Montana. Dept. of Environmental Quality.

Understanding electricity in Montana : a guide to electricity, natural gas and coal produced and consumed in Montana (Volume 2002) online

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Oregon 1

Energy Northwest Inc^


Fall River Rural Elec Coop Inc






Fergus Electric Coop Inc


Flathead Electric Coop Inc


Glacier Electric Coop Inc


Goldenwest Electric Coop Inc


North Dakota


Grand Electnc Coop Inc


South Dakota


Hill County Electric Coop Inc


Lincoln Electric Coop Inc


Lower Yellowstone R E A Inc


North Dakota


Marias River Electric Coop Inc


McCone Electric Coop Inc


McKenzie Electnc Coop Inc


North Dakota


MDU Resources Group, Inc


North Dakota




South Dakota 6

Mid-Yellowstone Elec Coop Inc


Missoula Electric Coop Inc




Montana Power Co^




Northern Electric Coop Inc


Northern Lights Inc





Park Electric Coop Inc


Powder River Energy Corp




Ravalli County Elec Coop Inc


Sheridan Electric Coop Inc


North Dakota


Southeast Electric Coop Inc


South Dakota




Sun River Electric Coop Inc


Tongue River Electric Coop Inc


Troy City of


USBIA-Mission Valley Power


Valley Electric Coop Inc


Vigilante Electric Coop Inc




Western Area Power Admin





Others 1 1

Yellowstone Valley Elec Coop Inc


* Less than 0.5 percent.

' Formerly known as Washington Water Power.

^ Formerly part of PacifiCorp; incorporated into Flathead Electric Cooperative in 2001.

^ Became Northwestern Energy in 2002.

Source: U.S. Department of Energy, Energy Information Administration, Electric Sales and Revenue 1999, EIA-0540.




Not Regulated By The Public Service Commission

electricirv distribition utilities
Regulated by the Pi blic Service Commission

Scobe yl

» Towns served by a regulated utility
J KorthWestem Energy

Montana-Dakota Utilities

NOTE; These udliiies provide electricity lo towns and varying amounts of the surrounding areas Their service areas
arc not necessarily continuous tovm to town. Tlic depictions of service areas in this map arc for illustrative
purposes only and may include some areas served by rural electric cooperatives


Chapter 2: Montana Electric Transmission
Grid: Operation, Congestion and Issues

The transmission grid serves the vital function of moving power from many different generating
plants to customers and their electric loads. However, it does more than that: it provides
service robustly and reliably even though individual elements of the transmission grid may be
knocked out of service or taken out of service for maintenance. This paper describes how the
transmission grid developed; how it works in terms of physics and how it is managed
commercially; and how reliability is ensured. It discusses the ownership and rights to use the
system; the extent of congestion and how it is managed; and how management would be
changed under the proposed RTO West. Finally, it discusses several issues involved in the
construction of new transmission lines to expand the capacity of the grid.

I. Historical Development of Transmission in Montana

The transmission network in Montana, as in most places, developed over time as a result of
local decisions in response to growing demand for power and decisions on where to build
generation. The earliest power plants in Montana were small hydro generators and coal-fired
steam plants, built at the end of the nineteenth century to sen/e local needs for lighting, power
and streetcars. The earliest long distance transmission lines were built from the Madison plant,
near Ennis, to Butte and from Great Falls to Anaconda. The latter was at the time of
construction the longest high voltage (100 kilovolt— kV) transmission line in the country.

As the Montana Power Company (MPC— now Northwestern Energy) system, and coop loads
dependent on MFC's system for delivery grew, MPC expanded its network to include 161 kV and
ultimately a 230 kV backbone. Long distance interconnections did not develop until World War

II. During the war the 161 kV Grace line was built from Anaconda south to Idaho. Later, BPA
extended its high voltage system into the Flathead Valley to interconnect with Hungry Horse
Dam and to serve the aluminum plant at Columbia Falls.

Montana's strongest interconnections with other regions are now the 500 kV lines from Colstrip
to Spokane, the BPA 230 kV lines heading west from Hot Springs, PacifiCorp's interconnection
from Yellowtail Dam south to Wyoming, WAPA's DC tie to the east at Miles City, and the AMPS
line running south from Anaconda parallel to the Grace line to Idaho.


Figure ETl. The Montana transmission network

Electric Transmission Lines of Montana

Transmission Line Voltage (kV)

- -61

■ ?30

■ 500
July 2002 fevision


-^ 115

As U.S. and Canadian utilities have grown and increasingly depended on each other for support
and reliability, the North American transmission network has developed into two major
interconnected grids, divided roughly along a line that runs through eastern Montana south to
west Texas. The western United States is a single, interconnected and synchronous electric
system (see next page). Most of the eastern United States is a single, interconnected and
synchronous electric system. Texas and Quebec are exceptions; Texas is considered a separate
interconnection with its own reliability council, ERCOT.

