# Words: 4,095

March 16, 2004

# DRAFT

# 4. Financial Performance and Investment

## 1. Introduction

Within two weeks of the August 14, 2003 blackout the Wall Street Journal
reported

> "The nation's electric power industry...is preparing to launch a
> public-education campaign to help it raise \$100 billion from
> investors, governments and consumers to upgrade the nation's power
> grid"[^1]

The estimate seemed plausible to the press given the Federal
Government's oft repeated concerns with grid investment. But, within
three months the Public Utilities Fortnightly published an article
saying

> " We don't know what caused the ...blackout but somehow we know that
> our transmission system needs \$50 billion to \$100 billion in
> investment and upgrades. And utilities need higher returns...The
> reality is that we aren't short \$50 billion or \$100 billion...the
> study said to support that conclusion doesn't do the job."[^2]

For the foreseeable future, Federal and state policy makers will remain
at the center of these controversies. They will be asked to decide: how
much investment is enough? Where should investments be made? What
returns are necessary to elicit those investments? Who should pay? What
charges are reasonable? To make informed decisions policy makers require
data to guide their judgments.

FERC is charged with ensuring "just and reasonable" prices for power in
interstate commerce. State regulators continue to be deeply involved in
transmission regulation in most states. They effectively regulate
transmission costs and prices for "internal transactions" and also
control siting and eminent domain.

FERC has long collected capital and operating cost data from investor
owned utilities (IOUs). FERC uses the information to ensure delivered
electricity tariffs bear a reasonable relation to costs. EIA complements
the FERC collections with less detailed reports from the other
generation and transmission owners to produce industry wide totals. Both
Agencies focus on generation and distribution data because
transmission's costs are a small portion of total costs. In 2000, for
example, major public electricity utilities' transmission operating
costs were only 4% of their total operating costs.[^3] Transmission
plant was 11% of total electric plant in service.[^4] In a cost of
service world where all costs are bundled together to form a single
price for delivered electricity, transmission's specific costs are
unimportant.[^5]

FERC's restructuring of the electricity industry has broadened its
perspective beyond cost recovery to the economics of transmission. Order
2000 in establishing Regional Transmission Organizations (RTOs) notes

> "effective and efficient RTOs... \[are\]... dependent in large measure
> on the feasibility and vitality of the stand-alone transmission
> business."[^6]

The difficulty in obtaining financial data showing "vitality" is that
transmission is rarely a stand-alone business. Almost all investor owned
utilities derive most of their total revenues from supplying bundled
power (energy, transmission and services) to native customers at
state-regulated prices. Separate transmission prices and revenues for
internal customers do not exist. Merchant transmission companies only
sell transmission but they are miniscule. Cooperatives and public power
are not in the business of selling transmission. The only "market like"
transmission prices are those customers pay for wheeling power across a
system. Wheeling revenues, however, are a very small amount of total
revenues.

**2. Measures of Financial Performance and Investment**

Unlike reliability, there is considerable agreement about how financial
performance should be measured and how financial data should be
interpreted. Even so there are long standing debates about how to obtain
better agreement between accounting and economic values and how to value
uncertain prospects and illiquid assets. FERC requires utilities it
regulates to use the Uniform System of Accounts. These accounts are more
detailed accounts and require far more disclosure that is usual for
publicly traded companies.

FERC collects financial and operating data annually from major privately
owned electric utilities on the FERC FORM 1: *Annual Report of Major
Electric Utilities, Licensees and Others.*[^7] FERC requires utilities
under its jurisdiction to submit the following schedules for the
calendar year

1.  Comparative Balance Sheet

2.  Statement of Income

3.  Retained Earnings

4.  Statement of Cash Flows

5.  Notes to Financial Statements.

All the are data are entered on the form following the Commission's
Uniform System of Accounts Prescribed for Public Utilities and Licensees
Subject to the Provisions of the Federal Power Act.

