IELR - DECOM NET COST NET VALUE

Decommissioning in
the UK Continental
Shelf:
Decommissioning
Security Disputes
Ben Holland
Squire Patton Boggs
Michael Davar
Squire Patton Boggs
Decommissioning; Installations; Oil and gas industry;
Security
Introduction
This is the first year in which the full impact of the oil
price decrease has been factored in the annual
decommissioning security process. Whether sufficient
security has already been or ought to now be placed in
trust is an area raising significant concern in the industry.
Against a backdrop of historic collaboration and practical
co-operation, disputes about the calculation of the amount
of security that ought to apply in anticipation of
decommissioning have begun to arise.
Decommissioning Security Agreements (DSA) have
evolved as a reaction to the extensive and continuing
liability created by the Petroleum Act 1998 as amended
by the Energy Act 2008. This regime provides that all
current and former co-licensees will be jointly and
severally liable for any decommissioning costs. DSAs
were, if executed appropriately, to provide the necessary
mutual protection needed to ensure that, if one party to
the DSA falls into financial difficulty, its security is called
upon and the funds are held in a trust until
decommissioning is completed.
This article focuses on whether the sustained decrease
in the oil price will result in insufficient security to cover
escalating decommissioning liabilities. As a result of
current market conditions, there has been an increase in
requests for data, closer scrutiny of operator projections
and a heightened risk of disputes about “net value” and
“net costs”, which are normally resolved through expert
determination.
The increasing focus on
decommissioning
Decommissioning activity is gaining increasing
momentum in the UK. In 2015, 50 per cent more fields
ceased production than anticipated at the start of the year1
.
The number of decommissioning programmes now
approved includes: the Murchison Field, for which the
decommissioning programme was approved in 2014; the
Brent Delta Platform, for which the decommissioning
programme was approved in 2015; Thames Area, for
which decommissioning programmes were approved in
2015; and the Leadon Field, for which decommissioning
programmes were approved in 2016. In addition, an ever
increasing number of decommissioning programmes are
under consideration. These currently include the Viking
Satellites CD, DD, ED, GD and HD, the Athena Field,
Markham ST-1 and Janice, James & Affleck Fields.
According to Oil & Gas UK’s 2016 Activity Survey, it
is expected that approximately 80 fields will cease
production over the next five years, equalling almost 30
per cent of the total number of fields currently in
production.2
With revenue projections having fallen and cessation
of production (CoP) dates brought forward, previously
healthy-looking security balances may now seem
marginal.
Decommissioning Security Agreements
(DSAs)
Under ss.293
and 304
of the Petroleum Act 1998, the
secretary of state may, by written notice, make a wide set
of participants connected with or interested in a particular
installation jointly and severally liable for all
decommissioning costs of that installation.
To deal with this extensive and overlapping liability,
the industry has developed DSAs, whereby each
participant agrees to deposit cash or, normally, another
type of security, such as letters of credit, into a trust. That
trust operates to pay the costs of decommissioning when
1
Oil & Gas UK, Activity Survey 2016, p.52.
2
Oil & Gas UK, Activity Survey 2016, p.52
3
Section 29(1) of the Petroleum Act 1998 states: “The secretary of state may by written notice require (a) the person to whom the notice is given; or (b) where notices are
given to more than one person, those persons jointly, to submit to the secretary of state a programme setting out the measures proposed to be taken in connection with the
abandonment of an offshore installation or submarine pipeline (an ‘abandonment programme’).”
4
Section 30(1) of the Petroleum Act 1998 states: “A notice under section 29(1) shall not be given to a person in relation to the abandonment of an offshore installation
unless at the time when the notice is given he is within any of the following paragraphs (a) the person having the management of the installation or of its main structure;
(b) a person to whom subsection (5) applies in relation to the installation; [(ba) a person to whom subsection (5)(a) and (b) applied in relation to the installation, but who—(i)
transferred the right mentioned in that subsection to another person, and (ii) has not obtained a consent required under the licence in relation to the transfer;] (c) a person
outside paragraphs (a) and (b) who is a party to a joint operating agreement or similar agreement relating to rights by virtue of which a person is within paragraph (b); (d)
a person outside paragraphs (a) to (c) who owns any interest in the installation otherwise than as security for a loan; (e) a [body corporate] which is outside paragraphs (a)
to (d) but is associated with a [body corporate] within any of those paragraphs.”
