Cost-of-Service Rates

Manual

Federal Energy Regulatory Commission

888 North Capitol Street, N.E.

Washington, D.C. 20426

United States of America

[www.ferc.gov](http://www.ferc.gov/)

June 1999

Table of Contents

[**Introduction** [1]{.underline}](#__RefHeading___Toc126142318)

[**Step 1: Computing the Cost-of-Service**
[6]{.underline}](#__RefHeading___Toc126142319)

[**The Cost-of-Service Formula**
[6]{.underline}](#__RefHeading___Toc126142320)

[**Test Period** [7]{.underline}](#__RefHeading___Toc126142321)

[**Rate Base** [8]{.underline}](#__RefHeading___Toc126142322)

[**Gross Plant** [9]{.underline}](#__RefHeading___Toc126142323)

[**Allowance For Funds Used During Construction (AFUDC)**
[9]{.underline}](#__RefHeading___Toc126142324)

[**Accumulated Reserve for Depreciation**
[10]{.underline}](#__RefHeading___Toc126142325)

[**Management Fee** [10]{.underline}](#__RefHeading___Toc126142326)

[**Accumulated Deferred Income Taxes (ADIT)**
[11]{.underline}](#__RefHeading___Toc126142327)

[**Working Capital** [12]{.underline}](#__RefHeading___Toc126142328)

[Cash working capital [12]{.underline}](#__RefHeading___Toc126142329)

[Materials and Supplies, and Prepayments
[13]{.underline}](#__RefHeading___Toc126142330)

[**Cost-of-Service** [13]{.underline}](#__RefHeading___Toc126142331)

[**Return** [13]{.underline}](#__RefHeading___Toc126142332)

[**Capitalization or Capital Structure**
[15]{.underline}](#__RefHeading___Toc126142333)

[**Cost of Debt** [16]{.underline}](#__RefHeading___Toc126142334)

[**Return on Equity** [16]{.underline}](#__RefHeading___Toc126142335)

[**Pretax Return** [17]{.underline}](#__RefHeading___Toc126142336)

[**Operation and Maintenance Expenses**
[18]{.underline}](#__RefHeading___Toc126142337)

[**Administrative and General Expenses**
[19]{.underline}](#__RefHeading___Toc126142338)

[**Depreciation Expense**
[19]{.underline}](#__RefHeading___Toc126142339)

[**Federal and State Income Taxes**
[20]{.underline}](#__RefHeading___Toc126142340)

[**AFUDC** [21]{.underline}](#__RefHeading___Toc126142341)

[**Effective Tax Rate** [22]{.underline}](#__RefHeading___Toc126142342)

[**Limited Liability Companies**
[22]{.underline}](#__RefHeading___Toc126142343)

[**Non-Income Taxes** [22]{.underline}](#__RefHeading___Toc126142344)

[**Credits to the Cost-of-Service**
[23]{.underline}](#__RefHeading___Toc126142345)

[**Step 2: Computing a Functionalized Cost-of-Service**
[23]{.underline}](#__RefHeading___Toc126142346)

[**K-N Method** [24]{.underline}](#__RefHeading___Toc126142347)

[**Step 3: Cost Classification**
[28]{.underline}](#__RefHeading___Toc126142348)

[**Classification of Costs Between Fixed and Variable**
[28]{.underline}](#__RefHeading___Toc126142349)

[**Classification of Costs Between Demand and Commodity**
[29]{.underline}](#__RefHeading___Toc126142350)

[Volumetric [30]{.underline}](#__RefHeading___Toc126142351)

[Fixed-Variable [30]{.underline}](#__RefHeading___Toc126142352)

[Seaboard [30]{.underline}](#__RefHeading___Toc126142353)

[United 31](#__RefHeading___Toc126142354)

[Modified Fixed-Variable [32]{.underline}](#__RefHeading___Toc126142355)

[Straight Fixed-Variable [32]{.underline}](#__RefHeading___Toc126142356)

[**Step 4: Cost Allocation**
[33]{.underline}](#__RefHeading___Toc126142357)

[**Mcf\'s and Dth\'s** [34]{.underline}](#__RefHeading___Toc126142358)

[**Allocation Factors and Billing Determinants**
[34]{.underline}](#__RefHeading___Toc126142359)

[**Load Factor** [35]{.underline}](#__RefHeading___Toc126142360)

[**Allocation of Costs Between Jurisdictional and Non-jurisdictional
Services** [36]{.underline}](#__RefHeading___Toc126142361)

[**Allocation of Costs Among Zones**
[37]{.underline}](#__RefHeading___Toc126142362)

[**Allocation of Costs Among Jurisdictional Services**
[37]{.underline}](#__RefHeading___Toc126142363)

[**Step 5: Rate Design** [39]{.underline}](#__RefHeading___Toc126142364)

[**Firm Service Rates** [40]{.underline}](#__RefHeading___Toc126142365)

[**Interruptible Service Rates**
[40]{.underline}](#__RefHeading___Toc126142366)

[**Interruptible Rate Computed as Derivative of Firm Rate**
[41]{.underline}](#__RefHeading___Toc126142367)

[**Revenue Check** [43]{.underline}](#__RefHeading___Toc126142368)

[**Rate Design and Load Factors**
[44]{.underline}](#__RefHeading___Toc126142369)

[**Small Customer Rates**
[44]{.underline}](#__RefHeading___Toc126142370)

[**Discounting and Discount Adjustments**
[45]{.underline}](#__RefHeading___Toc126142371)

[***Revenue Crediting Method***
[46]{.underline}](#__RefHeading___Toc126142372)

[***Proportional/Fractional Method***
[47]{.underline}](#__RefHeading___Toc126142373)

[Iterative Method [48]{.underline}](#__RefHeading___Toc126142374)

[**Distance Based Rates**
[52]{.underline}](#__RefHeading___Toc126142375)

[Mileage Based Rates [52]{.underline}](#__RefHeading___Toc126142376)

[Zoned Rates [52]{.underline}](#__RefHeading___Toc126142377)

[Mileage Costs [53]{.underline}](#__RefHeading___Toc126142378)

[Non-mileage Costs [53]{.underline}](#__RefHeading___Toc126142379)

[**Calculation of Zoned Rates for Pipeline U.S.A.**
[55]{.underline}](#__RefHeading___Toc126142380)

[**Calculation of Dth-Miles**
[56]{.underline}](#__RefHeading___Toc126142381)

[**Storage Services and Rates**
[58]{.underline}](#__RefHeading___Toc126142382)

[**Classification of Storage Costs**
[58]{.underline}](#__RefHeading___Toc126142383)

[**Allocation of Storage Costs**
[59]{.underline}](#__RefHeading___Toc126142384)

[**Design of Firm Contract Storage Rates**
[59]{.underline}](#__RefHeading___Toc126142385)

[**Design of Interruptible Contract Storage Rates**
[60]{.underline}](#__RefHeading___Toc126142386)

**Appendices**

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**Introduction**[]{#__RefHeading___Toc126142318 .anchor}

The Natural Gas Act (NGA) requires that rates charged for interstate
pipeline services be \"just and reasonable.\" Setting just and
reasonable rates requires a balancing of equities between the interests
of the pipeline and its ratepayers. The basic methodology we use to
establish just and reasonable rates is cost-of-service ratemaking. Under
cost-of-service ratemaking, rates are designed based on a pipeline\'s
cost of providing service including an opportunity for the pipeline to
earn a reasonable return on its investment.

The Commission sets rates for interstate pipeline services in a number
of proceedings. For example, when a pipeline files to increase its
rates, it makes a filing with the Commission under Section 4 of the NGA.
These types of filings are referred to as general Section 4 rate cases.
In these proceedings, the Commission reviews all of a pipelines rates
and services. A pipeline can file a general Section 4 rate case anytime
it wishes, provided the pipeline did not agree otherwise in a
settlement. A pipeline must demonstrate that the new rates it proposes
to charge are just and reasonable. When a rate increase filing is made
pursuant to Section 4, the application is typically suspended and set
for hearing by Commission Order. Once the application is set for
hearing, it is processed by the Commission\'s litigation staff in the
Office of Administrative Litigation (OAL). The issues in the application
can be settled if parties can reach consensus. However, if the issues
cannot be resolved, they will proceed to a hearing before an
Administrative Law Judge (ALJ). Whether the case is settled or proceeds
to hearing, the Commission will eventually need to act upon the
settlement, or upon the record in the hearing.

The Commission also has authority under Section 5 of the NGA to require
prospective changes in the rates charged by a pipeline when it can be
demonstrated that the rates are no longer just and reasonable. The
Commission can initiate a Section 5 proceeding on its own motion, or
upon complaint from an interested party. In a Section 5 proceeding, the
Commission has the burden of demonstrating that the currently effective
rates of the pipeline are no longer just and reasonable, and of
establishing just and reasonable rates.

The Commission also sets rates for pipeline services under Section 7 of
the NGA. Under Section 7(c) of the NGA a pipeline files to request a
\"Certificate of Public Convenience and Necessity\" to construct a new
pipeline or to expand existing facilities, in order to offer new or
additional services. The rates established by the Commission under
Section 7 for these services are referred to as \"initial rates\" and
generally remain in effect until such time as the pipeline files a
Section 4 rate filing in which all of a pipeline\'s rates are reviewed.

Additionally, the Commission sets rates for intrastate pipelines under
Section 311 of the Natural Gas Policy Act (NGPA). Under Section 311,
intrastate pipelines are permitted to transport gas for interstate
pipelines and local distribution companies (LDC) in interstate commerce
without becoming subject to jurisdiction under the NGA (intrastate
pipelines are regulated by their State Agencies). The rates established
under Section 311 must meet a \"fair and equitable\" standard, as
opposed to a \"just and reasonable\" standard. When this Commission sets
the rates for Section 311 service, the rates are computed using the same
cost-of-service methodology used under the NGA. However, an intrastate
pipeline may elect to use an approved cost-based rate on file with the
State agency that regulates its intrastate business.

Finally, there are \"limited\" Section 4 filings where pipelines file to
add a new service and establish new rates, as well as, complaint
proceedings that raise rate issues to be addressed by the Commission.

In order for the Commission\'s advisory staff to make recommendations to
the Commission on all of these types of filings, an understanding of the
rate making process is required. This manual is intended to provide a
basic understanding of how rates are computed based on the
cost-of-service methodology.

The basic tenet that pipeline rates should be based upon the cost of
providing service remains unchanged. However, it is worth noting that
the Commission has found over the years that other ratemaking methods,
in certain situations, can also meet the just and reasonable standard.
For example, the Commission has permitted rates to be set using:

\(1\) [selective discounting]{.underline}, where a pipeline is free to
charge any rate between the maximum rate, which is set at the
pipeline\'s average cost of providing service, and the minimum rate,
which is set at the average variable cost of providing service. The
pipeline however, must offer such discounts on a non-discriminatory
basis;

\(2\) [market-based rates]{.underline} have been approved when there has
been a showing that the pipeline has no market power; and, more
recently,

\(3\) [negotiated rates]{.underline} have been permitted when there has
been no showing by the pipeline of a lack of market power, but which
allows a pipeline and its customers to negotiate a rate for service
provided the pipeline has an appropriate \"recourse\" service on file
with cost-based rates that the customer could opt to select.

\(4\) [Pending Rate Issues]{.underline} On July 29, 1998, the Commission
issued a Notice of Proposed Rulemaking (NOPR) seeking comments from the
industry on short-term market issues, such as lifting the cost-based
rate cap on short-term transactions that compete in the market place.
Short-term market transactions are defined as short-term firm services,
capacity release and interruptible services. The Commission has also
issued a companion Notice of Inquiry (NOI) requesting comment on whether
long term transactions should continue to be priced in the same
cost-of-service manner or if other cost-based approaches may be better
to set rates, such as incentive regulation, performance-based rates, or
indexed rates. Comment was also sought regarding the future of the
Straight Fixed-Variable rate design methodology. Other topics were also
explored.

These ratemaking concepts, however, are topics for another discussion
but indicate that the market the Commission regulates is very dynamic
and the Commission is studying whether traditional cost-of-service
ratemaking, is the best way to set rates for pipeline services in the
future. The following material is intended to be an introduction to
cost-of-service ratemaking which remains the primary methodology used by
the Commission to establish just and reasonable rates.

