is, with

increasing frequency, today challenging receiving terminal

operations with multiple users, different scheduling yearsevolved during this decade. For example, a contract year of

April 1 to March 31 was established in the 1970 Brunei -

Japan SPA while a contract year of January 1 to December 31

was set in both the 1973 SPA between Indonesia

(Pertamina) and the Western Buyers and in the 1976 SPA

between Algeria (Sonatrach) and Distrigas of the U.S.

A few SPAs addressed liabil ities in

relation to an accident occurring while loading (or

unloading) of an LNG tanker. When such liability was

addressed, the negligence, willful misconduct or

intentional act of the party or its agents (including the LNGtransporter) was the determining factor, with no stated

financial limit for such liability exposure.

1980s

Indonesia and Algeria dominated this decade, signing the

vast majority of executed SPAs.6 However, the 1980s did

see the emergence of new supplies from Malaysia and

Australia (and a failed potential supplier, Dome Petroleum

Limited of Canada). On the importing side, South Korea

began its big push into LNG by signing ex ship agreements

with Indonesia, while new buyers in Belgium and Taiwan

also joined the industry. Most of these contracts were for a

term of 20 years, although Algerias SPAs with France were

25 year agreements. The average length of SPAs began to

approach 75 pages (though Algerian SPAs continued to fallin the 40 page range).

It should be noted that the first major dispute on a SPA

occurred during this period, when the Algerian government

refused to approve the LNG pricing authorized by U.S.

agencies, leading to various disagreements on pricing which

led to the eventual termination (or renegotiation) of most

Algerian SPAs providing for deliveries to U.S. terminals.7

Gas competition issues began to influence the structuring

approach to SPAs. For the first time, multiple participants in

one joint venture chose to execute separate, parallel SPAs with

each buyer. However, because performance of the multiple

SPAs was to occur simultaneously from an operational

standpoint, the parties agreed in each SPA that the LNG to be

sold and delivered to each Buyer under [the SPA] shall be sold

and delivered commingled with LNG to be sold and delivered by

[named other sellers] to each Buyer under the other sale and

purchase agreements concluded between Buyer and the Other

Sellers. Each of the multiple SPAs deems a set portion of each

commingled cargo to be from the respective seller.

This decade saw much less variety in the choice of law to

govern the SPA, with English law and New York being

almost the exclusive choices. Although the ICC arbitration

rules were still chosen on several occasions (with the

arbitration to be held in either Paris or New York), for the

first time the UNCITRAL Rules, adopted in 1976, were also


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utilized (with hearings to be in Geneva or New York). In one

unique provision in the 1981 Arun II Trade SPA signed between

Indonesia and Japanese buyers, the place of arbitration was

agreed to be Paris; yet, the SPA provides that if Pertamina had,

at the time of its dispute with the Japanese buyer, another

ongoing arbitration in Paris with another LNG purchaser and

if arbitrating in Paris could require Pertamina to take

mutually contradictory actions in its respective disputes,

then the place of arbitration would be moved to New York.

Take-or-pay clauses remained, typically on an annual basis

but in at least two instances on a quarterly basis. In the first

part of the decade, buyers had little ability to reduce their

take-or-pay amount (and in some cases the reduced amount

had to be re-taken within a certain number of years via so-

called Make-Good provisions). Interestingly, as the decade

drew to a close and lower oil prices brought on more of a

buyers market for LNG, buyers enjoyed more flexibility to

increase or decrease annual take-or-pay amounts.

Pricing of LNG generally followed existing approaches; for

example:

An initial price of $5.78 per MMBTU, FOB,

based on a 1981 crude oil export price of $35.69, with

annual adjustments for changes in such export prices.

A price determined, in part, on the average

landed price, in dollars, of all other liquefied natural gas on

long term contracts being imported into Japan, and the

actual figure shall be determined prior to the first delivery of

LNG in a fair and reasonable manner. The remaining portion

of the price was to be based on the Japanese Crude-oil Cocktail,

a weighted average landed price of all crude oil imported into

Japan during a reasonable period to be agreed.

An ex ship price divided into an LNG

Element based on crude oil export prices and a

Transportation Element (with the LNG Element having a

base LNG price of $4.284 per MMBTU and the

Transportation Element having a base price of $0.47 per

MMBTU (escalating at an agreed rate)).

Price review clauses, if included, were typically only an

obligation of the parties to review the price in good faith in the

light of all the circumstances relevant at the time; the contract

price would only be changed if the parties agreed to do so.

Continuing the practice in the 1960s and 1970s, few

specific remedies applicable to sellers non-performance

were built-in. If a clause dealing with remedies was

inserted, it was typically along these lines (in both English

law and New York law governed SPAs):

[Subject to Buyers liability for any take-or-pay

deficiency], the Seller shall be liable to either

Buyer and either Buyer shall be liable to Seller for

loss and damage which has been suffered as a

result of the breach by the party liable of any one or

more of its obligations hereunder, to the extent

that the party liable should reasonably have

forseen the loss or damage.

An important development occurred when the initial Japanese

FOB buyers from Indonesia insisted that a liability regime for

LNG accidents at the loading port be incorporated into the

SPA. Accordingly, a 1981 Indonesian SPA added a multi-page

exhibit of principles for determining the liability of the

shoreside interests and of the LNG vessel interests in theevent of an LNG incident. These SPA principles obligated

the parties to agree to separate Omnibus and Waiver

Agreements, governed by English law and subject to the

jurisdiction of the High Court of Justice in London, overriding

the existing Conditions of Use the Master of the LNG vessel

was required to sign upon entry of the vessel into the

Indonesian port. Under these liability principles the parties

set the liability limit of the LNG vessel owner at $150 million,

a limitation of liability which was to continue in effect for as

long as the [vessel] Owner can obtain customary P and I Club

cover for the risk. Somewhat surprisingly, although almost25 years has elapsed since the port liability limit for vessel

owners was established in Indonesia, the $150 million liability

limit has not been increased; recent SPAs have also adopted

this limit for other LNG ports, based in part on the view that

higher liability coverage is not yet available from P&I Clubs

insuring LNG vessels.

