This document discusses challenges facing transmission investment and proposes a formula-based approach. Key points: 1. Transmission investment faces competition for capital from generation and distribution investments within utilities. Regulatory uncertainty also poses challenges. 2. A formula-based, risk-based transmission pricing framework is proposed to attract investment and provide simplicity for investors. This would assess risk factors such as asset type, market conditions, and operational risks. 3. The framework would calculate total transmission investment costs as expected infrastructure costs plus a cost of economic capital reserve to absorb losses and provide liquidity. This reserve would be indicated by a company's credit rating.

1. Published online in Wiley InterScience (www.interscience.wiley.com).
DOI: 10.1002/gas.10101 © 2010 Wiley Pe­ri­od­i­cals, Inc.
To be sure, the aging U.S. transmission system must trans-
mit power from a growing array of renewable generation
sources to energy-hungry, distant population centers. But to
an integrated utility company, transmission investment is a
competing capital hazard to generation investment as well as
power-distribution investment.
Distribution and generation have stiff investment require-
ments. On the distribution side, to be able to get a tariff ap-
proved, utilities have to meet regulatory standards and go
through a rigid approval process to provide sufficient power-
distribution quality and customer satisfaction. On the genera-
tion side, the new mandate of fuel mix from upcoming clean
energy legislation will force utilities to focus voluntarily or in-
voluntarily on dramatic changes on the renewable technology
business, and this will require most of the investment capital
within the company. As a result of this competition for capi-
tal, transmission, as a regulated business with uncertain cost
allocation and recovery, will likely be again left challenged
due to internal capital competition. Legislative uncertainty
and the recent financial crisis have put even more limitations
into transmission investment of the limited capital pool.
To optimize the use and sharing of investment dollars for
the grid and to accommodate the diverse stakeholder inter-
Formula-Based Analysis for Transmission
Investment To Assist in Upcoming Capital
Needs Jenny Hou
The MONTHLY journal for Producers, Marketers, Pipelines, Distributors, and End-Users
Volume 26
Number 6
January 2010
Jenny Hou (jenny.hou@jh2risk.com) is with JH2 Risk Advisors
in Washington, D.C. She can be reached by phone at (202) 262-
9933. Hou is also an affiliate of the economic consulting firm LECG.
This article is © 2010 Jenny Hou. Printed with permission.
Other Features
Annual Outlook Issue
FERC—2010 Outlook
Transmission Planning Processes and
Cost Allocations Head FERC Agenda
Steven W. Snarr.................................... 7
Finance—Outlook
After Tranquil 2010, Working Capital
Credit Squeeze Looms
Robert E. Willett................................... 18
Outlook—Nuclear
“Not” in My Back Yard! Is Really “Yes” in
My Back Yard!
Ann Stouffer Bisconti........................... 23
Annual Outlook Issue
Natural Gas Issues
Natural Gas in 2010—Promise and
Challenges
Richard G. Smead............................... 29
Columns
grand award grand award

2. 2 © 2010 Wiley Periodicals, Inc. / DOI 10.1002/gas Natural Gas & electricity January 2010
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Kenneth L. Beckman, President
International Gas Consulting, Inc.
Houston
Christine Hansen, Executive Director
Interstate Oil and Gas, Compact
Commission
Oklahoma City
James J. Hoecker, Senior Counsel
Husch Blackwell Sanders LLP
Washington, D.C.
and Principal,
Hoecker Energy Law & Policy, PLLC
Markham, VA
Former Chairman, Federal Energy
Regulatory Commission
R. Skip Horvath, President
Natural Gas Supply Association
Washington, D.C.
Jonathan A. Lesser, President
Continental Economics, Inc.
Albuquerque, NM
Keith Martin, Esq.
Chadbourne & Parke
Washington, D.C.
Rae McQuade, Executive Director
North American Energy Standard
Board
Houston
Robert C. Means, President
USI Inc.
Arlington, VA
John E. Olson, Managing Director,
Houston Energy Partners, and
Chief Investment Officer,
SMH Capital, Houston
Brian D. O’Neill, Esq.
LeBoeuf, Lamb, Greene & MacRae
Washington, D.C.
David N. Parker, President / CEO
American Gas Association
Washington, D.C.
Donald F. Santa Jr., President
Interstate Natural Gas
Association of America
Washington, D.C.
Benjamin Schlesinger, President
Schlesinger and Associates, Inc.