The transmission revenues reported on Form 1 are those for wheeling
power for others. The FERC Form 1 specifically identifies 15
subcategories of transmission operating and maintenance costs (page 321)
and the book value (acquisition cost) of nine subcategories of the
transmission plant and equipment (page 206). The form also identifies
the calendar year additions to transmission plant and equipment. The
revenues from transmission of electricity for others (Account 456) are
broken down into energy charges, demand charges and other charges. FERC
has proposed to require explicit reporting of purchases and sales of
ancillary services.[^8] Debt, stockholder equity, taxes and
miscellaneous expenditures are listed and described in detail.

In addition to giving FERC information for approving company tariffs and
investments, FERC FORM 1 is used by financial analysts to assess private
utility's short-term solvency, its financial risk, long-term viability
and returns to investment and investors.

\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\--

Text Box: Ratio Analysis

Financial analysts often examine operating efficiency ratios and
operating profitability ratios to better understand how firms generate
profits. In a typical application a financial analyst would decompose
return on equity (ROE which is net income divided by equity) into
components to highlight differences among firms. The DuPont identity is
a popular decomposition. The DuPont identity expresses FOE as the
product of profit margin, total asset turnover, and financial leverage,
i.e.,

$$\begin{array}{r}
\text{Return}\ \text{on}\ \text{Equity}\  = \ \begin{array}{r}
\left( \text{Net}\ \text{Profit} \middle| \right) \\

\end{array} \\

\end{array}$$

An example of two hypothetical firms both earning 12% per year on equity
illustrates how these decompositions aid financial analysis.

  ----------- ------------ ------------ ----------------- -----------------
  **Firm**    **Net Profit **Asset      **Financial       **ROE**
              Margin**     Turnover**   Leverage          
                                        Multiplier**      

  A           8%           2.0          0.75              12%

  B           3%           1.0          4.00              12%
  ----------- ------------ ------------ ----------------- -----------------

While both firms have the same ROE (12.0%), the underlying means of
generating ROE are very different. Firm A has high net profit margins,
high turnover, and low financial leverage. Firm B has low net profit
margins, low operating efficiency, but has used financial leverage to
increase its return. The DuPont identity indicates that that Firm A is
stronger than Firm B, in terms of profitability, efficiency and risk.

EIA annually collects an abbreviated version of the FERC 1 , the EIA
412, from publicly owned utilities (municipalities, political
subdivisions, States and Federal entities). EIA requires the following
schedules for the respondent's fiscal year

1.  Balance Sheet

2.  Income Statement

3.  Electric Plant

4.  Taxes, Tax Equivalents, Contributions, and Services During the Year

5.  Sales of Electricity for Resale

6.  Electric Operation and Maintenance Expenses.

Like FERC, EIA collects data on wheeling revenues. EIA encourages, but
does not require, respondents to use the Uniform System of Accounts.
Analysts use the data to compare the operations of publicly owned and
investor owned utilities and to evaluate potential public exposure to
their debt. EIA uses the data to complete its statistical description of
the industry.

No system of accounts, no matter how conscientiously followed, captures
all economic values perfectly. Transmission equipment, for example, is
very long lived making book values poor measures of either replacement
or market value. Likewise most utility land holdings were acquired long
ago. Rights of way are also valuable assets originally obtained under
the implicit threat of eminent domain. Market values for them are
unavailable.

**3.** **Restructuring's impacts on relevant financial data**

FERC Order No. 888 required all public utilities that own or control
interstate transmission to functionally unbundle wholesale power
services. Functional unbundling requires the public utility to

(1) Take transmission services under the same tariff as do others;

(2) Post separate rates for wholesale generation, transmission and
    ancillary services: and

(3) Rely on the same information system that its customers use.

FERC considered but did not require divestiture of transmission from
generation and institutional changes to achieve functional unbundling.
FERC did not require public utilities to spin off transmission into
standalone business units.