**There are essentially 5 steps involved in cost-of-service
ratemaking:**

\(1\) Establishing a revenue requirement, or cost-of-service

\(2\) Functionalizing the cost-of-service

\(3\) Cost Classification

\(4\) Cost Allocation

\(5\) Rate Design

Each of these steps will be explained in further detail below and we
will show examples of each step by using an illustrative pipeline,
\"Pipeline U.S.A.\"

**Pipeline U.S.A.**![](media/image1.wmf){width="0.7680555555555556in"
height="0.4534722222222222in"}

Pipeline U.S.A. received a Certificate of Public Convenience and
Necessity from the Commission to construct and operate a jurisdictional
pipeline. In the certificate proceeding (CP), the Commission authorized
\"initial rates\" for firm and interruptible transportation service to
be provided by Pipeline U.S.A. Initial rates are established for new
services authorized in a certificate proceeding and must meet a public
convenience and necessity (\"PC&N\") standard. Initial rates established
in the certificate proceeding remain in effect until such rates are
reviewed by the Commission in a rate proceeding (RP). Pipeline U.S.A.
has been in operation for the past three years and has now filed a
Section 4 (of the NGA) rate filing to have its \"initial rates\"
reviewed under the \"just and reasonable\" standard. We will be
establishing a cost-of-service and designing rates for Pipeline U.S.A.
in the following pages. But, first, a few facts about Pipeline U.S.A.:

*Pipeline U.S.A. owns 370 miles of transmission pipeline. There are two
30,000 horsepower compressors located on its system. The capacity is
1,000,000 Mcf per day. Pipeline U.S.A. has 4 firm transportation
contracts each having 25 year terms and contract demands\* which total
the capacity of its system. Pipeline U.S.A. also provides interruptible
transportation service to several customers. The average heat content of
the natural gas transported on its system is 1.035 Dth per Mcf.*

*\*Contract Demand refers to a firm shipper\'s contractual entitlement
to service on any day. Contract Demand levels are expressed in Dth per
day. For example, a firm shipper with a contractual entitlement of
50,000 Dth*

*would be able to have up to 50,000 Dth of gas transported on any day of
the year. A firm shipper pays a firm reservation charge based on this
contractual entitlement to \"reserve\" capacity to guarantee this level
of service on any day. Because firm service is provided on a contract
basis, a pipeline is not required to provide service in excess of a
shipper\'s contract demand level.*

*A term frequently used to measure a firm shipper\'s use of its contract
demand is [load factor]{.underline}. A firm shipper\'s load factor is
calculated by dividing the amount of gas a shipper transports on an
average annual day by that shippers contract demand. For example, a
shipper who transports 25,000 Dth on an average day and has a contract
demand of 50,000 Dth/day, would have a 50% load factor. A shipper that
transported its full contract demand every day of the year would be a
100% load factor customer.*

*The shaded boxes that appear throughout the manual are referencing the
Appendices which illustrate the computation of each cost-of-service
component, as well as the steps for classifying, allocating and
designing rates for Pipeline U.S.A.*

**Step 1: Computing the Cost-of-Service**[]{#__RefHeading___Toc126142319
.anchor}

Cost-of-service may be defined as the amount of revenue a regulated gas
pipeline company must collect from rates charged consumers to recover
the cost of doing business. These costs include operating and
maintenance expenses, depreciation expense, taxes and a reasonable
return on the pipeline\'s investment. A cost-of-service is a measure of
a pipeline\'s annual \"revenue requirement\" that will provide a company
the opportunity to operate profitably and attract capital for future
growth.

This section is devoted to defining each element of the cost-of-service,
explaining how each element is computed and explaining the relationship
between the various components used to compute the cost-of-service.

**The Cost-of-Service Formula**[]{#__RefHeading___Toc126142320 .anchor}

To compute the cost-of-service a basic formula is followed:

Rate Base x Overall Rate of Return = Return

\+ Operation & Maintenance Expenses

\+ Administrative & General Expenses

\+ Depreciation Expense

\+ Non-Income Taxes

\+ Income Taxes

[- Revenue Credits]{.underline}

= Total Cost-of-Service

A cost-of-service includes the product of the pipeline\'s Rate Base
(which is the pipeline\'s investment) and the Overall Rate of Return,
plus its Operation and Maintenance Expenses (O&M), Administrative and
General Expenses (A&G), Depreciation Expense, Non-Income Taxes and
Income Taxes, less Revenue Credits.

*A summary cost-of-service for Pipeline U.S.A. is shown on [A-1](#A1).*

**Test Period**[]{#__RefHeading___Toc126142321 .anchor}. Another
important concept used in developing a cost-of-service is the test
period. The Commission has adopted the test period as a means to develop
rates based on current costs, adjusted for known and measurable changes.
As defined in the regulations, the test period consists of a base period
consisting of 12 consecutive months of most recently available actual
experience plus an adjustment period of nine months immediately
following the base period. The adjustment period is used to adjust the
base period for changes in revenues and costs that are known and are
measurable with reasonable accuracy at the time of the Section 4 filing
and that will become effective within nine months after the last month
of available actual experience. The adjusted base period is an annual
period and is usually referred to as the test period. Base period costs
and revenues are often adjusted to eliminate non-recurring items, to
annualize new costs or revenues, and to amortize costs or revenues that
occur periodically, but not annually, [i.e.]{.underline} every 2 years,
every 5 years, etc.

***One example of the test period concept:** Let\'s assume that for one
month of the base period, Pipeline U.S.A. included \$5,000 in its O&M
expenses to correct for a billing error, which occurred prior to the
base period, for field supplies purchased for the operation of certain
transmission facilities.* *This amount should be eliminated to develop
an appropriate test period amount for O&M expenses, as this cannot be
considered a representative cost of supplies to be purchased during the
period in which these rates will be effective. This adjustment reflects
the elimination of a non-recurring item.*

***Another example of the test period concept:** Let\'s assume that
every two years, Pipeline U.S.A. spends \$2,000 to have its meters
tested for accuracy. Assume this \$2,000 is recorded during one month of
the base period. This amount needs to be adjusted to arrive at an
appropriate test period expense. Because this expense is only incurred
every two years, it needs to be adjusted to an [annual]{.underline}
expense of \$1,000 per year, since the test period upon which we will
design rates is representative of one year. If this adjustment is not
made, Pipeline U.S.A. will overcollect its costs related to this item.
In fact, Pipeline U.S.A. would collect \$2,000 every year, rather than
\$2,000 every other year, if no adjustment is made. This adjustment
illustrates an example of an expense that must be amortized as it is
incurred periodically but not annually*.

**[Rate Base]{.underline}**[]{#__RefHeading___Toc126142322 .anchor}

Before actually computing a pipeline\'s cost-of-service, we must compute
the Rate Base. The Rate Base represents the total investment of the
pipeline and is used to compute certain components of the
cost-of-service. In particular, the Rate Base is used to compute the
Return component of the cost-of-service, which permits the pipeline to
earn a return on its investment. Additionally, components of Rate Base
are used to calculate the Depreciation Expense included in the
cost-of-service, which permits the pipeline to recover its investment.

To compute the Rate Base a basic formula is followed:

Gross Plant

[-Accumulated Depreciation]{.underline}

= Net Plant

-Accumulated Deferred Income Taxes

[+Working Capital]{.underline}

= Rate Base

As shown, Rate Base is calculated by subtracting the Accumulated Reserve
for Depreciation from the Gross Investment in Plant to arrive at Net
Plant. Net Plant represents the remaining plant balance that is not yet
depreciated. From the Net Plant we deduct the Accumulated Reserve for
Deferred Income Taxes and add the Working Capital. Below is a
description of each of the components of rate base.

*Pipeline U.S.A.\'s rate base is shown on [A-2](#A2).*

**Gross Plant**[]{#__RefHeading___Toc126142323 .anchor}**.** This is the
original cost of the plant, or facilities, owned by the pipeline.
Generally, if the pipeline purchases \"used\" (depreciated) facilities
from another utility, only the depreciated original cost of the
facilities can be included in rate base, not the amount actually paid by
the pipeline (since this may include a purchase premium which is not
allowable in rate base). In addition to including the actual amount of
the facilities, gross plant can also include amounts permitted to be
capitalized (that is, included in rate base) for the cost of land and
land rights, right of ways, surveys, line pack, and construction costs
including materials, labor, pipe coating, communication equipment,
overheads, funds used during construction, and legal fees.

*An itemization of Pipeline U.S.A.\'s test period gross plant is shown
on* [*A-3*](#A3)*.*

**Allowance For Funds Used During Construction
(AFUDC)**[]{#__RefHeading___Toc126142324 .anchor} **-** a pipeline is
permitted to include in rate base the cost of financing during the
construction period. The cost of financing consists of interest on
borrowed funds and equity return on the pipeline\'s own funds used
during the construction period. This computation is based on a
prescribed formula contained in Part 201 of the Commission\'s
regulations. These costs are a component of Gross Plant.

*As shown on [A-3](#A3), Pipeline U.S.A. has included in its Gross Plant
an amount of \$33,452,754 which is attributable to AFUDC.*

**Accumulated Reserve for Depreciation**[]{#__RefHeading___Toc126142325
.anchor}**.** The cost of the investment in gross plant is recovered
through the cost-of-service as Depreciation Expense. Accordingly, the
depreciation expense is accumulated and is credited against the gross
plant to reduce the remaining investment to be recovered. The remaining
balance is the **Net Book Plant.** The net book plant represents the
portion of gross plant that is not depreciated.

*Pipeline U.S.A. has been in operation for 3 years. The accumulated
reserve for depreciation balance computation is shown on [A-4](#A4). The
annual depreciation expense is added for each of the three years of
operation to arrive at this balance. The net book plant is computed by
subtracting the accumulated reserve for depreciation from the gross
plant (See computation on [A-2](#A2)).*

*Also, as shown by [A-4](#A4) and [A-11](#A11), the facilities of
Pipeline U.S.A. are 12% depreciated after 3 years of operation (3 yrs
divided by 25 years, or \$75,490/\$629,080).* *In year 25, assuming
Pipeline U.S.A. adds no additional rate base and that the depreciation
rate remains unchanged, Pipeline U.S.A. would be fully depreciated, or
in other words, Pipeline U.S.A. would have fully recovered its
investment.*

Over time, if the pipeline does not continue to add plant to its
pipeline system, the time will come when the balance in the accumulated
reserve for depreciation account will equal the gross plant. At this
point, the investment is fully recovered and net plant will be zero. If
the pipeline is continuing to operate after its investment is fully
recovered, the Commission may consider a management fee. Otherwise, the
pipeline would only be able to recover operating expenses and taxes
other than income taxes and would have no opportunity to earn a profit
as there would be no investment (rate base) to calculate a return.

**Management Fee**[]{#__RefHeading___Toc126142326 .anchor}**.** When a
pipeline is fully depreciated and the pipeline continues to provide
service, the Commission has permitted rates which provide for the
recovery of operating expenses, taxes and a reasonable management fee
that is equivalent to no more than 10% of the pipeline\'s average
pre-tax return during the years prior to when the pipeline became fully
depreciated.

**Accumulated Deferred Income Taxes
(ADIT)**[]{#__RefHeading___Toc126142327 .anchor}**.** This is the amount
of income taxes collected by the pipeline but not yet needed to pay
current income taxes. ADIT arise from differences in the methods of
computing taxable income for the various taxing bodies and income for
financial statement purposes. In ratemaking, ADIT associated with
depreciation expense is the main component of total ADIT. ADIT
associated with depreciation expense results because of differences due
to the amount of depreciation expense recovered in a pipeline\'s rates
versus the amount of depreciation expense that the pipeline can claim
for tax purposes.

For tax purposes, a pipeline can choose an accelerated method of
depreciation which produces a higher depreciation expense in the early
years compared to the straight-line method which is used for rate
purposes. A higher depreciation expense used as a deduction for income
tax purposes in the early year's results in a lower tax base and thus,
the pipeline actually pays taxes in an amount less than the taxes
collected in rates. This difference in the amount of taxes collected in
rates and the amount of taxes actually paid are accumulated each year
and are deducted from a pipeline\'s rate base as ADIT.

In essence, ratepayers are prepaying the income taxes and the pipeline
will have use of these extra dollars until it has to pay more income
taxes in subsequent years as its taxable deduction for depreciation
decreases. That is, there will be a point in time when the depreciations
expense computed on an accelerated basis for tax purposes will be less
than the depreciation expense under the straight-line method. At this
point, a pipeline will be collecting less taxes in rates than it needs
to pay for income tax purposes. Thus, the monies accumulated as ADIT
will be used to pay these taxes and the ADIT balance will start to
decline.

We deduct ADIT from rate base because we perceive these \"prepaid\"
dollars to be an investment by the ratepayers which is used by the
pipeline to finance its capital investment. The effect of this credit is
to reduce the cost of providing service to ratepayers by an amount equal
to the deferred income taxes multiplied by the overall rate of return.
ADIT associated with other cost and revenues affecting the cost of
service are also deducted from rate base.

