***[Compendium of Potential Transmission Recommendations]{.underline}***

**Draft 8-3-05**

This is a compendium of recommendations from other entities that the
Transmission Task Force may want to supplement and use as a starting
point of developing policy recommendations. These recommendations date
from 2001 to 2005. Staff has grouped the recommendations into three
categories.

1.  Generation interconnection

2.  Efficient use of existing wires

3.  Transmission expansion

    a.  Transmission planning

    b.  Cost allocation/cost recovery

    c.  Transmission siting

At next week's meeting in Portland, time has been allocated to review
this document and to begin identifying recommendations the Task Force
wants to develop.

The recommendations were derived from:

-   CDEAC Wind Task Force (extensive text reproduced)

-   CDEAC Solar Task Force

-   CDEAC Biomass Task Force

-   A report by the Keystone Center

-   DOE National Grid Study

-   Rocky Mountain Area Transmission Study

-   NARUC's National Electricity Policy

-   Edison Electric Institute

-   Transmission Issues Group (public power utilities in the Northwest)

-   Report to WGA "Financing Electricity Transmission Expansion in the
    West"

-   APPA (American Public Power Association)/TAPS (Transmission Access
    Policy Study group) Position Paper

-   Report to WGA "Conceptual Plans for Electricity Transmission in the
    West"

Following are excerpts of others' recommendations and where feasible
links to the studies from which the excerpt was taken.

I.  **GENERATOR INTERCONNECTION**

[**Transmission Issues
Group**](http://www.bpa.gov/corporate/business/restructuring/Docs/2004/July_2004_TIG_Package.pdf)

In addition, all application queues for new transmission service should
be merged into a single regional queue, accessed through the common
OASIS and administered by NTAC \[Northwest Transmission Assessment
Committee\]. Ultimately, NTAC should evaluate all individual requests
for service and develop a regional transmission expansion plan,
including non-wires alternatives. NTAC should also develop and implement
an open-season process for commercial transmission expansion. Relying on
NTAC and other regional commercial planning organizations, SSG-WI should
coordinate a WECC-wide plan, focusing on seams between the regions and
cross-regional projects. NTAC and SSG-WI should provide widely-accepted
and understood information on the technical and economic effects of
projects, while decision-making and capital commitments should remain
with the transmission owner(s) and state(s) involved in particular
projects.

**II. EFFICIENT USE OF EXISTING WIRES**

**[A. CDEAC Wind Task Force]{.underline}**[^1]

**Efficient Use of the Existing Transmission System**

Existing analyses on historic flows on major transmission paths in the
Western Interconnection suggest the existing transmission system could
be utilized more efficiently and provide transmission capacity for new
wind resources.

The Seams Steering Group-Western Interconnection (SSG-WI) has conducted
an analysis of actual flows for the years 1998-2002 using data from the
Western Electricity Coordinating Council's Extra High Voltage data base.
The graph below shows summary data from SSG-WI's 2003 report on actual
flows. Figure \_\_ below shows the percentage of time major transmission
paths reached at least 75 percent of the Operating Transfer Capacity
(OTC) limit during the highest summer, spring, and winter season from
1998-2002. The data suggests many paths operate significantly below
their physical capacity.

> ***Figure \_\_***

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

> Source: *Western Interconnection Transmission Path Flow Study*,
> SSG-WI, February 2003

Tapping the potential excess capacity on the existing transmission
system is problematic under the existing rules for transmission tariffs.
Current transmission tariffs differentiate between network service and
point to point service. For point to point service, a generator can
obtain firm service for a period of up to 10 years if sufficient
available transmission capability (ATC) is available. Alternatively,
non-firm service can be obtained for time periods up to one year. For
ATC to be available, the transmission operator must assess whether the
requested path capacity is available all year (or up to 10 years for
long-term service). If the path is projected to be constrained for even
a few hours during the period, firm service won't be offered, and the
generator must resort to obtaining non-firm service.

For wind developers, lenders providing project financing require that
the proposed project must be able to deliver the energy to market.
Non-firm transmission service, however, is for a limited duration and
does not guarantee that energy can be delivered beyond the one year
maximum. This can put wind projects in jeopardy of obtaining financing,
and ultimately, of succeeding.

These considerations have prompted a number of studies and potential
policy changes. The proposals below would encourage a more efficient use
of the existing transmission system and provide new transmission
opportunities for wind energy generation.

***Conditional Firm and Related Tariff Reform***

The Federal Energy Regulatory Commission (FERC) held a workshop in
Portland in March 2005 to explore possible conditional firm type
transmission products. The Bonneville Power Administration (BPA) is
considering a proposed conditional firm and commercial redispatch
product. The Western Area Power Administration (WAPA) has been
contemplating a Priority Non-Firm product.

BPA's proposed conditional firm (CF) and redispatch products would be
offered only in cases where long-term capacity is not available to serve
a transmission request during some months of the year. The proposed CF
product would be a long-term transmission service that provides for as
many months of firm service as possible during the year, combined with a
specified number of hours over a set number of "conditional" months when
firm transmission service may not be provided. This can allow the
transmission provider to offer more service and potentially serve new
resources that would otherwise not be able to get on line.

A Commercial Redispatch product is called for in the 888 Open Access
Transmission Tariff (OATT), however, utilities have not yet offered it.
This product would allow a transmission owner to offer more long term
service when their system in constrained on one or more paths by
arranging for dispatch of generation resources to relieve those
constraints when the system is at peak usage.

WAPA's Priority Non-Firm product is offered on a long term basis, which
has a curtailment priority below "firm" service but higher than all
other "non-firm" service. This may have more limited potential to enable
new projects to get financing, but may provide for more use of the
existing grid.

***Economic Dispatch of Transmission***

Under current operating procedures in much of the WGA region, the use of
existing transmission system during congested periods will not be
economically efficient since higher value power transactions can be
denied transmission access in favor of lower value power sales.[^2]

In the Western Interconnection, parties are prohibited from scheduling
power transfers on the transmission system if such schedules would
exceed the pre-calculated Operating Transfer Capacity of the
transmission path. The Western Interconnection has also adopted a loop
flow mitigation procedure to help compensate for the fact that contract
path transmission scheduling does not reflect the electrically reality
that power in an AC network will flow over the path of least resistance,
which may not be the contract path. However, this loop flow mitigation
procedure does not account for the economic value of different power
sales when curtailing use of the transmission system.[^3]

Regional Transmission Organizations offer the opportunity to create a
more economically-efficient system for managing access to the grid that
is consistent with the physical reality of the transmission network. A
market-based congestion management system would force transacting
parties to pay the actual costs of congestion caused by their
transactions. A market-based congestion management system would also
provide more accurate price signals to market participants regarding the
construction of new transmission capacity, the best locations to locate
new of central power plants to mitigate transmission congestion, and the
value of distributed generation and load management programs in
mitigating transmission congestion.

 

Under most RTO congestion management systems, an RTO would distribute a
transaction between two points on the transmission grid across the
\"flow paths,\" or links in a simplified model of the RTO's transmission
system. For the transaction to be accepted, the transmitting party would
either demonstrate it held firm transmission rights (FTRs) between the
point of injection and the point of withdrawal, or it would have to
specify its willingness to pay congestion costs. The RTO would manage
congestion by purchasing reverse transactions or an appropriate mixture
of increments and decrements of generation and/or loads at various
points around the grid. The value of FTRs would reflect the marginal
congestion management costs between the specific pairs of nodes that
they represent.

In this type of transmission congestion management system, higher value
economic power sales would use transmission system before lower value
power sales. In the WGA states, there are three operating RTO-like
organizations, the Midwest Independent System Operator, the California
Independent System Operator and the Electric Reliability Council of
Texas. RTOs have been proposed in the Northwest (GridWest) and the
Southwest (WestConnect) but they are years from implementing
economic-based transmission congestion systems. In addition to reaching
agreement on a transmission congestion management system, GridWest and
WestConnect must resolve many other hurdles before becoming operational.

