O I L & G AS I N D U ST RY
Current Oil & Gas Topics
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
Winter 2005, Issue 4
Congress Passes
Corporate Tax Legislation
By Elizabeth Wagner and
Katherine M. Breaks, KPMG LLP
In This Issue
In October, Congress passed the most
designed to be economically equivalent
significant piece of business tax legisla-
to a three-percentage point reduction in
tion since the Tax Reform Act of 1986.
the tax rate on U.S. based production
The American Jobs Creation Act of 2004
(H.R. 4520) includes sweeping changes
to the international taxation rules as well
Bill-and-Hold Transactions in the
Oilfield Services Sector
activities. The new deduction applies to
all eligible taxpayers regardless of
whether they export.
as significant changes to the tax rules
The legislation also provides a dividend-
that apply to corporate taxpayers, includ-
received deduction (DRD) for dividends
ing the oil and gas industry.
received by U.S. shareholders from their
The driving force behind this legislation
Congress Passes Corporate Tax
Legislation
EITF 01-08: Preponderance of the
Evidence
Canadian Tax Announcement
Clarifies Resource Taxation for
Partners and Partnerships
controlled foreign corporations (CFCs).
These provisions are discussed further
is the need to repeal an export tax bene-
In addition, there are several provisions
fit known as the extraterritorial income
targeted specifically to benefit the oil
(ETI) regime. Repeal is necessary to
and gas industry, including:
bring the United States into compliance
Relief for small refiners,
Activities
with a 2002 decision of the World Trade
A credit for oil and gas produced from
The legislation would provide a new
Organization (WTO), which held that the
ETI regime constituted an illegal export
subsidy under certain international trade
agreements.
marginal wells
A reduced recovery period for the
Alaskan natural gas pipeline
Expansion of the credit for electricity
The legislation replaces the ETI regime
produced from certain renewable
with a new deduction specifically
resources.
below.
Incentive for U.S. Production
deduction equal to the lesser of:
A percentage of the qualified production activities income (QPAI) of the taxpayer for the tax year
The taxpayer’s taxable income for the
tax year.
2 Current Oil & Gas Topics, Winter 2004
Domestic production gross receipts generally would include the gross receipts
of the taxpayer that are derived from
any lease, rental, license, sale,
exchange, or other disposition of:
Qualifying production property, which
was manufactured, produced, grown,
or extracted in whole or in significant
part by the taxpayer within the United
States
Any qualified film produced by the taxpayer
Electricity, natural gas, or potable
water produced by the taxpayer in the
United States
Construction performed in the United
States
Engineering or architectural services
performed in the United States for
construction projects in the United
States.
Qualifying production property would
include:
Tangible personal property
Computer software
The eligible percentage of QPAI would
QPAI would generally be equal to the
be:
excess (if any) of the taxpayer's domestic production gross receipts for such
tax year, over the sum of:
The cost of goods sold that are allocable to such receipts
Other deductions, expenses, or losses
directly allocable to such receipts
A ratable share of other deductions,
expenses, and losses that are not
directly allocable to such receipts or
another class of income.
Certain sound recordings.
Alternative Minimum Tax
The deduction would also be allowed for
purposes of the alternative minimum tax
(including adjusted current earnings).
The deduction in computing alternative
minimum taxable income would be
determined by reference to the lesser of:
QPAI (as determined for regular tax)
Alternative minimum taxable income
(in the case of an individual, adjusted
gross income) without regard to this
deduction.
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
3 Current Oil & Gas Topics, Winter 2004
Subsequently approved by the taxpay-
Limitations
produced or extracted “in the United
The deduction would not be available to
States” in order for the associated
er’s board of directors, management
the extent that it exceeds 50 percent of
income to qualify as domestic produc-
committee, executive committee, or
the wages paid by the taxpayer during
tion gross receipts. Further, natural gas
similar body.
the tax year.
producers would have to bifurcate their
The reinvestment plan must provide for
income into production income and disDomestic production gross receipts
the reinvestment of the amount in the
tribution income—and would have to
would not include the gross receipts of
United States (other than as payment
make an allocation of associated deduc-
the taxpayer that are derived from:
for executive compensation):
tions—in order to determine their
The sale of food and beverages pre-
deduction for U.S. production activities.
... as a source for the funding of
worker hiring and training, infrastruc-
pared by the taxpayer at a retail estabIncentives to Reinvest Foreign
ture, research and development, capi-
Earnings in the United States
tal investments, or the financial
electricity, natural gas, or potable
Under the legislation, certain dividends
stabilization of the corporation for the
water.
received by a U.S. corporation from
purposes of job retention or creation.
lishment
The transmission or distribution of
The conference report explains that, in
CFCs, in which it is a U.S. shareholder,
the case of natural gas, domestic pro-
would be eligible for an 85 percent divi-
duction gross receipts would include all
dends-received deduction (DRD). At the
The legislation also includes a number of
activities involved in extracting natural
taxpayer’s election, this deduction would
provisions that are specifically intended
gas from the ground and processing the
be available for dividends received dur-
to benefit the oil and gas industry.
