Evolution of Long-Term LNG Sales Contracts:
Trends and Issues
Philip R. Weems, Partner, King & Spalding LLP
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 1960’s, 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 Atlanticbasin 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 1960’s; 11 from
the 1970’s; 9 from the 1980’s; 17 from
the 1990’s; and 21 since 2000. These
SPAs are from 14 existing or planned
exporting nations (and 2 nations which
hoped 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.
1960’s
Compared to the 14 long-term SPAs executed in 2004,
relatively few SPAs were signed in the 1960’s. 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 1960’s.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
2
law was wide, 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
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.
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 Btu’s…. [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 Buyer’s 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 “due
regard 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 Buyer’s
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 1960’s 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 seller’s loading port are frozen for the
term (25 years) at the rate existing on July 15, 1969.
●
Two SPAs are silent on demurrage (with
one 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 one
SPA 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
buyer’s “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.
●
1970’s
By the end of the 1970’s, SPAs had been signed by several
other suppliers, including Brunei, Indonesia, and Abu
Dhabi. 3 Moreover, Iran sought to become a supplier and
in 1978 executed an SPA for proposed LNG sales to
Columbia LNG in the U.S. New importers signing SPAs in
the 1970’s included European buyers in Italy and Spain
and U.S. buyers constructing terminals on the East Coast
of the United States as well as Pacific Lighting in
California (who proposed to construct a terminal in
California to receive Indonesian LNG4).
Global LNG Routes (1977) In Operation (or Approved by
U.S. Authorities) 5
Many of the SPAs completed during the 1970’s continued
to be rather succinct documents of between 25 and 40
pages; however, a few began to become more detailed and
to cover issues not addressed in prior agreements. For
example, the 1973 SPA between Pertamina and its five
Japanese purchasers (known as the “Western Buyers”)
approached 100 pages, while the 1978 Agreement for the
Sale and Purchase of Liquefied Natural Gas between the
National Iranian Gas Company, as seller, and Columbia
LNG Corporation, as Buyer, was almost 80 pages.
Ample variety continued to be reflected in the choice of
law to govern the SPA, including the laws of Japan,
France, New York, and Iran; interesting selections were
the choice of the laws of the “United Kingdom” (rather
than of England) in the 1976 Sonatrach - Distrigas SPA
and the decision in the 1973 Pertamina - Pacific Lighting
SPA to apply “generally recognized principles of private
international law, custom and practice.” International
Chamber of Commerce arbitration rules were almost
universally chosen during the decade, with venue of the
arbitration being in Japan, Paris, Geneva or Zurich; the
lone exception was the National Iranian Gas Company
SPA in which the parties selected arbitration in Tehran
under Iranian arbitration procedures.
It was during the 1970’s that a contractual term of 20
years was established as the norm. More than one
contract during this time dealt with the complication of
splitting the quantity obligation between multiple
buyers. In most instances, no credit support was deemed
necessary to guarantee the obligations of the party
executing the SPA. Nonetheless, with the unusual choice
of a company based in Bermuda to serve as seller under
the 1970 Brunei - Japan SPA, the precedent of a full
guarantee of seller’s obligation was established as Shell
Petroleum N.V. and Mitsubishi Shoji Kaisha, Limited also
signed the SPA as “Guarantors”, agreeing that “[i]f Seller
fails so to perform any of its obligations under the
Agreement, the Guarantors, acting jointly and severally
with each other, shall themselves ensure the
performance of the obligations in question and shall
perform the obligations as Guarantors.”
The use of take-or-pay clauses developed into a standard
practice. Generally, the buyer’s obligation to purchase
was stated as an annual quantity obligation, but in one
instance the buyer was required to take in each quarter
"at least 97% of one-fourth of its [annual contract]
Quantity.” Pricing of LNG remained full of variety, with
approaches such as:
●
$0.486 per MMBTU, delivered by seller
on an ex ship basis.