**B. CDEAC Solar Task Force**

Issues for the Transmission Task Force

-   The working group is in the process of identifying the MW capacity,
    in each state, that is located close to load growth pockets and
    close to transmission with available capacity. To identify
    additional capacity would require knowing the available capacity of
    lines close to prime solar areas and the cost to build additional
    capacity to access those resources.

-   Detailed GIS maps are now available that show the prime areas for
    central solar power and the major transmission lines in each
    southwestern state.

**C. CDEAC Biomass Task Force**

Biomass power plants are generally considered as DER (Distributed energy
resources) which can be either power plants (steam turbine, internal
combustion engine, gas turbine) or CHP at appropriate locations in
combination with one of the above prime movers.

The economical size ranges are between 5 MW~e~ and 50 MW~e~ with a basic
levelized cost of electricity (LCOE)in the range 60 -- 120 \$ MWh^-1^ .
These delivered costs can be lower as biopower also gives a large range
of societal benefits that the Biomass group is trying to both quantify
and devise policy measures to be recommended to the WGA to capture these
benefits in the delivered LCOE. Examples of this include: forest health
and the avoidance of air quality problems; land fill diversion of urban
residues, and the capture of methane from landfills and confined animal
feed operations.

In general the current biomass generation (2.1 GW in the WGA in 2005 )
is connected at the distribution level of the T&D system -- generating
sets are usually at less than 13.8 kV and the connections are to
substations at the 69 kV or lower voltages.

The biomass task force has not completed its resource curve development
but offers to the transmission task force a set of tables of likely
connection points to the distribution system on the basis that towns of
\> 5,000 inhabitants will have both biomass resources and the requisite
access to the distribution system. These towns have been proposed based
on an overlay of sufficient biomass resources within a 90 km radius of
the town site. While transportation over greater distances may be
feasible, this will need to have a full assessment during the
determination of the supply curve. This is because there is a trade off
between decreasing capital investment on a \$ kW^-1^ basis with scale
while the transportation cost of the biomass is increasing with scale.

**D. [DOE National Grid
Study](http://www.eh.doe.gov/ntgs/gridstudy/MAIN_RECOMMENDATIONS.PDF)**

-   DOE will work with industry to demonstrate and document
    cost-effective uses of dynamic transmission system analysis.

**E. Report to WGA: [Conceptual Plans for Electricity Transmission in
the
West](http://www.westgov.org/wga/initiatives/energy/transmission_rpt.pdf)**

Transmission should enable access to more economical and less-polluting
resources, thereby minimizing environmental impacts on both a local and
regional basis.

**III. TRANSMISSION EXPANSION**

**A. Transmission Planning**

**[1. CDEAC Wind Task Force]{.underline}**

***Regional Transmission Planning***

Even with more efficient use of the existing transmission system,
achieving the goal of 30,000 MW of clean and diversified electricity
generation will require expansion of the transmission system. Successful
expansion of the transmission system to reach clean and diversified
generation (as opposed to expansion for system reliability) requires:

-   A pro-active, transparent transmission planning process open to all
    parties;

-   Agreement on how to allocate the cost of new transmission to the
    beneficiaries of such transmission and confidence that the cost of
    new transmission will be recovered; and

-   Timely permitting of facilities.

The existing transmission system is the product of discrete decisions by
utilities. Individual utilities, or occasionally groups of utilities,
built transmission to reach distant generating resources or to
interconnect with their neighbors to share reserves. There was no
regional transmission plan. This system worked well prior to FERC orders
to provide open transmission access and the development of regional
power markets.

Regional power markets present new opportunities to bring lower cost
generation to consumers and thus reduce costs to consumers. However,
regional power markets have changed the way the transmission grid is
used. The system is increasingly used for longer distance power sales
and to take advantage of short-term power sales that lower costs.

[Background]{.underline}

During the Western electricity crisis of 2000-2001, Western Governors
asked a roundtable of utilities, independent power producers and
regulators what new transmission was need. There was no answer. As a
result, Western Governors directed a crash effort to develop a
conceptual transmission plan for the Western Interconnection. This was
delivered by a joint industry/state effort in August 2001. The Governors
asked that this type of pro-active, interconnection-wide planning be
institutionalized.

In the Midwest and ERCOT regions, regional transmission organizations
have been formed. One of the key functions of RTOs is to conduct
regional transmission planning.

Successful regional transmission planning efforts have several
characteristics.

-   The planning process is pro-active and is not triggered by a
    specific project proposal.

-   The planning process is open to all parties and is driven by the
    interests of load serving entities, generation developers, state
    policy makers, and interest groups, as well as transmission owners.
    Effective participation by such stakeholders in the planning
    process, particularly state agencies, improves the chances of
    securing necessary regulatory approvals to transform plans into
    projects.

-   The planning process should generate information on who benefits
    from the transmission expansion. This is particularly important in
    areas without RTOs, since absent an RTO there is no mechanism to
    force unwilling parties who would benefit from a project to pay for
    part of the project.

-   The planning process is transparent; that is, the transmission
    planning data and modeling tools are available to all parties. Such
    transparency is essential to enable the products of the planning
    effort to be used in regulatory proceedings on cost allocation/cost
    recovery and siting.

-   The planning process is closely linked to the resource acquisition
    plans of load serving entities (LSE) and the plans of generators.
    Such linkages are needed so that (1) regional transmission plans can
    reflect the resource acquisition plans of load serving entities
    and (2) the resource acquisition plans of LSEs can be informed of
    new options that are created by significant transmission expansion
    that may be beyond the scope of any single LSE. One difficulty in
    linking LSE resource plans with regional transmission planning is
    that individual LSE resource planning processes are on different
    time schedules.

-   The planning process should have the capability to evaluate the
    impact of demand-side measures on the need for transmission and
    consider new transmission technologies.

Open, pro-active, stakeholder-driven transmission planning supported by
Western Governors (Resolution 03-19) has taken hold in most of the WGA
region. However, often such planning is done on an ad hoc basis without
sustained financing or an institutional structure (e.g., Rocky Mountain
Area Transmission Study). While producing useful analysis, such ad hoc
processes are inadequate to support the efforts necessary to move a
project from the planning stage to financing, permitting and
construction. Such ad hoc processes also limit the development of new
analytic tools that would do a better job of evaluating the costs and
benefits of new transmission and identifying the beneficiaries of
transmission expansion.

The value of pro-active transmission planning in developing projects can
also be undercut by the present FERC-mandated queuing requirements for
transmission interconnection and transmission service requests. The
current requirement that such requests must be processed sequentially
may result in economic transmission expansion opportunities being
overlooked, lower cost resources being unavailable to LSEs, and
increased reliance on default near-load gas-fired generation. Planning
processes may identify large scale transmission investments that would
lower costs and allow more distant clean and diversified resources to be
available to meet the needs of load serving entities. However,
cost-effective projects to connect to such transmission may be far down
in the queue. The limited manpower resources of transmission owners may
be diverted to processing the next application in the queue rather than
developing cost effective transmission projects that would serve
multiple applicants, many of whom may be far down in the queue.
Transmission owners need to be able to aggregate the analyses of
interconnection and transmission service requests within a region.
Additionally, generation projects that are selected by LSEs in open,
transparent resource acquisition processes should move to the top of the
queue.

[Recommendation: Transmission Planning]{.underline}

> a\. The existing pro-active, transparent interconnection-wide and
> sub-regional transmission planning processes need to be strengthened
> and made sustainable by providing financial resources and
> institutional homes for regional transmission planning.[^4]
>
> Provide financial support for on-going transmission planning based on
> a FERC-approved tariff rider for regional transmission planning.
> Western Governors have called for enhancing the capability of states
> to participate in the resolution of regional electric power issues,
> such as regional transmission planning. This requires additional
> resources for interstate collaboration.
>
> b\. Regional transmission planning efforts need to be closely linked
> to the resource acquisition plans of load serving entities (LSE) and
> the plans of generators.
>
> To accommodate the analysis of large scale transmission expansion that
> would serve the needs of more than one load serving entity or one
> generator, LSE resource planning efforts within an area need to be
> synchronized to the same time schedule so that generating options that
> require significant new transmission to reach markets will be
> considered in LSE resource plans.