Section 30(5) of the Petroleum Act 1998 states: “This subsection applies to a person in relation to an offshore installation if—[(a) the person has the right—(i) to exploit or
explore mineral resources in any area, (ii) to unload, store or recover gas in any area or to convert any natural feature in any area for the purpose of storing gas, or (iii) to
explore any area with a view to, or in connection with, the exercise of a right within sub-paragraph (i) or (ii), and] [(b) either—(i) any activity mentioned in subsection (6)
is carried on from, by means of or on the installation, or (ii) the person intends to carry on an activity mentioned in that subsection from, by means of or on the installation,]
or if he had such a right when any such activity was last so carried on.”
240 International Energy Law Review
2016 I.E.L.R., Issue 6 © 2016 Thomson Reuters (Professional) UK Limited and Contributors

the time comes. If a party falls into financial difficulty,
the security provided is intended to be sufficient to cover
that party’s share of decommissioning costs.
Parties to a DSA include:
(1) First-tier Participants—
this group will be composed of co-venturers
under a JOA. Each member of this group
will provide security for the upcoming
decommissioning programme;
(2) Second-tier Participants—
this group will be composed of those at risk
of being caught by the extensive
decommissioning regime. Such participants
include oil & gas companies that sold their
interest in the field, often many years ago.
Second-tier Participants typically remain
party to the DSA to ensure that sufficient
ongoing security is provided by the
First-tier Participants;
(3) Third-tier Participants—
these are not parties to the DSA, but can,
by agreement, enforce the terms of the DSA
using benefits derived under the Contracts
(Rights of Third Parties Act) 1999; and
(4) The secretary of state—
if there is concern that those liable for
decommissioning will be unable to
discharge their decommissioning
obligations; the secretary of state may, for
surveillance and enforcement reasons,
become party to the DSA.
How Decommissioning Security
Agreements operate
By avoiding duplication of security, DSAs facilitate the
transfer of mature fields from established companies to
smaller participants with limited financial recourses.
Where an interest in a field or structure is sold, the seller
will be concerned about its continuing and perpetual
liability to carry out decommissioning. For this reason,
it is likely to require security from the purchaser. Oil &
Gas UK has produced a standard-form DSA which has
recently been updated to take account of
Decommissioning Relief Deeds (DRDs), together with
updated guidance notes (the DSA Guidance Notes) to
capture industry practice.5
The Oil & Gas UK
standard-form JOA suggests that the JOA parties enter a
DSA before submitting a development plan for the field.
Under such DSA, each participant in a JOA will agree
to pay cash or other types of security into a trust, held
until the end of the decommissioning process. The share
of decommissioning costs will usually, but not always,
correspond with a participant’s participating interests
under the JOA.
DECC, which in mid-July 2016 was replaced by the
Department for Business, Energy and Industrial Strategy
(BEIS), recognises that “the over-riding aim of a DSA is
to ensure that guaranteed funds will be available to cover
the decommissioning costs at all times”.6
However, it
remains to be seen whether DECC (now BEIS) and/or
the parties to the DSA will meet this objective. Certain
industry commentators are concerned that DECC (now
BEIS) failed to adequately monitor the methodology
underpinning the amounts paid by participants under
DSAs, leading to a historic under-provision in
decommissioning security.
Impact of the oil price on
decommissioning security
A field that was economically viable when the oil price
was at US $100 per barrel is likely, at the current oil price
of US $40–50, to no longer be viable or only be viable
for a significantly shorter estimated field life.