The interconnections are not synchronous with each other. Each interconnection is internally in
synch at 60 cycles per second, but each system is out of synch with the other systems. They
cannot be directly connected because there would be massive instantaneous flows across any
such connection. Therefore they are only weakly tied to each other with AC/DC/ AC converter
stations. One such station is located at Miles City. It is capable of transferring up to 200 MW in
either direction. Depending on transmission constraints, a limited amount of additional power
can be moved from one grid to the other by shifting units at Fort Peck Dam. By contrast, this
transfer capacity is about one tenth the peak load in Montana, which is one of the smaller loads
in the West.


There are currently three DC converter stations between the western and eastern grids with a
combined capacity of 510 MW. Three more are planned or under construction at Lamar, in
eastern Colorado, Rapid City, and Miles City. There are also two converter stations with a
combined capacity of 420 MW linking the Western Interconnection with ERCOT. The peak load
of the Western Interconnection, by comparison, was around 131,000 MW in 2000.

Figure ET2. The Western Interconnection transmission network

Most of Montana is integrally tied into the Western electrical grid. However the easternmost
part of the state, with around 5 percent of total Montana load, is part of the Eastern
Interconnection and receives its power from generators in that grid.

2. How The Transmission System Works

There are big differences between the way the transmission system operates and is managed
physically, and the way it is operated commercially. The flows of power on the transmission
network follow certain physical laws. Transactions to ship power across the grid follow a
different and not fully compatible set of rules.

Phvsical operation: The transmission grid is sometimes described as an interstate highway
system for electricity, but the flow of power on a grid differs in very significant ways from the


flow of most other physical commodities. First, when power Is sent from one point to a distant
location on the transmission grid, the power will flow over all connected paths on the network.
It will distribute itself so that the greatest portions flow over the paths of lowest resistance
("impedance," in alternating current circuits), and it generally cannot be constrained to any
particular path or contract path. For example, power sent from Colstrip to Los Angeles will flow
mostly west to Oregon and Washington and then south to California. But portions will flow
south via Garrison into Idaho, and even southeast from Colstrip into Wyoming and then south
to Arizona before continuing to Los Angeles.

A second way in which power flows differently than other commodities is that flows in opposite
directions net against each other. If traffic is congested in both directions on an interstate
highway it will come to a halt in all lanes and not a single additional vehicle will be able to enter
the flow. By contrast, if 100 MW were shipped westbound on a transmission line from point A
to point B, and 25 MW were sent simultaneously eastbound from point B to point A, the actual
measured flow on the line would be 75 MW in a westbound direction. If 100 MW were sent in
each direction the net measured flow would be zero. If power were shipped simultaneously in
opposite directions at the full capacity of a transmission line, the net flow would be zero, and
additional power still could flow in either direction up to the full capacity of the line.

As a consequence of the above factors, the actual flows on the network are the net result of all
generators and all loads on the network. In any real transmission network there are many
generators located at hundreds of different points on the network, and many loads of varying
sizes located at thousands of different locations. Because of netting, regardless of where power
is sent or from where it is purchased, path loadings will depend only on the amounts and
locations of electric generation and load.

Management of the grid . In contrast with the physical reality of the transmission network,
management of transmission flows has historically been by use of a "contract path": A
transaction shipping power between two points will be allowed if space has been purchased on
any path connecting the two points, from the utilities owning the wires (or the rights to use
those wires, if they are transferable) along that path. Transactions are deemed to flow on the
contract path. Portions that flow on other paths are termed "inadvertent flows" or "unscheduled

For example, power sent from Colstrip to the West Coast uses a contract path along the 500 kV
lines through Garrison and Taft, then across the West of Hatwai path into western Washington
and Oregon. However somewhere between 15 and 20 percent of the power actually flows south
across two other paths, the Yellowtail-South path and the Montana-Idaho path south from

The topology of the western grid is such that major inadvertent flows occur around the entire
interconnection. Power sent from the Northwest to California flows in part clockwise through
Utah and Colorado into New Mexico and Arizona and then west to California. Conversely, a
portion of power sent from Arizona to California flows counterclockwise through Utah, Montana
and Idaho, then west to Washington and Oregon, and then south into California. These major
inadvertent flows are called "loop flow." Expensive devices ("phase shifters") have been


installed at several locations to control loop flow and to limit its effect on owners of affected
portions of the grid.