Bethesda, MD
John Shelk, President
Electric Supply Power Association
Washington, D.C.
Richard G. Smead, Director
Navigant Consulting, Inc.,
Houston
William H. Smith Jr., Executive
Director
Organization of MISO States
Des Moines, IA

3. January 2010 Natural Gas & electricity DOI 10.1002/gas / © 2010 Wiley Periodicals, Inc. 3
ests affected by transmission development, any
upgrade or expansion of the grid must be prag-
matically designed. A risk-based transmission
pricing framework would provide simplicity to
transmission investors and attract infrastructure
investment from the capital markets. This frame-
work should, in turn, provide principle-based (or
a so-called formula-based rate model) to future
infrastructure investment instead of the case-by-
case approach that the Federal Energy Regulatory
Commission (FERC) is currently adopting.
From an investor perspective, any investments
can be compared and benchmarked via return on
equity (ROE) across the entire capital markets.
That is, investors use ROE to compare different
asset risk profiles. From a bank lending perspec-
tive, the difference of borrowing cost among any
equity investors can be compared and bench-
marked via investor credit risk profiles (e.g.,
AAA-rated institutions vs. A- or BBB-rated insti-
tutions). In capital markets, investors are always
looking for answers for the following questions
for any investment across all industries:
1. What are the costs of investment capital?
2. What is the ROE?
3. What is the realization rate of collecting
revenue?
To investors, the first two issues could be
potentially addressed by FERC Order 679—
Promoting Transmission Investment Through
Pricing Reform—when it is final. The last issue
depends upon the final determination of the
transmission cost-allocation agreement between
FERC and state regulators.
Transmission investment projects for which
the capital is needed take a long time to de-
velop. Here, risk becomes involved. Any change
of regulation rules from federal and state down
the road may tilt the playing field easily, which
is why the investor is very cautious about put-
ting money into a transmission project. FERC
could issue enough incentives and high ROEs,
but the revenue has to be collected through the
state retail rate process. A tariff has to be ap-
proved by state regulators for investors to realize
the agreed-upon revenue stream.
Moreover, the complexity of the conventional
cost-allocation approach will impede the reve-
nue-collection process and increase compliance
costs and the operating burden, which result in
significant investment risk. Without clarification
and simplicity, the investor will not be able to
understand where the regulators stand. Thus, in-
vestors will be less interested in investing capital
in this business. Consequently, the nation’s trans-
mission network will not meet the growing needs
of the open market, will show a dramatic increase
in congestion cost, and will hinder reliability.
For transmission investments, recently the
commonly applied models for ranking ROEs—
Discounted Cash Flow (DCF) and Capital
Asset Pricing Model (CAPM)—have become
less reliable.1
The assumptions and statistical
methods upon which the DCF and CAPM are
based cannot capture the complexity of capital
markets, dynamic corporate structures, and un-
certain regulatory environments that have been
subject to constant changes under new proposed
legislation. There is a growing desire to develop
or identify a new method to reflect the current
financial and energy market reality. Among
such models, the formula-based rate model has
attracted much attention from the industry.
To respond to the increasing need of identi-
fying a new method of market-determined risk
premium associated with transmission invest-
ment, we have developed a consistent method-
ology and framework that positions transmis-
sion companies compared to other comparable
private investments across multiple industries.
Rigorous capital market modeling can then be
used to support rate incentive filings with FERC
and state public utility commissions (PUCs).
Risk-based Transmission Pricing
Methodology
All risks must be enumerated, measured, and
combined in a formula.
Risk Factors
Risks and returns depend on four key vari-
ables: (1) the corporate structure of equity in-
vestments (e.g., wholly owned subsidiary, joint
venture, or independent investor), (2) the risk
associated with invested assets and the method
of revenue collection, (3) the ability to absorb
loss exposure on the balance sheet, and (4) the
probability that the expected revenue stream or
ROE will be realized.
The first variable represents the investor’s
risk profile, which consists of the following risk
parameters:

4. 4 © 2010 Wiley Periodicals, Inc. / DOI 10.1002/gas Natural Gas & electricity January 2010
cost allocation and recovery, revenue
streams
• Internal competition for investment capi-
tal at the IOU (assuming clean energy leg-
islation) among generation, transmission,
and distribution
• Lack of explicit financial incentive guid-
ance (may result in the financial viability
of stand-alone TransCo)
• Balancing shareholder pressure with social
welfare and public interest
• Grid network value assessment
• Large regional scale and scope
• Strategic locations
• Congestion reduction (Interconnect vs.