With the growth of independent power suppliers, the transmission
business has become something of a mongrel. The transmission owning
utility earns revenues by charging others posted rates for wholesale
transmission and services; it charges itself for its own wholesale sales
at the same rates. The utility neither posts transmission rates for
bundled retail sales nor does it charge itself for transmission.
Instead, the charges for transmission are bundled with the price of
delivered power. FERC has not required "financial unbundling" by line of
business. Consequently it is not possible to know total revenue or to
know if the utility is charging nondiscriminatory rates for transmission
to retail customers.

Since reasonable transmission and service rates for others are partially
defined based on costs, sharp distinctions between transmission's costs
and those of distribution and generation are important under
restructuring. The FERC 1 allows respondents to determine their own
boundaries. That makes meaningful comparisons across transmission
providers difficult, if not impossible.

An implicit assumption behind financial accounts is that each company's
revenues and costs capture the major economic benefits and costs. Before
system interconnections and large power flows across systems became
important, integrated utility costs and benefits were essentially the
same as total costs and benefits, i.e., they were internal to the
utility. The same identification is dubious in a restructuring
transmission industry.

An economically important external cost occurs when one system's
operations load lines in other systems to the point that the impacted
system cannot use their lines much as they otherwise would. Lines loaded
to their security limits are congested. Electricity flows everywhere in
a connected AC system in response to relative line resistance and the
locations and amounts of generation and consumption. How an operator
decides to dispatch generators, secure imports or otherwise meet (or
refuse to meet) demand can cause lines to be congested far outside his
system's boundaries. Faced with line congestion, operators can only meet
their customers' increased demands by running more costly, but better
situated, generators. These additional costs show up in the books of the
impacted system; costs are artificially lower in the books of the system
causing the congestion.[^9]

Congestion costs within individual systems are being measured and valued
(inconsistently) in a few parts of the country. Chapter 5 contains a
discussion of congestion costs and revenues. These costs are not
identified on the FERC 1.

FERC's 2000 Regional Transmission Organization order would bring
together many transmission providers into a few regional transmission
organizations. In a regional setting individual companies cannot be held
solely responsible for the costs borne by customers. A particular
company may experience abnormally high costs because it made
expenditures that lower overall regional costs; another may have
artificially low costs because it exploits "beggar thy neighbor"
opportunities.[^10] In a restructured industry the costs of a Regional
Transmission Organization as a whole, not just its individual companies
reporting on the FERC 1, would be relevant to costs, tariffs and
investments.

Restructuring has also motivated public policy concern about the level
and kinds of investment being made in the grid. The FERC 1 collects data
on transmission plant and equipment and additions to plant and
equipment. Unlike the national income accounts, the "additions" data is
not restricted to acquisitions of new equipment. Plant and equipment
refers to the purchase price of any qualifying good, including land,
regardless of its age. When a utility sells old equipment at above net
book value to another reporter, the data shows net additions, though
nothing has changed on the ground. Generators have sold for much more
than net book value in the recent past. Net additions (after subtracting
land acquisitions) may, or may not be a good proxy for the economic
concept of investment.

As mentioned in Chapter 3, power flows are more volatile and likely to
change course more than before restructuring. In this environment,
investment in system metering, communication, computation and control
are critical to improving reliability when power flows are more volatile
and changing. These classes of capital are not identified on the FERC 1.

Restructuring has also brought about transmission investments from new
entities. Merchant transmission companies are one example. As discussed
in the following chapter, new independent generators are making
significant grid investments as a condition of connecting to the grid.
Since FERC does not require merchants and independent generators to make
detailed financial reports to FERC, their investments may not be
recorded in official data.