gas into pipeline quality gas. However,
ing the taxpayer’s:
gross receipts of a taxpayer attributable
Last tax year beginning before the
to transmission of pipeline quality gas
from a natural gas field (or from a natu-
date of enactment
First tax year which begins during the
ral gas processing plant) to a local distri-
one-year period beginning on the date
bution company’s city gate (or to
of enactment.
another customer) would not be domes-
Oil and Gas Provisions
Relief for Small Refiners
Under the legislation, a small business
refiner of crude oil would be allowed to
elect to expense, rather than depreciate,
75 percent of certain capital costs it
pays or incurs to comply with the
Limitations
Highway Diesel Fuel Sulfur Control
gas purchased by a local gas distribution
This DRD would apply only to certain
Requirements of the Environmental
company and distributed from the city
extraordinary repatriations in excess of
Protection Agency. Qualified capital
gate to the local customers would not
the taxpayer’s average repatriation level
costs would be those related to con-
give rise to domestic production gross
in recent tax years.
structing or modifying a facility so that it
receipts.
Certain additional limitations would
tic production gross receipts. Likewise,
Implications for Oil and Gas Producers
produces diesel fuel with a sulfur content of no more than 15 parts per million.
apply. For instance, the legislation would
require that the dividends received must
A small business refiner of crude oil also
The ETI regime generally does not apply
be invested in the United States pur-
would be allowed a general business tax
to income from the sale of oil and gas
suant to an appropriate domestic rein-
credit equal to five cents per gallon for
that was extracted, produced, or refined
vestment plan that is:
low sulfur diesel fuel produced at such a
in the United States. The new deduction
for U.S. extraction and production activities, however, would apply to such activities. Note that oil and gas must be
Approved by the taxpayer’s senior
management (president, CEO, or comparable official) before the dividend is paid
facility. The total credit for any facility (for
all years) could not exceed 25 percent of
its qualified capital costs with respect to
the facility.
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
4 Current Oil & Gas Topics, Winter 2004
A small business refiner would be
Expansion of the Credit for Electricity
be equal to $4.375 per ton (adjusted for
defined as one with no more than 1,500
Produced from Certain Renewable
inflation) of qualified refined coal pro-
individuals engaged in refinery opera-
Resources
duced by the taxpayer at an eligible facil-
tions on any day during the year and
The section 45 general business credit
ity and sold to any unrelated person
whose average daily domestic refinery
for electricity produced from certain
during the ten-year period beginning on
run or production for all its facilities dur-
renewable resources (and sold to an
the date the facility was originally placed
ing calendar year 2002 did not exceed
unrelated person) would be extended
in service. A qualifying facility would use
205,000 barrels.
and expanded.
coal to produce a lower-emission, higher-
Credit for Oil and Gas Produced from
Under the legislation, the credit would
duce steam to generate electricity. A
Marginal Wells
continue to be allowed for electricity
phaseout of the credit could apply
A general business tax credit would be
produced from wind, closed-loop bio-
depending on increases in the price of
provided for production of oil or gas
mass, and poultry waste, and would be
crude oil.
from a qualified marginal well, generally
allowed for “open-loop biomass” (gener-
defined as:
ally, various waste materials including all
In the case of facilities that may be eligi-
animal waste), geothermal energy, solar
ble for the section 45 credit as well as
energy, small irrigation power, and
section 29 (credit for producing fuel
municipal solid waste and closed-loop
from a nonconventional source) or sec-
biomass co-fired with coal, other bio-
tion 48 (energy credit), the provision
mass, or both. Facilities would generally
would prohibit the taxpayer from claim-
need to be originally placed in service
ing multiple credits.
value fuel intended to be burned to pro-
A domestice well, production from
which is treated as marginal production for purposes of the percentage
depletion rules
A domestic wll that, during the tax
year, has average daily production of
no more than 25 barrel-of-oil equiva-
before January 1, 2006.
Conclusion
lents and produces water at a rate not
For the newly eligible types of facilities,
The new legislation raises dozens of dif-
less than 95 percent of total well efflu-
the credit generally would be available
ficult interpretive questions, including
ent.
for only the five-year period beginning
how to allocate deductions to domestic
The credit amount would be $3 per bar-
on the date the facility is originally
production gross receipts, how to appor-
rel of qualified crude oil and 50 cents
placed in service (rather than the ten-
tion income between natural gas pro-
per 1,000 cubic feet of natural gas. Prod-
year period for facilities qualifying under
duction and natural gas distribution and
uction that exceeds 1,095 barrels or bar-
current law). Further, the credit amount
transmission, and what types of U.S.
rel-of-oil equivalents during the tax year
would be reduced by half for open-loop
reinvestment will be permitted under
would not qualify.
biomass, small irrigation power, and
the repatriation provision. Future guid-
municipal solid waste.
ance is expected to answer some of
The legislation would also provide a
these questions, but the application of
Reduced Recovery Period for Alaska
Natural Gas Pipeline
credit under section 45 for the produc-
this new law to specific taxpayers will
A seven-year depreciation recovery peri-
tion of refined coal from a facility placed
raise difficult technical issues for tax pro-
od would be assigned to any Alaska nat-
in service before 2009. The credit would
fessionals for years to come. ural gas pipeline that meets certain
capacity requirements.