*Schedule [A-5](#A5) shows a method for computing ADIT when the only tax
timing difference results from the difference in computing depreciation
expense for tax purposes versus computing depreciation expense for rate
purposes. The schedule shows that you can simply take the difference
between the depreciation expense computed for rate purposes and the
depreciation expense computed for tax purposes, for each year of
operation, and multiply these differences by the effective tax rate. The
cumulative total for each year represents the surplus, or excess taxes
collected by Pipeline U.S.A. in rates but not yet payable for tax
purposes.*

*[Note]{.underline}: If we were to compute the ADIT through year 25, the
economic life of the pipeline, the balance at year 25 would be 0. For
the initial years, the ADIT balance increases each year until it reaches
the \"crossover\" point and then starts to decline. The crossover point
is reached when the accelerated depreciation method begins producing a
depreciation expense lower than the straight-line method, at this point,
the balance starts to decline each year until it reaches 0.*

**Working Capital**[]{#__RefHeading___Toc126142328 .anchor}**.** The
Commission recognizes working capital as an additional investment by the
pipeline upon which it is entitled to earn a reasonable return. This
item includes cash working capital, prepayments, and materials and
supplies.

[Cash working capital]{.underline}[]{#__RefHeading___Toc126142329
.anchor} is the amount of cash which a pipeline needs in daily
operations to pay operating expenses. This is the amount claimed to
bridge the timing gap between when expenses are incurred and when
revenues are received. In order to include cash working capital in rate
base, the Commission requires the pipeline to provide a \"lead-lag\"
study to show that the company actually has a lag between expenses and
receipts of revenue.

*Pipeline U.S.A. has not submitted a lead lag study, therefore, there is
no allowance included in rate base for cash working capital. Most
pipelines choose not to file lead-lag studies.*

[Materials and Supplies, and
Prepayments]{.underline}[]{#__RefHeading___Toc126142330
.anchor}[.]{.underline} Under the regulations, pipelines may include an
allowance in rate base for the average of 13 monthly balances of
materials and supplies and prepayments. These items are included in rate
base because they represent investments paid for by the pipeline, which
have not been used by the pipeline. For example, a pipeline keeps an
inventory of materials and supplies on hand for future use. This
inventory is considered an investment by the pipeline upon which it
should be allowed to earn a return. Once the materials and supplies are
used, they are expensed (removed from a capital account, and charged to
an expense account). Similarly, prepayments represent payments for
services in advance, such as insurance premiums. These monies are
considered an investment by the pipeline for future coverage/service, as
with insurance premiums. Once the prepayments are \"used\" they are
amortized over the period that the prepayment covers and expensed based
on the amortization schedule.

*[A-6](#A6) shows the average of thirteen monthly balances for materials
and supplies, and prepayments to be included in Pipeline U.S.A.\'s rate
base.*

**[Cost-of-Service]{.underline}**[]{#__RefHeading___Toc126142331
.anchor}

Following is a description of the components of the cost-of-service.

**Return**[]{#__RefHeading___Toc126142332 .anchor}**.** Under
cost-of-service ratemaking, pipelines are given the opportunity to earn
a reasonable return on their investment. As discussed previously, a
pipeline\'s rate base represents the total investment of the pipeline.
Thus, the Return component of the cost-of-service is calculated as
follows:

Rate Base

[x Rate of Return]{.underline}

= Return

The Return that we include in a pipeline\'s cost-of-service represents
the **After Tax Return**. The Return includes an amount which provides a
return on the pipeline\'s equity investment, as well as including an
amount to recover the interest on a pipeline\'s debt. That is, it
represents the amount of profit we are permitting the company to earn,
after payment of all of its expenses (except interest on long term
debt), including taxes, allowed in the cost-of-service. As shown, the
Return allowance is determined by multiplying Rate Base by the overall
**Rate of Return (ROR)**.

*[A-7](#_1199886883) shows the calculation of Pipeline U.S.A.\'s return
allowance of \$53,067.*

**The Overall Rate of Return** is computed as a function of the
following three components: the capitalization ratio of the pipeline,
the cost of debt, and the allowed rate of return on the pipeline\'s
preferred and common equity.

*As shown on [A-8](#_1199886892), to arrive at the rate of return of
9.975%, the \"weighted\" cost of debt of 5.775% is added to the
\"weighted\" cost of equity of 4.20%. The \"weighted\" cost of debt is
the actual cost of debt of 8.25% weighted by the percentage of debt in
the capital structure of 70% (i.e. 8.25% times 70% = 5.775%). Similarly,
the \"weighted\" cost of equity represents the equity return of 14.00%
weighted by the percentage of equity in the capital structure (14.00%
times 30% = 4.20%). More explanation follows regarding the components
which appear on this schedule.*

Following is a more detailed explanation of each of the components
necessary to calculate the Overall Rate of Return.

> **Capitalization or Capital Structure**[]{#__RefHeading___Toc126142333
> .anchor}**:** A pipeline\'s capital structure is a representation of
> how a pipeline has financed its investment (rate base). It is
> represented as a ratio of a pipeline\'s debt, common equity and
> preferred equity. For example, a pipeline which has financed its
> investment with \$6 million debt and \$4 million in common equity, is
> referred to as having a 60%/40% debt-equity capitalization ratio.
>
> We generally accept the pipeline\'s actual capital structure. However,
> more recently the Commission determined that it was only reasonable to
> use a subsidiary pipeline\'s actual capital structure when the
> subsidiary pipeline issues its own debt which is not guaranteed by its
> parent, has its own bond rating, and its equity ratio is comparable to
> other equity capitalizations approved by the Commission. If the
> pipeline does not meet these criteria, the parent company\'s capital
> structure will be used in instances where the parent issues stock and
> incurs debt for the pipeline.
>
> In the past, if the pipeline proposed a capital structure of 100%
> equity and no debt (or a very high equity ratio), staff often proposed
> use of a hypothetical capital structure that establishes a lower
> equity component and imputes a debt component. We do this because it
> is more costly to the rate payer to finance a pipeline\'s investment
> with equity.

*As shown on [A-8](#_1199886892), Pipeline U.S.A.\'s own capital
structure of 70% debt and 30% equity is used to compute the overall rate
of return.\* It is common that newer companies, such as Pipeline U.S.A.
which has only been in service for three years, have high debt ratios.
As shown by columns (1) and (2), 70% of Pipeline U.S.A.\'s investment
(rate base), or \$372,403,000 is debt financed as Pipeline U.S.A. issued
debt to bondholders to finance this portion of its investment. Also,
note that 30% of Pipeline U.S.A.\'s investment, or \$159,602,000, is
equity financed. This means that the owners of Pipeline U.S.A. used
their own funds to finance this portion of their investment.*

*\* Pipeline U.S.A. issues its own debt which is not guaranteed by its
parent, has its own bond rating and its capital structure is comparable
to other equity capitalizations approved by the Commission. Therefore,
Pipeline U.S.A. meets the Commission\'s criteria for using its own
capital structure for setting its rates.*

> **Cost of Debt**[]{#__RefHeading___Toc126142334 .anchor}**:** This
> refers to the cost of long term debt incurred by the pipeline to
> construct or expand the pipeline. For ongoing pipelines that have been
> issuing debt, we use the actual imbedded cost of debt in the capital
> structure. The actual imbedded cost of debt is the weighted average of
> all the debt issued and the cost at which the debt was issued. For new
> pipelines that have indicated that they would issue debt to finance
> their investment, but have not yet actually issued the debt, we
> compute the cost of debt based on a projection, or recent historical
> debt cost such as historical average Baa utility bonds (Moody\'s Bond
> Survey), which is the most prevalent rating for utilities. We also use
> Moody\'s to compute the cost of debt if we decide use of a
> hypothetical capital structure is appropriate.

*[A-8](#_1199886892), column 3, shows the cost of debt of Pipeline
U.S.A. of 8.25%. The cost of debt represents a return to Pipeline
U.S.A.\'s bondholders. The debt return dollars appearing in Column 5
represents the cost to Pipeline U.S.A. to pay the interest on the debt
to its bondholders. This debt return, or interest on debt, of
\$30,723,000 as shown in column (5) is included in the Return component
of the cost-of-service*.

> **Return on Equity**[]{#__RefHeading___Toc126142335 .anchor} **or Cost
> of Equity**: This is the pipeline\'s actual profit, or return on its
> investment. The return on equity is derived from a range of equity
> returns developed using a Discounted Cash Flow (DCF) analysis of a
> proxy group of publicly held natural gas companies. The Commission
> currently uses a two-stage Discounted Cash Flow (DCF) methodology. The
> two-stage method projects different rates of growth in projected
> dividend cash flows for each of the two stages, one stage reflecting
> short term growth estimates and the other long term growth estimates.
> These estimates are then weighted, two-thirds for the short-term
> growth projection and one-third on the long-term growth, and utilized
> in determining a range of reasonable equity returns. Two-thirds is
> used for the short-term growth rate on the theory that short-term
> growth rates are more predictable, and thus deserve a higher weighting
> than long term growth rate projections. An equity return is then
> selected within this zone based on an analysis of the company\'s risk.
> It is assumed, that most pipelines face risks that would place them in
> the middle of the zone of reasonableness. However, a case could be
> made depending on the facts of the specific pipeline that the return
> on equity should be outside the zone. As an example, a pipeline with a
> high debt capitalization ratio is usually considered more risky and
> thus, a higher return on equity would be expected.

*We have determined that a reasonable return on equity for Pipeline
U.S.A. is 14.00%. This return was at the high end of our range of equity
returns because Pipeline U.S.A. is a relatively new pipeline company
with a high debt capitalization ratio. The equity portion of the return
permitted to be collected in rates is \$22,344,000 shown in column (5)
of [A-8](#_1199886892).*

**Pretax Return**[]{#__RefHeading___Toc126142336 .anchor}**.** Pretax
return is the amount earned by a pipeline before income taxes and debt
interest payments. Pretax return is often calculated for pipelines and
used to further settlement negotiations. Using a pretax return figure
can avoid the lengthy discussions and debates that surround the issues
of capitalization ratios and ROE calculations and analyses. Use of a
pretax return reduces these issues down to one number, a pretax
percentage that can easily be compared to other pipeline\'s pretax
returns. The pretax return figure represents the amount the company
receives from the rate payers. This includes the after-tax return (both
debt and equity) and related income taxes. In order to compute the
pretax return the following information is needed: The overall rate of
return (ROR), the combined effective income tax rate, and the weighted
interest deduction.

*[A-9](#A9) shows the steps and formula\'s necessary to compute Pipeline
U.S.A.\'s pretax return. First, you need to calculate the combined
effective tax rate which will be used as a component in the pretax
formula computation. Next, you calculate the pretax return percentage
using the formula as shown. The resulting 12.53% represents Pipeline
U.S.A.\'s before tax, or pretax return. The formula is adding the
pipeline\'s overall (after tax) rate of return percentage of 9.975% to
the grossed up taxes expressed on a percentage basis. This sum is the
pretax return of 12.53%. This formula computes on a percentage basis the
same pretax return which is arrived at by adding the Federal and State
Income Taxes and the Return components of Pipeline U.S.A.\'s
cost-of-service, as shown on [A-1](#A1), the sum of which is
\$67,265,000 and dividing by the Rate Base of \$532,005,400
([A-2](#A2)). The resulting pretax return is 12.64%. This percentage
differs from the pretax return computed using the pretax formula because
the pretax formula does not include tax adjustments, such as the AFUDC
tax adjustment included in Pipeline U.S.A.\'s tax computation on
[A-12](#A12)[.]{.underline}*

**Operation and Maintenance Expenses**[]{#__RefHeading___Toc126142337
.anchor} **(O&M).** These expenses represent the pipeline\'s cost of
operating and maintaining its utility plant and equipment, or the cost
of running the physical pipeline system.

*Schedule [A-10](#A10) shows Pipeline U.S.A.\'s transmission O&M and A&G
expenses by account. Each account contains costs related to Labor and
Non-Labor (Materials and Supplies) amounts. This distinction will be
important later, when we classify costs as fixed or variable. The
Non-Labor, or Materials and Supplies, portion of the accounts related to
compressor station operation and maintenance are traditionally
classified as variable costs. (See [A-17](#A17)).*

**Administrative and General Expenses**[]{#__RefHeading___Toc126142338
.anchor} **(A&G).** These expenses include salaries and wages, office
supplies, outside services, regulatory commission expenses, rents and
general plant maintenance. In cases where the pipeline is a subsidiary
or owns other pipeline systems, the parent company or main office may
incur overhead expenses on behalf of the subsidiary, or for all systems.
In such a case, it is necessary to directly assign, or allocate, to the
particular subsidiary, or system, a portion of these overhead costs.
Next, we must directly assign, or allocate, a pipeline\'s total A&G
expenses, including the overhead assigned or allocated from the parent,
to the various functions of the pipeline, such as the transmission
function. Typically, A&G expenses are not easy to directly assign to a
particular function. Therefore, most A&G expenses must be allocated to
each function.