In a fully restructured environment, financial data for evaluating the
economics of transmission would include:

1.  Stand alone financial accounts for the transmission business.

2.  Estimates of external costs and benefits, especially the value of
    congestion.

3.  Integration of individual transmission provider accounts to the
    appropriate RTO.

4.  Complete investment totals that include an identification of those
    undertaken for grid control.

**4. Official Transmission Financial Data**

***Standalone accounts:*** Except for those few utilities that are
strictly dedicated to transmission, it is not possible to construct
stand-alone financial statements for transmission from official data.
Both the EIA 412 and the FERC 1 identify transmission sold (purchased)
from others. FERC has proposed that utilities report the grid's sales
(purchases) of ancillary services. Neither form reports transmission and
services provided to the utility's own generators. As a consequence it
is not possible to calculate transmission's returns on either investment
or equity. Ratio analysis of the kind sketched above cannot be done.
Official data does however indicate how restructuring has affected
revenues from transmission sells to others.

*Transmission Revenues:* Transmission for others, called wheeling, has
grown since the start of restructuring (1996) in some regions and
declined in others. Nationwide volumes and revenues more than doubled
over the period 1996-2001. Tables 4-1 and 4-2 show net wheeling,
("wheeling for others" minus "wheeling by others") volumes and revenues
for the United States and for utilities located in the North Central
States (ECAR), Midwest (MAPP) and the West (WECC).

**Table 4-1. Gross Volume of Wheeling in Three Regions (billion kWh)**

  -------------- -------------- -------------- -------------- --------------
  **Year**       **ECAR**       **MAPP**       **WECC**       **United
                                                              States**

  1993           28.4           14.1           74.6           268.6

  1994           26.2           16.5           65.2           252.6

  1995           29.7           15.5           64.4           264.2

  1996           55.2           15.2           69.7           303.8

  1997           61.7           17.2           67.4           326.4

  1998           67.6           18.7           73.7           373.3

  1999           67.9           22.2           76.9           370.1

  2000           85.4           18.8           87.1           490.5

  2001           157.3          18.8           112.1          671.8

  2002           159.4          13.8           105.5          705.8
  -------------- -------------- -------------- -------------- --------------

## Sources: EIA staff assembled this table from RDI's PowerDat compilation of the EIA 412, FERC 1 and RUS7 and 12 data.

Table 4-2 Gross Revenue from Wheeling in Three Regions (millions of 2002
dollars)

  -------------- -------------- -------------- -------------- --------------
  **Year**       **ECAR**       **MAPP**       **WECC**       **United
                                                              States**

  1993           \$109.29       \$22.14        \$224.50       \$1,362.01

  1994           \$112.27       \$21.99        \$212.91       \$1,365.09

  1995           \$121.15       \$30.03        \$198.17       \$1,373.15

  1996           \$189.08       \$38.31        \$231.88       \$1,541.67

  1997           \$235.31       \$61.04        \$240.63       \$1,821.70

  1998           \$370.58       \$57.21        \$232.01       \$2,181.30

  1999           \$335.68       \$44.20        \$294.18       \$2,417.00

  2000           \$484.71       \$51.17        \$352.33       \$2,828.12

  2001           \$546.53       \$56.15        \$469.15       \$3,400.21

  2002           \$632.31       \$56.13        \$470.24       \$3,968.41
  -------------- -------------- -------------- -------------- --------------

## Sources: EIA staff assembled this table from RDI's PowerDat compilation of the EIA 412, FERC 1 and RUS 7 and 12 data.

Figure 4-1 shows the average revenue from wheeling for these regions.
Average revenue varies from a low of just over one dollar in 1994 for
MAPP to just under six dollars in 1998 and 2000 for ECAR. Over time the
range in price difference between the three regions has varied between
roughly \$0.50/MWh and \$4.50/MWh.

**Figure 4-1. Average Revenue from Wheeling in Three Regions**

![](media/image1.wmf){width="5.995138888888889in"
height="4.100694444444445in"}

Source: EIA staff assembled this table from RDI's PowerDat compilation
of the FERC 1 data.