Decommissioning security, which could previously be
spread over numerous years of ongoing production, can
now only be spread over a much shorter timeframe. More
security has to be put aside each year. This is occurring
at a time when oil & gas operators are under significant
pressure from drastically reduced revenue streams. In
addition to there being fewer years of revenue from the
field from which security can be drawn, decommissioning
may now take place far earlier than previously estimated.
The recently established Oil & Gas Authority (OGA)
and the UK Continental Shelf Maximising Economic
Recovery (UK MER) strategy have only caused further
uncertainty.
UK MER7
provides as follows:
(a) in the introductory sentence: “a. all
stakeholders should be obliged to maximise
the expected net value of economic
recoverable petroleum from relevant UK
waters … c. compliance with the Strategy
may oblige individual companies to allocate
value between them, matching risk to
reward. However, while the net result
Section 30(6) of the Petroleum Act 1998 states: “The activities referred to in subsection (5) are—[(a) the exploitation or exploration of mineral resources in the exercise of
the right mentioned in subsection (5)(a); (aa) the unloading, storage or recovery of gas in the exercise of that right; (ab) the conversion, in the exercise of that right, of any
natural feature for the purpose of storing gas; (ac) the exploration in exercise of that right with a view to, or in connection with, the exercise of a right within subsection
(5)(a)(ii);] (b) the conveyance in the area so mentioned, by means of a pipe or system of pipes, of minerals got, or gas being stored or recovered, in the exercise of that right;
and (c) the provision of accommodation for persons who work on or from an installation which is or has been maintained, or is intended to be established, for the carrying
on of an activity falling within paragraph (a) [to (b)] or this paragraph.”
5
References are to the September 2013 version, www.oilandgasuk.co.uk [Accessed 19 August 2016].
6
DECC, Decommissioning of Offshore Oil and Gas Installations and Pipelines under the Petroleum Act 1998, Guidance Notes (Version 6, March 2011), Annex G, para.2.
7
The Maximising Economic Recovery Strategy for the UK; Presented to Parliament pursuant to Section 9G of the Petroleum Act 1998 as amended by the Infrastructure Act
2015.
Decommissioning in the UK Continental Shelf: Decommissioning Security Disputes 241

should deliver greater value overall, it will
not be the case that all companies will
always be individually better off …” (our
emphasis)8
;
(b) under para.7, defining the central obligation
under UK MER: “Relevant persons must,
in the exercise of their relevant functions,
take the steps necessary to secure that the
maximum value of economically
recoverable petroleum is recovered from
the strata beneath relevant UK waters” (our
emphasis)9
;
(c) under para.14: “… relevant persons must
give due consideration to: … b. whether or
not any infrastructure already in existence
could be used in such a way as to reduce
costs or otherwise increase the recovery of
economically recoverable petroleum from
the region. This includes consideration as
to whether any such infrastructure (whether
proposed to be constructed or already in
existence) could be so used if reasonable
adjustments were to be made to it” (our
emphasis)10
;
(d) under para.16: “Owners and operators of
infrastructure must ensure that it is
operated in a way that facilitates the
recovery of the maximum value of
economically recoverable petroleum from
(as applicable): a. the region in which it is
situated; and b. where the infrastructure is
used by or for the benefit of others, the
regions in which those others are
situated”11
;
(e) under para.20: “Before commencing the
planning of decommissioning of any
infrastructure in relevant UK waters,
owners of such infrastructure must ensure
that all viable options for their continued
use have been suitably explored, including
those which are not directly relevant to the
recovery of petroleum such as the transport
and storage of carbon dioxide”; and
(f) under para.22: “Where the OGA produces
a plan… which relates to the obligation in
paragraph 20, it may identify particular
pieces of infrastructure the
decommissioning of which would prejudice
the maximising of the recovery of
economically recoverable petroleum in a
region.” (Our emphasis.)12
Although MER UK provides certain safeguards, it is clear
from the provisions set out above that operators seeking
to decommission their economically unviable assets may
face barriers in doing so. This is particularly the case for
offshore infrastructure that, as a result of their
interconnectivity, if decommissioned, may result in a
decommissioning domino effect on neighbouring
installations and tie-ins, thereby decreasing the “expected
net value of economic recoverable petroleum from
relevant UK waters”.13
For such “critical” infrastructure, what CoP date should
be used? What would the revenues be (if any) and who
are to bear the costs of maintaining such infrastructure?