*At the bottom of [A-10](#A10), the transmission A&G expenses for
Pipeline U.S.A. are shown by account. These costs were allocated to the
transmission function using the Commission approved K-N methodology
which will be discussed under Step 2: Cost Functionalization. Also,
these A&G costs include an amount of costs allocated from Pipeline
U.S.A.\'s parent which shares certain executive personnel. A portion of
these executive\'s salaries are allocated to Pipeline U.S.A.*

**Depreciation Expense**[]{#__RefHeading___Toc126142339 .anchor}**.**
This is the return [of]{.underline} investment in the pipeline
facilities over the estimated useful life of the facilities. This amount
represents the recovery of the investment in facilities as opposed to
profits from the investment. We typically use the straight line
depreciation method for computing the depreciation rate. Under the
straight-line method the depreciation rate can be calculated by dividing
the estimated useful life of the facility into the ratio of the
undepreciated gross plant to total gross plant. For example, if the
facility is yet to be depreciated, the calculation for would be 100%
divided by the remaining life, which will yield the depreciation rate.
We typically use a minimum life of 25 years (4.0% per year), or 20 years
(5.0% per year), for transmission and storage facilities. If a facility
is 50% depreciated, and the remaining useful life is estimated to be 25
years, the depreciation rate would be 50% divided by 25, or 2%.
Depreciation is a method of recovering the investment in gas plant over
its estimated useful life. As consumers are charged for depreciation in
the cost-of-service, the amounts recovered are accumulated annually
(monthly) and deducted from gross plant investment in arriving at net
(undepreciated) plant yet to be recovered by charges to consumers. These
accumulated amounts of depreciation expense are shown as a reduction to
gross plant as the Accumulated Reserve for Depreciation .

*[A-11](#A11) shows the calculation of Pipeline U.S.A.\'s annual
depreciation expense. First, the depreciable plant must be computed.
Note that land is not depreciable and must be deducted from gross plant
to arrive at depreciable plant. Next, the depreciable plant of \$629,080
is multiplied by a 4% annual depreciation rate to arrive at the annual
depreciation expense of \$25,163. The 4% depreciation rate is based on a
depreciable life of 25 years (100% divided by 25 years). This rate was
authorized at the time Pipeline U.S.A.\'s initial rates were approved by
the Commission.*

**Federal and State Income Taxes**[]{#__RefHeading___Toc126142340
.anchor}**.** These are amounts included in the cost-of-service to allow
the pipeline to recover federal and state income taxes. Income taxes are
assessed on the equity portion of the return allowance. The current
federal income tax rate is 35% of taxable income. State tax rates vary
by state, but usually fall between 4% and 8%. Some states including
Texas and South Dakota, have no state tax rate.

To compute the tax allowance we begin by computing taxable income. To
compute taxable income we start with the total return dollars and deduct
the interest expense, or the cost of debt. Interest expense is computed
by multiplying the weighted cost of debt by the rate base. The remaining
amount is the after tax return, or the equity return after taxes. To
this, we add an amount for the permanent tax timing differences such as
for the Allowance for Funds Used During Construction (AFUDC), the
necessity of which is described in more detail below. This gives us the
Taxable Income.

We cannot simply multiply the Taxable Income by the appropriate tax
rate. This is because the company receives, as permitted in its
cost-of-service, an additional revenue stream which includes an amount
for taxes. Therefore, the pipeline must pay taxes on this tax allowance.
In order to be completely reimbursed so that it receives its equity
return, the company must also receive an amount to pay the taxes on the
tax allowance included in its rates. This is accomplished by a tax on
tax formula which is the tax rate divided by one minus the tax rate. For
Federal Income Taxes it would be .35 divided by 1 minus .35. For State
Income Taxes the Taxable Income must be increased for the amount of the
Federal Tax Allowance because the company must pay taxes on this
allowance. Then a similar formula using the state rate is applied to the
State Taxable Income. In this case it is .0429 divided by 1 minus .0429.

Another way to compute total income taxes (both State and Federal) is to
multiply the Taxable Income using the Combined Effective Tax Rate in the
tax on tax formula. The combined effective tax rate is 37.79% (See
[A-13](#A13) and description below) so the formula would be .3779
divided by 1 minus .3779.

**AFUDC** []{#__RefHeading___Toc126142341 .anchor}- the equity portion
of AFUDC which is included in depreciation expense is not considered
deductible by the Internal Revenue Service (IRS). However, for rate
purposes we consider all expenses, including 100% of the depreciation
expense, to be deductible when we calculate the income tax allowance.
Because the IRS does not permit this deduction, we must add the AFUDC
portion of the depreciation expense to the tax base in order to compute
the proper income tax expense for the pipeline. Otherwise, the pipeline
will not be permitted to collect the proper income tax allowance.

*[A-12](#A12) shows the computation of Pipeline U.S.A.\'s Federal Income
Taxes and State Income Taxes to be included in the cost-of-service. This
schedule also shows the computation of these taxes on a composite
(combined) basis.*

**Effective Tax Rate** []{#__RefHeading___Toc126142342 .anchor}**or
Combined Tax Rate or Composite Tax Rate** - When computing a
cost-of-service we must include both federal and state income taxes. The
federal income tax rate is 35% and the state rate for Pipeline U.S.A. is
4.29%. However, these rates are not additive. That is, we cannot
conclude that Pipeline U.S.A. is paying taxes equivalent to 39.29% of
taxable income. Because state taxes are considered to be appropriate
deductions when computing federal income taxes, the actual combined
federal and state tax rate is less than the sum of the two tax rates.

*[A-13](#A13) shows the formula for computing the effective combined tax
rate for Pipeline U.S.A. The first step is to multiply the state tax
rate by the federal tax rate. The product is then subtracted from the
federal rate, producing the effective federal tax rate given that state
taxes are a deduction. Next, the state tax rate is added to the reduced
federal rate. The sum of which is the combined effective tax rate of
37.79%.*

> **Limited Liability Companies**[]{#__RefHeading___Toc126142343
> .anchor}, or partnerships are not subject to federal taxation and thus
> special rules apply. However, if the members of a partnership are
> corporations subject to corporate income taxes on their allocated
> shares of the partnership\'s income, the Commission permits the
> partnership a tax allowance in the cost-of-service.

**Non-Income Taxes**[]{#__RefHeading___Toc126142344 .anchor}**.** These
include property taxes or ad valorem taxes, franchise taxes and
employment taxes. These vary from state to state. Property or ad valorem
taxes are taxes on the value of real estate, and personal property.
These taxes are often assessed on the plant investment a pipeline has in
a given state. Franchise taxes are sometimes assessed by a city in
return for allowing the pipeline to provide service to the city.
Employment taxes are assessed on the payrolls of the pipelines to pay
for FICA taxes, which include social security and Medicare, and
unemployment insurance.

*[A-14](#A14) shows the test period property and employment taxes for
Pipeline U.S.A.*

**Credits to the Cost-of-Service**[]{#__RefHeading___Toc126142345
.anchor}**.** There are many items that could be credited to a
pipeline\'s cost-of-service. A credit to the cost-of-service is a
reduction to the cost-of-service. If the pipeline has processing
facilities, it may extract salable liquids from the gas stream. We
attempt to project the level and the price for the products and we
credit this amount to the cost-of-service. If the pipeline rents out
facilities, or receives payment from leased facilities, staff may
recommend a credit to the cost-of-service for these amounts. If the
pipeline has been collecting excessive revenue from the imposition of
penalties such as penalties for violating Operational Flow Orders
(OFO\'s), staff may recommend that these monies be credited to the
cost-of-service. Additionally, one method for computing a discount
adjustment is to credit the revenues from the discounted services to the
cost-of-service while removing the associated volumes from the rate
design determinants. Discount adjustments and revenue crediting will be
discussed later in this manual.

*Pipeline U.S.A. does not have any revenues that will be credited to the
cost-of-service.*

**Step 2: Computing a Functionalized
Cost-of-Service**[]{#__RefHeading___Toc126142346 .anchor}

Prior to Order No. 636, a pipeline\'s costs were traditionally
functionalized into three broad categories; Production, Storage and
Transmission, which recognized the functions of the facilities owned by
the pipeline. The Production function included the costs associated with
a pipeline\'s own production as well as purchased gas costs and
gathering costs. Today, as a result of Order No. 636, pipeline\'s no
longer act as gas merchants. This function has primarily been taken over
by the pipeline\'s affiliated marketer. Additionally, many pipelines
have sold or assigned their gathering facilities to non-jurisdictional
entities. Thus, today a pipeline primarily has two functions, Storage
and Transmission.

A functionalized cost-of-service is computed by directly assigning or
allocating operation and maintenance expenses and other costs incurred
by the company to the various functions, [e.g.]{.underline} storage
function and/or transmission function, of the particular pipeline
company.

**How are costs functionalized?**

**O&M** expenses are directly assigned to the function for which they
are incurred. In fact, pipelines are required to book their expenses to
particular accounts under the Commission\'s Uniform System of Accounts.
These accounts are set up on a functionalized basis.

**A&G** expenses include wages and salaries, rent expense, insurance
premiums, supplies, charitable contributions, expenses for outside
services employed and regulatory commission expenses. These expenses are
not set up on a functionalized basis under the Uniform System of
Accounts as these items often cannot be directly assigned, nor easily
identified with a particular function. Thus, for ratemaking purposes,
the costs that cannot be directly identified with a function must be
allocated among the functions. The *Kansas-Nebraska Method* (K-N) is the
preferred methodology used by the Commission to allocate these A&G costs
to functions as described in more detail below.

> **K-N Method**[]{#__RefHeading___Toc126142347 .anchor}**.** The K-N
> Method is a Commission approved method for allocating a pipeline\'s
> A&G expenses that are not directly assigned among the various
> functions\--today, those are primarily storage and transmission, using
> cost causation principles. That is, the method uses functionalized
> labor and plant ratios as allocation factors. In theory, when applied,
> this method is designed to prevent cross subsidization of one service
> over another.

The K-N Method involves the following steps:

> 1\) First, the pipelines total A&G expenses are listed by account.
>
> 2\) Second, these expenses are then classified as being related to
> \"labor\", \"plant\" or \"other.\" The expenses related to labor
> include A&G Salaries, Office Expenses, and Pension and Benefit
> Expenses. A&G expenses related to plant, include Property Insurance
> and General Plant Maintenance. The expenses that are not particularly
> related to plant or labor are listed as \"other\" and these expenses
> include Outside Services, Regulatory Commission Expense and
> Miscellaneous General Expenses.
>
> 3\) Third, the costs classified to \"other\" are then allocated
> between the labor and plant categories.
>
> 4\) Fourth, the total labor related amount of A&G is then allocated to
> the pipeline\'s storage and transmission functions based on the
> percentage of direct labor associated with each function. Similarly,
> the plant-related amount of A&G is allocated to the functions based on
> the percentage of gross plant associated with each function.

**Depreciation** expense is functionalized on the basis of the gas plant
devoted to each function.

**Taxes Other Than Income** are functionalized by first directly
assigning the costs that are specifically related to a specific
function. Second, the remaining costs are identified as either being
related to plant or labor. Plant-related costs, such as property taxes,
are functionalized on the basis of the gas plant ratios. Those taxes
related to labor, such as unemployment taxes, are functionalized on the
basis of the direct labor ratios.

**Income Taxes** are a function of the return allowance associated with
the rate base computed for the function.

**Return** for each function is the product of each functions rate base
multiplied by the rate of return.

**Revenue Credits** are typically directly assigned to the function to
which they relate.

When all expenses and return have been functionalized, the items are
totaled for each function. The result is a functionalized
cost-of-service for each function of the pipeline.