●
3
An ex ship price divided into an “LNG
Abu Dhabi is not reflected on the U.S. government's map, as the trade commenced later in the decade.
4
For more information, see Weems and Keenan, "Greenfield LNG Import Terminal Approvals," LNG Journal (May-June 2002) (available at
www.kslaw.com/practice_areas/energy/publications.asp).
5
Transportation of Liquefied Natural Gas, Office of Technology Assessment, Congress of the United States (1977).
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
seller’s 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 agreed
rate), 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 buyer’s 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 economic
circumstances 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 1960’s, 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 seller’s 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 Lighting’s 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 at
its 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 into
account 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 1970’s are
as follows:
A distinguishing characteristic between
force majeure under some Asian SPAs and those from
●
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.
●
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 Algeria’s SPAs with France were
25 year agreements. The average length of SPAs began to
approach 75 pages (though Algerian SPAs continued to fall
in the 40 page range).
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 seller’s 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 years
evolved 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 liabilities 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 LNG
transporter) was the determining factor, with no stated
financial limit for such liability exposure.
1980’s
Indonesia and Algeria dominated this decade, signing the
vast majority of executed SPAs.6 However, the 1980’s did
see the emergence of new supplies from Malaysia and
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
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 socalled “Make-Good” provisions). Interestingly, as the decade
drew to a close and lower oil prices brought on more of a
buyer’s 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 1960’s and 1970’s, few
specific remedies applicable to seller’s 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 Buyer’s 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 the
event 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 almost
25 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 1980’s 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
●
ex ship contracts to not take any action which would lead to
seller having a permanent establishment in buyer’s country.
In place of an unrestricted indemnity for taxes in the buyer’s
country, in some cases the seller agreed to “use its best
efforts to cease to be subject to [the importing country’s]
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 party’s
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.
●
●
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
seller’s 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 buyer’s assertion that buyer is
excused from taking LNG due to a force majeure event.
●
1990’s
The 1990’s 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.
●
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 was
delayed. 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.
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).
The length of SPAs signed during the 1990’s 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 1990’s 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 $13
billion. 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 purchase”
the 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-pay
quantity 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 Buyer’s 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 seller’s 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).
imported in Japan; however, the price automatically
adjusts upon a 5% differential between the contract price
and pricing under buyer’s existing SPAs for Middle East
LNG supplies.
Aside from the SPA mentioned above, the 1990’s 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 buyer’s
credit. The importance of the soundness of contractual
arrangements increased as sellers had to find comfort that
buyer would perform by examining the soundness of
buyer’s 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
buyer’s guarantor being able to limit its parent guarantee
amount, the seller limited its maximum liability.
Extensive remedies clauses became more fashionable
during the 1990’s. 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 seller’s 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 seller’s liability, 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 the
discharge 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 boiloff 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 seller’s liability, liquidated damages
of 25% of the average contract sales price multiplied by the
shortfall quantity.
●
●
As to buyer’s liability, confirmation that
“Buyer’s 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 a
force majeure event as an “event occurring outside the
party’s 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
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 buyer’s 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 during
the 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
buyer’s facilities if damage or failure resulted from gross
negligence on the part of buyer’s 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 purchases
between 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
seller’s LNG facilities, each in form acceptable to seller in
seller’s sole discretion; and (b) made an affirmative final
investment decision, in its sole discretion, to construct, own
and operate seller’s proposed LNG facilities.
Destination restrictions lingered in SPAs of the 1990’s,
with the following being representative of the effects of
such restrictions:
“… all LNG sold hereunder shall be for Buyer’s
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 Discharge
Port or with the LNG Ship, in which case, Buyer may
change the discharge destination to another
suitable port in [Buyer’s country]. Should Buyer
wish to change the destination to a port outside
[Buyer’s country] in accordance with the foregoing,
Buyer must first secure Seller’s 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 contracts
were 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 “nonlegal 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
strict liability under the law or by contract) on the
part of any of the parties, including Ship Owner
against which it is brought, 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 the
interest of all the parties, including Ship Owner, and
preserving the smooth operation of the matters
contemplated in this Agreement.”