Additional observations regarding SPAs of the 1980s are as

follows:

In at least one instance, the SPA had a

hardship clause which (in recognition that the SPA was a

long-term contract that the parties intended to be fair and

reasonable for its full term) obligated the parties to make,

in a spirit of mutual understanding and cooperation,

mutually acceptable revisions to the SPA to eliminate any

substantial hardship suffered from a change in

circumstances.

Tax clauses in some instances became more

comprehensive. For example, some clauses required seller in


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ex ship contracts to not take any action which would lead to

seller having a permanent establishment in buyers country.

In place of an unrestricted indemnity for taxes in the buyers

country, in some cases the seller agreed to use its best

efforts to cease to be subject to [the importing countrys]

income tax, by appropriately reordering its affairs connected

with the performance of the SPA.

As a result of a disputed force majeure

event centered on whether a party could claim force

majeure if an employee caused an accident due to its

negligence, a few contracts entered into late in the decade

were amended to remove the outside the reasonable

control of the party requirement. In its place, force

majeure was deemed to also comprise, for example, any

serious accidental damage to a facility unless it resulted

from the willful negligence on the part of the partys

management.

Moreover, several SPAs began to address

the possibility of extended force majeure, providing either

that the other party had the right to terminate the SPA

after a set period (2 to 3 years) or, in the case of seller, to

sell otherwise undeliverable LNG to third parties if the

force majeure had exceeded 9 months.

Non-utilization provisions first

appeared during this period to address the exposure of the

shipping party to un-reimbursed transportation costs if the

other party suffered a force majeure. Under some SPAs, the

party claiming force majeure would in certain instances

still be required to make payments during the force

majeure in an attempt to make the other party whole for

the cost of its unused, dedicated LNG shipping fleet.

Destination restrictions existed, either

expressly in the SPA or practically due to transportation

limitations and location specific pricing provisions. For

example, one ex ship SPA stated if buyer made an

emergency need request, seller may, in its discretion,

agree to change the place of delivery to another port in the

same country as the buyer.

Again, not all SPAs included the obligation

to pay demurrage if loading/unloading of a cargo wasdelayed. One ex ship SPA simply required the parties to

discuss in good faith how to distribute any additional costs

incurred by a party as a result of a delay in berthing,

unloading or departing.

Most favored nations pricing provisions

were not uncommon, with the stated purpose in one

instance being to maintain comparability between the

Contract Sales Price under the [SPA] and prices payable

under the Japanese Contracts existing on the date of the

SPA.

The rise in project financed liquefaction

facilities resulted in more provisions aimed at ensuring that

sellers revenues are not unnecessarily interrupted. An example

is the disputed force majeure clause in one SPA of this period

that required buyer to continue to pay in full, to an escrow

account at a bank in a neutral country, for the contractual

quantity of LNG regardless of buyers assertion that buyer is

excused from taking LNG due to a force majeure event.

1990s

The 1990s saw a steep rise in developments affecting the

LNG industry, with SPAs being signed by new exporters in

Qatar, Oman, Nigeria and Trinidad and by new importers in

Turkey, Puerto Rico and Greece. In the first part of the

decade, Asian suppliers (particularly Indonesia8, Malaysia and

Qatar) signed, renewed or substantially amended a multitude

of SPAs with principally Japanese, South Korean or Taiwanese

buyers. On the other hand, the second half of the decade

witnessed the re-birth of U.S. LNG imports, increases in

supplies to Europe and the emergence of the Middle East as a

key Asian supplier. The decade also saw, in dollars terms, the

largest contractual dispute to date on an SPA.

11 For the Indonesian perspective on contractual and legal issues associated with SPAs, see A. Nasution, Special Advisor to Pertamina President Director, "Allocating

Price Risk in LNG Sales Contracts" (IBA Energy Law Conference, The Netherlands, 1990). To contrast the Indonesian seller's view with the Japanese buyer's approach,

see Greenwald, "LNG Export Projects to Japan: The Purchaser's View" (IBA Energy Law Conference, The Netherlands, 1990).


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The length of SPAs signed during the 1990s continued to

vary, in part based on the style of the draftsmen; while a

few remained in the 50-60 page range, several exceeded 80

pages and one SPA, in a rather odd example for a major

project that did not proceed after signing, exceeded 175

pages. With an average length reaching around 90 pages,

most agreements were for a 20 year term, but at least two

Middle East SPAs had a term of 25 years.

None of the SPAs from this decade that were reviewed for this

article had a governing law other than New York or England.

Although the number of SPAs governed by New York law

exceeded that of English law, especially during the end of the

decade, the number of agreements governed by English law saw

a marked increase. In some SPAs, the parties expressly agreed

that the newly effective United Nations Convention on Contracts

for the International Sale of Goods 9 and the Convention on the

Limitation Period in the International Sale of Goods would not

apply to the SPA. From a dispute resolution standpoint, the

methods chosen were the following: (i) ICC in Geneva; (ii) ICC in

London; (iii) UNCITRAL in London; (iv) UNCITRAL in New York;

and (v) in several instances, ICC in Paris.