The information contained herein is general in nature and based on
authorities that are subject to change. Applicability to specific situations
is to be determined through consultation with your tax adviser.
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
5 Current Oil & Gas Topics, Winter 2004
Bill-and-Hold
Transactions in the
Oilfield Services Sector
By John C. Christopher, KPMG LLP
Determining and defining appropriate
revenue recognition has been a primary
focus of companies, regulators, standard setters, and auditors in recent
years. Improper revenue recognition has
been one of the leading causes of financial statement restatements. Perhaps no
area of revenue recognition has received
as much scrutiny as “bill-and-hold”
transactions. Also known as “ship-inplace” transactions, these transactions
generally refer to scenarios where revenue is recognized after a seller has
substantially completed its obligations
under an arrangement, but prior to the
buyer, or a common carrier, taking physical possession of the goods.
Background
In a recent interview, former SEC
Chairman Arthur Levitt referred to recognizing revenue on bill-and-hold transactions as “hocus pocus accounting.” He
said, “Companies try to boost revenue
by manipulating the recognition of revenue. Think about a bottle of wine. You
before the product is delivered to the
GAAP violation, unfortunately it has long
wouldn’t pop the cork on that bottle
customer, or at a time when the cus-
been associated with incidents of finan-
before it was ready. But some compa-
tomer still has options to terminate,
cial fraud. In its October 2002 Report on
nies are doing this with their revenue—
void, or delay the sale.” Although the bill-
Financial Statement Restatement, the
recognizing it before a sale is complete,
and-hold transaction in itself is not a
General Accounting Office (GAO) said
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
6 Current Oil & Gas Topics, Winter 2004
that revenue recognition is the largest
single issue involved in restatements,
more than half of financial reporting
frauds involve the overstatement of revenue, and restatements for revenue
recognition have resulted in the largest
drops in market capitalization compared
with any other type of restatements.
There remains an intense scrutiny
around a company’s revenue recognition
principles for these types of transactions, and management and auditors
should be unusually skeptical about the
appropriateness of recording revenue for
these transactions.
Bill-and-hold scenarios frequently arise
in the oilfield services sector. It is important to note that the form of these transactions is neither illegal nor unethical. In
fact, most have very good business or
economic purposes. For example, there
is currently a trend in the oil and gas
industry towards developing fields in the
deep waters toward the Gulf of Mexico
or other more remote locations throughout the world. Development plans for
these large deepwater offshore fields,
as well as remote onshore fields
throughout the world, will commonly
have long timelines; therefore, the oilfield service companies have long lead
times for delivery of equipment and
products. As the development plan gets
under way, many of the original timelines and milestones will change along
companies manufacture and deliver are
criteria relate to the risks of ownership,
extremely capital intensive and will be
the commitment and request on the
manufactured and ready for their fixed
part of the buyer, the business purpose
delivery dates without regard to any
of the transaction, the delivery date, and
changes in the development plan. These
the performance obligations, among oth-
products are generally very large built-to-
ers (these criteria are discussed in more
suit equipment such as wellhead con-
detail in the next section). As an exam-
nection equipment and completion
ple, an oilfield services company may
products.
complete the manufacturing of the cus-
the way as information about the reser-
There are certain criteria that companies
voir becomes better. However, many of
must meet in order to recognize rev-
the products that the oilfield services
enue on bill-and-hold transactions. These
tomer’s requested products, have them
shipped to a company-owned warehouse, determine a fixed delivery sched-
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
7 Current Oil & Gas Topics, Winter 2004
ule to the customer’s well site, obtain a
enue may be recognized on the product
the functionality of the delivered prod-
legal acknowledgement from the cus-
element when the company has com-
ucts. In addition, remaining activities
tomer that the risk of loss has been
pleted the product only if it is a separate
would not be inconsequential or per-
transferred, and have no additional obli-
unit of accounting, or if there are any
functory if failure to complete the activi-
gations to perform such as installation of
services involved in the transaction (e.g.,
ties would result in the customer
the equipment. All of this may take
warehousing), and those services are
receiving a full or partial refund or reject-
place prior to the particular point in the
inconsequential or perfunctory to one
ing, or a right to a refund or to reject the
well development plan that calls for the
unit of accounting. The company may
products delivered. The SEC provided
installation of the product. In this exam-
need to consider whether the services
the following factors in SAB No. 104,
ple, the oilfield services company might
are a separate unit of accounting, if they
which are not all-inclusive, as indicators
(although only based on careful analysis
are inconsequential or perfunctory, and
that a remaining performance obligation
of the SEC and FASB guidance related
whether there are other performance
is substantive rather than inconsequen-
to bill-and-hold transactions) be able to
obligations yet to be performed in deter-
tial or perfunctory:
recognize revenue immediately upon
mining the appropriate revenue recogni-
The seller does not have a demonstrat-
completing the manufacturing process
tion policy for the entire arrangement.
and meeting all of the bill-and-hold revenue recognition criteria.
Inconsequential or Perfunctory
Element
ed history of completing the remaining
tasks in a timely manner and reliably
estimating their costs.