*The transmission cost-of-service appearing on [A-1](#A1) represents a
functionalized transmission cost-of-service for Pipeline U.S.A. Note
that Pipeline U.S.A. only owns transmission facilities. Therefore,
developing a functionalized cost-of-service is easy because there is
only one function. However, let\'s assume that Pipeline U.S.A. owns both
transmission and storage facilities. Now, we must develop functionalized
transmission and storage cost-of-services.*

*Illustrative functionalized cost-of-services appear on
[A-15](#A15)[.]{.underline} The amounts for each function were derived
as discussed above. Most costs are directly assigned to the appropriate
function, such as O&M and revenue credits. Other costs such as return
and taxes are a function of the rate base for each function.
Depreciation expense is derived by multiplying the depreciable plant for
each function by the annual depreciation rate for each function. One of
the most involved calculations in developing a functionalized cost of
service is the allocation of A&G expenses among or between the various
functions.*

*The A&G expenses cannot be directly assigned to the storage and
transmission functions as these costs are incurred to support both
functions. Therefore, these costs must be \"allocated\" to each
function. Schedule [A-16](#A16) shows the allocation of total A&G costs
between the storage and transmission functions based on the K-N
methodology. As shown, the total A&G expenses of Pipeline U.S.A. are
listed by account. Then they are classified as related to Labor, Plant
or Other. The Other costs are then allocated between the Labor and Plant
columns based on the ratio of the Labor and Plant column total,
respectively, to the total of these two columns. In this case, 76% of
\"Other\" costs are allocated to the Labor column and 24% are allocated
to the Plant column. Next, these allocated amounts are added to the
Labor and Plant column totals to arrive at new totals.*

*Next, the Allocation Factors for allocating these Labor and Plant
related costs between the transmission and storage functions are
calculated. First, as shown, 30% of Labor related costs will be
allocated to the Storage function and 70% to the Transmission function.
Similarly, as shown, 59% of the Plant related costs will be allocated to
the Storage function and 41% will be allocated to the Transmission
function.*

*Finally, at the bottom of [A-16](#A16) , the Direct Labor related costs
and the Gross Plant related costs are then allocated to each function
based on the above allocation factors. These amounts are then totaled
for each function to arrive at the total A&G costs allocated to each
function.*

**Step 3: Cost Classification**[]{#__RefHeading___Toc126142348 .anchor}

Cost classification is a two step process. First, functionalized costs
are classified as either fixed or variable. Next, fixed and variable
costs are then classified as reservation (demand) or usage (commodity).
Prior to Order Nos. 436 and 636 when pipelines offered primarily bundled
sales service, the rate components were referred to as \"demand\" and
\"commodity.\" After Order Nos. 436 and 636, which paved the way for
pipeline\'s to become solely transporters of natural gas, the Commission
started using the terms \"reservation\" and \"usage\" rates which are
more akin to transportation terms. However, in practice these terms are
synonymous and will be used interchangeably in this manual and in the
Appendices.

**Classification of Costs Between Fixed and
Variable**[]{#__RefHeading___Toc126142349 .anchor}

In cost classification, the costs that make up the cost-of-service are
identified as either fixed or variable, depending on their
characteristics. Fixed costs are costs which remain constant regardless
of the volume of throughput and are predominately associated with
capital investment in the pipeline system. Fixed costs include
investment related costs such as depreciation, return and taxes, as well
as certain O&M expenses, including labor, A&G expenses and as-billed
third party reservation costs.

Variable costs are costs which vary with the volume of throughput. Prior
to Order No. 636, variable costs primarily consisted of purchased gas
costs and compressor fuel costs. Many companies also traditionally have
classified the non-labor portion of certain O&M expense accounts as
variable costs. Non-labor costs include materials and supplies. Since
Order No. 636, pipelines are no longer sellers of gas, thus purchased
gas costs are no longer collected in a pipeline\'s rates. As for fuel,
many pipelines retain fuel as a percentage of total receipts of gas,
thus, pipeline\'s today often do not include fuel costs in their rates.

*[A-17](#A17) shows Pipeline U.S.A.\'s transmission costs classified
between fixed and variable costs. As shown, the variable costs represent
the Non-labor or Material and Supplies portion of the O&M accounts
related to compressor and meter stations (See [A-10](#A10)). The
remainder of the costs are classified as fixed costs.*

**Classification of Costs Between Demand and
Commodity**[]{#__RefHeading___Toc126142350 .anchor}

After functionalized costs are classified as fixed and variable, they
are then classified as demand or commodity. The demand and commodity
components have generally been associated with providing peak and annual
services. Variable costs have always been classified to the commodity
component in order to match their recovery with the level of throughput.
Sometimes an issue may arise as to whether a cost is variable. However,
the basic premise that variable costs are classified to the commodity
component is relatively uncontroversial. However, the classification of
fixed costs between demand and commodity components has historically
been a controversial issue. The issue becomes particularly heated
because the choice of a cost classification method can have direct
effects not only on the rates paid, but also on the revenue
responsibility of a particular class of customer. For example, a
particular cost classification method could result in more costs being
allocated to a particular service. Additionally, depending on a
customer\'s load factor, a particular cost classification method may
mean a customer pays a higher unit rate per dekatherm of gas
transported. Because these decisions have a direct monetary impact on
individual customers, or classes of customers, it is the cause for much
debate.

The Commission has used various cost classification methods to classify
costs in response to particular industry trends and situations. In most
cases, the cost classification method used will be followed for
allocating costs and designing rates.

**In 1938,** the Natural Gas Act was passed and the transportation and
sale of natural gas in interstate commerce became subject to the
jurisdiction of the Commission. During this time period, rates were
designed on a volumetric basis, that is, all costs were collected in
commodity rates. This made sense at the time as pipelines had
contractual obligations to serve a customer\'s total requirements.
Contracts did not specify a specific contract demand level for service
to a particular customer. Instead, a pipeline was obligated to supply
all of a customer\'s requirements, whatever those requirements were and
customers were required to pay a rate per unit of gas transported. This
was known as the Volumetric []{#__RefHeading___Toc126142351
.anchor}method.

*[A-18](#A18) shows the classification of costs for the design of a 100%
volumetric, or commodity rate. Here, 100% of the costs are classified to
the commodity component.*

**In 1942,** the Commission used the \"peak responsibility\" or
Fixed-Variable[]{#__RefHeading___Toc126142352 .anchor} method for
classifying costs. Under the Fixed-Variable method all fixed costs are
assigned to the demand component. Variable costs are included in the
commodity component. During this time period, service obligations became
more centered on defining a peak level of service to be offered as
opposed to the pipeline having an open ended commitment for service. At
that time, the Commission reasoned that because pipeline capacity and
pending expansions controlled service levels, it was reasonable to place
all fixed costs in the demand component to reflect the importance of
capacity costs.

*[A-19](#A19) shows Pipeline U.S.A.\'s transmission costs classified
under the Fixed-Variable or Straight Fixed-Variable (SFV) methods.*

**In 1952,** the Commission determined that both peak and annual use
were of equal importance in determining cost responsibility and thus
established the Seaboard []{#__RefHeading___Toc126142353
.anchor}methodology. Under Seaboard, fixed costs associated with
transmission and storage functions were apportioned 50 percent to the
demand category and 50 percent to the commodity category. All production
costs were assigned to the commodity category.

*[A-20](#A20) shows the classification of Pipeline U.S.A.\'s
transmission costs to the demand and commodity components using the
Seaboard methodology. Remember that Pipeline U.S.A. does not have
storage or production functions.*

**In 1973,** the Commission adopted the
United[]{#__RefHeading___Toc126142354 .anchor} methodology. Under
United, 25% of fixed storage and transmission costs are classified to
the demand component and 75% of the storage and transmission fixed costs
are classified to the commodity component. Production costs remained in
the commodity charge. During this time period, gas shortages and
resulting curtailments prevailed. The Commission found that a change
from the Seaboard methodology was warranted. In Seaboard, the Commission
concluded that neither peak nor annual usage predominated. In United,
the Commission reasoned that peak usage was no longer a valid measure of
a customer's responsibility for capacity costs. Given the gas supply
situation in the early 1970\'s, a customer's payment of a demand charge
for capacity rights did not assure the customer of receiving gas. Thus,
the Commission concluded annual usage represented a more reasonable way
to collect fixed costs. Thus, more costs were shifted to the commodity
component. Additionally, the Commission found that the result of the
shift of costs to the commodity component, which would increase the cost
to industrial high load factor customers, was not unreasonable given
that these industrials were the least favored customers in the
curtailment plans and many were capable of using alternative fuels. To
date, other than a purely volumetric rate, the United methodology
classifies the most fixed costs to the commodity component compared to
other classification methods used by the Commission.

*[A-21](#A21) illustrates the classification of Pipeline U.S.A.\'s
transmission costs between demand and commodity components using the
United methodology.*

**In 1983,** the Commission adopted the Modified
Fixed-Variable[]{#__RefHeading___Toc126142355 .anchor} (MFV) method.
Under MFV, all fixed costs in the transmission and storage functions are
classified to the demand category, except for return on equity and
related income taxes which are classified to the commodity component
along with all variable costs. All production costs except for as-billed
pipeline supplier demand costs were classified to the commodity
category. During this time period, pipelines were underutilized on an
annual basis due to competition from alternative fuels. The MFV method
was intended to provide an opportunity for market enhancement and
increased rate flexibility and to maximize the use of system capacity.
In most cases, depending on the pipeline\'s capital structure, less
fixed costs are classified to the commodity component than under either
the Seaboard or United methods. The lowering of the commodity rate was
intended to increase gas sales. Also, by placing the pipeline\'s return
on equity, or its profit, in the commodity component of rates, it was
theorized that pipelines would be more aggressive in their effort to
market and sell gas services.

*[A-22](#A22) shows Pipeline U.S.A.\'s transmission costs classified
using the MFV methodology. The fixed costs classified to the commodity
component include \$22,344,000 in equity return ([A-8](#_1199886892))
plus income taxes of \$14,197,000 ([A-12](#A12)), for a total fixed
costs of \$36,541,000. These fixed costs plus variable costs of
\$2,600,000 equal the total costs of \$39,141,000 classified to the
commodity component*.

**In 1992,** with the issuance of Order No. 636, the Commission adopted
the Straight Fixed-Variable[]{#__RefHeading___Toc126142356 .anchor}
method (SFV). Under SFV, all fixed costs are classified to the demand
component and all variable costs are classified to the commodity
component. The Commission reasoned that a change from MFV was necessary
because each pipeline, depending on its capital structure, had different
levels of fixed costs in the usage (commodity) rates, thus hindering gas
on gas competition in the marketplace. The purpose of SFV was to promote
the development of a competitive market for natural gas at the wellhead
by eliminating transportation rate differentials.

*[A-19](#A19) shows the classification of Pipeline U.S.A.\'s
transmission costs using the SFV methodology.*

**1998 and 1999.** Now that Order No. 636 and the SFV rate design have
been in effect since 1992 and 1993, the Commission has been faced with
proponents that request a movement away from SFV. These proponents
promote a move toward incorporating or shifting more fixed costs to the
commodity (usage) component of rates arguing that this is necessary to
encourage short-term markets, to market freed-up capacity and to keep
costs low. The Commission will need to address these issues. In select
cases, or in approving settlements, the Commission has already approved
deviations from the SFV rate design. Also, as mentioned at the beginning
of this manual, the Commission has requested comments from the industry
on several rate matters (and specifically on SFV) as well as other
policy issues regarding the best way to regulate the new markets that
have developed since the issuance of Order No. 636.

**Step 4: Cost Allocation**[]{#__RefHeading___Toc126142357 .anchor}

Cost allocation entails apportioning the functionalized and classified
costs between jurisdictional and non-jurisdictional services, among
zones and among jurisdictional services. Costs are allocated between
services using volumes usually expressed in dekatherms (Dt, Dth, Dkt) as
allocation factors. Costs are typically allocated among zones using
Mdt-miles as allocation factors.

**Mcf\'s and Dth\'s**[]{#__RefHeading___Toc126142358 .anchor}

Gas is measured by volume in cubic feet (cf). Pipeline capacity is
expressed in Mcf, or 1,000 cubic feet.

1 Mcf = 1,000 cubic feet

1 MMcf = 1,000,000 cubic feet

1 Bcf = 1,000,000,000 cubic feet

Gas is sold, and rates are designed, based on the heat content of the
gas. The heat content of gas is measured in British thermal units (Btu)
or dekatherms (Dth, Dt, or Dkt)**.**

1 MMBtu **=** 1 Dth

To Convert Mcfs to Dths (or MMBtus) you need a conversion factor. The
conversion factor will vary depending on the heat content of the gas.
Let\'s assume the heat content of the gas to be transported is 1,035 Btu
per cubic foot. The conversion factor is:

1 cf = 1,035 Btu, or

1 Mcf = 1.035 MMBtu, or 1.035 Dth

Example:

1,000,000 Mcf = ? Dth

1,000,000 Mcf x 1.035 Dth/Mcf = 1,035,000 Dth

*[A-23](#A23) shows the conversion of Pipeline U.S.A.\'s firm
contractual entitlements of 1,000,000 Mcf, which equates to the capacity
of the pipeline, to dekatherms.*

**Allocation Factors and Billing
Determinants**[]{#__RefHeading___Toc126142359 .anchor}

Allocation factors are used to allocate costs among services. Billing
determinants are used to design rates. Both are based on some measure of
service level to a particular customer, or class of customers. In some
instances, allocation factors and billing determinants can be the same.
For example, commodity or usage costs are usually allocated between
services using commodity volumes. These commodity volumes are also used
to design the commodity (or usage) rates for each service. In other
circumstances, they can be different. For example, one could allocate
demand, or reservation, costs between services based on
consecutive-three day peak volumes. The demand rates, however, would be
designed on contract demand levels.