As mentioned above, the SPAs of the 1990s bred the largest

SPA dispute to date and one of the largest in English legal

history. When the Italian state electric utility, ENEL,

attempted in 1996 to cancel its SPA with Nigeria LNG Ltd

(reportedly claiming force majeure), the result was the filing

of a breach of contract arbitration against ENEL for $13billion. At the time, this claim was reportedly the largest one

ever brought under English law. Fortunately, the matter

soon settled when the parties agreed that Nigerian LNG

would be shipped to France instead of Italy, in exchange for

Russian gas diverted by French buyers to Italy. 10

Take-or-pay clauses continued to be relied upon,

determined now almost exclusively on an annual basis. In

spite of this, the parties to a 175 page SPA, which was

governed by English law, decided to avoid using the words

denoting take-or-pay; instead, the buyer under this SPA

was granted an annual right to either lift and purchasethe annual contractual quantity or accrue a right to be

allocated Make-Up LNG by payment for the

corresponding quantity not lifted. Buyers continued to

have some limited ability to reduce their take-or-pay

amounts (generally not exceeding 5%). With the evolution

of annual contract quantities, quantities to be made-up

from prior year reductions, make-up LNG, option

quantities, force majeure restoration quantities, etc.,

provisions were added to the SPA to account for the relative

priority of each contractual quantity right or obligation.

Flexibility in scheduling delivery of the take-or-payquantity began to be of major concern to some buyers,

especially those located in countries with peak winter

demand. This resulted in one Atlantic SPA requiring

delivery of 62% of the annual contract quantity during

October 1- March 1 and 38% of the annual contract quantity

during April 1 to September 30.

As new markets for LNG opened, pricing of LNG began to

move gradually more away from its crude oil origins; for

example:

A price based on the Net Back Fraction

calculated using actual sales of LNG and regasified LNG by

buyer to customers within certain U.S. states, with buyer

having the obligation to diligently seek to maximize the

proceeds from such resale by negotiating terms with

customers which in Buyers reasonable commercial

judgment are the most favorable available to Buyer in the

prevailing circumstance.

A price based approximately 90% on crude

oil export prices (based on an initial factor of $3.24 MMBTU

at $18 per barrel) and approximately 10% on changes in U.S.inflation.

A price divided into an LNG element based

on certain crude oil prices and on a transportation element,

with buyer paying sellers actual cost of transportation

using certain dedicated LNG tankers.

A price based on crude oils imported in

Japan in that month plus a Constant (initially set at $.77)

to be revised upward prior to the first delivery under the

SPA if agreed by the parties to be necessary by taking into

consideration relevant factors including the prevailing

energy situation.

Notwithstanding that the importer was

located in another country, a price based on crude oils

9 The CISG came into effect in 1988; it is presently in effect in the U.S. but not in England. Note that the United Kingdom, however, may soon ratify the CISG as well.

See UK Parlimentary Debate, 7 Feb 2005.

10 See Weems and Keenan, "Greenfield LNG Import Terminal Approvals," LNG Journal (May-June 2002) (www.kslaw.com/practice_areas/energy/publications.asp).


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imported in Japan; however, the price automatically

adjusts upon a 5% differential between the contract price

and pricing under buyers existing SPAs for Middle East

LNG supplies.

Aside from the SPA mentioned above, the 1990s saw few

uses of most favored nations clauses for comparative

pricing. Price review clauses, also called contract price

reopeners, were sometimes incorporated into Atlantic SPAs

supplying LNG to Europe. Rather than making any changes

dependent on the parties ability to reach agreement, a party

was allowed to resort to arbitration to determine

adjustments, bearing in mind pricing of LNG and gas in

Western Europe, which in any event allow buyer to market

the LNG supplied in competition with all competing

sources or forms of energy (including, but not limited to,

natural gas, fuel oil, gasoil, coal, LPG, district heating and

electricity). such that Buyer is able to achieve a reasonable

rate of return on the LNG delivered hereunder.

Creditworthiness of the buyer became more of a focus

during this decade as special purpose companies and

subsidiaries of smaller gas companies without large

balance sheets executed SPAs. This was especially the case

in situations where the seller project financed its

liquefaction facilities partly on the strength of the buyers

credit. The importance of the soundness of contractual

arrangements increased as sellers had to find comfort that

buyer would perform by examining the soundness ofbuyers gas resale agreements and power sales agreements.

In one example, the subsidiary was required to provide a

parent guarantee for several hundred million dollars.

However, if seller was not required to finance the

construction of additional facilities to provide the

quantities sold under the SPA, the buyer was simply

required to obtain the issuance of letters of credit for the

value of 2 to 3 cargoes. In some SPAs, in exchange for

buyers guarantor being able to limit its parent guarantee

amount, the seller limited its maximum liability.

Extensive remedies clauses became more fashionable

during the 1990s. Although many contracts maintained

the prior approach of relying on remedies afforded under

the governing law (including those governed by the

Uniform Commercial Code via the choice of New York law

and certain Asian SPAs into Japan governed by English

law), other contracts chose more detailed and specific

remedies for non-performance. The remedies for seller

non-performance were broadly divided into three

categories: (a) the actual net cost of replacement gas or

LNG; (b) the actual net cost of alternative replacement

fuels; or (c) liquidated damages. The following are

highlights of example provisions detailing remedies for

non-performance of the sale or purchase obligations:

As to sellers liability, determined based on

the costs buyer reasonably incurs to purchase either LNG

(on an FOB basis), natural gas or a reasonable alternative

fuel in replacement for the shortfall quantity of LNG, plus

reasonable additional shipping costs incurred by buyer, but

minus the contract sales price and any costs saved.

As to sellers liabil ity, a Shortfall

Payment in dollars for the quantity (exceeding a minimum

threshold of 2.5%) not delivered, determined by multiplying

the Shortfall Quantity by the following:

(a) the cost to buyer of replacement

naptha/condensate/distillate volumes, delivered to thedischarge port; multiplied by (b) a pre-agreed heat rate

adjustment factor to convert the LNG Shortfall Quantity to

naptha/condensate/distillate (which buyer would utilize at

its downstream power station to generate the same amount

of electricity), minus a pre-agreed adjustment for LNG boil-

off and losses during regasification; minus

the cost (on a $/MMBTU basis, delivered ex

ship) which would have been incurred by buyer for the

Shortfall Quantity of LNG.