The cost or time to perform the
SEC and FASB Guidance on Revenue
According to SAB No. 104, Revenue
Recognition and Bill-and-Hold
remaining obligations for similar con-
Recognition, if the undelivered element
Arrangements
tracts historically has varied significant-
is both inconsequential or perfunctory
ly from one instance to another.
EITF Issue 00-21; Multiple Elements in a
and not essential to the functionality of
The skills or equipment required to
Bill-and-Hold Arrangement
the delivered element, it would be
complete the remaining activity are
appropriate to recognize revenue on the
specialized or are not readily available
arrangement at the time of delivery and
in the marketplace.
Companies must first apply the separation model described in EITF Issue 0021, Revenue Arrangements with
Multiple Deliverables, to determine the
number of units of accounting in the billand-hold arrangement. Bill-and-hold
arrangements in this industry can
include both the sale of products and
the performance of certain services,
such as warehousing for the product if it
is shipped to a company-owned warehouse. If the SEC staff’s revenue recognition criteria (discussed in the next
section) are met for the product element
in the bill-and-hold arrangement, rev-
accrue the cost of providing the services
The cost of completing the obligation,
related to the undelivered element.
or the fair value of that obligation, is
However, if the undelivered element is
more than insignificant in relation to
neither inconsequential nor perfunctory
such items as the contract fee, gross
or is essential to the functionality of the
profit, and operating income allocable
delivered element, the revenue for the
to the unit of accounting.
delivered element should be deferred
and recognized based on the accounting
requirements of the undelivered ele-
The period before the remaining obligation will be extinguished is lengthy.
The timing of payment of a portion of
ment. The SEC’s guidance on the deter-
the sales price is coincident with com-
mination of whether an element is
pleting performance of the remaining
inconsequential or perfunctory is related
activity.
to whether that element is essential to
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
8 Current Oil & Gas Topics, Winter 2004
The buyer must have a commitment to
purchase, preferably in written documentation.
The buyer, not the seller, must originate the request that the transaction
be on a bill-and-hold basis.
The buyer must have a substantial
business purpose for ordering the
goods or equipment on a bill-and-hold
basis.
Delivery must be for a fixed date and
on a schedule that is reasonable and
consistent with the buyer’s purpose
(this requirement will generally be difficult for an oilfield services company to
meet due to the variable nature of the
movement of timelines and milestones
for oilfield development).
The seller must not retain any signifiCustomer Acceptance
tomer acceptance provisions exist, the
cant specific performance obligations
The SEC has also established require-
SEC generally believes that the seller
under the agreement such that the
ments in SAB No. 104 related to cus-
should not recognize revenue until cus-
earnings process is not complete.
tomer acceptance. After delivery of a
tomer acceptance occurs or the accept-
product, if uncertainty exists about cus-
ance provisions lapse. Since customer
regated from the seller’s inventory and
tomer acceptance, revenue should not
acceptance provisions may preclude rev-
may not be subject to being used to fill
be recognized until acceptance occurs.
enue recognition, companies should
other orders.
Customer acceptance provisions may be
review their arrangements for these
included in a contract, among other rea-
types of provisions prior to their analysis
sons, to enforce a customer's rights to
of the SEC’s bill-and-hold revenue recog-
test the delivered product, require the
nition criteria in SAB No. 104.
seller to perform additional services subsequent to delivery of an initial product,
SEC Bill-and-Hold Criteria
The goods or equipment must be seg-
The goods or equipment must be complete and ready for shipment.
The SEC emphasized that that the above
criteria are not a simple checklist. A
transaction might meet all of the criteria
and still fail the revenue recognition
or identify other work necessary before
The SEC has established specific criteria
accepting the product. The SEC pre-
codified in SAB No. 104 that a seller of
sumes that such contractual customer
goods or equipment must meet to rec-
acceptance provisions are substantive,
ognize revenue for a bill-and-hold trans-
bargained-for terms of an arrangement.
action, including:
ment from the buyer and whether the
Accordingly, when such contractual cus-
The risks of ownership must have
seller has modified its normal billing
passed to the buyer.
guidelines. The following factors also
must be considered:
The date the seller expects actual pay-
and credit terms for the buyer
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
9 Current Oil & Gas Topics, Winter 2004
The seller’s past experiences with billand-hold transactions
Whether the buyer has the expected
risk of loss in the goods’ or equip-
Some of the more common pitfalls in
Multiple elements—oilfield service
proper revenue recognition for bill-and-
companies should pay particular atten-
hold arrangements are:
tion to their evaluation of the services
Fixed delivery schedule—the fixed
that they will perform for the customer
ment’s market value during the bill-
delivery date and the corresponding
related to the products in order to con-
and-hold phase
amount of time that the products may
clude on whether multiple elements of
be in storage should be consistent
accounting exist.