Should such potential costs even be included in
decommissioning security calculations? If so, how are
they to be estimated?
The magnified impact of decreased revenues, increased
costs, short CoP timeframe and uncertain variables has,
for the first time, caused those seeking to protect
themselves from potential liability to carefully scrutinise
both the current level of decommissioning security in
place and the calculations by which the level of future
security is defined.
Decommissioning security disputes
The standard-form DSA requires that every year all of
the First-tier Participants pay their respective share of:
(a) “net costs” (representing an amount equal to the best
estimated cost of performing all decommissioning
activities multiplied by a risk factor); less (b) “net value”
(representing an amount equal to expected production
receipts from the field) and the amount of security that
the participant has already provided.
Both net cost and net value are assessed on a net
present value (NPV) basis. Where the NPV of the net
cost exceeds the NPV of the net value, security is required
to cover the difference. As production continues, the
intention of the DSA is that the amount of security
increases so that it fully funds decommissioning at CoP.
As a result of prior beneficial market conditions,
numerous industry participants consider that, historically,
optimistic assumptions as to future “net value” have been
made. By making such optimistic assumptions of “net
value”, the security required to meet estimated “net costs”
has been less year-on-year, resulting in serious
under-provision of decommissioning security. This
approach, on the part of First-tier Participants, can be
explained by their wish to free up cash to invest in
production activities or to reduce the asset retirement
obligation required so as to leverage themselves further
or position themselves for sale.
8
The Maximising Economic Recovery Strategy for the UK , p.2.
9
10
The Maximising Economic Recovery Strategy for the UK , pp.4–5.
11
12
13

Current depressed market conditions have caused
Second-tier Participants (those benefitting from the
security without paying in themselves) to become
concerned with the adequacy of the security in place.
Depressed production revenue due to falling oil and gas
prices is causing Second-tier Participants to seek higher
levels of security. Second-tier Participants that sold their
interest many years ago are liable to contribute to
decommissioning costs if the First-tier Participants
default. Optional language under the standard-form DSA
governs whether Second-tier Participants have a right to
approve the operator’s proposals or merely comment on
them.
These requests for additional security from Second-tier
Participants are coming at a time where falling revenues
and increasing costs are impacting on First-tier
Participants’ ability to provide the greater levels of
security sought. In addition, not all of the First-tier
Participants will have the same funding profile. Parties
to a JOA may legitimately take differing positions on the
assumptions made by the operator. This is particularly
the case for those First-tier Participants who are highly
leveraged through reserves-based lending.
For these new-entrant oil and gas operators, providing
suitable estimates is, on a practical note, an unenviable
task. Not only is calculating accurate decommissioning
estimates, no matter how carefully done, not an exact
science, but smaller oil and gas operators, who are keen
to match costs to revenues, have also reduced investment
in much needed personnel (such as specialist engineers)
and technology (such as decommissioning software).
Decommissioning Relief Deeds (DRD)
DRDs permit security to be provided on a post-tax basis.
Security is, as a result, no longer being paid in at a
(higher) pre-tax relief basis. Since October 2013, when
DRDs were introduced, a reduction in both any previously
existing decommissioning security “buffer” that resulted
from payments having been made on the (higher) pre-tax
relief basis, and the absolute amount of security set aside
has arisen. This is, unless, of course, a higher risk factor
has been applied to net costs.