**2. CDEAC Solar Task Force**

-   Transmission line planning, including siting and capacity, must
    include the high potential for central solar plants deployed during
    the period to 2015, and 2025.

-   Identification of where distributed solar could relieve transmission
    constraints is needed.

**[3.]{.underline}** [**Keystone
Dialogue**[^5]](http://www.electricity.doe.gov/documents/regional_transmission_project.pdf)

**Recommendation 1a:** A regional approach to transmission needs
assessment and planning is needed. This will require the creation of
voluntary regional planning bodies in areas without RTOs/ISOs. Where
RTOs/ISOs exist, transmission planning and needs assessment must be a
core function. (Keystone, p. 3)

**Recommendation 1b:** Regulatory authorities should extend due
deference to identification of need and development of cost allocation
guidelines for transmission expansion decisions that evolve from a
regional planning process if it meets the following minimum criteria:
(1) meets NERC reliability criteria and supports competitive wholesale
electricity trade; (2) considers the roles of generation and demand-side
management, as well as transmission, in meeting regional needs; (3)
involves states and other regional stakeholders in the process; (4) uses
an independent analysis of transmission needs; (5) results in a regional
plan of sufficient geographic scope; and (6) provides opportunities for
due process and fair participation. (Keystone, p. 4)

**Recommendation 1c:** States should take a leadership role in bringing
together

stakeholders and forging agreement about solutions to regional
transmission needs,

cost allocation, and siting where RTOs/ISOs do not exist. Where
RTOs/ISOs do exist, states should be actively involved in the regional
planning process, in order to build a common understanding of the range
and impacts of possible solutions. To enable effective state
participation, adequate funding should be provided for staff time.
(Keystone, p. 4)

**4. [Rocky Mountain Area Transmission Study
(RMATS](http://psc.state.wy.us/htdocs/subregional/FinalReport/Chapter4.pdf))**

Transmission planning capability will need to be available to support
Phase II activities, including the application of pricing principles to
specific projects, evaluating other benefits of transmission projects,
such as increased reliability, fuel diversity, and providing input to
federal and state regulatory processes.

The RMATS planning function should continue to be coordinated with other
sub-regional plans through the broader west-wide planning performed by
SSG-WI. Further, if Grid-West becomes operational, the RTO could assume
the transmission planning function, and RMATS regional planning could
devolve. (RMATS ,p. 4-11)

**5.
[NARUC](http://www.naruc.org/displaycommon.cfm?an=1&subarticlenbr=29)
National Electricity Policy**

Congress should require that RTOs or other regional bodies have
sufficient authority to conduct long term planning for their regions
and, working with the States and transmission owners, implement
long-term planning that should:

-   Take into account fuel diversity including renewables resources;

-   Recognize the need for new investment in generation and transmission
    facilities that provides adequate reserve margins;

-   Assure that reliability is not compromised by resource imbalances;

-   Reduce any decisional role for entities with unreasonable generation
    or transmission market power;

-   Include broad public participation and collaboration among market
    participants and third party participation in offering competitive
    alternatives such as demand-side and distributed generation options;

-   Develop a cost allocation method that is objective,
    non-discriminatory, weighs environmental and societal risk, and
    associates costs with benefits;

-   Allow the use of competition, subject to appropriate regulatory
    oversight, to encourage robust wholesale markets; and

-   Assure adequate resources in all regions of the nation.

**6. [Edison Electric
Institute](http://www.eei.org/industry_issues/energy_infrastructure/transmission/eei_tranmission_principles_5_10.pdf?ObjectID=35619)**

1.  1\. State and federal policy should eliminate regulatory impediments
    and provide regulatory certainty, particularly with respect to
    attractive returns, incentives, cost allocation and cost recovery,
    in order to raise the capital necessary to construct needed,
    cost-effective transmission facilities.

    2\. Transmission pricing should (a) allow for cost recovery of fixed
    and variable costs and a reasonable return on transmission
    investment, (b) ensure, to the extent practicable, that cost
    responsibility follows cost causation, (c) minimize the potential
    for cost shifting, (d) permit the recovery of all prudently incurred
    transition costs, and (e) promote efficient siting of new
    transmission and generation facilities.

    3\. Conflicting federal and state regulatory policies can result in
    unrecoverable, trapped costs. FERC and the states must ensure that
    the necessary regulatory mechanisms are in place to allow for the
    full recovery of all prudently incurred costs and the avoidance of
    trapped costs.

```{=html}
<!-- -->
```
1.  4\. FERC and the states should allow full recovery of all prudently
    incurred costs to design, study, pre-certify, and permit
    transmission facilities. FERC should amend its rules to allow full
    recovery of the prudently-incurred costs of abandoned transmission
    projects.

    5\. FERC should allow utilities to include construction work in
    progress (CWIP) in rate base (in lieu of AFUDC) as this will
    encourage transmission construction through improved cash flow and
    greater rate stability.

    6\. FERC should allow for accelerated depreciation in ratemaking to
    improve financial flexibility, and promote additional transmission
    investment.

    7\. Where states require purchases of renewable resources that lack
    siting flexibility, FERC should allow alternative transmission
    pricing and cost recovery approaches to support the building of
    transmission facilities to help achieve state renewable resource
    goals.

**7. [Transmission Issues
Group](http://www.bpa.gov/corporate/business/restructuring/Docs/2004/July_2004_TIG_Package.pdf)**

Northwest transmission owners have already established the Northwest
Transmission Assessment Committee (NTAC), a subcommittee of the
Transmission Planning Committee of the Northwest Power Pool (NWPP). NTAC
will perform commercial transmission planning for the Northwest,
complementing the NWPP's responsibilities for reliability planning. NTAC
membership is open to all interested entities. The Seams Steering
Group-Western Interconnection (SSG-WI) is engaged in similar commercial
planning efforts for the entire Western Electricity Coordinating Council
(WECC), complementing WECC's reliability planning responsibilities. Our
goal is to develop and implement long-term funding for both NTAC and
SSG-WI planning work, including funding for an oversight committee
comprised (at least) of state regulators, Governor's offices, and other
state agencies involved in transmission siting or approval.

**8. [DOE National Grid
Study](http://www.eh.doe.gov/ntgs/gridstudy/MAIN_RECOMMENDATIONS.PDF)**

-   DOE, through a rulemaking, will determine how to identify and
    designate transmission bottlenecks that significantly impact
    national interests.

-   DOE will further develop the analytic tools and methods needed for
    comprehensive analysis to determine national-interest transmission
    bottlenecks.

-   In an open public process, DOE will assess the nation's electricity
    system every two years to identify national-interest transmission
    bottlenecks.

**9. Report to WGA: [Conceptual Plans for Electricity Transmission in
the
West](http://www.westgov.org/wga/initiatives/energy/transmission_rpt.pdf)**

Future analysis should consider the capital costs of expanding the
natural gas pipeline

system to meet demand and building new generation facilities, the
benefits of fuel diversity, and transmission\'s value in mitigating
market power. The working group also identified alternatives to
conventional transmission expansion that should be considered as
transmission expansion plans are developed. The alternatives are:

1\. Emerging transmission technologies that increase the transfer
capability on

the existing transmission system;

2\. More efficient use of electricity that reduces overall demand;

3\. Peak load management that reduces the need for new transmission used

only for a few hours per year during peak demand periods; and

4\. Distributed generation located at ornear the customer load.

A forward-looking Western interconnection-wide transmission planning
process should be established.

**B. Cost Allocation/Cost Recovery**

**[1. CDEAC Wind Task Force]{.underline}**

***Cost Allocation and Recovery for Transmission***

The future potential of wind energy in the West is closely linked to the
development of new transmission. Transmission expansion, however, has
been plagued by a problem referred to as the chicken and egg dilemma.
Transmission owners are reluctant to build new transmission lines
without commitments from generators, and conversely, generation
developers are reluctant to build new generation resources without
access to transmission.