Owners of rights or contracts on contract paths are allowed to schedule transactions as long as
the total schedules do not exceed the path ratings. Scheduling against reverse flows is not
allowed, despite their netting properties, because the capacity created by reverse schedules is
not deemed to be firm. (If the flow scheduled in one direction was reduced at the last minute,
capacity to carry power in the opposite direction would automatically go down by the same

Inadvertent flows may interfere with the ability of path owners to make full use of their rights.
The Western Electricity Coordinating Council (WECC) Unscheduled Flow Reduction Procedure
requires utilities whose wires are affected by inadvertent flows to first accept flows up to the
greater of 50 MW or 5 percent of the path rating by curtailing their own schedules. If further
reductions are necessary the path owners can request the operation of phase shifters (to block
loop flows) or curtailments of schedules across other paths that affect their ability to use their
own path. Phase shifters are limited to operation no more than 2000 hours per year, because
they have limited lifetimes and are degraded by use.

The shift to management of the grid by an RTO (discussed below) will do away with the use of
the contract path, and with it, the necessity for special management of inadvertent flows.

If the scheduled flows do not exhaust the path rating, the unused capacity may be released as
non-firm transmission capacity. This capacity cannot be purchased in advance; it can be
scheduled only at the last hour. Owners of capacity who do not plan to use it could release it
earlier, but often are reluctant to do so because of their own needs for flexibility or a desire to
withhold access by competitors to their markets.

3. Grid Capacity and Reliability

The amount of power a transmission line can carry is limited by several factors. A major factor
is its thermal limit. When flows get high enough the wire heats up and stretches, eventually
sagging too close to the ground and arcing. Other factors relate to inductive and capacitative
characteristics of AC networks. (Inductive characteristics are associated with magnetic fields
that are constantly expanding and contracting in AC circuits wherever there are coils of wire
such as transformers. Capacitative characteristics are associated with electric flows induced in
wires that are parallel to each other, such as long transmission lines.) But the most important
factor, indeed the limiting factor, is reliability. The transmission network is composed of
thousands of elements that are subject to random failure, caused by such things as lightning
strikes, ice burdens, pole collapse, trees falling on conductors and vandalism. Since customers
value reliability and can be greatly harmed by loss of power, reliability of the grid is assured by
building redundancy into it. The grid is designed to withstand the loss of key elements and still
provide uninterrupted service to customers. Service is provided by the network, not by
individual transmission lines. Reliability concerns limit the amount of power that can be carried
to the amount of load that can be served with key elements out of sen/ice.


Two examples will show how this applies. Within Montana Power's service area the reliability of
the transmission system is evaluated by computer simulation of the network at future load and
generation levels, taking individual elements out of service and determining whether all loads
can be served with voltage levels and frequencies within acceptable ranges. If acceptable limits
are violated, the network must be expanded and strengthened. Typically this means adding
transmission lines or rebuilding existing ones to higher capacities. Identical procedures are used
by other utilities and by regional transmission and reliability organizations.

The second example relates to major transmission paths used to serve distant load or to make
wholesale transactions. Paths are bundles of related transmission lines that carry power
between the same general areas. Most major paths are rated in terms of the amount of power
they can carry, based on their strongest element being unavailable. (In some cases the
reliability criteria require the ability to withstand two or more elements out of service.) For
example, the Colstrip 500 kV lines are a double circuit line, but they cannot reliably carry power
up to their thermal limit because one circuit may be out of service. Recently there has been a
move by the Western Electricity Coordinating Council, which is the reliability council for the
Western Interconnection, to require the paths of which the Colstrip lines are a part to model
both circuits out of service, because of the possibility of a tower collapse.

Figure ET3. Rated paths on the transmission network


The paths through Montana toward the west have been rated and are limited generally to 2200
MW east to west. The West of Hatwai path, which is comprised of a number of related lines
west of the Spokane area, is rated at 2800 MW.

4. Ownership and Rights To Use The Transmission System

Rights to use the transmission system are generally held by the owners or by holders of long-
term contract rights. Rights to use rated paths have been allocated among the owners of the
transmission lines that comprise the paths. In addition the owners have committed to a variety
of contractual arrangements to ship power for other parties. Scheduled power flows are not
allowed to exceed the path ratings.

FERC Order 888, issued in April 1996, required that transmission owners functionally separate
their transmission operations to make them independent of their power marketing operations.
They must allow other parties to use their systems under the same terms and conditions as
their own marketing arms. They must maintain a web site ("Open Access Same Time
Information System," or OASIS) on which available capacity is posted.

Available transmission capacity (ATC) is calculated by subtracting committed uses and existing
contracts from total rated transfer capacity. Little or no ATC is available on most major rated
paths, including those leading west from Montana to the West Coast. The rights to use the
capacity are fully allocated and closely held. None is available for purchase by new market

These existing rights - and ATC, if any were available - are rights to transfer power on a firm
basis every hour of the year. The owners of the rights on rated paths may or may not actually
schedule power in even/ hour, and when they don't, the space they are not using may be
available on a non-firm basis. In fact, the paths are fully scheduled for only a small portion of
the year, and non-firm space is almost always available. For example, according to MFC, in the
12 months through September 2001, the West of Hatwai path was fully scheduled or over-
scheduled about 8 percent of the time. The remainder of the time, 92 percent of the year, non-
firm access was available.