As to sellers liability, liquidated damages

of 25% of the average contract sales price multiplied by theshortfall quantity.

As to buyers liability, confirmation that

Buyers sole liability for or arising out of or in connection

with any failure to take delivery of, or if not taken, to pay for

LNG when required to do shall be limited to its obligation

to make [take-or-pay] payments.

Broad force majeure clauses, covering much more than

simply acts of God, retained their dominance in SPAs

during this decade. The traditional approach to defining aforce majeure event as an event occurring outside the

partys reasonable control remained popular; but, several

SPAs of this period avoided such a test and instead named a

specific and exclusive list of events that were deemed to

constitute force majeure. The debate also centered on

events affecting transportation assets and downstream

assets which should be specifically included or excluded;

for example:

Inclusion of damage to, loss or failure of


10/17

the pipeline transmission and distribution facilities or of

trucks engaged in the transportation of LNG or Regasified

LNG from the receiving facilities.

Inclusion of delays in construction of

relevant upstream facilities, new liquefaction trains and

related facilities, certain new buyer facilities, and port

facilities and the dredging thereof.

Inclusion of the inability of one or more

of buyers customers to take delivery of LNG, Regasified

LNG or Natural Gas pursuant to its/their purchase

contract(s) with Buyer.

Inclusion of certain events preventing a

power plant from continuously purchasing regasified LNG

from buyer for at least 30 consecutive days (but pro-rating

the effects of such event based on a comparison of the

contract quantity under the SPA over the last 12 months to

the total amount of Natural Gas whether domestic or

otherwise and including LNG purchased by Buyer duringthe same period of time).

Exclusion of circumstances which

constitute a Political Force Majeure, as defined in the

Power Purchase Agreement between buyer and the state

electricity board.

Exclusion of damage to an LNG tanker

during certain voyages when carrying LNG not produced by

seller.

Exclusion of circumstances affecting

buyers facilities if damage or failure resulted from gross

negligence on the part of buyers management.

A marked difference in the approach to reserves depletion

developed. Asian SPAs addressed depletion of specified

reserves of natural gas, while Atlantic SPAs specifically

excluded the natural depletion by production of gas

reservoirs. Lastly, although apportionment clauses had

long been used to require seller to divide any available LNG

supplies between long-term buyers, provisions were added

requiring buyer to (for example) devise and notify to Seller

a fair and equitable system for apportioning its purchasesbetween Seller and such other suppliers.

The approach to conditions precedent varied by project. In

some SPAs, the parties decided to bear considerable

condition precedent risk for a set period of time while

awaiting certain governmental approvals, the execution of

ancillary contracts, and financing or other investment

decisions. In one instance (addressed in a 4 page provision in

the SPA), in addition to conditions precedent relating to

government approvals obtained in form and substance

satisfactory to the [relevant party] in it sole discretion, seller

was able to terminate the SPA with no liability unless seller

had (a) executed a gas supply contract, an additional SPA with

another purchaser, and an EPC contract for construction of

sellers LNG facilities, each in form acceptable to seller in

sellers sole discretion; and (b) made an affirmative final

investment decision, in its sole discretion, to construct, own

and operate sellers proposed LNG facilities.

Destination restrictions lingered in SPAs of the 1990s,

with the following being representative of the effects of

such restrictions:

all LNG sold hereunder shall be for Buyers

account only. Buyer shall deliver LNG purchased

hereunder into the LNG receiving facilities at

[______] (the Discharge Port), unless prevented

from so doing by reasons of Force Majeure or

operational problems encountered at the DischargePort or with the LNG Ship, in which case, Buyer may

change the discharge destination to another

suitable port in [Buyers country]. Should Buyer

wish to change the destination to a port outside

[Buyers country] in accordance with the foregoing,

Buyer must first secure Sellers consent, which

shall not be unreasonably withheld.

Some, but by no means all, SPAs executed during this

period addressed liabilities for LNG accidents occurring at

the loading/unloading terminal. While some contractswere silent on the subject, others specifically required the

party responsible for transportation to take certain actions

aimed at causing the vessel owner and other related parties

to execute port liability agreements provided the

agreements are (in one instance) reasonably acceptable to

reputable insurers; the level of protection and indemnity

insurance required does not unreasonably increase the

cost of such insurance; and Seller is not exposed to any

liability under the [agreement]. An unusual provision

used for an SPA (governed by English law) for Japanese

deliveries provided the following in order to resolve non-legal claims, presumably resulting from an LNG incident

involving the vessel:

If any demand or claim is made by any third party

in Japan against Seller, Ship Owner, and each

Buyer collectively or any of them, although according

to the unanimous opinion of Seller and each Buyer

there is no legal liability for the claim (for which

purpose legal liability shall include cases of


11/17

strict liability under the law or by contract) on the

part of any of the parties, including Ship Owner

against which it is bro ught, then the parties,

together with the Ship Owner if willing, shall

promptly discuss the claim in good faith and shall

continue to do so as necessary until the claim is

disposed of in order to find a reasonable solution

with a view to disposing of the claim, protecting theinterest of all the parties, including Ship Owner, and

preserving the smooth operation of the matters

contemplated in this Agreement.

In another SPA, Buyer agreed to be jointly liable with its

transporter for any damage to the Loading Port Facilities,

discharge of oil within the Loading Port or any other

obstruction affecting the normal operation of the Loading

Port Facilities. Under this provision, the aggregate liability

of Buyer and its transporter for any one incident was limited

to $150 million or such higher amount of insurance

coverage as the Parties may agree from time to time is

available and would generally be taken out by reputable

operators of LNG vessels, based on normal industry practice,

to cover such incidents and which is available from a

recognised P&I club under usual P&I club rules.