A higher net cost risk factor, however, is unlikely to
have been applied. First-tier Participants, incentivised to
maximise cash flows, are likely, where possible, to have
used lower risk factors, higher reserve estimates and other
metrics to reduce the level of decommissioning security
due under a DSA. Second-tier Participants may have been
comfortable with lower estimates for the calculation of
security due to net costs having been calculated on a
pre-tax basis and making forward assumptions based on
the vibrant oil and gas market at the time. The move to a
post-tax calculation of net costs has exacerbated this
historic under-provision of security.
The recalculation and review of decommissioning
security calculations is now being carefully monitored
by both co-venturers and by Second-tier Participants.
There has been an increase in requests for data, closer
scrutiny of projections of “net value” and “net costs”, and
a greater interest in the use of expert determination in the
event that the participants cannot agree.
Disputes over the calculation of net cost
Net cost represents the best estimated cost of performing
all decommissioning activities at the time at which they
can be best expected to need to be performed. There is
significant scope for disputes over this calculation.
(a) When will decommissioning occur?
A core assumption input into the calculation of net cost
is the expected date of decommissioning. The estimated
date for decommissioning has a significant impact on the
level of security to be provided. The hope that ageing
infrastructure might find alternative economically viable
uses, as some structures (particularly pipelines) could be
used via tiebacks and brownfield developments, currently
seems challenging in the current low oil price
environment. Of course, decommissioning may now be
delayed if such infrastructure is required by the OGA to
be maintained in accordance with UK MER. However,
there is no guarantee that this will be economical.
Other new technology such as enhanced oil recovery
(EOR) could also have postponed the date of
decommissioning, but this is also only made economic
by high oil prices. These possible ways to reduce net cost,
which could have been discounted back (through the NPV
calculation) so as to reduce the amount of security
required (and also to have postponed the trigger date for
provision of security) are unlikely to be viable. This is
significant, because these assumptions might legitimately
have been included in previous calculations, made when
the oil price was higher. Disputes are arising wherever
these assumptions are being reversed out and falling oil
prices are bringing the expected date of decommissioning
forwards. Where optimistic assumptions have been made,
inadequate security is likely to be provided.
(b) What is the scope of decommissioning?
There are many different forms of installation. Most
installations will require an individually tailored and
untested method of decommissioning. With so many
variables, how accurate can the “net cost” calculation be?
It is common to underestimate decommissioning costs.
For example, the decommissioning close out report of
the Fife, Fergus, Flora and Agnus Fields highlights that
costs overran by approximately 20 per cent.14
14
Fire, Fergus, Flora and Angus Fields Decommissioning Programmes Close-Out Report, p.32.

Further scope exists for disputes over whether net
costs should be based on a “left in place” basis for
installations capable of attaining a derogation.15
Adopting
this approach would reduce net cost. DECC guidance
suggests it is likely to require the decommissioning costs
for large concrete structures to be estimated on this basis.16
For example, such a derogation would be likely for the
Brent field platforms (Bravo, Charlie and Delta) which
consist of concrete gravity-based structures (GBS)
weighing 300,000 tonnes each.17
Derogations may, however, become less common due
to advances in technology, and if this approach changes
net cost may increase significantly.18
On the other hand,
concerns about the carbon budget of extensive
decommissioning operations, where every component is
laboriously cut up and sorted onshore, may alternatively
lead to more derogations being granted. It is easy to see
how there is scope for disputes as to the most appropriate
estimate to be used.
(c) What is the proper risk factor to apply?
The Oil & Gas UK standard-form JOA provides for the
use of a risk factor in the security calculation. This is to
provide a degree of caution against possible rises in
decommissioning costs.19
Net cost estimates will usually
be prepared on a P50 basis. This assumes that there is an
equal chance of there being under-spending or over
spending as against the costs estimate. The risk factor
reflects uncertainties about the net cost estimate. The risk
factor may not always have been calculated, or updated,
in a fully statistically rigorous manner. These uncertainties
should reduce with time as the operator obtains a better
understanding of these costs, and optional language in
the DSA allows the contingency to be increased or
reduced in a stepped process. Presently, the ease with
which this variable can legitimately be changed is making
it a target for attention and a prominent source of disputes.