*[A-23](#A23) shows the firm and interruptible service levels for
Pipeline U.S.A. As described earlier, Pipeline U.S.A. has 4 firm
customers with contract demand entitlements which total the capacity of
the pipeline system 1,000,000 Mcf per day.* *This schedule shows the
total contractual entitlements of these four firm customers, as well as
their average day use of the pipeline system. This schedule also shows
the annual interruptible (IT) quantities transported, and the average
day* *IT quantities.*

**Load Factor**[]{#__RefHeading___Toc126142360 .anchor}

Load factor is a measure of a customer\'s, or group of customer\'s, use
of their contractual entitlements (or peak usage). A firm customer\'s
load factor is the ratio of his average day use to his daily contract
demand. If a customer transported 10,000 dth on average each day of a
year and his daily contract demand is 20,000 dth per day, that
customer\'s load factor is 50%. If a customer\'s average day were equal
to his daily contract demand, the customer would be a 100% load factor
customer. In some instances you will see load factor defined as a
measure of a customer\'s annual use compared to peak use. Here, for
purposes of this manual, we are using contract demand for a customer, or
group of customer, to be an accurate representation of peak day use.

A pipeline\'s \"system average load factor\" is computed by computing
the average annual day of total firm and interruptible transportation on
the pipeline and dividing by the pipeline\'s total firm daily contract
demand. Typically, the contract demand for firm customers on a pipeline
system is equivalent to the pipeline\'s total capacity. However, if it
is not, the system average load factor can be computed using the
pipeline\'s capacity as the denominator rather than the firm contract
demands. This provides a measure of the actual use of a pipeline system.

*[A-24](#A24) shows the firm service average load factor computed for
Pipeline U.S.A.\'s firm customers. It also shows the computation of
Pipeline U.S.A.\'s system average load factor.*

**Allocation of Costs Between Jurisdictional and Non-jurisdictional
Services**[]{#__RefHeading___Toc126142361 .anchor}

Prior to Order No. 636, an important allocation issue involved the
allocation of costs between jurisdictional and non-jurisdictional
services. Non-jurisdictional services consisted primarily of direct
sales to end-users which are not \"sales for resale\" under the NGA, and
thus, the Commission has no authority to set the rates for these
services. Instead, the Commission would allocate costs to these services
and the pipelines were free to charge any rates necessary to recover the
allocated costs. To allocate demand costs between jurisdictional and
non-jurisdictional services the basis used was peak utilization of the
system, such as the three-day sustained peak deliveries. Variable costs,
or commodity costs, were allocated on the basis of annual throughput of
the system. However, as a result of Order No. 636, which required
pipelines to offer unbundled sales and transportation services, and
pipelines subsequent assignment of their sales business to marketing
affiliates, has essentially eliminated the need for allocating costs to
non-jurisdictional business, as pipelines today do not make sales for
resale or direct sales.

*Pipeline U.S.A. does not have any non-jurisdictional business.
Therefore, there is no allocation between jurisdictional and
non-jurisdictional services.*

**Allocation of Costs Among Zones**[]{#__RefHeading___Toc126142362
.anchor}

When a pipeline system is divided into geographic regions, or zones,
costs are usually allocated to the zones based on Dth-miles. A detailed
discussion regarding the allocation of costs between zones and the
design of zoned rates, appears later in this manual on Pages 53-57.

*Pipeline U.S.A. does not have zones. Therefore, we can skip this step
in allocating costs. For now, we are merely allocating costs and
designing postage stamp rates for Pipeline U.S.A. A \"postage stamp\"
rate is a rate that is paid by all shippers regardless of the distance
the gas is transported on the system. A one mile haul would be subject
to the same maximum transportation rate as a 200 mile haul under postage
stamp rates.*

**Allocation of Costs Among Jurisdictional
Services**[]{#__RefHeading___Toc126142363 .anchor}

Once costs are classified between demand and commodity components, the
costs are allocated to the pipeline\'s services.

Transmission costs are allocated between a pipeline\'s transportation
services, such as firm and interruptible transportation services.
Previously, prior to Order No. 636, pipelines offered firm and
interruptible sales services. At that time, transmission costs were
allocated between sales and transportation service. Now, as a result of
Order No. 636, pipelines are no longer in the sales business. Therefore,
there is no longer a need to allocate transmission costs between sales
and transportation services. Transmission costs are now allocated among
the various types of transportation services offered by the pipeline
([i.e]{.underline}. no-notice transportation, short-term firm
transportation, interruptible transportation services, overrun services,
etc.)

*[A-25](#A25) shows the total transmission reservation and usage costs
under the SFV cost classification allocated between the firm and
interruptible transportation services of Pipeline U.S.A.*

*As shown, the reservation cost allocation factor for firm service of
1,035,000 Dth, is equivalent to the firm contract demand of Pipeline
U.S.A.\'s 4 firm customers. The interruptible reservation allocation
factor of 32,878 Dth is imputed at a 100% load factor. To arrive at the
imputed allocation factor at 100% load factor, the projected annual
interruptible service volume of 12,000,000 Dth is divided by 365 days
(365 days times 100%). (If the load factor for designing the
interruptible rate were 50%, the reservation cost allocation factor
would be derived by dividing the 12,000,000 Dth by 182.5 days (365 times
50%). The usage cost allocation factors for firm and interruptible
service are equivalent to the annual projected volume for these
services.*

*To arrive at the allocated costs for firm service, the total
reservation costs are multiplied by the ratio of the firm reservation
allocation factor of 1,035,000 dth divided by the total reservation
allocation factor of 1,067,878 Dth, or 96.92%. The remaining 3.08% of
reservation costs are allocated to interruptible service. Similarly, the
same calculation is used to allocate the usage costs between firm and
interruptible service. As shown, 95.43% of the total usage costs are
allocated to firm service, the remaining 4.57% of usage costs are
allocated to interruptible service.*

*Next, these allocated costs are used to design rates. As shown on
[A-26](#A26), the firm reservation rate is derived by dividing the
reservation costs allocated to firm service (from [A-25](#A25)) by the
firm billing determinants. The firm billing determinants are derived by
multiplying the firm contract demands of Pipeline U.S.A.\'s four firm
customers by 12 months. This is necessary to develop a monthly
reservation charge. Similarly, the firm usage rate is derived by
dividing the usage costs allocated to firm service (from [A-25](#A25))
by the projected annual units of firm transportation service.*

*Next, [A-27](#A27) shows the derivation of the interruptible
transportation rate. The reservation and usage costs allocated to
interruptible service (from [A-25](#A25)) are totaled and divided by the
projected annual interruptible transportation volumes to arrive at the
interruptible transportation rate per Dth of gas transported.*

***Note:** We have shown for illustrative purposes* *how costs can be
allocated between firm and interruptible transportation services
([A-25](#A25)) and how rates are then designed based upon these
allocated costs ([A-26](#A26) and [A-27](#A27)). However, when the
allocation factors are equivalent to the billing determinants, as the
case is here, a [separate]{.underline} cost allocation step does not
need to be performed. Instead, cost allocation can be combined into the
rate design step. With the Commission\'s current policy regarding the
design of the interruptible rate as the 100% load factor derivative of
the firm rate, we allocate costs to the interruptible rate in the rate
design step as discussed below in Step 5: Rate Design.*

**Step 5: Rate Design**[]{#__RefHeading___Toc126142364 .anchor}

Rate design is the final step and is used to directly translate the
costs allocated to the jurisdictional customers into unit charges or
rates. Rates are designed to recover the jurisdictional cost-of-service
which consists of the demand and commodity costs as determined by the
cost classification and cost allocation for each service.

**Firm Service Rates**[]{#__RefHeading___Toc126142365 .anchor}

Rates for firm service are usually two-part rates; that is, they contain
a reservation charge and a usage charge. The reservation charge is
usually a monthly charge per Dth of daily contract demand (CD). It
represents the amount that a firm customer must pay monthly to guarantee
service on any day up to the CD. For example, a customer with a CD of
200,000 Dth per day would pay \$2,000,000 per month, if the firm
reservation charge were \$10.00. The \$2,000,000 must be paid every
month regardless of the amount of gas actually transported. Even if the
customer does not transport any gas the customer must pay the
reservation charge. The payment of the reservation charge reserves a
right to the customer to receive service up to 200,000 Dth on any day.
In addition to the monthly reservation charge, the customer is also
billed a usage charge per unit of gas actually shipped.

The usage charge is a charge per Dth of gas actually transported. For
example, if the customer with the CD of 200,000 Dth per day, actually
transported 3,000,000 Dth during one month, that customer would pay
reservation costs of \$2,000,000 plus usage costs of \$150,000, assuming
a usage rate of \$0.05 per Dth, for that month.

**Interruptible Service Rates**[]{#__RefHeading___Toc126142366 .anchor}

Interruptible rates are designed as volumetric rates and charged per
unit of gas transported. The Commission has had a long-standing policy
that, in most cases, interruptible transportation rates should be
designed as the 100% load factor derivative of the firm transportation
rates. A discussion of the 100% load factor rate follows.

**Interruptible Rate Computed as Derivative of Firm
Rate**[]{#__RefHeading___Toc126142367 .anchor}

As mentioned, long-standing Commission policy requires that the
interruptible rate be the 100% load factor derivative of the firm
transportation rate. That is, the interruptible rate is derived from the
firm transportation rate. The Commission determined that the 100% load
factor rate was the appropriate rate for interruptible services as it
makes a reasonable contribution to the fixed costs of the pipeline
system, yet adequately recognizes the inferior quality of interruptible
service compared to firm service.

The Commission concluded that the 100% load factor rate recovered a
reasonable share of both reservation and usage costs and thus met the
criteria of being a \"fully allocated\" rate as required by the
regulations. The Commission found it was reasonable that interruptible
shippers should contribute to the fixed costs of the system - since
interruptible customers on most pipelines are only able to receive
transportation in instances where firm customers are not using all of
their firm entitlements.

Also, by paying the lowest unit rate that a firm shipper could pay for
firm service, appropriately recognizes the inferior quality of
interruptible service. A firm shipper would actually pay a unit rate
equivalent to the 100% load factor rate if that shipper took 100% of his
contact demand every day of the year.

The first step in designing the interruptible rate as a derivative of
the firm transportation rate, is to design the firm transportation
rates. To design the firm reservation fee, the reservation costs are
divided by the contract demand volumes for firm services plus an imputed
volume for interruptible service (in this case interruptible volumes are
imputed at 100% load factor), multiplied by 12 months (multiplying by 12
months is necessary to compute a monthly reservation fee). The resulting
reservation rate is charged to firm customers per unit of their contract
demand per month. Next, the firm usage rate is computed by dividing the
total usage costs by the projected annual firm and interruptible
transportation volumes. This rate is charged per unit (Dth) of gas
transported. Now that the firm reservation and usage rates have been
computed, the 100% load factor interruptible rate is derived by dividing
the firm reservation rate by 30.4 days (30.4 days represents the average
days for each month of the year, 365 days/year divided by 12 months).
This converts the monthly firm reservation fee to a unit daily charge.
This unit daily charge is added to the firm commodity rate. The total
represents the 100% load factor derivative of the firm transportation
rate. This interruptible rate is charged per unit of interruptible
service.

*[A-28](#A28) shows the derivation of the firm and interruptible
transportation rates under the SFV methodology as a \"one-step\"
process. The firm reservation rate is derived by dividing the total
reservation costs by the total firm billing determinants, which include
an imputed amount for interruptible service at 100% load factor. The
firm billing determinants are derived by multiplying the firm contract
demands of Pipeline U.S.A.\'s four firm customers, plus a daily volume
imputed at 100% load factor for interruptible service, by 12 months.
Multiplying by 12 months is necessary to develop a monthly reservation
charge.*

*Similarly, the firm usage rate is derived by dividing the total usage
costs by the total annual projected units of firm and interruptible
transportation service. This yields a firm usage rate per Dth of gas
transported.*

*Once the firm rates are derived, we can calculate the 100% load factor
interruptible rate. The interruptible rate is calculated by dividing the
firm reservation rate by 30.4 days (30.4 days time 100%). This
recognizes that we are designing a 100% load factor interruptible rate.
If we were designing an interruptible rate equivalent to the 50% load
factor derivative of the firm rate, we would divide the firm reservation
rate by 15.2 days (30.4 days times 50%). The resulting rate per Dth
represents the amount of reservation costs to be included in the
interruptible rate. Next, to this unit reservation rate we add the firm
usage rate. The total represents the 100% load factor interruptible
rate. This rate is collected per Dth of interruptible volumes
transported.*

*Schedules [A-29](#A29) through [A-32](#A32) show the calculation of
firm rates, and interruptible rates computed as the 100% load factor
derivative of the firm rates, using other rate design methodologies such
as MFV, Seaboard, United and the Volumetric method. [A-33](#A33) shows a
summary sheet of the firm and interruptible rates computed under each
method.*

**Revenue Check**[]{#__RefHeading___Toc126142368 .anchor}

Once you have designed rates, to ensure their accuracy, a revenue check
must be done. To do a revenue check, the rates for each service are
multiplied by the respective billing determinants. The product should
\"equal\" the cost-of-service (revenue requirement) established for the
company. Note however, the revenues generated by the revenue check will
not \"exactly\" equal the cost of service due to rounding. Rounding
errors should be negligible. The difference between the revenues
generated by the rates and the cost of service generally should not
differ by more than 1/100th of a percent. If the revenue check does not
produce revenues that are within this guideline, there is an error in
the calculation of the rates. The error needs to be found and corrected.