Not surprisingly, as more complex project structures came to

pass (especially as more special purpose entities became

LNG purchasers), more detailed termination clauses were

adopted. In some SPAs these provisions occupy severalpages of the agreement. For example, in one instance buyer

is specifically authorized to terminate the SPA if (a)

construction of Sellers Facilities is not completed by a

deadline; (b) seller becomes bankrupt, etc.; (c) seller fails to

pay to Buyer an amount exceeding an agreed threshold

amount; (d) seller fails to deliver at least 50% of the annual

quantity in two consecutive years (for reasons other than

force majeure); (e) if a sellers force majeure prevents

delivery of at least 50% of the annual quantity in any year

and it is apparent such prevention will continue for another

year; or (f) if seller disposes of a substantial part of Sellers

Facilities without the prior consent of buyer. Moreover, in

circumstances where the buyer was entitled to resell a

portion of its LNG to a third party for import into a different

receiving terminal, special termination provisions arose to

enable seller to terminate such resale SPA if such seller is

unable to receive LNG under its supply SPA for a specified

period of time (e.g., 48 months) due to a breach of contract

and if such seller shares a portion of the damages payable to

it for breach of the supply SPA.

Lastly, during the 1990s yet another scheduling year was

established, with Trinidad contracts adopting an October 1 to

September 30 contract year.

2000s

During the period since 2000 the LNG industry has

experienced the signing of an unprecedented number of

SPAs. The International Group of Gas Importing Companies

(GIIGNL) reported earlier this year that at least 63 long

term and medium term contracts were in force at the end of

2004. GIIGNL also reported that 14 SPAs were signed in

2004, and 2005 has seen the signature of many others (e.g.,

Yemen with Kogas, Total and Suez LNG; Sakhalin in Russia

with various Japanese buyers; and Iran with Indian buyers).

Many of these contracts anticipate deliveries to North

America. 11 While the first decades of LNG history were

dominated by a few players, recent years have opened the

industry to many more participants. As noted in the

following table, 12 countries exported LNG in 2004 while 13

countries imported LNG.

11 LNG imports into the U.S. in 2004 reached a record 652 Bcf, compared to 2003 imports of 507 Bcf. However, LNG imports still represent only about 2.9 % of U.S.

consumption and 15.5 % of U.S. imports, so additional LNG demand in the U.S. is expected by many LNG suppliers.


12/17

The signing of the latest SPAs suggests that, by the end of

the decade, the number of exporting countries is set to

increase to at least 18 and importing countries to at least 16.

In early 2005, liquefaction facilities began shipping from

Egypt, and facilities in Norway, Russia, and Equatorial

Guinea are now under construction (with Iran and Yemen

soon to commence construction). On the import side, a new

regasification terminal opened in the United Kingdom in

2005 and new regasification terminals are now under

construction in Mexico and China. As shown in the

following map of key trade routes in operation as of 2004,

Asian and Atlantic trades are becoming much more

intertwined than in the past.

Key LNG Trade Routes 2004 12

In the sampling of recent SPAs reviewed, New York law was

chosen in half. The length of SPAs continues to rise

somewhat from the last decade (e.g., after excludingtechnical exhibits, this sampling contains, respectively,

106, 99, 75, 74, 80, 65, 95, 109, 104 and 151 pages).

Arbitration provisions in both Asian and Atlantic SPAs

have followed similar paths, with common choices being

UNCITRAL arbitration in London or New York, ICC

arbitration in Paris or London, or, in at least one instance,

AAA in New York. While the majority of current SPAs are

consistently for a term of 20 years (or 25 years, for some

Middle East and Australian agreements), a 3.4 million tons

per annum agreement signed in 2004 was for a term of only

17 years. It is noteworthy that of the 14 SPAs that GIIGNLreports were signed in 2004, 10 of these were for an annual

volume of less than one million ton per annum.

At least two significant public SPA disputes have occurred

since 2000. First, as a result of the failure of Enrons LNG

terminal project in Dabhol, India, it is reported that both

Oman LNG LLC and Abu Dhabi Gas Liquefaction Company

Limited have each invoiced for take-or-pay amounts due

under SPAs signed in the late 1990s with the Enron

subsidiary Dabhol Power Company. Recently, these ongoing

SPA claims, along with amounts not paid under related

shipping contracts, were said to amount to $1.3 billion. 13

Second, a dispute concerning an Algerian SPA signed in

1987 with Trunkline LNG is ongoing in both London and

Houston. In an UNCITRAL arbitration seated in London,

Sonatrach and its affiliates are reportedly seeking

approximately $600 million of damages. In 2003, the

London arbitration panel found that Duke Energy LNG

Sales Inc. repudiated the 1987 SPA by failing to diligently

perform LNG marketing obligations; however, the panel

also found that Sonatrach and Sonatrading breached their

obligations under the 1987 SPA to provide shipping.

Apparently, a hearing on damages issues is scheduled to

commence in September 2005. The Houston portion of the

second dispute concerns Dukes contract for the sale of the

Algeri an regasified LNG. After Sonatrading ceased

supplying LNG to Duke under the 1987 SPA, Duke asserted

in 2002 to its gas buyer under the resale contract, Citrus

Trading, that it had suffered a loss of LNG supply

preventing it from performing its supply obligations. As a

result, Citrus filed a lawsuit in March 2003 in the U.S.

District Court for the Southern District of Texas 14 against

Duke LNG alleging that Duke LNG breached the Citrus gas

resale agreement by failing to provide sufficient volumes of

gas to Citrus. Citrus has denied that Duke LNG had the

right to terminate the gas resale agreement and contends

12 Source: "The LNG Industry in 2004," GIIGNL, Paris.

13 See GE, Bechtel Clear Last Hurdle in Dabhol Restart, The Financial Express, July 7, 2005 (available at www.financialexpress.com).