Disputes over the calculation of net
value
Net value represents the best estimated production and
other receipts from the field for so long as it is estimated
that the field will remain in production. There is
significant scope for disputes over this calculation.
(a) What oil and gas prices to use?
Fluctuating oil prices will have a significant impact on
net value. Regular recalculations may lead to periodic
changes as oil and gas prices rise and fall. Assumptions
as to future oil and gas prices should be clearly stated in
the DSA.20
Published indices for oil and gas prices will
need to be agreed. Any gas price indexation formula
contained in any existing gas sales contract should be
used when calculating future gas revenue.21
Essential to this calculation is the date on which
production will cease. With so many variables, even slight
adjustments can give rise to very significant variances
between the parties. Since the introduction of DRDs, net
revenues and net costs are normally inputted on a post-tax
basis. This includes royalties, corporation
tax/supplemental charge, and any PRT that is applicable.
Recent changes to these taxes will need to be taken into
account. Net value does, however, also take into account
any tax relief or grants given or expected to be given
unrelated to the costs of decommissioning. The operator
is required to perform two calculations, one with and one
without the effect of the relief.
(b) What reserves data should be used?
Optional language under the standard-form DSA governs
whether only reserve estimates approved by the Joint
Operating Committee are to be used to calculate net value,
whether the operator’s best estimates, acting as a
reasonable and prudent operator, are adequate, or other
alternatives.22
Commonly, newer entrants into the UKCS
will seek to maintain the level of reported reserves. There
is concern that this may lead to the reserves estimate used
in the calculation of net value being optimistic, which
would result in the understatement of security. Without
clear drafting, there is significant scope for disputes on
these assumptions.
(c) How to account for tiebacks and other
revenue?
Many fields receive significant revenues from tariff and
other receipts from third parties, such as tiebacks. As
these form revenue from the field, absent express
provision in the DSA to the contrary, they should be
included. A dispute may emerge as to the degree of
certainty required that these receipts will accrue. On one
extreme, it is arguable these receipts should only be taken
into account in situations where send-or-pay arrangements
ensure that such tariff income is secured. On the other,
such tariff income can be taken into account even though
no agreement has been concluded, or where such
agreement has been concluded but is of only a limited
15
A limited number of installations may be eligible for derogation from the prohibition on the dumping, or leaving wholly or partly in place, of offshore installations.
Derogation will only be granted where it is a preferable means of disposal than reuse, recycling or disposal on land.
16
DECC, Decommissioning of Offshore Oil and Gas Installations and Pipelines under the Petroleum Act 1998, Guidance Notes (Version 6, March 2011), Annex F, para.14.
17
Oil & Gas UK Activity Survey 2015, p.69.
18
Oil & Gas UK Decommissioning Security Agreement Guidance Notes (March 2009), p.38.
19
20
21
Oil & Gas UK Decommissioning Security Agreement Guidance Notes (March 2009), p.39. However, see below in relation to concerns as to confidentiality.
22
Oil & Gas UK Industry Model Form Decommissioning Security Agreement (September 2013), App.5, para.7.10. See also Oil & Gas UK Decommissioning Security
Agreement Guidance Notes (March 2009), p.39.

duration, so long as there is no other route to export for
the tieback. The standard-form DSA contains options to
address these alternatives.23
Expert determination under DSAs
Under the Oil & Gas UK’s standard-form DSA, the cost
estimation based on the foregoing forms an important
part of an operator’s decommissioning schedule and
budget (the Proposed Plan). The operator will submit the
Proposed Plan for approval under the JOA. Disputes may
be referred to determination by an expert, if:
• the Proposed Plan submitted and/or
performed by the operator is challenged;
• the operator fails to produce the Proposed
Plan or perform the cost estimation; or
• the operator’s determination that
decommissioning has been completed is
challenged.