Whether the seller’s custodial risks are
insurable and insured.
with the company’s history for those
The expectations from regulators and the
Once all of these criteria have been con-
products, competitors’ products, and
public toward audit committees, manage-
sidered and documented for an individual
the industry in general. Oilfield service
ment, and the independent auditors have
arrangement, a company’s senior man-
companies should pay particular atten-
increased significantly over the last sever-
agement and audit committee should be
tion to this criterion since it is often
al years. Consequently, more time is
made fully aware of the facts and circum-
difficult to designate a fixed date for
being spent at the top levels of manage-
stances. This should allow for a sound
future delivery of a product to the well
ment and in audit committee meetings
and proper conclusion on the accounting
site when there are so many variables
discussing and scrutinizing company
for the bill-and-hold arrangement.
in the development timeline. This
accounting policies and practices.
would indicate that meeting this criteriAudit Committee, Managment, and
on for an oilfield services company
Independent Auditor Involvement
might be rare.
The audit committee, management, and
Customer request—the customer, not
the independent auditors should monitor
the seller, must request that the trans-
the accounting for all bill-and-hold agree-
action be on a bill-and-hold basis (in our
ments. Specifically, management should
example, that the products be held in
be aware of and review in detail all significant bill-and-hold customer contracts
bills of lading, shipping documents, and
while in warehouse. Careful scrutiny of
credit terms to ensure they are being
the relevant legal documents is neces-
accounted for appropriately.
sary to make this assessment. With
arrangements and discuss the key areas
of judgment involved in accounting for
these transactions.
very large and complex products and
equipment that carry significant
amounts of economic value, and given
the level of regulatory scrutiny over
the warehouse), preferably in writing.
accept the risk of loss for the products
committee of any significant bill-and-hold
oilfield services sector generally involve
Risk of loss—the customer must
and their related sales orders, invoices,
Management should inform the audit
Since bill-and-hold arrangements in the
regard to the oilfield services sector, in
some cases title of the products will
transfer to the customer, although the
risk of loss still remains with the seller
while the seller is warehousing the
products.
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
10 Current Oil & Gas Topics, Winter 2004
these arrangements, it is expected that
are obtained prior to (revenue) recogni-
audit committee and senior manage-
tion, and whether the company has
ment involvement in the assessment of
modified its normal billing and credit
these arrangements will increase. Senior
terms for bill-and-hold inventory.”
management should meet regularly with
the operational management of the
Action Points
company to gain a better understanding
As evidenced in this article, document-
of these transactions and to develop or
ing and concluding on the accounting for
refine the company’s processes for iden-
bill-and-hold arrangements involves read-
tifying transactions subject to this
ing a lot of literature and having to make
unique area of accounting. They should
several judgmental decisions, making
understand the key judgments and esti-
revenue recognition for bill-and-hold
mates used in the revenue recognition
arrangements generally a lengthy and
principles and whether there are any dif-
complex activity. Therefore, in order to
ficulties that exist in the process for
facilitate this process as much as possi-
accounting for these transactions.
ble, the following are some significant
Within the context of the SarbanesOxley Act of 2002, audit committees
and senior management should also
action points to consider for bill-and-hold
arrangements (not all-inclusive):
Senior management and the audit
consider the internal controls surround-
committee should become fully
ing their bill-and-hold transactions and
engaged in the process of understand-
any necessary disclosures and presenta-
ing and documenting proposed bill-
tion in the company’s SEC filings. In a
and-hold arrangements and conclude
speech at the AICPA National Confer-
on the appropriate accounting prior to
ence on Current SEC Developments,
entering into such arrangements.
Michael Schoenfeld, the SEC’s Assistant
Companies should consult with their
Chief Accountant, mentioned that “the
independent auditors about the facts
staff encourages a discussion of the
and circumstances of the arrange-
risks and uncertainties surrounding bill-
ments and their understanding of the
and-hold arrangements and their poten-
applicable accounting literature.
tial impact on the financial statements.
Public companies with bill-and-hold
Such disclosure might include the com-
arrangements in place should consider
pany’s relationship with distributors, that
pre-clearing proposed revenue recogni-
fixed commitments to purchase goods
tion models for bill-and-hold arrangements with the SEC. © 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved.
Printed in the U.S.A. 10042DAL
This article is not intended to be prescriptive or used as guidance for
companies; however, it can be used as talking points with directors and
management of oilfield service companies that have bill-and-hold
arrangements to ensure that they will ultimately need to satisfy themselves that the appropriate amount of due diligence has been applied to
the transactions, that they understand where the key judgments were
applied in the process, and they have made all of the necessary disclosures surrounding the arrangements.
11 Current Oil & Gas Topics, Winter 2004
EITF 01-08:
Preponderance of the
Evidence
By Hershell W. Cavin, KPMG LLP
companies recognize revenue or costs
in earnings and, in some cases, altering
asset recognition and classification.
Examples of Arrangements Affected
Consider the following examples of contracts in which accounting may be
impacted by EITF 01-08: Refiners routinely execute throughput agreements,
which are similar to take-or-pay contracts
because they represent arrangements
between the owner of a transportation
or storage facility (a pipeline or tank
farm) and purchaser where the purchaser pays specified amounts periodically in
return for the right to transport product.