*[A-34](#A34) shows the revenue check for Pipeline U.S.A. under the SFV
methodology.* *Due to rounding the revenues generated do not exactly
equal the cost-of-service. Note, that the rounding error here is minimal
\$1,000/\$120,430,000 = 0.00083%.*

> **Rate Design and Load Factors**[]{#__RefHeading___Toc126142369
> .anchor}
>
> The revenue responsibility of a particular customer, or group of
> customers, is impacted by the rate design methodology used to design
> rates and the particular load factor of the customer, or group of
> customers. For example, a low load factor customer will have a high
> unit rate. A high load factor customer will have a low unit rate. A
> rate design which includes more costs in the commodity component of
> the rate, such as volumetric rates, or rates designed under the United
> methodology, is beneficial to low load factor firm customers. High
> load factor firm customers are better off under rate designs which
> include more costs in the demand or reservation charge, as with SFV
> and MFV. In order of decreasing negative impact on costs to low load
> factor customers, the cost classification and rate design methods can
> be listed as follows: SFV, MFV, Seaboard, United and Volumetric rates.
>
> *[A-35](#A35) through [A-38](#A38) show calculations of customers unit
> rates at various load factors, under each of the rate design
> methodologies.* *[A-39](#A39) shows a comparison of the unit rates a
> firm customer would pay under various rate designs at different load
> factors in order of decreasing impact on low load factor customers and
> increasing impact on high load factor customers.*
>
> **Small Customer Rates**[]{#__RefHeading___Toc126142370 .anchor}

Prior to Order No. 636, pipelines often offered bundled sales service to
small customers on their systems at subsidized rates. Small customers
were often defined as those that had contract demands of less than
10,000 Dth per day, although it varied by pipeline. Small customers are
often low load factor customers. That is, they do not take gas at a
constant amount each day of the year but tend to have seasonal
fluctuations. Most pipelines had specific rate schedules on file to
serve small customers. The rate was often designed on a volumetric basis
and was designed at an \"imputed\" load factor above the actual load
factor of the group of small customers. For example, if the small
customer groups\' load factor was 40%, the rate would be designed on
something higher, like a 60% load factor. The higher the load factor,
the lower the unit rate. Therefore, the small customers benefited from
the rate subsidy, as well as the fact that they did not have to pay a
demand charge. The volumetric rate permitted small customers to pay only
when they received service.

In Order No. 636, the Commission required that pipelines that offered
sales or firm transportation services to small customers on a one-part
volumetric basis, at an imputed load factor, were required to continue
to offer firm and no-notice service on the same basis. This
grandfathering of the small customer rate was intended as a mitigation
measure from the shift to the SFV rate design as required by Order No.
636. A rate design such as SFV, which includes all fixed costs in the
firm reservation charge has the effect of shifting costs to low load
factor customers.

*[A-40](#A40) shows an example of how to compute a small customer rate
as a 60% load factor derivative of the firm rate. Note that demand costs
are allocated to the small customer service at an imputed load factor of
60%.* [*A-40*](#A40) *also shows what the small customer rate would be
if the actual load factor of 40% were used to allocate costs the small
customer service and design rates. As shown, the small customer rate
designed at 60% is less than the rate designed at the actual load factor
of 40%, and thus represents a rate subsidy.*

**Discounting and Discount Adjustments**[]{#__RefHeading___Toc126142371
.anchor}

As part of the move to open access transportation under Order No. 436,
the Commission permitted pipelines to selectively discount their rates
between an established maximum rate and established minimum rate. The
maximum rate is established as the pipelines average cost of providing
service. The minimum rate is the variable costs of providing the
service. The Commission found this was necessary to permit pipelines to
lower their rates in an effort to retain load or to capture new load in
an increasingly competitive market.

The Commission later determined that if a pipeline discounted its rates
for competitive reasons, pipelines could receive a \"discount
adjustment\" when designing their rates in a rate proceeding. The
Commission reasoned that if the pipeline could offer a competitive rate
to retain or gain new customers, all customers of the pipeline would be
better off. That is, by retaining or gaining new customers, throughput
would increase and, designing rates on higher throughput would mean
lower rates for all, even when those volumes were added at a discounted
rate. Under this policy, the pipeline was better off as it received more
revenues, and customers were better off because their rates were
reduced, albeit not at the maximum rate.

There are essentially three methodologies the Commission has used in
deriving an appropriate discount adjustment. These are the (1) Revenue
Crediting Method, (2) Proportional/Fractional Method, and (3) Iterative
Method. These will be briefly discussed in turn.

***[Revenue Crediting
Method]{.underline}***[]{#__RefHeading___Toc126142372 .anchor}

Under this method, the revenue generated from discounted transactions is
computed. For example, if 25,000,000 Dth of throughput were transported
at a discounted rate of 40 cents per Dth, then the revenue generated
from discounted transactions would be \$10 million. This amount would
then be credited to the pipeline\'s cost-of-service. Next, the
discounted volumes of 25,000,000 Dth would be deducted from the total
rate design determinants. Thus, rates would be computed by dividing the
total cost of service adjusted for discounted revenues, by the total
billing determinants adjusted for discounted volumes.

Total Cost of Service, unadjusted \$50,000,000

Discounted Revenues [(10,000,000)]{.underline}

Cost of Service, adjusted \$40,000,000

Total Volumes, unadjusted 100,000,000

Discounted Volumes [25,000,000]{.underline}

Total Volumes, adjusted 75,000,000 Dth

Maximum Rate 53.33 cents/Dth

As shown above, assuming the total cost of service adjusted for discount
revenues is \$40 million (\$50 million less \$10 million in discounted
revenue), divided by the adjusted rate design volume of 75,000,000 Dth,
produces a maximum rate of 53.33, or approximately 53 cents per Dth.

***[Proportional/Fractional
Method]{.underline}***[]{#__RefHeading___Toc126142373 .anchor}

Under this method, total volumes transported by the pipeline are
adjusted to reflect discounting by including volumes for discounted
transactions in proportion to the discounted rate-to-maximum rate ratio.
For example, let\'s say a pipeline transported 100,000,000 Dth of gas
during the test period and 25% of these volumes, or 25,000,000 Dth were
transported at a discounted rate. The following is an illustrative
calculation of a maximum rate, adjusted for discounting using this
method.

Total Cost of Service \$50,000,000

Total Volumes, unadjusted 100,000,000 Dth

Maximum Rate, unadjusted 50 cents/Dth

Total Discounted Volumes 25,000,000 Dth

Average Discounted Rate to Maximum Rate 80%

(40 cents/50 cents)

Adjusted Discounted Volumes 20,000,000

Total Volumes at Maximum Rates [75,000,000]{.underline}

Total Volumes Adjusted for 95,000,000

Discounting

Maximum Rate, adjusted 52.63 cents

(Total Cost-of-Service divided

by Adjusted Volumes)

As shown above, the [discounted]{.underline} volumes that would be
included in the rate design determinants would be 20,000,000 Dth
(25,000,000 Dth x 80%). The total rate design volume would be 95,000,000
Dth (75,000,000 Dth transported at the maximum rate plus 20,000,000 Dth
included as adjusted discounted volumes). Assuming the total cost of
service of \$50 million, dividing by the adjusted volumes of 95,000,000
Dth, produces a maximum rate of 52.63, or approximately 53 cents.

> Iterative Method[]{#__RefHeading___Toc126142374 .anchor}

Not surprisingly, the iterative method involves iterations in order to
generate a more accurate maximum rate adjusted for discounting. This
method is iterative because the maximum rate is adjusted and compared to
the discounted rates, then a new discount adjustment is derived and used
to compute a new maximum rate, and so on\.... until the new maximum rate
generated is equivalent to the maximum rate generated under the previous
iteration. The litigation staff uses a complex computer generated model
to compute the maximum rate adjusted for discounting under the iterative
method. For a further explanation of the computer generated model, see
the \"Manual For Gas Pipeline Ratemaking - Introduction to Cost
Allocation and Rate Design\" (June, 1999) prepared by the Office of
Administrative Litigation (OAL). For purposes of this manual, we will
show a simplified version of the iterative method. Often, pipeline
companies choose this approach. For example, let us use the proportional
method example above as the first iteration.

[First Iteration]{.underline}

Using the resulting rate derived under the proportional method above, as
the first iteration, produces a maximum rate, adjusted for discounting,
of 52.63 cents per Dth. To \"fine tune\" that rate under the iterative
method we run the calculations again, this time using the 52.63 cents
per Dth as the maximum rate.

[Second Iteration]{.underline}

Total Cost of Service \$50,000,000

Total Discounted Volumes 25,000,000

Ave. Discounted Rate to New

Max Rate 76%

(40 cents/52.63 cents)

Adjusted Discounted Volumes 19,000,000

Total Volumes at Max Rates [75,000,000]{.underline}

Total Volumes Adjusted for 94,000,000

Discounting

Maximum Rate, adjusted 53.19 cents

(Total Cost-of-Service divided

by Adjusted Volumes)

As shown, the Second Iteration produces a new Maximum Rate of 53.19
cents.

[Third Iteration]{.underline}

Total Cost of Service \$50,000,000

Total Discounted Volumes 25,000,000

Ave. Discounted Rate to New

Max Rate 75.2 %

(40 cents/53.19 cents)

Adjusted Discounted Volumes 18,800,000

Total Volumes at Max Rates [75,000,000]{.underline}

Total Volumes Adjusted for 93,800,000

Discounting

Maximum Rate, adjusted 53.30 cents

(Total Cost-of-Service divided

by Adjusted Volumes)

The Third Iteration produces a new Maximum Rate of 53.30 cents.

[Fourth Iteration]{.underline}

Total Cost of Service \$50,000,000

Total Discounted Volumes 25,000,000

Ave. Discounted Rate to New

Max Rate 75.05%

(40 cents/53.30 cents)

Adjusted Discounted Volumes 18,762,500

Total Volumes at Max Rates [75,000,000]{.underline}

Total Volumes Adjusted for 93,762,500

Discounting

Maximum Rate, adjusted 53.33 cents

(Total Cost-of-Service divided

by Adjusted Volumes)

The Fourth Iteration produces a new Maximum Rate of 53.33 cents.

[Fifth Iteration]{.underline}

Total Cost of Service \$50,000,000

Total Discounted Volumes 25,000,000

Ave. Discounted Rate to New

Max Rate 75%

(40 cents/53.33 cents)

Adjusted Discounted Volumes 18,750,000

Total Volumes at Max Rates [75,000,000]{.underline}

Total Volumes Adjusted for 93,750,000

Discounting

Maximum Rate, adjusted 53.33 cents

(Total Cost-of-Service divided

by Adjusted Volumes)

The Fifth Iteration produces the same Maximum Rate of 53.33 cents,
calculated in the Fourth Iteration. This is an indication it is time to
stop the iterations and use the 53.33 cents as the Maximum Rate adjusted
for discounting.

Note: All things being equal, i.e. cost-of-service, discount volumes,
average discount rate, maximum unadjusted rate, the three methods
produce similar results. As shown above, the maximum rate adjusted for
discounting approximates 53 cents per Dth under each method. Note that
under the revenue crediting method and the iterative method the same
result of 53.33 cents is calculated.

**Distance Based Rates**[]{#__RefHeading___Toc126142375 .anchor}

The regulations require that rates be calculated to reasonably reflect
any material variation in costs with regard to the distance the natural
gas is transported. Distance based rates are used to reflect that the
cost of transporting natural gas increases with the distance the gas is
transported. With distance based rates, customers close to the source(s)
of supply, or points of receipt, pay lower rates. Customers farther away
from the source(s) of supply, or points of receipt pay higher rates.
Distance-based rates are appropriate for long-line pipeline systems with
one directional gas flow and varied load density. There are different
methods for calculating distance based rates, such as,

 [Mileage Based Rates]{.underline}[]{#__RefHeading___Toc126142376
.anchor} Under this method a rate per mile of haul, or per 100 miles of
haul, is calculated. Customers are billed based on the rate per
dth-mile, multiplied by the number of miles the gas is transported,
multiplied by the quantities of gas transported.