An expert is also engaged when the cost estimation
performed by the operator needs to be independently
reviewed, even where no dispute exists between the
parties to the DSA. To address this last issue, the
standard-form DSA provides options that allow: (i) for a
review of the net cost, net value and—where a DRD
applies—PRT relief, calculations by an expert at regular
intervals; or, alternatively, (ii) to have less frequent
reviews initially followed by annual reviews later in the
field life. A provision that a review is triggered if the
operator believes that there has been a change in net cost
or net value over an agreed tolerance may also be
included.
(a) Identifying the right expert
As decommissioning involves a variety of specialised
and technical stages, any expert chosen may need
assistance from multiple specialist disciplines, such as
reservoir engineering, offshore engineering, process
engineering, drilling, subsea contractors, heavy-lift/barge
contractors and disposal/refurbishment contractors. The
standard-form DSA provides for this and allows the expert
to obtain technical and legal advice.
If multiple expert disciplines are engaged, the expert
will need to rely on and assess the views of several other
experts, not just rely on his own qualifications and
experience. These views would all need to have been
commissioned,24
provided to and then considered by the
expert before the preliminary decision can be released.
Delay in any of the technical elements would prevent
further progress.
It may also be hard for the parties to have confidence
that the expert, even with this technical assistance, can
manage all technical and procedural aspects. This is
particularly the case if any party is seeking to elongate
the process, for example by referring the expert to greater
and greater volumes of documents that are said to be
relevant.
In the construction industry, where multiple
specialisms are often involved, a trend towards the
appointment of legally qualified adjudicators rather than
those with engineering qualifications has evolved. Given
the similarities, it shall be seen whether the offshore
decommissioning industry finds it preferable to appoint
legally trained experts possessing relevant UKCS
decommissioning experience, who can request technical
assistance from relevant disciplines. The legal and
procedural expertise, for example familiarity with hearing
the parties, determining questions about admissibility of
documents, setting submission deadlines and weighing
up competing evidence, may be preferable to assist good
governance of the procedure in complex multiple
disciplinary cases.
(b) Appointment of the expert
Following any required negotiations stipulated in the
DSA, a reference to an expert can be made. For challenges
to the Proposed Plan (but not for other challenges), the
standard-form DSA limits the right to refer the matter to
the expert to the party objecting to the Proposed Plan (the
Objecting Party). This might present difficulties for the
operator, who would not appear to have the right to refer
the matter to the expert should the Objecting Party fail
to do so. Nor, absent either unanimity or determination
by the expert, can the Proposed Plan become approved.
It may be necessary to apply to court for an order that the
Objecting Party refer the matter to the expert or, in
default, be deemed to have done so. Conversely, under
the standard-form DSA only the operator can submit the
cost estimation for independent periodic review. However,
if the operator upon notice to do so fails to promptly
comply, any other party to the DSA may itself refer the
cost calculation to the expert.
The standard-form DSA contains options for
appointment of the expert: either the expert will be
selected by unanimous vote of the parties to the DSA, or
each party to the DSA will nominate three candidates
who are ready, willing and able to act. Those candidates
will then be scored by all parties to the DSA in order of
preference. The expert need not be an individual
person—a firm and company can be appointed. The expert
may not have “any financial or personal interest in the
result”. This restriction is very wide and does not allow
for nominal shareholdings or for the expert to have
financial connections to the parties. Coupled with the
absence of immunity from suit, this may deter acceptance
of the appointment. Many candidates with experience of
decommissioning are likely to work for the main offshore
contractors, and connections to some of the parties in
dispute may be probable. If agreement on the selection
of the expert is not possible within 10 business days, the
23
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Commissioned by the expert (normally with the approval of the parties in dispute).

standard-form DSA allows any party to the DSA to apply
to the President of the Energy Institute to appoint the
expert. The Energy Institute is a reliable and effective
appointing authority.
(c) The scope of the expert’s power
Expert determinations, despite being capable of quickly
and effectively resolving technical disputes, do not,
without specific provisions to the contrary, require:
• adherence to rules of natural justice, such
as the right to a hearing;
• the expert to come to decisions within
(rather than outside) the range suggested
by the conflicting parties; or
• the expert to be independent of the parties.