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.
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.”
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.
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 several
pages of the agreement. For example, in one instance buyer
is specifically authorized to terminate the SPA if (a)
construction of Seller’s 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 seller’s 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 Seller’s
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
11
Lastly, during the 1990’s yet another scheduling year was
established, with Trinidad contracts adopting an October 1 to
September 30 contract year.
2000’s
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.
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 GIIGNL
reports were signed in 2004, 10 of these were for an annual
volume of less than one million ton per annum.
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 excluding
technical 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
At least two significant public SPA disputes have occurred
since 2000. First, as a result of the failure of Enron’s 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 Duke’s contract for the sale of the
Algerian 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.dukeenergy.com/investors/publications/sec.asp).
that Duke LNG’s 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 buyer’s
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 market’s 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].…”
seller’s right to reduce the annual quantity for major
scheduled maintenance of seller’s facilities or its vessels; (iv)
buyer’s right to reduce the annual quantity for major
scheduled maintenance of buyer’s facilities or its vessels or
due to “operational constraints at [a third party’s LNG import
facilities]”; (v) seller’s right to reduce the annual contract
quantity due to inadequate gas reserves or deliverability
from the defined gas supply area; (vi) adjustments due to
differences 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 provisions
in one recent SPA approach 25 pages, in part to address
separate rules for seller’s 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
It is not uncommon for an SPA to now address quantity
adjustments in relation to a multitude of circumstances,
such as: (i) buyer’s 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) seller’s ability, upon Buyer’s
agreement, to reduce the annual quantity for a “Seller’s
Diversion” (i.e., a diversion from delivery to buyer); (iii)
16
www.abareconomics.com/australiancommodities/june05/pdf/asiapacificlng.pdf.
While the Indonesian SPAs of the 1990’s 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 deliveries
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.”
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.”
●
●
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 receiving
terminal 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 to
maximize 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
Buyer’s … 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 Platt’s 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
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
buyer’s 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
buyer’s 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 buyer’s capacity and associated
vaporization rights in a specified regasification terminal;
and (ii) an assignment of buyer’s 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, buyer’s limit of liability is typically
specifically stated. For instance, the limit may be a phrase
such as “the payment of the Annual TOP Quantity… shall
constitute 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 seller’s liability for non-performance. For
example:
In Asia, capping the seller’s 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
●
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 to
deliver 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 facilities
or events in a different manner for each receiving terminal;
and (ii) if force majeure prevents deliveries at buyer’s
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”, including
“new 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 buyer’s 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
seller’s 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 around
government approvals, financing (including the
satisfaction of all conditions precedent to the initial drawdown 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 few
years in some countries, one SPA specifically stated that
buyer’s 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) for
supply 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 seller’s permission to
divert, may result in the use of a pre-agreed (or agreed at
the time of the proposed diversion) alternative pricing
approach or formula.
With respect to each party’s liability for an LNG accident in
the other’s 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
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 party’s 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 an
LNG tanker’s 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 buyer’s 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 party’s
ability to continue to perform in the future (e.g., insolvencyrelated 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 seller’s (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
buyer’s failure to make payment is normally tied to a
threshold amount (in one case, at least $100 million), which
may be directly tied to the amount of credit security provided
by buyer’s 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) buyer’s 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 vessel
reaching 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 today’s 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.
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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 require
seller 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
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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 and
Atlantic-basin SPAs and common alternative drafting and
risk-sharing methodologies. The 1960’s 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 buyer’s downstream gas market and its competing fuels,
the delivery point, LNG transportation structures, take-orpay flexibility, whether multiple users aggravate schedule
issues, influences by gas competition regulators, concerns
of lenders, sufficiency of seller’s 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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