However, non-firm access cannot be scheduled in advance or guaranteed. It is a workable way
to market excess power for existing generators. It may be a reasonable way to make firm
power transactions if backup arrangements can be made to cover the contracts in the event the
non-firm space turns out to be unavailable. However it may be difficult to finance new
generation if it cannot be shown with certainty that the power can be moved to market.

5. Congestion

A transmission path may be described as congested if no rights to use it are for sale.
Alternately, congestion could mean that it is fully scheduled and no firm space is available. Or it
could mean that the path is fully loaded. These are three different concepts.


By the first definition, the paths west of Montana are congested - no rights are available and
no ATC is offered for sale on the OASIS.

By the second definition, the paths are congested a few hours of the year - the rights holders
fully use their scheduling rights a fraction of the time, and the rest of the time they use only
portions of their rights. From October 2000 through September 2001, the West of Hatwai path
was congested under this definition around 8 percent of the time.

The third definition is based on actual loadings. Actual loadings are different than scheduled
flows because of the difference between the physics and the management of the grid -
schedules are contract-path-based, and actual loadings are net-flow-based. Actual flows on the
paths west of Montana are almost always below scheduled flows, because of the net impacts of
inadvertent flows and loop flows. Actual hourly loadings on the West of Hatwai path are posted
on BPA's OASIS site. Figure 4, below, shows that the first eight months of 2001, highest actual
loadings were around 90 percent of the path capacity for only a few hours. For most hours the
path was not heavily loaded. By the third definition, the lines currently are never congested -
even when the lines are fully scheduled, the net flows are below path ratings.

Figure ET4. West of Hatwai path cumulative loading curve Jan-Aug 2001

(Negative flows mean power was flowing from west to east)

West of Hatwai Jan -August 2001 EW Cumulative Loading Curve





1 1

-0 4

-0 6




Portion of lime


6. Grid Management By RTO West

Discussions have been underway for several years among the transmission owners and other
stakeholders in the Northwest to have an independent body take over operation and control of
access for the transmission system. This was partly out of a recognition by the transmission
owners that proof of independence, as required by FERC Order 888, would become an
increasingly difficult burden, and partly out of anticipation that FERC would ultimately move to
order such a transfer. Initial discussion revolved around IndeGO, a proposed independent
system operator that would lease and operate the wires. The IndeGO discussions ultimately
foundered on cost-shifting concerns, but after FERC issued Order 2000 the discussions revived,
focusing now on a Regional Transmission Organization (RTO) that would operate the system
under a contractual Transmission Operating Agreement (TOA) with the participating
transmission owning utilities.

Assumption of responsibility for grid management by RTO West is important because for the
first time it would provide for a market-driven means of managing congestion. The current fixed
assignment of rights to use the grid prevents non-incumbents from making use of unused
capacity, and even hinders their ability to bid for it. The RTO would allow all parties to signal
their willingness to pay for access and to make efficient use of the grid. In addition the RTO
management would result in congestion price signals that would allow economic decisions on
location of new generation and on expansion of capacity on congested transmission paths. RTO
West made its filing with FERC on March 29, 2002. Details of the filing can be found at

7. Major Issues of Transmission

There are a number of issues affecting the transmission system and the need for and ability to
complete new transmission projects. These include the downgrading of capacity for reliability
reasons; the way reliability criteria are set; the limited number of hours the system is
congested; the problems involved in siting high voltage transmission lines; the cost of new
capacity; making the commitment for new capacity; and the alternatives for financing new
transmission discussed in the Western Governors Association Transmission Study.

Availability of Existing Capacitv. A considerable amount of existing capacity is not available for
use because it is held off the table for reliability reasons when paths are rated. (See discussion
of reliability issues, below.) Transmission owners may withhold capacity because of uncertainty,
the need for flexibility and in some cases, a desire to protect their markets.

Uncertainty affects the transmission needs of utilities because they don't know in advance what
hourly loads will be or which generating units may be unavailable.

The need for flexibility affects transmission needs because utilities want the right to purchase
power to serve their loads from the cheapest source at any given time. When RTO West tried
to convert existing contract rights into flow based rights the claims greatly exceeded available
capacity. This was largely due to utilities that had a right, for example, to move 100 MW on any
of several paths, claiming a simultaneous right of 100 MW on all of them.


Withholding of capacity for market protection is a violation of Order 888. Withholding has been
a problem since the order was issued, with a number of utilities around the country being cited

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