Unless agreed otherwise, which for obvious reasons it
often is, decisions of experts are binding even in the
presence of fraud or manifest error. Decisions of experts
are also binding in instances where the expert sets about
answering the wrong question. This introduces a degree
of uncertainty in the process. The standard-form DSA
seeks to limit this, by requiring that an Objecting Party
express a stated written objection. In any challenge to the
Proposed Plan (but not the operator’s determination of
completion of decommissioning), the expert must consider
and determine this area of concern. The expert cannot
step beyond the scope of this challenge in order to
re-determine other elements. Limiting the expert in such
a way also seeks to limit the cost of the expert process.
In practice, parties may seek to raise additional statements
of objections at a later stage in proceedings. Judicious
use of the expert’s power to control the procedure of the
determination will be necessary in deciding whether
supplemental statements of objections are permissible
and within what time frame.
(d) Procedural matters for determination by
the expert
The standard-form DSA suggests that the parties to the
DSA agree carefully defined assumptions which the
operator must apply in drawing up the Proposed Plan and
which the expert must also follow. These may be
contentious and will be subject to individual negotiation
between the parties to the DSA. In addition to the
assumptions, it is common practice in expert
determinations for an expert and all those appointing him
to sign terms of reference further specifying the expert’s
obligations and remuneration.
In relation to documents, a significant hurdle to be
overcome in practice is the task of supporting the
operator’s assumptions with corroborative material, much
of which will be confidential. Revealing information
about gas sales prices, day rates, etc. to other industry
participants might also infringe competition law. Unlike
arbitration, it is not fatal to the integrity of an expert
determination for the parties in dispute to agree to provide
documents to the expert without copies to other parties;
however this may not be an ideal solution in many cases.
(e) Timing
Very speedy determination is envisaged under the
standard-form DSA. It is desirable for any reference to
the expert to be completed in time to allow security to be
replaced before existing security expires. Otherwise,
interim invoices may need to be raised. The expert must
notify the operator of his preliminary decision within 30
business days of acceptance of his appointment. The
parties will then be given 10 business days to make
representations. The expert must, having taken account
of such representations, reach his final decision within
30 days of notification of his preliminary decision to the
operator.
There is potential for references to an expert to have
a very broad scope. The timings envisaged may not,
however, be feasible, particularly for large or
multi-installation assets, or for the review of the first cost
estimation for the installation.
(f) The expert’s determination
The determination can be valid even if only a simple value
or date (as appropriate) is determined, unless a reasoned
determination has been agreed to be given. If the expert
determines that greater security be paid than estimated
by the operator, that additional security is required to be
paid.
(g) Costs of the expert determination
Options exist in the standard-form DSA for payment of
the expert’s fees and expenses depending on the nature
of the dispute being referred. The starting premise,
however, is that the Objecting Party pays. Options also
exist in relation to the recovery of a party’s own legal and
other costs, which will be the subject of individual
negotiation.
Conclusion
Decommissioning security is becoming a topic of
increased concern. Given current market conditions,
unexpected levels of additional decommissioning security
may significantly impact participants’ financial
capabilities. This is particularly in respect of highly
leveraged new entrants.
There is much scope for disagreement over the amount
of security that is contractually required. Uncertainty
surrounding the accuracy of the variables involved in
calculating decommissioning security has increased due
to the fall in market prices. Participants are more likely
to take different positions on the inputs and accuracy of
all the variables involved.

Larger and smaller participants may now have
diverging incentives. The ability of many participants to
access the necessary funding is in doubt. Sensitive
commercial negotiations are being undertaken, and
securing the unanimous approval from all First and
Second-tier Participants of the amounts of
decommissioning security to be paid is now harder to
achieve. All this is resulting in the dispute resolution
procedures governing decommissioning security being
put to the test.

IELR - DECOM NET COST NET VALUE

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