The transmission problem for wind energy is exacerbated by a geographic
and timing mis-match. Wind resources tend to be located in remote rural
areas that are far from load centers. Since wind generators need to be
located near wind resources, wind energy is dependent upon significant
new transmission investments to deliver the energy to loads. The timing
issue arises from divergent time horizons between wind and transmission
development. Wind developers can generally permit and construct a wind
generation project in two years or less. New transmission projects can
take about 5 to 8 years to build.

This section proceeds with background on the regulatory institutions and
policies on cost allocation and recovery that influence transmission
investments, and then makes recommendations to address the transmission
expansion problem and take advantage of the vast wind resources in the
West.

[Background]{.underline}

The federal government and state governments regulate different areas of
the electric industry. The Federal Energy Regulatory Commission (FERC)
regulates interstate electric wholesale transactions and sets wholesale
transmission tariffs. State regulatory commissions (PUCs) have exclusive
jurisdiction over bundled retail rates within their respective states.

The electric power industry can be divided into two broad groups:
jurisdictional and non-jurisdictional entities. Jurisdictional entities
are generally investor owned utilities (IOUs) which are subject to both
state and FERC regulation. Merchant power and transmission entities are
subject to FERC jurisdiction. Power marketing entities created by the
federal government (e.g. Bonneville Power Administration (BPA), Western
Area Power Administration (Western)) or local governments (municipals,
public utility districts "PUDs", rural cooperatives, generation and
transmission cooperatives) are non-jurisdictional entities that are not
subject to FERC or state jurisdiction for most purposes. Many
non-jurisdictional entities follow FERC rules by voluntary choice or
under reciprocity provisions.

Most states require IOUs to plan for resource acquisitions and
transmission expansion through the integrated resource plan (IRP)
process. Some states vest siting decisions with their PUC or another
state-wide entity, while other states require siting decisions be made
by a combination of state and local jurisdictions. Prior to
construction, states generally require that the transmission project
sponsor obtain a certificate of public convenience and necessity (CPCN)
by demonstrating the need and public interest of the proposed project.
States allow transmission owners to recover the portion of prudent
transmission costs used to provide retail service through the retail
price of electricity set by the PUC and paid by electricity customers.
The balance of transmission cost recovery is through wholesale
transmission rates, or tariffs, set by FERC.

Prior to 1992, most electric utilities operated as vertically-integrated
monopolies and were responsible for coordinating all generation,
transmission and distribution functions within their respective service
territories. After passage of the Energy Policy Act of 1992 and Order
888/889 in 1996, IOUs (and some public power entities) became
functionally separated between generation and transmission, and faced
competition in the generation sector. FERC encouraged the formation of
regional transmission organizations (RTOs) and Independent System
Operators (ISOs) to manage the regional electrical network and
coordinate transmission investments. With the exception of portions of
western states covered by the California ISO, the Midwest ISO, ERCOT,
and the Southwest Power Pool, the movement towards RTOs in the rest of
the West has stalled for now. Absent cost recovery mechanisms defined by
broad regional transmission organizations in the West, state PUCs
continue to have decision-making responsibility about cost recovery for
projects in their respective states.

[Current Policy on Cost Allocation and Recovery]{.underline}

New transmission for the purpose of connecting a generator to the grid
is called generation tie-lines i.e., lines from the generator to the
first point of interconnection with the grid. FERC generator
interconnection rules provide that the interconnecting generator bears
the full cost of the line.[^6] Network upgrades are defined as the
additions, modifications, and upgrades to the transmission system at or
beyond the point of connection to the grid to accommodate the generator
to the system. The full cost of the network upgrade for a generator
interconnection is borne by and rolled into the transmission rates of
the transmission owner. The transmission owner, however, may require the
interconnecting generator to provide upfront funding for the network
upgrade and then credit the funds, with interest, back to the generator
over time following commercial operation of the generator. This type of
cost allocation is known as "participant funding". This funding/credit
back policy places the developmental risk on the interconnecting
generator rather than the transmission owner or its customers. FERC
interconnection policy does not draw a distinction between new
transmission required for reliability reasons and transmission developed
for economic reasons.

For transmission developed outside of a request for interconnection from
a generator, cost allocation is handled differently in different
regions. Western states generally allocate transmission costs based on
the dual principles of cost causation and beneficiary pays. Cost causers
are the parties that cause the cost of transmission to be incurred.
Beneficiaries are those parties deriving a direct benefit from the
transmission project. The cost of new transmission would be allocated to
the identified cost causers and/or beneficiaries based on their relative
use of the total benefits created by the project. Customers in a local
area that benefit the most from a new facility would pay more than
customers in another region that derive little or no benefits from the
project. This approach provides price signals promoting the efficient
level of new transmission investments relative to other potential
investments in the system.

In contrast, other regions such as New England[^7] and Texas[^8] have
adopted cost allocation policies that share equally or socialize costs
for transmission projects with regional purposes or the beneficiaries
can't be clearly identified. Transmission costs are socialized in these
regions by rolling in the costs into general rates faced by all users.
Proponents of socializing transmission costs point out that it is very
difficult to accurately identify the current beneficiaries of
transmission investments. Over time, the distribution of benefits from
transmission becomes even more diffuse since incremental transmission
investments improve overall reliability to the system, and the
interactions of additions of new generation and other transmission
projects alter the flow of electricity over the grid in complex and
unanticipated ways.

The proposals described below provide opportunities to address the
critical problem of coordinating transmission investments with
generators of clean and renewable energy. These proposals assume that
RTOs will not be adopted in the foreseeable future.

[Recommendation: Cost Allocation and Recovery]{.underline}

a.  **Enhanced Regional Planning**. In recent years, numerous regional
    and sub-regional ad hoc pro-active planning efforts have examined
    transmission opportunities.[^9] These ad hoc efforts rely on
    voluntary contributions of resources and lack sustained reliable
    funding mechanisms. The SSG-WI interconnection planning effort will
    terminate next year. Future interconnection-wide planning may be
    preformed by the existing Western Electricity Coordinating Council
    (WECC) or the new Western Assessment Group (WAG). The outlook for
    transmission expansion is tied to an enhanced regional planning
    effort. The West needs to create and financially support regional
    planning efforts across the entire western interconnection on behalf
    of state regulators, policy makers and industry. Regional planning
    should utilize the best available data and modeling techniques to
    identify economically efficient investments in transmission,
    generation and demand-side resources. Sophisticated regional
    planning provides critical information necessary to justify large
    long-term investments in transmission.

    -   Economic analyses of potential transmission projects can
        identify the benefits to different parties. The identification
        of regional beneficiaries is important part of the collaborative
        process in building approval and financial commitments among
        divergent interests for potential projects.

    -   The identification of economically efficient investment projects
        provides key evidence to support a regulatory determination that
        a project is in the public interest and a prudent investment.

    -   Regional analyses that identify efficient investments ex ante
        provide the basis for greater certainty about cost recovery, and
        thereby reduce the risk exposure for project developers and
        investors.

b.  **Coordination of State Regulatory Commissions**. States should take
    steps to coordinate their respective regulatory reviews of
    multi-state transmission projects in a manner that builds upon
    existing regulatory principles and respects the public interest of
    individual states. States can improve regulatory coordination by the
    following actions.

    -   Organize a convention of western state regulatory commissions
        that would develop common principles for cost allocation and
        recovery for multi-state transmission projects. This convention
        would establish a process that would lead to a memorandum of
        understanding or regional protocol among western states.
        Potential role models for this multi-state coordination effort
        include the Western Transmission Siting Protocol and the
        Multi-state Protocol by states in the PacifiCorp service area.

    -   Adopt a common western procedural process that coordinates
        regulatory commission reviews of multi-state projects. This
        process would identify and coordinate the applications, forms,
        analyses and deadlines that a project sponsor encounters in
        seeking regulatory approvals for a multi-state transmission
        project.

c.  **Presumption of Prudence.** An important regulatory step to recover
    costs is a regulatory finding that project costs were prudent. To
    reduce the uncertainty of an adverse prudence finding by state and
    federal regulators, regional planning processes can provide
    information to regulators and enable them to give assurances that a
    proposed project meets requirements for a prudence finding.