14 Citrus Trading Corp. v. Duke Energy LNG Sales, Inc., Cause No. 2003-12166 (U.S. 165th District Court, Harris County, Texas).

15 The Sonatrach and Citrus disputes are reported in Duke Energy Corp.'s 10-Q filing with the SEC, filed on August 9, 2005 (available at www.duke-

energy.com/investors/publications/sec.asp).


13/17

that Duke LNGs termination of the agreement was itself a

breach, entitling Citrus to terminate the gas resale

agreement and recover damages in the amount of

approximately $187 million.15 The Duke-Citrus case has

not yet gone to trial.

Recent SPAs have granted the buyer somewhat more

flexibility as to its take-or-pay obligations (however, this

flexibility should be viewed in context, because the buyers

commitment is still typically well in excess of 90% of the

annual contract quantity). In any event, the take-or-pay

contract remains alive and well (although some argue that

in concept take-or-pay is less of an issue for the U.S.

because the markets liquidity now always provides a gas

purchaser at the market price). A recent major Asian SPA

governed by English law clearly sets out the basic sale and

purchase obligation on an FOB basis:

Seller shall sell and deliver LNG in Cargoes at the

Delivery Point or make available for delivery LNG

and Buyer shall take and pay for, or pay for if not

taken, LNG in accordance with and subject to the

provisions of this Agreement.

The October 13, 2003, Nigeria LNG Limited and BG LNG

Services, LLC agreement (as filed with the U.S. Securities

and Exchange Commission) states the basic take-or-pay

obligation in the English law SPA as follows:

in any Sales Period, Buyer shall be entitled to take

the [annual contract quantity] required to be made

available for loading pursuant to the above (less

Boil-off and LNG Heel) in such Sales Period or to

accrue a right to Make up LNG in respect of all or

part of such quantity as it does not so take but in

any event Buyer shall have the obligation to make

full payment in respect of the entire [annual

contract quantity].

It is not uncommon for an SPA to now address quantity

adjustments in relation to a multitude of circumstances,

such as: (i) buyers right to increase or decrease the annual

quantity by a set amount (in one SPA, referred to as Buyer

Upward Flexibility Quantity or Buyer Downward

Flexibility Quantity); (ii) sellers ability, upon Buyers

agreement, to reduce the annual quantity for a Sellers

Diversion (i.e., a diversion from delivery to buyer); (iii)

sellers right to reduce the annual quantity for major

scheduled maintenance of sellers facilities or its vessels; (iv)

buyers right to reduce the annual quantity for major

scheduled maintenance of buyers facilities or its vessels or

due to operational constraints at [a third partys LNG import

facilities]; (v) sellers right to reduce the annual contract

quantity due to inadequate gas reserves or deliverability

from the defined gas supply area; (vi) adjustments due todifferences in gross heating value from that estimated in the

annual scheduling program; (vii) differences in the parties

obligations to purchase during a build-up period versus the

basic quantities to be sold and purchased throughout the

term of the SPA; (viii) the parties rights to cancel a cargo

which buyer cannot schedule for delivery; (ix) the effects of a

force majeure; (x) fractional cargoes due to the conversion

from cargoes to BTUs; and (xi) off-spec LNG. Such quantity

adjustments, especially if multiple delivery destinations are

anticipated under the SPA, are resulting in more detailed

quantities provisions; for instance, the quantities provisionsin one recent SPA approach 25 pages, in part to address

separate rules for sellers deliveries under the ex ship SPA to

European receiving terminals and to North American

receiving terminals.

Although (as discussed below) destination restrictions have

eased further, pricing provisions remain based on the gas

market where the LNG will be imported. The following table

indicates the wide differences in LNG pricing in 2004-2005

for Asian import prices. 16

16 www.abareconomics.com/australiancommodities/june05/pdf/asiapacificlng.pdf.


14/17

While the Indonesian SPAs of the 1990s did not include S

Curves which moderate LNG prices when oil is above or

below a certain range, many recent Asian SPAs tend to

include such S Curves. There has also been a move in

some markets to link LNG pricing to power pricing.

Examples of pricing approaches in recent Atlantic SPAs are

as follows:

A price for North American deliver ies

which is a set percentage of the NYMEX Henry Hub

Natural Gas Futures Contract traded at the Nymex

Exchange for the calendar month when completion of

unloading or deemed completion of unloading of the

relevant cargo takes place.

A price for U.S. deliveries where the

formula varies depending on whether the agreed NYMEX

Henry Hub Price for the month is less than $2.50, between

$2.50 and $4.50, or greater than $4.50 per MMBTU.

A price determined for each receivingterminal where seller will deliver LNG, such price to be

based on an agreed reference price for that receiving

terminal for the month, minus adjustments for certain

agreed shipping costs to that receiving terminal, minus

agreed pipeline costs, minus agreed terminal costs, and

minus agreed fuel costs for such receiving terminal.

A price for deliveries into the U.S. based in

part on the net proceeds, after actual transportation costs,

received by buyer from reselling the LNG purchased under

the SPA at named receiving terminals, with the

understanding that Buyer shall diligently seek tomaximize the net proceeds from its sales of LNG and

Regasified LNG acquired hereunder [, an obligation]

which is intended to ensure that the amount paid to Seller

under this Contract reflects the fair market value to

Buyers LNG customers.

For deliveries into Europe, for 85% of the

quantities, a price based on the unweighted average of the

monthly average prices for Gas Oil and Heavy Fuel Oil as

published in Platts Oilgram, and for 15% of the volumes, a

price based on an index for downstream power prices.