 [Zoned Rates]{.underline}[]{#__RefHeading___Toc126142377 .anchor}
Under this method the pipeline is divided into geographic segments
called zones. Zones are often several hundreds of miles in length and
usually incorporate one or more load centers (markets). With zoned based
rates, in any given zone, each customer is assessed the same relative
cost responsibility and are assessed the same rates regardless of where
they are located within a zone. Costs are allocated to the zones based
on \"Dth-Miles.\" Dth-Miles are calculated by multiplying each
customer\'s volume (Dth) from each source of supply, or receipt point,
by the number of miles between each source of supply (receipt point) and
the customer's delivery point. The Dth-Miles are totaled for each zone
and ratios are calculated based on each zones total Dth-Miles to the
total of all zones Dth-Miles. These ratios are then used to allocate
costs to the respective zones. Rates are developed for each zone based
on these allocated costs. Customers that take delivery of gas in Zone 1
are charged the Zone 1 rates. Customers that take delivery of gas in
Zone 2, pay the Zone 2 rates.

Not all costs vary with distance. There are mileage and non-mileage
related costs. Only the \"Mileage Related Costs\" vary with distance and
are allocated to the zones based on Mdt-miles.

[Mileage Costs]{.underline}[]{#__RefHeading___Toc126142378 .anchor}
Generally all transmission fixed and variable costs, excluding
Administrative and General Expenses, are considered to be costs that
increase with the distance the gas is transported.

[Non-mileage Costs]{.underline}[]{#__RefHeading___Toc126142379 .anchor}
Administrative and General Expenses, which include expenses related to
salaries of administrative personnel and office supplies, are not
considered to increase with the distance the gas is transported.
Supervision and Engineering, Storage costs and Account No. 858 costs,
are not considered to vary with distance. All customers pay the same
unit rate for these costs, as these costs do not increase with the
distance the gas is transported. The non-mileage costs are usually
presented in a pipeline\'s tariff as separately stated \"Access
Charges,\" or these costs may be embedded in the total zone of delivery
rate under \"Matrix Charges.\" These are different methods for stating,
or presenting, the rates in the tariff and often will not result in any
rate difference for a shipper.

> [Access Charges]{.underline}: Some pipelines have separately stated
> \"Access Charges\" which collect the non-mileaged costs. These
> \"Access Charges\" represent the costs of accessing a pipeline system
> for service. In addition to paying the access charge, a shipper would
> pay a mileage rate for each zone through which the shipper\'s gas is
> transported.
>
> [Matrix Charges]{.underline} Often pipelines with zone-based rates
> show these rates in their tariffs in matrix form. A matrix shows the
> total rate that will be paid by a shipper depending on the zone in
> which the gas is received and the zone in which the gas is delivered.
> Under matrix charges, the \"access charge\" is included in the total
> rate. For a two zone system such as Pipeline U.S.A., the matrix would
> include the following combinations of receipt and delivery patterns a
> shipper could use: Zone 1 to Zone 1; Zone 1 to Zone 2; and Zone 2 to
> Zone 2. (These represent the forward haul options.) As shown on Page
> 56, the Zoned Rates/Dth appearing at the bottom of the page represent
> zoned rates presented in a matrix. Missing from this matrix is rates
> for transportation where the gas is received and delivered in Zone 2.
> The rates for a within Zone 2 transportation service in this example
> would be \$5.3400 reservation and \$0.0056 usage. The derivation of
> these rates is described in more detail below.

The following page shows an example calculation of zoned rates for
Pipeline U.S.A. First, as shown on Page 56, total reservation and usage
costs are shown broken out between mileage and non-mileage related
costs. The Mileage costs are allocated to the zones based on the
Dth-mile study shown on Page 57. The allocated mileage costs for each
zone are divided by the respective zoned billing determinants. These
billing determinants are based on delivered amounts to each zone (as
opposed to amounts traversing a zone), to arrive at the Mileage
component of the rate. Next, the non-mileage rate is computed by
dividing the non-mileage costs by the total system billing determinants
to arrive at the non mileage rate component. Finally, the zoned
\"matrix\" rates are computed by adding the mileage and non-mileage rate
components for each zone. As shown, for deliveries in Zone 1 the
customer pays a reservation charge of \$5.2299 per Dth of contract
demand and a usage charge of \$0.0054 per Dth of gas transported. For
deliveries in Zone 2 the customer pays a reservation charge of \$10.1863
per Dth and a usage charge of \$0.0110 per Dth of gas transported.
Notice how these rates compare to the postage-stamp rate computed
consisting of a \$9.1951 reservation fee and a \$0.0099 usage rate
([A-28](#A28)).

**[Calculation of Zoned Rates for Pipeline
U.S.A.]{.underline}**[]{#__RefHeading___Toc126142380 .anchor}

**Reservation Usage**

**Total Costs:** \$117,831,000 \$2,600,000

Mileage (96%) \$112,915,000 \$2,600,000

Non-mileage (4%) \$4,916,000 \$0

**Allocation Factors**

**(Dth-Miles):**

Zone 1 11% 29,923,680 29,923,680

Zone 2 [89%]{.underline} [249,004,520]{.underline}
[249,004,520]{.underline}

Total 100% 278,928,210 278,928,210

**Allocated Mileage**

**Costs:**

Zone 1 \$12,420,650 \$286,000

Zone 2 [\$100,494,350]{.underline} [\$2,314,000]{.underline}

Total \$112,915,000 \$2,600,000

**Billing Determinants:**

Zone 1 20% 2,562,904 52,470,200

Zone 2 [80%]{.underline} 1[0,251,617]{.underline}
[209,880,800]{.underline}

Total 100% 12,814,521 262,351,000

**Mileage Rates/Dth:**

Zone 1 \$4.8463 \$0.0054

Zone 2 \$9.8027 \$0.0110

**Non-mileage Rate/Dth:** \$0.3836 \$0.0000

**Zoned Rates/Dth:**

Zone 1 \$5.2299 \$0.0054

Zone 2 \$10.1863 \$0.0110

**[Calculation of
Dth-Miles]{.underline}**[]{#__RefHeading___Toc126142381 .anchor} **[-
Assumptions]{.underline}**

 370 mile pipeline

 2 Zones, 185 miles each

 20% of volumes delivered in Zone 1, 80% delivered in Zone 2

 100% of volumes enter in Zone 1 at two receipt points, R1 and R2

 4 customers, 2 in each zone

Zone 1 Customer A

  ------------------------ --------------------- ------------------------
  **R1**                   **Miles**             **Dth-Miles**

  ------------------------ --------------------- ------------------------

10,402 Dth 90 936,180

  ------------------------ --------------------- ------------------------
  **R2**                   **Miles**             **Dth-Miles**

  ------------------------ --------------------- ------------------------

93,882 Dth 120 11,258,640

Customer B

  ------------------------ --------------------- ------------------------
  **R1**                   **Miles**             **Dth-Miles**

  ------------------------ --------------------- ------------------------

51,388 Dth 160 8,222,080

  ------------------------ --------------------- ------------------------
  **R2**                   **Miles**             **Dth-Miles**

  ------------------------ --------------------- ------------------------

51,388 Dth 185 9,506,780

Total Zone 1 Dth-Miles **29,923,680** **(11%)**

Zone 2 Customer C

  ------------------------ --------------------- ------------------------
  **R1**                   **Miles**             **Dth-Miles**

  ------------------------ --------------------- ------------------------

> 145,704 Dth 250 36,426,000

  ------------------------ --------------------- ------------------------
  **R2**                   **Miles**             **Dth-Miles**

  ------------------------ --------------------- ------------------------

> 339,868 Dth 280 95,163,040

Customer D

  ------------------------ --------------------- ------------------------
  **R1**                   **Miles**             **Dth-Miles**

  ------------------------ --------------------- ------------------------

> 308,196 Dth 340 104,786,640

  ------------------------ --------------------- ------------------------
  **R2**                   **Miles**             **Dth-Miles**

  ------------------------ --------------------- ------------------------

34,232 Dth 370 12,628,840

Total Zone 2 Dth-Miles **249,004,520 (89%)**

Total Zone 1 and Zone 2 Dth-Miles **278,928,210 (100%)**

**Storage Services and Rates** []{#__RefHeading___Toc126142382 .anchor}

This manual has been dedicated primarily to developing a cost of service
and designing rates for Pipeline U.S.A.\'s transmission function. Many
post-Order No. 636 pipeline\'s have storage functions as well as
transmission functions. Storage fields can be used by a pipeline to
support system operations (for example, to provide system balancing or
support for no-notice transportation services), to provide contract
storage service (storage service to third parties), or a combination of
both. When a pipeline\'s storage fields are used entirely to support
system operations, the storage costs are classified and allocated in the
same manner as transmission costs. However, in situations where the
pipeline uses its storage fields to provide both system operations
support and contract storage service, or in situations where the
pipeline uses its storage fields solely to provide contract storage
service, the storage costs are classified and allocated in the manner
described below.

**Classification of Storage Costs**[]{#__RefHeading___Toc126142383
.anchor} For pipelines that offer contract storage service, storage
function costs are classified using the [Equitable]{.underline} method.
Under the [Equitable]{.underline} method, all fixed storage costs are
classified equally between the \"Deliverability\" and \"Capacity\"
components; that is, 50% of the total storage fixed costs are classified
to the \"Deliverability\" component and 50% are classified to the
\"Capacity\" component. All storage function variable costs are
classified to the \"Injection/Withdrawal\" component. This storage
function classification, which is also used for rate design, recognizes
that fixed storage costs are incurred to support the storage field's
deliverability and capacity functions. The \"Deliverability\" function
of a storage field refers to the ability of the storage field to
withdraw gas on a particular day. The \"Capacity\" function refers to
the storage field's capacity to store gas for a designated customer or
for system operations. The \"Injection/Withdrawal\" component refers to
the storage fields function injecting and withdrawing gas for customers
or for system operations. Therefore, the Commission has reasoned that
such costs are properly apportioned between the deliverability and
capacity components. Storage variable costs, however, are incurred as
gas is injected into and out of the storage field, therefore, are
appropriately assigned to the injection/withdrawal component.

**Allocation of Storage Costs**[]{#__RefHeading___Toc126142384 .anchor}
If the pipeline uses the storage field for system operations (such as
for balancing or no-notice services), and to provide contract storage
service to third parties, costs are allocated between system and
contract storage services after the costs have been classified to the
\"Deliverability,\" \"Capacity\" and \"Injection/Withdrawal\"
components. The storage costs allocated to \"system storage\" are then
re-classified using the same manner as transmission function costs.
Transportation rates, which include the reclassified storage costs, are
then designed.

**Design of Firm Contract Storage Rates**[]{#__RefHeading___Toc126142385
.anchor} The costs allocated to contract storage service remain
classified as \"Deliverability,\" \"Capacity,\" and
\"Injection/Withdrawal\" for rate design purposes. The firm contract
storage rates are designed by dividing the Deliverability and Capacity
costs by the certificated deliverability (and imputed deliverability at
100% load factor for interruptible storage service) and capacity of the
storage field(s) (plus projection for interruptible storage volumes)
(multiplied by 12 months), respectively. The result is a monthly
Deliverability charge and a monthly Capacity charge, which are similar
to a firm transportation reservation charge. These rates are assessed
monthly per each firm customer\'s contract level for deliverability and
capacity. The Injection/Withdrawal costs are divided by the annual
projection of injection and withdrawal activity. The
Injection/Withdrawal charge is assessed per unit of volumes actually
injected or withdrawn by each firm and interruptible customer. Volumes
are included in the design of the firm storage rates for interruptible
storage service, in order to allocate deliverability, capacity and
injection/withdrawal costs to the interruptible storage service. The
design of interruptible storage rates follows.

**Design of Interruptible Contract Storage
Rates**[]{#__RefHeading___Toc126142386 .anchor}

As with interruptible transportation rates, interruptible storage rates
are typically computed as the 100% load factor derivative of the firm
contract storage rates. There are essentially two methods for computing
100% load factor storage rates.

Under the first and most predominate method, the firm monthly
deliverability rate is converted to a monthly capacity charge and added
to the firm capacity charge. This combined deliverability and capacity
charge is assessed per Dth of each interruptible storage customer's
average inventory balance in storage for a given month. To convert the
firm deliverability charge you need to know the ratio of deliverability
to capacity. Let\'s assume this ratio is 1/50. This represents the
Maximum Daily Withdrawal Quantity divided by the Maximum Storage
Quantity. This ratio is then multiplied by the monthly deliverability
rate and added to the monthly capacity charge. Another way to calculate
this combined charge is to add the total Deliverability and Capacity
costs together and divide by the Capacity billing determinants. The
interruptible storage customer is also assessed an injection/withdrawal
charge for each unit of gas injected into or withdrawn from the storage
fields.

Under the second method, the firm monthly deliverability charge is
converted to a rate per Dth of gas either injected or withdrawn. The
unit deliverability charge can then be assessed either per unit of gas
injected, or per unit of gas withdrawn. The monthly capacity charge
remains unchanged and is assessed each month on an interruptible
contract storage customer\'s average balance in storage for a given
month.

**June 1999**

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