Purchasers, or shippers, are often obligated to make cash payments for the
minimum quantities even if they do not
transport the contracted quantities (i.e.,
known as “throughput” or “take-or-pay”
contracts). Examples of these arrangements follow:
EITF 01-08,Determining Whether an
Arrangement Contains a Lease, was
issued in May 2003 (see Fall 2003
Current Oil & Gas Topics) with the intent
of clarifying how to determine whether
a sale or purchase contract, or any other
type of arrangement, contains a lease
that must be accounted for separately
from the arrangement. Examples of
arrangements that have been impacted
by this guidance include service or sales
contracts that depend on the use of
specific assets, full-service leases, and
“throughput” or “take-or-pay” contracts,
just to name a few. Adoption of this
Refiner A enters into an agreement
guidance has impacted purchasers and
with Hydrogen Company to provide for
suppliers in all sectors of the energy
the delivery of hydrogen to support its
business by altering how and when such
production process. The agreement
provides for Hydrogen Company to
provide hydrogen from a 100
mmscf/day unit that is in close proximity to Refiner A. Refiner A pays a
monthly fixed capacity charge, regardless of the amount of hydrogen purchased each month, and pays a
variable charge for each mmscf of
hydrogen purchased each month.
Refiner A executes an agreement with
Pipeline Company to transport crude
oil (and/or refined products) to (from)
its refinery. Refiner A agrees to pay for
a minimum of 200,000 bbl/day of
transportation capacity (“take-or-pay”).
Refiner A executes a take-or-pay crude
oil (and/or refined products) storage
facilities agreement for 100,000 bbl
capacity/day, often in connection with
a transportation contract.
These agreements are typically entered
into because the purchaser desires a
certain level of known capacity to move
and store feedstocks and refined products and may not have the permits,
infrastructure, or capital to build
pipelines and storage facilities. The
assets or facilities are usually shared
among a number of downstream customers who execute throughput contracts with the owner of the property,
plant, or equipment, but there may also
be situations where purchasers are the
sole user or part of a small group of
users of the assets.
The fee structure for these arrangements comes in various forms, but usually includes a base fee (i.e., per barrel
throughput fee for basic services to be
provided) with a guaranteed minimum
throughput per day. The fee also can be
variable given whether there is a “preferential use” of the assets over a given
period of time. Preferential use provides
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
12 Current Oil & Gas Topics, Winter 2004
the purchaser with the ability to be the
sole user of the asset for a specified
period of time, but not over the entire
life of the arrangement. The fee structure is typically designed to recover the
owner’s investment in the assets,
including a reasonable rate of return, as
well as costs to operate and maintain
the assets and facilities. Where the owner of the assets/facilities enter into an
arrangement before actual construction
of the asset/facility, it is common for
these arrangements to include “walkaway” payments to protect the owner’s
investment, whereby the purchaser pays
a penalty to terminate the agreement.
Before the adoption of EITF 01-08, some
financial statement preparers accounted
for these types of contracts as service
contracts while other preparers accounted for them as leases or accounted for a
portion of the contracts as leases. EITF
01-08 clarified that all arrangements
must be analyzed to determine if they
are a lease or if they contain a lease and
are accounted for accordingly. These
arrangements must now be reviewed to
determine whether they convey the
right to use specific property. Significant
judgment is required to determine
whether a lease exists within the contract that conveys to the purchaser (lessee) the “right to use” a specific asset.
Process for Evaluating Whether a
Lease Exists
To determine whether a lease exists in
an arrangement, we must first understand how a lease is defined for financial statement accounting purposes.
FASB Statement No. 13, Accounting for
Leases, defines a lease as:
... an agreement conveying the right
to use property, plant, or equipment
(land and/or depreciable assets) usually for a stated period of time.
EITF 01-08 reiterates that the property,
plant, or equipment must be specified in
the arrangement and clarifies that such
specificity may be implicit or explicit.
That is, although specific property may
be stated in the arrangement, “it is not
considered subject of a lease if the fulfillment of the arrangement is not
dependent on the use of the specified
property, plant, or equipment.” For
example, using the hydrogen plant
example above, if Hydrogen Company
has the right and ability to provide hydrogen to Refiner A with production from
multiple hydrogen units, then a specific
hydrogen unit, although it may be specifically stated in the arrangement, is not
considered specific property, plant, or
equipment for purposes of applying
lease accounting. Conversely, if the
arrangement with Hydrogen Company
does not explicitly specify which unit will
provide the hydrogen, but Hydrogen
Company owns only one unit that it can
reasonably use to fulfill the obligation to
deliver hydrogen, then that unit is implicitly specified for purposes of applying
lease accounting. The focus of this evaluation should be on whether the owner
has the “right and ability” to provide
those goods or services using other
property, plant, or equipment, and
whether such alternatives are economically feasible.
If property, plant, or equipment is specified in the arrangement, we then need
to decide whether the arrangement conveys the right to use the specified property, plant, or equipment. EITF 01-08
provides the following key factors in
determining whether the arrangement
conveys the right to use the specified
property, plant, or equipment:
(a) The purchaser has the right or ability
to operate the property or direct others to operate the property while using
more than a minor amount of the output of the property. For example, a
company should consider the ability to
fire or replace the asset’s operator, the
ability to approve significant operating
policies and procedures, and the ability
to specify significant operating policies
and procedures with the owner having
no ability to change such policies and
procedures. Some arrangements are
silent as to the rights and responsibilities regarding operation of the assets.