“inside the fence”)
• Impacts of newly proposed rules for ca-
pacity and ancillary services markets on
new network connections
• Technology shift
• Upgradingexistinglinestohigher-voltage/
double-circuited lines to avoid NIMBY
(“Not in my back yard”) and other un-
certainties (e.g., Super Grid technology
developed by American Superconductor)
• Adding Merchant Phase Angle Regulators
(PARs) or Phase Shifters to improve control
of megawatt flow through transformers
• Installing DC links instead of AC lines to
enable full control of power flow (e.g., GE
Linden VFT Transmission Facility)
• Material pricing risk
• Global competition on infrastructure ma-
terial supplies
• Dollar devaluation causes increases on
various commodity prices
• Operational risk/permit process, construc-
tion duration and cost, material delivery risk,
and other operational issues
• More complicated and carrying more rep-
utation risk and financial liability com-
pared to generation asset
• System and control issues (e.g., ISO- or
IOU-controlled areas)
• System outage/reliability issues (e.g., evo-
lution of FERC electric reliability organi-
zation [ERO] reliability standards)
• Communication method and timing of
business information
The third variable represents cash reserve or
liquidity positions the investment entity holds
• Asset ownership structure/corporate structure
• Subsidiary of investor-owned utility (IOU)
• Independent transmission company
• Joint venture with transmission owners
in independent system operator (ISO)-
controlled area
• Joint venture with IOUs in IOU-con-
trolled area
• Public-private partnership
• General market risks/macroeconomic envi-
ronment
• Capital market risk/tightening credit market
and financing cost
• Overall financing challenge and lending
costs
• Investment community’s reaction to the
business plan and ROE
• Enterprise credit risk/investment entity bal-
ance-sheet impact
• Equity market borrowing costs based on
short-term/long-term interest rates, reve-
nue streams, and credit rating fluctuations
• Measuring/monitoring market risk related
to periodic regulator tariff review (poten-
tial impact on credit rating)
• Legal and liability risk
• Reputation risk and financial liability is-
sues related to outage
• Changes to organizational structure and
oversight responsibilities due to corporate
governance
• Critical resource issues
• Critical resource issues specifically related
to regulated business model, digital sys-
tem control and network security, op-
eration data, and other computer system
management
• Cost shifting for maintenance of grid reli-
ability
• Natural disaster recoveries
• Labor force competencies
The second variable represents the invested
asset risk profile, which consists of the following
parameters:
• Regulatory uncertainties causing business
risks/revenue realization
• Transmission tariff formula changes per
FERC Order 679 (case-by-case review)
• Evolving market structures on regional
transmission organization (RTO)/ISO,

5. January 2010 Natural Gas electricity DOI 10.1002/gas / © 2010 Wiley Periodicals, Inc. 5
Total Costs of Capital = Expected Infrastruc-
ture Cost + Cost of Economic Capital
The cost of economic capital, or the so-called
capital reserve, serves as a venue to provide a stream
of cash flow in addition to traditional revenue col-
lection, to absorb loss exposure, and to provide
adequate financial liquidity on the balance sheet.
This reserve is critical to balance the lengthy nature
of transmission investments, the intensive capital
required, and long-term depreciation. The reserve
usually serves as the indicator of the company’s li-
quidity position, and the higher the reserve, the
lower the borrowing cost. In general, a company’s
credit rating is applied as a proxy to reflect equity
borrowing power and financial strength.
Exhibit 1 illustrates the relationship between
total costs and the cost of economic capital.
From the exhibit, we can tell that the lower the
cost of economic capital the company has on
the financial statement, the lower the rating the
company has, and the higher borrowing cost the
company has to pay to the capital market.
In the traditional transmission pricing frame-
work, a tariff is overseen and approved by the
regulator, mainly based on marginal cost plus a
minimum rate of return as operating margin, and
the tariff is reviewed and approved frequently.
Given long-term capital depreciation and regula-
tory requirement, the more capital the company
invests in transmission business, the more bor-
rowing cost the company incurs, and the more
rating downgrade pressure the company faces in
this cost-plus environment, as the tariff is under
scrutiny at every reviewing and approving cycle.