*Revenues from Grid Supplied Ancillary Services:* FERC does not now
collect information on the prices, volumes or revenues the transmission
sector earns from supplying ancillary services. FERC proposes to collect
revenues from ancillary service sales. Since the grid is often the
major, if not sole, source of ancillary services, is useful to collect
price and corresponding volume information. That information can be used
to test that grid supplied services are priced at marginal cost.
Transmission provider OASIS sites contain some ancillary service prices,
but these are incomplete, do not include volumes and are not maintained
as a time series, see Chapter 5. The ISOs report some scattered,
incomplete information on their websites.

*Operations and Maintenance Costs:* Official data also utility operating
costs. Table 4-3 shows the total O&M costs for utilities located in
WECC, MAPP and ECAR.

Table 4-3. Total Transmission O&M Costs by Region (millions of
2002dollars)

  -------------- -------------- -------------- -------------- --------------
  **Year**       **ECAR**       **MAPP**       **WECC**       **United
                                                              States**

  1993           \$414.27       \$182.66       \$1,003.33     

  1994           \$423.20       \$205.65       \$1,021.57     

  1995           \$412.54       \$213.68       \$1,016.04     

  1996           \$420.06       \$223.42       \$1,044.68     

  1997           \$400.53       \$249.22       \$1,091.33     

  1998           \$442.11       \$340.38       \$1,264.55     

  1999           \$448.54       \$269.00       \$1,293.42     

  2000           \$540.14       \$274.36       \$1,166.54     

  2001           \$691.16       \$203.12       \$950.95       

  2002           \$810.76       \$220.70       \$827.02       
  -------------- -------------- -------------- -------------- --------------

## Sources: EIA staff assembled this table from RDI's PowerDat compilation of the EIA 412, FERC 1 and RUS 7 and 12 data.

In 2002 , wheeling revenues were about 75% of O&M costs in ECAR, almost
60% in WECC and about 25% in MAPP.

*Book values of Plant and Equipment:* FERC maintains voluminous records
on book values of plant and equipment and on its depreciation. FERC's
concentration on the book value of transmission assets reflects its
concern with the recovery of prudent costs, including a reasonable
return to capital. These historical costs, and their associated debt,
will continue to be important to FERC's determination of capital
recovery for wholesale transmission. The difference under restructuring
is that the precise boundaries between transmission, generation and
distribution matter.

*External costs and benefits:* The system of uniform accounts underlying
the FERC Form 1 does not attempt to identify and value benefits and
costs that the responding utilities impose on others. Reliability and
congestion are leading examples of these costs and benefits. Congestion
internal to the northern ISOs is being valued and paid for by market
participants. Chapter 5 explains how congestion is valued and presents
recent estimates of congestion costs.

## 

***Regional accounts:*** FERC does not require companies to disaggregate
their accounts by RTO or ISO. Nor does FERC collect financial data
pertaining to RTOs and ISOs. It is not possible to use official data to
construct consolidated accounts either for RTOs or ISOs and the
transmission providers within their boundaries. Currently most of the
United States operates outside of the RTO/ISO structure. At such time as
those organizations come to operate large portions of the grid,
consolidated regional accounts may become necessary for evaluating
regional transmission costs and investments.

*Utility Investment and capital stock:* Much has been made of the slow
growth in the high voltage grid in comparison to the growth in
generation NERC, for example annually publishes its compilation of lines
230kV and above

Table 4-4.

  --------------- ----------------------- -------------- -------------------
                  **Transmission Lines -                 Generation
                  AC and DC**                            

                  **(230 kV and above)**                 

                  **(circuit miles)\***                  Billion of
                                                         Kilowatthours\*\*

  **Year**                                               

  **2002**        158,605                                3,838

  **2001**        157,314                                3,736

  **2000**        156,435                                3,802

  **1999**        155,669                                3,694

  **1998**        154,679                                3,620

  **1997**        153,533                                3,492

  **1996**        152,098                                3,444

  **1995**        150,111                                3,353

  **1994**        150,826                                3,248

  **1993**        150,953                                3,197

  **1992**        149,020                                3,084

  **1991**        148,059                                3,074

  **1990**        147,271                                3,038

                                                         