    -   States should extend a rebuttable presumption of prudence for
        multi-state project proposals that have been endorsed as an
        economically efficient investment based on a detailed economic
        assessment by the regional planning entity.

    -   FERC should adopt a rebuttable presumption of prudence for
        western project proposals that have been recommended by the same
        western regional planning entity.

d.  **Open Season.** The natural gas industry has used the open season
    process to test the market demand for gas pipeline expansion for
    many years. Recent applications by NorthWestern Energy and BPA
    demonstrate how the open season process can be applied to proposed
    transmission projects.

    -   States should encourage the use of an open season process by
        project developers as a means demonstrating the demand for and
        value of new transmission projects. .

e.  **Public Interest and Regulatory Incentives**. Many western states
    have adopted renewable portfolio standards (RPS) to stimulate
    greater use of renewable resources. States that have adopted
    mandatory RPS goals have expressed a general public interest in
    expanding the use of clean renewable energy. Regulatory commissions
    should acknowledge these public interest benefits as system-wide
    benefits, and make corollary public interest findings for cost
    effective transmission projects that will enable the state or region
    to meet its energy policy goals. The public interest findings would
    provide grounds for:

    -   A certificate of public convenience and necessity for
        construction of transmission projects necessary to meet state
        energy goals and other necessary rulings to ensure efficient
        siting of new transmission and generation facilities;

    -   Rolled-in rate treatment for transmission projects deemed
        necessary to meet state energy goals;

    -   Expedited and streamlined recovery of construction expenses for
        transmission projects deemed necessary to meet state energy
        goals.

    -   Modification of queue rules to permit flexibility and
        coordination of multiple generation and transmission projects
        that are necessary to meet state energy goals.

f.  **Renewable Trunkline**. Transmission projects that connect
    designated wind resource regions to the grid should be subject to
    cost recovery rules similar to the renewable trunk line proposal by
    Southern California Edison (SCE) for its Tehachapi/Antelope
    transmission project.[^10] This proposal removes key impediments
    that discourage transmission investments in remote wind resource
    regions. The proposed changes would encourage phased-in transmission
    investments based on the predictable growth of many independent wind
    generation projects in a designated concentrated area. The proposal
    provides a practical solution to the "chicken and egg" problem, and
    avoids the pitfall of inefficient piecemeal studies required under
    current interconnection rules. These proposed policies should apply
    where it is consistent with a state's policy requiring procurement
    of renewable resources and the state has determined, through its
    state regulatory authority or RTO/ISO, that the upgrades are
    necessary to meet its policy objectives and costs should be
    recovered from the users of the network. The specific elements of
    the SCE proposal are described in Appendix B and are summarized
    below:

    -   Rolled-in rate treatment for high-voltage (220kV or higher)
        trunk-line transmission project costs necessary to integrate
        large concentrations of renewable generation resources located a
        reasonable distance from the existing grid. To be eligible for
        this treatment, the large concentration of renewable resources
        should be located in a limited geographic area.

    -   Permit rolled-in rate treatment and cost recovery for prudent
        costs for transmission facilities describe above regardless of
        whether the full increment of forecast generation that would
        justify the upgrades commences commercial operations.

    -   Grant 100% cost recovery for prudent costs even if the
        transmission project is cancelled or abandoned either because
        there is insufficient generation development in the region or
        necessary regulatory approvals for project construction are not
        granted. Under current policy, FERC limits recovery from
        ratepayers to only 50% of the utility's prudently-incurred
        investment in abandoned or cancelled FERC-jurisdictional plant
        (facilities not completed and placed into operation).

**[2.]{.underline} [Keystone
Dialogue](http://www.electricity.doe.gov/documents/regional_transmission_project.pdf)**

**Recommendation 3a:** States, stakeholders, and RTOs/ISOs should
develop a region-wide set of guidelines on cost allocation for new
transmission facilities that limits case-by-case review of allocation
decisions. (Keystone p. 6)

**Recommendation 3b:** Regions should use accepted economic and
engineering models and develop clearly understood and accepted
analytical procedures based

on best practices, which (1) determine need and (2) identify costs and
benefits of

transmission expansion over a reasonable, near-term time period (e.g., 5
to 10 years). (Keystone p. 7)

**Recommendation 3c:** RTOs/ISOs and their participating transmission
owners (TOs)

should agree that TOs will construct transmission identified by
RTOs/ISOs as

needed when reasonable conditions are met, including sufficient
assurance of cost

recovery and environmental and siting approvals. (Keystone p. 7)

**Recommendation 3d:** DOE and FERC should organize a conference on best

practices to provide information on the siting process and its
relationship to

stakeholders. (Keystone p. 8)

**Recommendation 3e** FERC should direct each RTO/ISO to work with
regional

stakeholders to develop workable and equitable mechanisms for providing

long-term financial transmission rights or other appropriate instruments
that provide

transmission customers effective financial hedges against transmission
congestion

costs. (Keystone p. 8)

**3. [Rocky Mountain Area Transmission Study
(RMATS](http://psc.state.wy.us/htdocs/subregional/FinalReport/Chapter4.pdf))**

**Develop Multi-State Pricing Principles**. RMATS recommends that the
Rocky Mountain states, through their regulatory commissions and after
hearings, enter into a memorandum of agreement (MOA) adopting pricing
principles, and jointly file such an MOA at FERC and request the
Commission's endorsement. These principles would then be used as
criteria for decision-making for any applications for transmission cost
recovery received by regulatory commissions within the RMATS region,
thus providing a degree of clarity and consistency in regulatory
treatment. These principles could also be included in tariff filings
made by FERC-jurisdictional utilities.

A binding agreement among the commissions should be explored, as well as
voluntary approaches to application of pricing principles. RMATS
recommends that the pricing principles recently approved by FERC for the
Northeast region serve as the model for pricing principles developed by
RMATS.

RMATS also recommends exploring means to increase regulatory certainty,
including, but not limited to: forms of pre-approval; higher rates of
return on transmission investments; and quicker rate-basing of
transmission investments,. In Phase II, a joint stakeholder and
regulatory group could be formed to provide a forum for exploring these
options. (RMATS p. 4-10)

**Coordinate Regional Transmission Planning with LSE Resource Plans:**
To improve regional transmission planning efforts and LSE resource
plans, RMATS recommends the (1) the RMATS transmission recommendations
be considered in the resource plans of LSEs in the Rocky Mountain region
and in the review of such plans by the regulatory commissions in
Colorado, Idaho, Montana, Utah and Wyoming; and (2) future RMATS
transmission planning build on the most recent resource plans and
resource acquisition actions of LSEs in the Rocky Mountain region. RMATS
broke new ground in regional transmission planning by explicitly
incorporating the resource plans of Idaho Power Company, PacifiCorp. and
Xcel into the analysis of transmission Alternative 1. The development of
a "quasi" integrated resource plan for the region (Alternative 2)
highlighted potential investments in new generation and transmission
that could lower costs compared to existing LSE resource plans. Closer
coordination of regional transmission planning with LSE resource plans
can improve the quality of both efforts and should be encourages. (RMATS
4-11)

1.  **Engage the Wyoming Infrastructure Authority**

In the 2004 legislative session, Wyoming enacted a law creating the
Wyoming Infrastructure Authority (WIA). The WIA has the authority to
own, operate and maintain high-voltage interstate transmission
facilities. Within the state of Wyoming, the WIA also has condemnation
power to facilitate transmission expansion planning and siting.

The WIA became effective July 1, 2004 and is governed by a five-member
board, appointed by the Wyoming governor. To begin its work, the Wyoming
legislature appropriated operating funding. This funding is deemed a
loan and the WIA will ultimately be obligated to repay the loan with
interest.