Hence, the traditional cost-plus framework
is not attractive to new investment both from
utility and from capital market standpoints. The
lesson learned on risk and return from genera-
tion business to both the utility and the capital
market has created a desire for a new pricing ap-
proach. Including the cost of economic capital
will mitigate that financial risk and bring cer-
tainty to business operations.
The new risk-based pricing framework will
still be cost-plus; however, the “cost” between
traditional framework and new proposal is sig-
nificantly different. In addition to marginal cost,
the cost of economic capital is considered a risk
premium and needs to be adjusted constantly
based on the company borrowing power. This
risk-based pricing tariff is also different from a
to prevent any potential losses, which is derived
from economic capital the entity possesses. The
fourth variable represents the assessment of fi-
nancial incentive realization from the state pub-
lic utility commission.
Methodology
In order to capture and quantify these key risk
factors associated with new transmission invest-
ments, our new ROE methodology applies a fi-
nancial risk management concept commonly used
incapitalmarketsandallbanklendinginstitutions.
It consists of two tiers: (1) the risk scoring model
and (2) the risk premium model for pricing incen-
tive, which is based on the weighted average of risk
score of the investment entity and asset profile, and
the level of cost of equity capital.
The risk scoring model measures all key risk
factors by performing a comprehensive, qualita-
tive, and quantitative risk assessment of the new
transmission investment, assigning risk weights
to each risk factor, finalizing elements of the
risk matrix, and deriving the cumulative risk
score. The core of the Tier-2 risk-based pricing
model is to quantify investment risk factors via
the Tier-1 risk scoring model and translate them
into the risk premium of the pricing formula.
This risk premium can be interpreted as financial
compensation both for expected loss and capital
reserves held to survive unexpected loss given
business uncertainties and regulatory risks.
This risk-based model leverages the FERC
Transmission Pricing Incentive Ruling (Order
679) and calculates both risk-based incentive
components of pricing and the existing infra-
structure cost.
Total Cost of Capital
We are proposing the total costs of transmis-
sion investment capital consist of operating cost or
marginal cost and cost of economic capital. Mar-
ginal cost is a standard project finance terminol-
ogy and has been addressed extensively by utility
regulatory filing and pricing formula of traditional
tariff. It is a pure pass-through cost in tariff.
Cost of financing depends on (1) debt struc-
ture, (2) the expected infrastructure cost (or
operating working capital), (3) the impact of
the investor risk profile, and (4) the cost of eco-
nomic capital (or equity capital).
Total Equity Investment = Total Costs of Capital

6. 6 © 2010 Wiley Periodicals, Inc. / DOI 10.1002/gas Natural Gas electricity January 2010
guide decisions on debt/equity ratio, ROE tar-
gets, final complete pricing, and new tariffs. The
specifics include the following:
• Determining the optimal financing structure
• Assessing the impact of key risk factors on
investment return
• Estimating the cost of economic capital
• Calculating a reasonable return on equity
• Assisting in final decision making
Oncethetotalinvestmentcapitalisdetermined,
it can be converted easily to a tariff at dollars a
megawatt-hour based on expected electric flow
usage through the transmission line with year-end
adjustment on actual. Again, the rate includes the
risk premium and operating cost on unit pricing.
If this framework is adopted, it would apply not
only to utility investment but also to any financial
investors. If investment in transmission attracts a
broader base of investors, it will reduce the overall
borrowing cost, increase market liquidity, and
benefit the rate payers in the long run.
NOTE
1. Edison Electric Institute. (2009, February). Survey of cost of
equity capital methods. White paper, distributed to members.
Washington, DC: Author.
generic fixed rate of return approach, as with the
changes in company operation and business size,
the required return on economic capital varies.
Multiple Uses and other
advantages
From an investor perspective, any investment
can be compared and benchmarked via ROE
across the entire capital market. This model
outputs investment scorecards and recommends
solutions that do the following:
• Create a benchmarking table across all in-
dustries
• Map underlying investment structures to the
benchmarking table
• Identify the level of risk and resources re-
quired and allow detailed recommendations
in alliance with investment best practices
from the capital market
• Assess the likelihood of transmission tariff ap-
proval from the federal and state regulators
• Provide alternative scenarios to adjust for op-
timal debt/equity structure
Based on the outcome of the risk premium
and benchmarking comparison, the model can
Exhibit 1. Investment Capital Derives From Expected Marginal Cost and Cost of
Economic Capital