In such cases, companies should look
to the intent and responsibilities of
both the owner and the purchaser to
operate the assets.
(b) The purchaser has the ability or right
to control physical access to the property while using more than a minor
amount of the output of the property.
Physical access does not necessarily
mean that the asset is located on the
property of the purchaser. For example, a portion of Pipeline Company’s
pipeline might be built on the property
of Refiner A, but that alone does not
mean that Refiner A controls physical
access to the pipeline (Pipeline
Company may have a right of way in
order to maintain and operate the
pipeline).
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
13 Current Oil & Gas Topics, Winter 2004
(c) Thirdly, facts and circumstances are
remote that a party other than the purchaser will take more than a minor
amount of the output and the price
per unit is variable. For example, if
Refiner A was paying a fixed price to
transport refined product through a
pipeline, regardless of quantities transported, and they were the only refiner
that had access to the pipeline, it
might be concluded that it is more
than remote that another party other
than the purchaser would take more
than a minor amount of the output.
This factor should be evaluated considering normal operating conditions of
the asset. For example, when evaluating whether it is more than remote
that any party other than the purchaser
will take more than a minor amount of
the output, a company should consider
normal operating capacity and output
of the asset rather than assuming that
the asset will always operate at full
capacity. All evidence should be considered when making the assessment
as to the possibility that other parties
will take more than a minor amount of
the output.
Other factors that should be considered include:
Are there provisions that tie the purchaser to the specific property, plant,
or equipment (e.g., purchaser provided
inputs to the production process, purchaser payment of property taxes, pricing tied to a specific asset)?
Does the owner of the asset recoup
its investment through the minimum
payments of a sole purchaser?
Events Triggering Ressessment
An assessment of arrangements must
be made at inception of the arrangement. Subsequent reassessment of the
arrangement to determine whether a
lease exists is required if:
The contractual terms are altered
An extension or renewal option is
agreed
The seller no longer has the ability to
deliver under the terms of the arrangement solely using the property specified in the arrangement
There has been a substantial change in
the physical state of the specified
property.
Preponderance of the Evidence
Evaluation of contracts under EITF 01-08
requires significant judgment and consideration of all the “facts and circumstances” and the substance of each
arrangement, which is easier said than
done. Purchasers in arrangements that
require analysis under EITF 01-08 are
finding it extremely difficult to gather the
necessary information with which to
make the assessment. For example,
purchasers find it difficult to determine
whether the property is “specified” in
the arrangement because they often do
not have knowledge of the supplier’s
other assets that may be used to supply
the purchaser. Also, assessing whether
other customers of the supplier will take
more than a minor amount of the output
from the specified asset is difficult for
the purchaser, given the lack of market
information available to the purchaser.
However, EITF 01-08 does not give an
out when information is not readily available. Therefore, parties to arrangements
that may fall within the scope of EITF
01-08 must share information necessary
to make the required assessments.
When evaluating transactions to determine whether a lease arrangement
exists, care should be taken to evaluate
all of the information and consider the
preponderance of the evidence when
concluding whether the arrangement (or
a portion of the arrangement) constitutes a lease. Companies should consult
with their external auditors early in the
process when negotiating these
arrangements. © 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
14 Current Oil & Gas Topics, Winter 2004
Canadian Tax
Announcement
Clarifies Resource
Taxation for Partners
and Partnerships
By Wayne Chodzicki, KPMG LLP
As reported in Current Oil & Gas Topics
in Fall 2003, a five-year package of
measures to improve the Canadian taxation of resource income was introduced
on June 9, 2003, in a Notice of Ways
and Means Motion (the June Notice).
While the changes were generally positive, they produced adverse tax consequences in certain cases. The taxation of
resource income earned through a partnership is one such case.
The June Notice included a proposal to
introduce a full deduction for actual
provincial and other Crown Royalties
paid and eliminate the existing 25 percent resource allowance over the same
five-year period.
The proposal is being phased in as illlustrated in the chart below.
These rates are effective on January 1
of the applicable year and will be prorated for off-calendar years.
As reported in Fall 2003, the transition
rules adversely affect income from many
partnerships. Deductible and nondeductible crown royalties are calculated
at the partnership level, while the
resource allowance is calculated at the
partner level. If the partnership year-end
differs from that of the partners (a common occurrence in Canada), different
rates are used to compute these
amounts. Generally this causes the loss
of more resource allowance than would
otherwise be expected in the transition.
bursed Crown charges are not deductible). A taxpayer who reimburses another person for Crown charges is deemed
not to have paid the reimbursement but
to have incurred a Crown charge. The
recipient is deemed not to have received
the reimbursement for income tax purposes but continues to have a nondeductible Crown charge (under the old
rules there was no need to eliminate
this non-deductible item).
To resolve these differences, many taxpayers resorted to using section 80.2,
which deals with reimbursements of
Crown charges, to align the deductible
percentage of Crown charges to the lost
resource allowance deduction. However,
the mechanics in place under the
Income Tax Act gave taxpayers the
opportunity to enhance their deductions
beyond what the Department of Finance
expected.