The WIA has the authority to issue revenue bonds to raise capital to
build transmission infrastructure it would own. There is no statutory
limit on this bonding authority for projects the WIA might own. The WIA
also has the capability, within an outstanding bond cap of \$1 billion,
to issue bonds to build transmission facilities owned by other entities.
All WIA-issued bonds would be exempt from state taxation. Tax-exempt
bond financing may reduce the cost of transmission projects compared to
private-sector equity and debt financing.

The WIA is constitutionally barred from issuing revenue bonds backed by
the faith and credit of the State of Wyoming. This means for any WIA
bond issuance to be successfully received by the financial community,
the bonds will likely need to be secured by an expected revenue stream
from the transmission investment. This security could take the form of
subscription-type contracts with entities expected to use the
transmission, a lease agreement with one or more utilities agreeing to
take transmission capacity, or other means.

The WIA is a new institution that will become involved in transmission
planning and expansion. This creates opportunities to collaborate on
transmission investments, to pursue partnerships with public and private
entities, to begin to address siting and rights-of-way issues, and to
explore creative financing and contracting. These opportunities should
be vigorously examined in RMATS Phase II, and should involve the WIA
board. (RMATS p.11-12)

**RTOs:** RMATS recommends that Governors and regulators consider the
formation of an RTO with features appropriate to the region, including
independence and cost-effectiveness. RMATS encourages ongoing efforts to
explore formation of Grid West, including its collaborative approach
with regional regulators and stakeholders. (RMATS, p.4-12)

**4. Report to WGA:** [**"Financing Electricity Transmission Expansion
in the
West"**](http://www.westgov.org/wga/initiatives/energy/final_rpt.pdf)

**(2002)**

There is consensus among the TFC \[Transmission Finance Committee\]
members that the formation of RTOs with clearly defined functions and
operating rules will help to remove at least some of the uncertainties
that are hindering investment in transmission expansion. The TFC
therefore recommends the following.

1\. The Governors should support the timely formation of Regional
Transmission Organizations (RTOs) in the West to identify and facilitate
expansion of the transmission infrastructure.

2\. The Governors should call on the RTOs to address at an early stage
any factors that may inhibit investment in transmission expansion in the
West. For market-financing expansions to occur, the RTOs must clearly
define the property or financial rights that accrue to a market
participant making a transmission infrastructure investment. (WGA, p.
23)

\[Prior to formation of RTOs\] the Governors should recognize and
encourage the recent initiative of the Seams Steering Group - Western
Interconnection (SSG-WI) to develop a robust interconnection-wide
"proactive" transmission planning process. This process, to be
implemented in advance of the formation of RTOs would identify problems
that can be addressed by transmission (or alternative non-transmission)
solutions. Information developed in such a planning process will be
valuable to market participants regardless of which financing model is
used for a particular project. Such a process is essential to garner the
public and political support that would be needed to implement the total
system cost model, especially in those cases where costs are to be
recovered on a regional basis.

The Governors should urge FERC and state Public Utility Commissions
(PUCs) to form joint State/FERC panels to adopt appropriate mechanisms
that will enable cost recovery of transmission investments made before
the RTO structures are fully implemented. Working in conjunction with
the SSG-WI, these panels could drive agreements between state and
federal regulators, transmission developers and their investors that
would provide cost recovery assurances sufficient to induce development
of needed infrastructure. The panels should also explicitly consider the
risks and need for financing incentives.

The Governors should jointly encourage the Internal Revenue Service to
issue permanent regulations that clarify and extend the use of tax
exempt bonds for investment to expand the transmission infrastructure.
Specifically the IRS should be encouraged to make it clear that transfer
of operational control of transmission assets financed with tax-exempt
securities does not constitute a private business use or otherwise
jeopardize the tax-exempt status of those securities.

The Governors should urge the Administration and Congress to approve any
reasonable requests by federal power marketing administrations to
increase their borrowing authority, to allow Congressional
appropriations, or to allow the use of revenue streams for needed
transmission investment.

(WGA, p. 23-24)

**5. [Edison Electric
Institute](http://www.eei.org/industry_issues/energy_infrastructure/transmission/eei_tranmission_principles_5_10.pdf?ObjectID=35619)**

1\. State and federal policy should eliminate regulatory impediments and
provide regulatory certainty, particularly with respect to attractive
returns, incentives, cost allocation and cost recovery, in order to
raise the capital necessary to construct needed, cost-effective
transmission facilities.

2\. Transmission pricing should (a) allow for cost recovery of fixed and
variable costs and a reasonable return on transmission investment, (b)
ensure, to the extent practicable, that cost responsibility follows cost
causation, (c) minimize the potential for cost shifting, (d) permit the
recovery of all prudently incurred transition costs, and (e) promote
efficient siting of new transmission and generation facilities.

1.  3\. Conflicting federal and state regulatory policies can result in
    unrecoverable, trapped costs. FERC and the states must ensure that
    the necessary regulatory mechanisms are in place to allow for the
    full recovery of all prudently incurred costs and the avoidance of
    trapped costs.

    4\. FERC and the states should allow full recovery of all prudently
    incurred costs to design, study, pre-certify, and permit
    transmission facilities. FERC should amend its rules to allow full
    recovery of the prudently-incurred costs of abandoned transmission
    projects.

5\. FERC should allow utilities to include construction work in progress
(CWIP) in rate base (in lieu of AFUDC) as this will encourage
transmission construction through improved cash flow and greater rate
stability.

6\. FERC should allow for accelerated depreciation in ratemaking to
improve financial flexibility, and promote additional transmission
investment.

7\. Where states require purchases of renewable resources that lack
siting flexibility, FERC should allow alternative transmission pricing
and cost recovery approaches to support the building of transmission
facilities to help achieve state renewable resource goals.

**6. [APPA/TAPS Position
Paper](http://www.tapsgroup.org/sitebuildercontent/sitebuilderfiles/030918finalincentives.pdf)**

In any rulemaking to establish transmission rate treatments to promote
investment in the interstate transmission grid, FERC should consider the
following actions to reduce risk and increase certainty in ways that
will benefit both investors and customers.

**1) Allow current recovery of precertification expenses.** In many
jurisdictions, including FERC, costs incurred for new transmission lines
before siting and other regulatory approvals are granted cannot be
currently expensed and recovered in rates. Instead, these costs are held
to be capitalized as part of the project if it goes forward. If the
project does not go forward, recovery of these costs is at risk. This
treatment (i) creates significant uncertainty and risk because of the
controversy that inevitably occurs in siting major transmission
projects; (ii) increases the costs to customers of successful projects
\-- because the carrying costs that result from delayed recovery are
added to project costs; and (iii) adds to construction cash flow
problems. A win-win solution is to permit current recovery in rates of
reasonable and prudent precertifcation expenses for major new
transmission projects. This treatment would shield investors from the
risks associated with required precertification activities and benefit
consumers by reducing the overall cost of the transmission facility.

**2) Allow construction-work-in-progress (CWIP) in rate base.**
Currently, most jurisdictions do not allow utility rates to include a
return on construction funds invested in projects *until* the project
goes into operation. Instead, these costs are carried by the utility and
added to its rate-base, along with the carrying costs incurred during
construction, when the project is put in service. The alternative would
be to allow a *current* return in rates on transmission construction
funds. For investors, CWIP in ratebase will increase the certainty of
recovery and provide significant cash flow to support construction of
needed transmission facilities with less reliance on external sources of
capital. The impact on customers would be to increase rates somewhat in
the early years but reduce them in later years, providing a net benefit
to consumers.

**3) Spread the cost of high voltage, backbone lines across broad
regions.** The present debate over mandatory participant funding is
creating tremendous uncertainty over what the rules of the transmission
game will be and, therefore, is retarding investment. The proponents of
this untested cost-allocation mechanism do not want to build
transmission. Instead, they want to force users to front the costs of
new lines, based on the speculative value of long-term transmission
rights provided in exchange for funding. The value of these rights will
change with each new power plant and line added to the system over time
and so will be very uncertain. Also, mandating participant funding for
the integrated grid will encourage "freeriders" to sit back and wait for
others to fund needed upgrades that will benefit them as well. This
approach is a recipe for delay. It will increase the value of existing
generation and subject everyone to increasing reliability risks. It is
an ineffective solution to the equity problem that arises if costs of
regional facilities are assigned only to the customers of the individual
system where a regional line happens to be located. FERC can resolve
this equity problem and eliminate the uncertainty created by this debate
if it retains the flexibility to assign the costs of major backbone
facilities across all regional load.