                                                         

                                                         

                                                         

                                                         

                                                         

  **\*Source:**   **NERC ES&D 2003**                     

  \*\*EIA,        Annual Energy Review                   
                  2002                                   

                                                         

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

Annual "Investment" data show little change in response either to
generation or increased wholesale trade (see Table 5-7 ). The FERC Form
1 and the EIA Form 412 record capital additions for publicly owned
utilities, investor owned utilities (IOUs). The RUS 7 and 12 report
investment data for cooperatives. Table 4-5 shows additions to
transmission plant in service, "investment", for 1988-2002. Some the
additions represent purchases of existing facilities (and land) and
therefore are not investments in the sense of the National Income
Accounts. As noted earlier, publicly owned utilities report to EIA on a
fiscal year basis and IOUs report on a calendar year. The annual totals
therefore are a mixture of fiscal and calendar year expenditures.
Moreover, the boundaries between transmission and distribution vary with
reporter.

Table 4-5. Capital Additions 1988-2000 (millions of dollars)

  ----------- ------------ ------------ ------------------ ------------ ------------
  **Year**    **Public**   **IOUs**     **Cooperatives**   **Total \$** **Total
                                                                        2002\$**

  1988        \$910.48     \$2,027.85                      \$2,938.33   \$4,053.31

  1989        \$1,126.49   \$2,179.64                      \$3,306.13   \$4,393.48

  1990        \$522.33     \$2,622.63                      \$3,144.96   \$4,022.00

  1991        \$811.06     \$2,174.25                      \$2,985.31   \$3,684.37

  1992        \$789.26     \$2,498.62   \$3.38             \$3,291.26   \$3,965.35

  1993        \$683.33     \$2,378.64   \$121.63           \$3,183.60   \$3,745.63

  1994        \$614.52     \$2,529.35   \$191.84           \$3,335.72   \$3,844.74

  1995        \$964.96     \$2,430.74   \$191.03           \$3,586.73   \$4,045.69

  1996        \$1,300.00   \$2,312.90   \$206.90           \$3,819.81   \$4,226.86

  1997        \$851.96     \$1,957.70   \$149.74           \$2,959.40   \$3,212.23

  1998        \$640.78     \$2,173.06   \$255.16           \$3,069.00   \$3,290.61

  1999        \$708.58     \$2,308.66   \$156.19           \$3,173.43   \$3,354.35

  2000        \$929.74     \$2,612.89   \$192.55           \$3,735.18   \$3,866.69

  2001        \$836.67     \$4,217.03   \$246.27           \$5,299.97   \$5,359.81

  2002        \$1,124.13   \$3,302.30   \$220.33           \$4,646.75   \$4,646.75
  ----------- ------------ ------------ ------------------ ------------ ------------

## Sources: EIA staff assembled this table from RDI's PowerDat compilation of the EIA 412, FERC 1 and RUS 12 data. Nominal dollars were converted to year 2001 dollars using the .....deflator. 

Independent Power Producers, Merchant Transmission and RTO/ISO
investments:

Independent power producers do not report their connection costs. To
some extent the costs they incur for grid reinforcement may be reported
on the FERC 1. Whether they are or not, they are not identifiable.
Merchant Transmission companies do not report capital investment to
either FERC or EIA. RTO/ISOs are considered utilities by FERC and are
required to report.

**4. Filling the Information Gaps**

FERC's Commissioners are concerned with the economics of transmission as
a standalone enterprise because of their obligation to ensure just and
reasonable prices in a restructuring environment. But FERC's financial
accounts are more appropriate to the circumstances of integrated
regulated utilities selling bundled electricity in a pre-restructuring
environment. Apart from a few "transmission only" enterprises,
transmission revenues are mostly unrecorded in official data. The data
describing transmission's operating costs, capital stock, and investment
data are not comparable across reporters because the FERC 1 does not
impose a common definition separating transmission from distribution.