Most favored nations provisions are not as typical in

Asian SPAs as they once were. Lengthy price review

provisions are no longer uncommon. A recent SPA for sales

into Europe contains a 4 page procedure (which leads to

arbitration if the parties cannot agree to revised pricing) if

either party has a good faith basis for believing that for

reasons outside the control of the requesting party the

method for determining the [price] does not reflect the

value of regassified LNG at the import points in the

European system at the time when the review is

requested. In fact, some contracts now specify when a

price review procedure will not apply, such as the 2003

Nigeria LNG Limited and BG LNG Services, LLC agreement

(as filed with the U.S. SEC) which states that [f]or the

avoidance of doubt there is no price review mechanism

for deliveries to Lake Charles.

Creditworthiness of both parties is becoming an issue in

some SPAs, but no uniform approach has developed. Full

parent guarantees are sometimes required to support the

buyers credit. In one instance for the U.S. market, both the

parent of the buyer and the parent of the seller issued

certain payment guarantees. In another instance, although

the stated limit of the payment guarantee provided by the

buyers parent is several hundred million dollars, the

guarantee amount reduces if the buyer provides Step-In

Rights to apply to any termination of the SPA by the buyer,

namely: (i) a release of buyers capacity and associated

vaporization rights in a specified regasification terminal;

and (ii) an assignment of buyers rights under specified

shipping contracts.

Specific remedy provisions for failure to purchase or sell, as

the case may be, are now commonly found in many, but not

all, recent SPAs. Although prior contracts were often silent

on the issue, buyers limit of liability is typically

specifically stated. For instance, the limit may be a phrase

such as the payment of the Annual TOP Quantity shallconstitute the sole and exclusive remedy Sellers shall have

against Buyer for the obligation to take delivery of LNG.

On the other hand, the practice still varies, if a remedy is

stated, for sellers liability for non-performance. For

example:

In Asia, capping the sellers liability, in

effect, to a percentage of the value of the cargo not

delivered.

Providing for liquidated damages of 25% of

the total amount that would have been payable by buyer for

the quantity that was not delivered (unless the non-delivery

was due to wilful misconduct, in which case the liquidated

damages percentage increased to 35%).

If the shortfall in deliveries in a year is less

than 10 cargoes, buyer is granted a 10% discount in the

nature of liquidated damages; a stated liquidated damage

amount is payable if the shortfall exceeds 10 cargoes.

Different remedies depending, in part, on

the timing of when seller provided notice of cancellation of


15/17

delivery or of substitution of an LNG vessel with reduced

capacity.

A shortfall payment based on the average

contract price over the last 12 months, minus certain costs

saved by buyer.

The lesser of the cost to replace the gas not

delivered or 20% of the contract price.

Liquidated damages may also be payable if seller fails todeliver on a timely basis.

No major alteration in the approach to force majeure has

occurred in SPAs of this decade, although provisions are

tending to lengthen as more detail is devoted to the parties

obligations to take actions to resume deliveries of LNG (e.g.,

procuring additional shipping). Noteworthy developments

with regard to force majeure in recent SPAs are:

In SPAs providing for multiple delivery

destinations: (i) coverage of certain downstream facilitiesor events in a different manner for each receiving terminal;

and (ii) if force majeure prevents deliveries at buyers

nominated terminal, the obligation for buyer to use

reasonable endeavors to receive LNG at another LNG

terminal that seller approves (with seller having the right

to refuse to unload at such other terminal due to potential

additional cost or risk to seller, scheduling difficulties, or

safety/operational issues).

The express obligation of seller, in the

event of an accident affecting gas production, to take such

measures that are required to resume deliveries, includingnew investments and also temporary deliveries of LNG

from [other LNG terminals].

In some recent Asian contracts, the

exclusion of depletion of gas reserves from allowable force

majeure events.

Coverage of buyers downstream power

customers only for events which occur during the first 5

contract years or only while such customer is off-taking at

least a certain percentage of all of the regasified LNG sold

at the receiving terminal.

The exclusion of events affecting LNG

receiving terminals other than the scheduled receiving

terminal.

The inclusion of provisions detailing

sellers rights if a buyer force majeure occurs.

The obligation of buyer to apportion

available capacity at the receiving facility between the SPA

and other long-term contracts (i.e., having a term of at least

15 years) only.

In a recent Asian SPA, the obligation of

buyer to use reasonable endeavors to take any quantity of

LNG not taken previously as a result of Force Majeure.

The purchase and sale obligations under many, but by no

means all, SPAs of this decade are conditional on the

fulfillment of one or more conditions precedent. As is

customary, the listed events are centered aroundgovernment approvals, financing (including the

satisfaction of all conditions precedent to the initial draw-

down of funds), or the execution of ancillary contracts,

with the obligation to satisfy the condition within a

relatively short time (generally less than 6 months). In one

instance, the SPA was conditional on seller making a final

investment decision on the construction of an additional

train. The parties typically agree to use reasonable

endeavors, or at least to act in good faith, in attempting to

satisfy the stated conditions precedent. Given the shortage

of excess receiving terminal capacity over the last fewyears in some countries, one SPA specifically stated that

buyers obligations are not conditional on buyer making an

investment decision, constructing or purchasing capacity

at any receiving terminal.

As a result of pressure during 2001-2002 by the European

Commission, SPAs for supply into Europe no longer contain

destination restrictions (for example, it is reported that

Nigeria LNG undertook not to introduce territorial

restriction clauses in its SPAs signed after October 2002).

Many SPAs (especially those of an ex ship nature) forsupply into Asia continue to have some restrictions on the

ability of the buyer to alter the destination of the cargo;

however, some contracts for supply into the U.S. are

becoming more flexible (with one FOB contract mentioning

that buyer may redeliver any cargo to any LNG terminal so

long as the redelivery does not result in buyer failing to

arrive timely at the load port in accordance with the

loading schedule). Moreover, a change in destination for

deliveries to a North American port in an ex ship

agreement, in addition to requiring sellers permission to

divert, may result in the use of a pre-agreed (or agreed atthe time of the proposed diversion) alternative pricing

approach or formula.