**4) Allow "formula" transmission rates.** Transmission costs are
primarily fixed and represent a small portion of a utility's total
costs. Yet FERC transmission rate cases are costly and time consuming.
As a result of these factors, transmission rates may not be kept
current. A solution is to allow "formula" rates, subject to audit by
FERC and customers, so that transmission rates track current costs
accurately -when they increase or decrease. FERC has approved a formula
transmission rate for the American Transmission Company, which was
supported by its customers. When assigning an "A" bond rating to this
company \-- which is unusually high for a brand new company with no
track record \-- the rating agencies have cited this rate mechanism,
which allocates costs to all load, as advocated in above.

**7. [DOE National Grid
Study](http://www.eh.doe.gov/ntgs/gridstudy/MAIN_RECOMMENDATIONS.PDF)**

-   DOE will work with NGA, regional governors' associations, NARUC, and
    other appropriate statebased organizations to promote innovative
    methods for recovering the costs of new transmissionrelated
    investments. These methods should consider situations where rate
    freezes are in effect and also examine incentive regulation
    approaches that reward transmission investments in proportion to the
    improvements they provide to the system.

-   DOE will research and identify performance metrics and evaluate
    designs for performance-based regulation.

-   The Department of Treasury should evaluate tax law changes related
    to electricity modernization. Treasury should review its current
    regulations regarding the application of private use limitations to
    facilities financed with tax exempt bonds in light of dynamics in
    the industry and proceed to update and finalize its regulations.
    This will give greater certainty to public power authorities
    providing open access to their transmission and distribution
    facilities.

-   Entrepreneurial efforts to build merchant transmission lines that
    pose no financial risk to ratepayers and that provide overall system
    benefits should be encouraged.

-   DOE and the Department of Treasury will evaluate whether tax law
    changes may be necessary to provide appropriate treatment for the
    transfer of transmission assets to independent transmission
    companies.

-   DOE will work with NARUC to develop guidance for state regulators
    and utilities on evaluating the risks of investment in innovative
    new technologies that advance public interests. These guidelines
    will help determine when a technology is a reasonable performance
    risk and how to weigh the costs and benefits of using a new versus
    an established technology.

-   The PMAs and TVA should maintain their leadership of demonstration
    efforts to evaluate advanced transmission-related technologies that
    enhance reliability and lower costs to consumers

-   DOE will develop national transmission-technology testing facilities
    that encourage partnering with industry to demonstrate advanced
    technologies in controlled environments. Working with TVA, DOE will
    create an industry cost-shared transmission line testing center at
    DOE's Oak Ridge National Laboratory (with at least a 50% industry
    cost share).

-   DOE will accelerate development and demonstration of its
    technologies, including high-temperature superconductivity, advanced
    conductors, energy storage, real-time system monitoring and control,
    voluntary load reduction technologies and programs, and
    interconnection and integration of distributed energy resources.

-   DOE will work with industry to develop innovative programs that fund
    transmission-related R&D, with special attention to technologies
    that are critical to addressing transmission bottlenecks.

**8. Report to WGA: [Conceptual Plans for Electricity Transmission in
the
West](http://www.westgov.org/wga/initiatives/energy/transmission_rpt.pdf)**

• Transmission pricing and cost recovery should provide incentives for
regionally beneficial expansion and system improvement.

-   Recognizing that decisions on transmission-line construction will
    hinge

on financing mechanisms, the working group identified three broad
approaches to

this pivotal issue:

1\. Spread the costs of new transmission across all users of the
transmission system. Once in place, Regional Transmission Organizations
(RTOs), could be the vehicle through which costs are recovered from all
users.

2\. Provide that a portion of the difference in electricity prices
between two

delivery points (congestion costs) is used for the construction of
transmission to relieve transmission system congestion.

3\. Implement the "open season" model developed for the natural gas
pipeline industry, allowing all transmission users to bid on the
capacity of a new transmission line and provide the capital for its
construction.

**C. Transmission Siting**

**[1. CDEAC Wind Task Force]{.underline}**

**Transmission Siting and Permitting**

The siting and permitting of new transmission can be a very contentious
process. It is argued that siting of interstate transmission lines may
be particularly difficult where there are few benefits to some of the
states along the route. Congress has contemplated proposals to pre-empt
states in the siting of transmission in the belief that only the federal
government has sufficient scope to adequately weigh the costs and
benefits of major transmission expansion.

Western Governors have developed a [Transmission Permitting
Protocol](http://www.westgov.org/wieb/electric/Transmission Protocol/index.htm)
to enable federal, state and provincial permitting agencies to
collaborate in the review of proposed interstate transmission lines. The
WGA Transmission Permitting Protocol has been signed by 12 governors
(AK, AZ, CA, CO, ID, MT, NV, NM, OR, UT, WA, WY) the Premier of Alberta,
and four federal agencies (DOE, DOI, USDA, CEQ). The Protocol has not
yet been tested, as no new interstate transmission lines have been
proposed. Successful implementation of the Protocol will require
political commitment and adequate resources to state agencies to enable
them to participate in the project review teams that would be created
when the Protocol is triggered for a specific interstate transmission
project.

Historically, one of the major challenges to siting new transmission in
many parts of the West has been securing the necessary permits to cross
federal lands. The federal government is the largest land owner in the
West and almost every long distance transmission line in the Western
Interconnection and in Alaska will cross federal lands.

Existing rights-of-way and utility corridors across federal lands
provide excellent opportunities to expand transmission capacity while
minimize visual and environmental impacts. Higher voltage transmission
and new transmission technologies allow greater transfers of power
within the existing transmission footprint. Where possible, such
opportunities to expand transmission capacity in existing rights-of-way
and corridors should be preserved.

Federal law requires the designation of utility corridors across federal
lands. However, Congress has not provided the resources to implement the
law. Designation of corridors across federal lands would help expedite
permitting of transmission needed to achieve 30,000 MW of clean and
diversified generation.

While the designation of corridors will be useful, such designations
must not preclude the expeditious processing of right-of-way
applications across federal lands that fall outside corridors. It is
very difficult to accurately anticipate the location of load growth and
the sites of new generation decades in advance, which is what corridor
designation seeks to achieve. It would be helpful if generation
developers provide information to federal land management agencies and
regional transmission planning processes on the location of potential
generation sites and potential markets as soon as possible and not wait
until a formal project application is submitted.

[Recommendation: Transmission Permitting]{.underline}

-   Western Governors should ensure that there are resources and the
    political commitment to successfully implement the WGA Transmission
    Permitting Protocol for new interstate transmission proposals.

-   Congress should provide resources to federal land management
    agencies to: (1) adequately catalogue existing rights-of-way and
    corridors across federal land, including any opportunities to expand
    the transmission capabilities within existing rights-of-way and
    corridors; (2) manage existing rights-of-way to prevent unintended
    consequences of land use decisions that would limit the expansion of
    transmission capacity; (3) evaluate and designate transmission
    corridors; and (4) expeditiously decide on right-of-way applications
    that may fall outside of designated corridors. In the analysis of
    opportunities to expand transmission capabilities in existing
    rights-of-way and corridors, federal land management agencies, with
    the assistance of the Department of Energy, should consider new
    transmission technologies.

-   As soon as possible, and well before specific project applications,
    developers of clean and diversified energy resources should inform
    regional transmission planning processes and federal land management
    agencies of the location of potential generation sites and potential
    markets.

-   Promote funding to enable federal and state agencies to collectively
    and adequately; (1) catalogue existing rights-of-way and corridors
    across the West, including any opportunities to expand the
    transmission capabilities within existing rights-of-way and
    corridors; (2) manage existing rights-of-way to prevent unintended
    consequences of land use decisions that would limit the expansion of
    transmission capacity; (3) develop a planning mechanism to compile
    reliable transparent data and utilize modeling tools to evaluate the
    costs and benefits on new transmission; (4) evaluate and designate
    transmission corridors; and (5) expeditiously decide on right-of-way
    applications that may fall outside of designated corridors.