The FERC 1 says almost nothing about the economics of transmission.
Official data do not capture transmission's financial performance in
large part because most transmission revenue is not identifiable. If
transmission were fully unbundled its revenues would be unambiguous.
Absent that, FERC could require line-of- business reporting, a
fundamental change tantamount to a new form. Line of business reporting
would require utilities to treat their own bundled sales as if they were
unbundled and carried out by others. They would "earn" revenues on
transmission to their own customers presumably at the same rates as they
charge others under the FERC tariff. Such transfer prices would then be
proxies for what transmission would earn if it were in fact a standalone
enterprise. How useful or valid these estimates would be is a serious
question.

Far less dramatic changes to the FERC 1 would make the data more useful
for cost and investment (but not financial) analysis. Sharp definitions
of transmission would be a logical place to start. Moreover, additions
to transmission plant and equipment reflect purchases of existing assets
from others, land and other expenditures that, while relevant for some
purposes, are not "investment" in the sense of the National Income
Accounts. The EIA forms that are modeled after the FERC 1 share those
attributes.

Disaggregating line investment by voltage and identifying investment in
grid metering and control would also be helpful. EIA would have to adopt
FERC 1 conventions, including FERC's calendar year convention, to permit
national totals. In addition, FERC and EIA could require that the
accounts be segregated by region (ISO/RTO or NERC region) as
appropriate.

Table 4- 6 contains more specific suggestions for the FERC 1 and EIA 411
short of line of business reporting.

Table 4-6. Modify Existing Data Collections.

+-----------------+-----------------+-----------------+-----------------+
| Information     | Form            | Changes         | Comment         |
| Need            |                 |                 |                 |
+-----------------+-----------------+-----------------+-----------------+
| 1\. Consistent  | FERC 1, EIA 412 | Explicitly      | Current data is |
| separation of   |                 | define          | an "apples and  |
| transmission    |                 | transmission    | oranges" mix.   |
| from            |                 | the same way    |                 |
| distribution    |                 | for all         |                 |
| accounts        |                 | utilities and   |                 |
|                 |                 | use that        |                 |
|                 |                 | definition in   |                 |
|                 |                 | assigning       |                 |
|                 |                 | costs, revenues |                 |
|                 |                 | and net         |                 |
|                 |                 | capital.        |                 |
+-----------------+-----------------+-----------------+-----------------+
| 2.Ancillary     | FERC 1, EIA 412 | Require         |                 |
| service         |                 | reporting as    |                 |
| revenues        |                 | proposed by     |                 |
|                 |                 | FERC            |                 |
+-----------------+-----------------+-----------------+-----------------+
| 3\. Re-Dispatch | FERC 1, EIA 412 | Require         | Only applicable |
| Costs           |                 | reporting.      | to utilities    |
|                 |                 |                 | owning          |
|                 |                 |                 | generators. Not |
|                 |                 |                 | necessary for   |
|                 |                 |                 | ISOs            |
+-----------------+-----------------+-----------------+-----------------+
| 4\. Utility     | FERC 1, EIA 412 | 1\. Adopt NIA   | Current         |
| investment in   |                 | definition of   | "additions to   |
| the high        |                 | investment.     | plant and       |
| voltage grid    |                 |                 | equipment" data |
|                 |                 | 2\. Report line | has very        |
|                 |                 | and associated  | limited use for |
|                 |                 | equipment       | economic and    |
|                 |                 | investment by   | reliability     |
|                 |                 | voltage level.  | analysis,       |
|                 |                 |                 | though it is    |
|                 |                 | 3\. Report      | important to    |
|                 |                 | investment in   | capital cost    |
|                 |                 | metering,       | recovery.       |
|                 |                 | communication,  |                 |
|                 |                 | software and    |                 |
|                 |                 | control of the  |                 |
|                 |                 | high voltage    |                 |
|                 |                 | grid            |                 |
+-----------------+-----------------+-----------------+-----------------+
| 5\. IPP         | EIA 860         | Collect direct  | Some of these   |
| investment      |                 | connection and  | investments may |
|                 |                 | grid            | not be picked   |
|                 |                 | reinforcement   | up on the       |
|                 |                 | costs from IPPs | FERC 1. See     |
|                 |                 | on the EIA 860  | Chapter 5       |
+-----------------+-----------------+-----------------+-----------------+
| 6\. Merchant    | EIA 412         | Add to the list | Merchant        |
| transmission    |                 | of respondents  | investment and  |
| Investment      |                 | and require     | line data is    |
|                 |                 | them to report  | not currently   |
|                 |                 | transmission    | collected.      |
|                 |                 | investments, as |                 |
|                 |                 | defined above,  |                 |
|                 |                 | and to fill out |                 |
|                 |                 | Schedules 10    |                 |
|                 |                 | and 11.         |                 |
+-----------------+-----------------+-----------------+-----------------+
| 7\. Consistent  | EIA 412         | Adopt FERC      | EIA currently   |
| aggregation     |                 | definitions,    | allows          |
|                 |                 | see above, and  | reporting by    |
|                 |                 | require         | fiscal year.    |
|                 |                 | reporting by    |                 |
|                 |                 | calendar year   |                 |
+-----------------+-----------------+-----------------+-----------------+
| 8\. Regional    | FERC 1, EIA 412 | Require         | This would      |
| costs           |                 | reporters to    | allow regional  |
|                 |                 | disaggregate    | cost            |
|                 |                 | cost, revenue,  | comparisons.    |
|                 |                 | net capital     |                 |
|                 |                 | stock and       |                 |
|                 |                 | investment by   |                 |
|                 |                 | appropriate     |                 |
|                 |                 | region          |                 |
+-----------------+-----------------+-----------------+-----------------+