The Department of Finance now
believes the special reimbursement rule
produces deductions exceeding those
expected during the phase-in period,
and thus it does not operate as intended. This result occurs because the recipient of the reimbursement continues to
have a Crown charge, regardless of the
reimbursement. Thus, under the 2003
amendments, the recipient (as well as
the payer of the reimbursement) is
allowed certain deductions for these
charges.
The Concern
Previously, taxpayers were not allowed
to deduct resource-related Crown
charges. In certain circumstances, taxpayers entered into reimbursement
agreements for Crown charges to help
facilitate cash flow (usually within a
related group of entities) or for other
business purposes.
A special reimbursement rule put the
taxpayer making the reimbursement in
the same position as the recipient in
relation to the Crown charge (i.e., reim-
Further, in the case of partnerships
where the reimbursement is delayed,
the reimbursement may be deductible
at a greater percentage than the nondeductible percentage of the resource
allowance.
The Proposed Amendments
The Department of Finance’s proposed
amendments are intended to ensure
that only the taxpayer reimbursing the
Crown charge is entitled to a deduction.
The deductible amount is based on the
amount that would have been available
had the taxpayer incurred the Crown
charges at the time they became
payable or receivable.
The requirement to determine the
deductibility of a reimbursement accord-
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL
15 Current Oil & Gas Topics, Winter 2004
are not permitted to use section 80.2 to
enhance their deductions beyond this
point.
If the taxpayer or the recipient of the
reimbursement is required to amend a
previously filed tax return, no penalties
or interest will apply to any additional
tax payable as a result of these rules, as
long as the tax is paid within two
months of September 17, 2004.
ing to when the Crown charge became
payable or receivable generally will not
apply to a reimbursement by a taxpayer
of actual Crown charges incurred by a
partnership during a particular fiscal period, if certain conditions are met.
Among other conditions, the taxpayer
must be a member of the partnership at
the end of a particular fiscal period of
the partnership, and the reimbursement
must be made in the taxation year of
the taxpayer in which the fiscal period of
the partnership ends.
If these conditions are met, the proposed amendments confirm that the
matching of the deductible percentage
of Crown charges to the non-deductible
percentage of resource allowance will
be similar between entities operating
through either a partnership or a corporate structure. In essence, taxpayers are
permitted to use section 80.2 reimbursements to increase the percentage
deductible to the same percentage used
to reduce the resource allowance. They
To ensure that taxpayers or partnerships
do not enter into reimbursement
arrangements to artificially increase the
amount that would otherwise be
deductible for a Crown charge, for reimbursements made on or after September 17, 2004, the Department of Finance
proposes to deny a deduction for the
amount of a reimbursement that
exceeds the eligible portion of the reimbursement.
The eligible portion of a reimbursement
is the amount that can reasonably be
considered to be the taxpayer’s share of
the Crown charges that apply to a particular property determined by reference to
the taxpayer’s share of the production or
net income from production from the
property.
Contact Us
Current Oil & Gas Topics is a periodic
publication produced by KPMG LLP.
For more information about this publication or KPMG’s Oil & Gas practice, contact:
Bill Kimble
Partner
National Sector Leader–Energy &
Chemicals
wkimble@kpmg.com
Greg Bergman
Director–Energy & Chemicals
gsbergman@kpmg.com
*****
All information provided is of a general nature
and is not intended to address the circumstances of any particular individual or entity.
Although we endeavor to provide accurate and
timely information, there can be no guarantee
that such information is accurate as of the date
it is received or that it will continue to be accurate in the future. No one should act upon such
information without appropriate professional
advice after a thorough examination of the particular situation.
The amount of a reimbursement that
exceeds the eligible portion of the reimbursement will be included in computing
the income of the recipient and will generally be deductible in computing the
taxpayer’s income.
These proposals were announced in a
press release and may change before
they are enacted. Taxpayers affected by
these changes may need to amend legal
documents and tax returns once the
proposals are enacted. © 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved.
Printed in the U.S.A. 10042DAL
16 Current Oil & Gas Topics, Winter 2004
KPMG’s 2005
Global Energy
Conference
May 24–25, 2005
InterContinental Hotel
Houston, Texas
S A V E
T H E
D AT E
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executives at KPMG’s Global Energy
Conference for financial executives
in the oil and gas industry on May
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Keynote Speaker:
The Honorable James A. Baker III,
Former Secretary of State
Topics that will be addressed by
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• U.S. Accounting Issues
• Controls Transformation /
Sustainability
• Sarbanes-Oxley: Lessons
Learned
• Global Tax Update: Middle East
globalenergyconf@kpmg.com
www.kpmgglobalenergyconference.com
W H O S H O U L D AT T E N D ?
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• Audit Committee Members
• Chief Executive Officers
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Controllers, Financial
Reporting Directors, and Staff
• Chief Risk Officers
• Internal Audit Directors
• Industry Analysts
• Investors
• Investment and Commercial
Bankers
• Tax Directors and Staff
• General Counsel
© 2005 KPMG LLP, the U.S. member firm of KPMG International, a Swiss cooperative. All rights reserved. Printed in the U.S.A. 10042DAL