**[2.]{.underline} [Keystone
Dialogue](http://www.electricity.doe.gov/documents/regional_transmission_project.pdf)**

**Recommendation 2a:** The siting process should be inclusive and
credible so that it

meets the needs of all stakeholders. This should be accomplished through
outreach,

education, and public participation initiatives. (Keystone p. 5)

**Recommendation 2b:** To better inform the overall siting process,
siting should be

considered within the technical planning process. (Keystone p.5)

**Recommendation 2c:** An improved, coordinated, and more efficient
siting

process should be created for consideration by policy-makers on
multi-state

transmission projects. Because there may be no consensus solution for
all regions of the

country, a range of models for implementation is offered. (Keystone p.5)

**Recommendation 2d:** In regions of the country where it is feasible, a
corridor

identification process should be developed, together with a permit
pre-filing process for

transmission facilities located within such corridors. (Keystone p.6)

**3.
[NARUC](http://www.naruc.org/displaycommon.cfm?an=1&subarticlenbr=29)
National Electricity Policy**

States should retain authority to site electric facilities, while
Congress should support the States\' authority to negotiate and enter
into cooperative agreements or compacts with federal agencies and other
States to facilitate the siting and construction of electric
transmission facilities as well as to consider alternative solutions to
such facilities, such as distributed generation and energy efficiency.

**4. [Edison Electric
Institute](http://www.eei.org/industry_issues/energy_infrastructure/transmission/eei_tranmission_principles_5_10.pdf?ObjectID=35619)**

Regional State Committees (RSCs) should assist in coordinating state
siting activities through the use of standardized applications, joint
data and studies, coordinated schedules and deadlines, and other
mechanisms, where possible.

Regardless of whether there is an RSC in their region, states should
streamline their transmission line siting processes and take regional
considerations into account as appropriate.

FERC should have backstop siting authority if states cannot or will not
act on applications to build transmission to relieve critical
transmission bottlenecks and the Department of Energy (DOE) should act
as lead agency to coordinate all authorizations and environmental
reviews required under federal law to site transmission facilities on
federal lands and to set deadlines for federal reviews.

**5. [DOE National Grid
Study](http://www.eh.doe.gov/ntgs/gridstudy/MAIN_RECOMMENDATIONS.PDF)**

-   FERC and DOE should work with states, pertinent federal agencies,
    and Native American tribes to form cooperative regional transmission
    siting forums to develop regional siting protocols.

-   Utilities and state utility commissions should develop an inventory
    of underutilized rights of way and space on existing transmission
    towers. DOE will work with PMAs and TVA to conduct a comparable
    evaluation.

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-   DOE will work with NGA, regional governors' associations, NARUC, and
    other appropriate statebased organizations to develop a list of
    "best practices" for transmission siting.

-   DOE will undertake demonstration programs to support the use of
    innovative approaches to transmission planning and siting (e.g.,
    open planning processes, consideration of a wide range of
    alternatives, incorporation of innovative or uncommonly employed
    technologies, use of alternative mitigation measures, etc.).

-   Federal agencies should be required to participate in regional
    siting forums and meet these forums' deadlines for reviews or
    complete reviews within 18 months, whichever occurs first.

-   All federal agencies with land management responsibilities or
    responsibilities for oversight of non-federal lands should assist
    FERC-approved RTOs in the development of transmission plans.

-   Congress should grant FERC limited federal siting authority that
    could only be used when national-interest transmission bottlenecks
    are in jeopardy of not being addressed and where regional bodies
    have determined that a transmission facility is preferred among all
    possible alternatives.

-   The Council on Environmental Quality should continue to coordinate
    efforts with the Secretary of the Interior, Secretary of Energy,
    Secretary of Agriculture, Secretary of Defense, and Administrator of
    the EPA to ensure that federal permits to construct or modify
    facilities on federal lands are acted upon according to timelines
    agreed to in any FERC-approved regional protocol. The agencies
    should work together to re-evaluate the development of transmission
    corridors across federal lands and identify the current and
    potential future use of existing transmission corridors on federal
    lands.

**6. Report to WGA: [Conceptual Plans for Electricity Transmission in
the
West](http://www.westgov.org/wga/initiatives/energy/transmission_rpt.pdf)**

-   All siting review processes must be streamlined and coordinated to
    enable the timely construction of transmission. State review
    processes should address both local and Western Interconnection
    needs, and federal agency review processes must be coordinated
    internally as well

[^1]: CDEAC Wind Task Force, Draft Report 7-15-05.

[^2]: That is, high value power sales (that would lower overall variably
    electricity production costs) would be bumped off the system during
    times of transmission congestion in favor of lower value power sales
    that happen to own rights to use the transmission system at the time
    of congestion.

[^3]: In the Eastern Interconnection, schedules are generally allowed up
    to the thermal limit of the line. When reductions are required
    because moving all the scheduled power over a line would threaten
    reliability, a Transmission Loading Relief (TLR) order is issued and
    schedules are curtailed on a pro rata basis without regard to which
    transactions are of greater value

[^4]: Such processes in the WGA region include: the Seams Steering
    Group-Western Interconnection, Southwest Transmission Expansion
    Project; Southwest Area Transmission study; Rocky Mountain Area
    Transmission Study; Northwest Transmission Assessment Committee;
    Colorado Coordinated Planning Group; and Midwest ISO.

[^5]: The Keystone Center, "Expanding Regional Electricity Transmission:
    Finding Solutions," May 2005.

[^6]: Standardization of Generator Interconnection Agreements and
    Procedures, 104 FERC ¶ 61,103 (2003) ("Order 2003").

[^7]: Order on Complaint and the Proposed Amendments to the NEPOOL
    Tariff and the Restated NEPOOL Agreement, 105 FERC ¶ 61,300 (2003)
    (Docket No. ER03-1141-03) The New England Power Pool (NEPOOL) and
    the New England ISO adopted a default cost allocation mechanism that
    socializes transmission costs where beneficiaries could not be
    clearly identified and upgrades produce regional benefits.
    Transmission facilities rated 115kV and higher are eligible for
    regional cost support and this covers approximately 95% of the
    existing pool of transmission facilities in New England. The New
    England policy calls for participant funding for elective upgrades,
    upgrades for generator interconnections, merchant transmission
    facilities, and local upgrades.

[^8]: See Texas Public Utility Regulation Act, §35.004 (Texas statute on
    the socialization of transmission costs in ERCOT)
    ([www.puc.state.tx.us/rules/statutes/Para03.pdf](http://www.puc.state.tx.us/rules/statutes/Para03.pdf));
    and Texas PUC Substantive Rule 25.195(c), which is a generation
    interconnection rule with cost allocation based on a
    highway/driveway model. (Generators are responsible for facility
    costs from the generator to the interconnection (driveway).
    Transmission owners are responsible for all other costs for upgrades
    necessary to accommodate the requested transmission service
    (highway))
    ([www.puc.state.tx.us/rules/subrules/electric/](http://www.puc.state.tx.us/rules/subrules/electric/)25.195/25.195.pdf)

[^9]: As noted above, the transmission planning efforts include the
    Seams Steering Group-Western Interconnection (SSG-WI) (regional);
    the Southwest Area Transmission (SWAT); Southwest Transmission
    Expansion Plan (STEP); Rocky Mountain Area Transmission Study
    (RMATS); and the Northwest Transmission Area Committee (NTAC).

[^10]: On July 1, 2005, FERC issued a split decision that rejected the
    renewable trunkline features of the SCE proposal but accepted cost
    recovery features of 2 of the 3 proposed transmission system
    upgrades. The majority rejected the trunkline feature on grounds
    that it was contrary to FERC policy on generation interconnection
    policies and that SCE did not establish system-wide benefits to all
    consumers of the transmission system.