[^1]: Failka, John J., "Power Industry Sets Campaign to upgrade Grid,"
    *Wall Street Journal, August* 25, 2003 page A3.

[^2]: Huntoon, Steve and Metzner, Alexandra, "The Myth of the
    Transmission Deficit," Public Utilities Fortnightly, November 1,
    2003, page 28

[^3]: EIA, Electric Power Annual 2001, Table 8.3, page 51.

[^4]: Available at
    [www.eia.doe.gov/cneaf/electricity/public/t11p01p1.html](http://www.eia.doe.gov/cneaf/electricity/public/t11p01p1.html)
    . Appears as Table 11, Electric Utility Plant for Major U.S.
    Publicly Owned Generator Electric Utilities at End of Period,
    1996-2000.

[^5]: The transmission grid's relatively small costs do not mean that
    its efficient operation and development is unimportant. Efficiency
    reduces costs in the short run and ensures that the grid is not a
    drag on economic growth and competition. Efficient grid operation
    generally means its services are priced at marginal cost. Efficient
    development means that all potential investments are considered and
    those whose net benefits, adjusted for risk and timing, are greatest
    are made. The need to consider all relevant investments is easy to
    overlook. Line congestion, outages and other transmission problems
    may best be solved by investments in distributed generation, demand
    side management or other alternatives to transmission facilities.

[^6]: FERC, Regional Transmission Organizations, Order 2000, 65 Fed.
    Reg. 809(June 6,2000), FERC Stats.& Regs. At 31, 170.

[^7]: FERC has proposed to collect quarterly financial data on a new
    Form No. 6-Q. See Federal Regulatory Commission, Quarterly Financial
    Reporting and Revisions to the Annual Reports, 18CFR Parts 141.
    260,357 and 375, June 26, 2003.

[^8]: Op cit, Appendix B.

[^9]: Operating decisions which relieve congestion and lower costs in
    other areas are not compensated either.

[^10]: One role of RTOs is to internalize significant external costs and
    to manage them on an equal footing with each systems cash costs.