With respect to each partys liability for an LNG accident in

the others terminal, practices in this respect remain

inconsistent. While some SPAs elect to not lay out a special

liability regime for the LNG loading or unloading port, an

Asian SPA included a detailed provision requiring buyer,

transporter, seller, and all their related associates, to sign


16/17

a separate agreement governed by English law that

implements the liability regime enunciated in the SPA.

Where under such liability provisions a party agrees to

indemnify for damages caused by such partys LNG vessels,

the limitation of liability is typically set at $150 million or

such higher amount of insurance coverage which is

available from a recognized protection and indemnity club

under usual protection and indemnity rules covering anLNG tankers liabilities while in or near docking facilities.

In some cases, a party is required to waive, on behalf of

itself and the disponent owner and charterer of the LNG

vessel, any right of such party to limit buyers liability

under applicable laws, including the Convention on

Limitation of Liability for Maritime Claims 1976.

Termination clauses, once infrequent, are now common, with

some being very detailed and several pages in length. Events

which allow termination of the long-term sales contract can

be grouped generally into those related to extended force

majeure, those related to failure to pay or deliver LNG, or

those related to other events which give rise to the partys

ability to continue to perform in the future (e.g., insolvency-

related events, credit support events). With regard to

extended force majeure, termination is now an available

remedy, generally, if the event has occurred for at least 24-36

consecutive months and the event prevented the delivery of at

least 50% of the annual contract quantity for such period. As

an alternative to termination in one instance, if only a portion

of the annual contract quantity had been affected, the party

was granted the right to reduce the annual contract quantity

under the remaining term of the SPA to in effect eliminate the

portion that was not deliverable. Failure of the seller to

deliver for non-Force Majeure events may be addressed in

several ways, including sellers (i) failure to make available an

amount of LNG of at least [__]% of the annual contract

quantity in [__] consecutive years; (ii) failure to deliver any

LNG Cargo Lot for a period of more than 120 consecutive

days; and/or (iii) delay of at least [__] in commencement of

deliveries during the first contract year. Termination for

buyers failure to make payment is normally tied to a

threshold amount (in one case, at least $100 million), whichmay be directly tied to the amount of credit security provided

by buyers guarantor. Lastly, other events which have (in at

least one instance) been added to the list of those justifying

termination of the SPA are (x) buyers failure to make

available regasification capacity equivalent to [__ billion

cubic meters] in any period of [__] years or less and (y) changes

in control of a party without the execution of documents

confirming existing credit support obligations or without a

corresponding transfer of the underlying gas supply assets.

Transfer of title, thought to be an issue long ago resolved,

has become an issue of import again in some SPAs,

especially ex ship sales when the seller is concerned with

potential liability for accidents or the parties wish to

ensure that the sale is not considered a taxable event in the

importing country. Such concerns have in more than one

instance driven the parties in ex ship sales to agree to

transfer title offshore, immediately prior to the vesselreaching the boundary line of the importing country. A host of

issues arise from such offshore title transfers, compounded by

situations in which the buyer assumes responsibility for

transportation from the offshore delivery point to the

receiving terminal and back to the offshore delivery point.

True CIF sales, in which seller retains responsibility for

transportation but buyer acquires title to LNG at the loading

port, are also a recent phenomenon in SPAs.

Lastly, the following are some additional observations

regarding SPAs signed since 2000:

Although some SPAs allow the buyer to

reject an off-spec cargo if quality non-conformance is

known soon after loading (e.g., within one day), most SPAs

commonly obligate the buyer to use reasonable endeavors

to attempt to receive the off-spec LNG (i.e., such as treating

or blending the LNG with other LNG at the receiving

terminal). In light of known quality issues in North

American and UK gas markets for todays typical LNG

specification and caps (e.g., 15% of the contract price) in

some SPAs on the amount which seller will reimburse buyer

for costs incurred in attempts to treat/blend off-spec LNG,

some of the risk associated with off-spec LNG appears to

have been transferred from seller to buyer.

Due to multiple offtakers in many loading

and unloading terminals (particularly receiving terminals

under construction which will be used by multiple

customers based on two and three day set windows for

unloading), scheduling issues have taken on increasing

complexity.

Although the LNG industry is said to be

moving to more of a commodity business, few SPAs requireseller to issue negotiable bills of lading. Instead, the

common approach remains to rely on the issuance of cargo

receipts evidencing the quantity loaded, rather than having

the effect of a document of title. However, in one late 2001

SPA, the seller is required to provide appropriate bills of

lading; if the bill of lading is not available when buyer is

obligated to pay for the cargo, the SPA requires the seller to

issue an indemnification letter in a form (attached to the


17/17

SPA) which heretofore has been utilized for shipments of

crude oil rather than for LNG.

Conclusion

This article has provided a general overview of changes to

contracting practices for representative Asian andAtlantic-basin SPAs and common alternative drafting and

risk-sharing methodologies. The 1960s concept of rather

succinct, fixed price SPAs linking a creditworthy seller

with a creditworthy buyer and using ships dedicated to a

single trade has evolved over the last four decades. SPAs

today vary in complexity, influenced by a variety of factors

such as the parties concerned and their creditworthiness

(or lack thereof), the pricing basis for LNG sold, the depth

of buyers downstream gas market and its competing fuels,

the delivery point, LNG transportation structures, take-or-

pay flexibility, whether multiple users aggravate scheduleissues, influences by gas competition regulators, concerns

of lenders, sufficiency of sellers gas reserves, and the

allocation of commercial, operational and political risks

related to performance of the agreement. Counsel drafting

and negotiating SPAs would be wise to consider both past

LNG precedent gained from decades of experience with

LNG issues and the need to develop new techniques to

appropriately deal with the multitude of challenges

presented by the rapidly expanding LNG trade.

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evolution of long-term lng sales contracts

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