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

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and fined by FERC for violations. The failure of Order 888 to result in open and comparable
access was a major reason for FERC Order 2000, which requires utilities to form RTOs.

Reliability Criteria. Reliability is an issue because the criteria governing the setting of path
capacity and the operation and expansion of the transmission system relate only vaguely to
economics. They do not reflect very well the probability or the consequences of the events
being protected against. Since the system is quite reliable as currently built and operated,
reliability concerns generally focus on very low probability events that may, depending on when
they occur, have high costs. The criteria apply everywhere on the transmission grid despite the
fact that in some areas and on some paths the consequences may be minimal while in other
areas and other paths the same type of event may have large consequences. For example. Path
15 in central California or the Jim Bridger West path in Idaho, where a line outage can result in
cascading failure and impact many millions of people, should probably be operated more
stringently than parts of the transmission grid where an outage might cause a generating unit
to trip off, but not affect any load.

Reliability criteria for the Western Interconnection are set by the Western Electricity
Coordinating Council (WECC), which is part of the National Electric Reliability Council (NERC).
The Western Electricity Coordinating Council was recently formed from a merger of the Western
Systems Coordinating Council (WSCC) with several other transmission organizations.

WSCC was largely a creature of the transmission owning utilities. It historically was
unsympathetic to applying cost-benefit considerations to the reliability criteria, although it
recently convened a group to develop probablistic criteria that will likely be sensitive to
economic concerns.

WSCC, at times, may have tightened reliability standards to increase reliability without regard
to the impacts of its decisions. For example in 2001, WSCC set a 1000 foot separation rule for
new transmission lines, precluding the use of existing corridors and rights of way for siting new
lines adjacent to existing ones. In areas where siting opportunities are limited such a move may
greatly increase the difficulty of building additional capacity.

WECC will have much broader representation on its board than the WSCC did, and will have
stakeholder advisory committees.

Limited Hours of Congestion . As discussed above, the congested portions of the transmission
grid tend to be fully or heavily scheduled and loaded only a few hours to a few hundred hours
of the year. The rest of the time excess capacity is available, although it is a challenge to make
use of it on a firm basis. Expanding capacity is expensive and difficult. Yet it has been the
preferred method of gaining access for additional transactions and additional flows. If the costs
could be assigned to the congested hours only it is very likely cheaper alternatives to new
construction would be found. For example, some current users with relatively low valued
transactions or with ready alternatives might be willing, at some price, to sell their rights to
new users.


Siting. High voltage transmission lines can be difficult and contentious to site, especially in
forested, mountainous or populous areas. For example, the Colstrip double circuit 500 kV lines
were relatively easy to site in eastern Montana where they traversed rolling agricultural and
grazing land. Siting in western Montana was a different story, particularly in the areas of
Boulder, Rock Creek and Missoula. The resulting route had to stay away from the interstate
highway corridor, instead opening new corridors through forested areas with issues such as
impacts to elk security areas and increased access. Lengthy detours around Boulder and
Missoula added considerably to the cost of the line. Rural growth and residential construction in
western Montana since the Colstrip lines were sited in the early 1980s, combined with the
already limited siting opportunities due to wilderness areas and Glacier National Park, can be
expected to make siting challenges likely for additional construction.

Further, the recent proposed changes in WECC criteria, mentioned above, have increased the
likelihood that new lines would have to open additional corridors instead of making use of
existing corridors.

Cost. High voltage transmission lines are expensive to build. A typical single-circuit 500 kV line
may run over $1 million per mile. A double-circuit 500 kV line may cost around $1.5 to $1.75
million per mile. 500 kV substations cost around $50 million each, depending on the complexity
caused by their location on the network. If series compensation is required, 500 kV substations
may cost up to $100 million. 230 kV lines are somewhat cheaper - about half the cost per mile
of 500 kV lines, and substation costs run around $25-30 million each. DC lines are a bit cheaper
but the equipment required to convert alternating current to direct current and back is
extremely expensive, so this technology is generally used only for very long distance
transmission with no intermediate interconnections. At present there are only two DC lines in
the Western Interconnection - the Pacific DC Intertie, from Celilo in southern Oregon to Sylmar
near Los Angeles, and the IPP line from the Intermountain Power Project generating station in
Utah to the Adelanto substation, also near Los Angeles. Neither line has any intermediate

Capacity for New Generation in Montana. There is considerable interest in Montana in building
in-state energy facilities as an economic development tool. The lack of available transmission
capacity to reach west coast markets may be a significant barrier. As discussed above, there is
a considerable amount of unused capacity on the existing transmission network for a large part
of the time, but it is not available on a firm basis. Changes in the way the transmission system
is managed could make this space available, and could support some modest increase in new
generation in the state. Significant additional generation would require new transmission

There is a "chicken and egg" problem in developing new transmission to facilitate economic
development. If no capacity is available to reach markets, generation developers may have a
difficult time financing their projects. Yet without financing, they probably can't make the firm
commitments for transmission sen/ices that would encourage utilities to invest on their own in
transmission capacity for new projects. The alternative approaches, where the generation
developers build needed new capacity or where new merchant transmission capacity is built in
the hopes new generation will appear, still need to convince the financial markets that the


transmission project is viable. In any event, the regulatory structure requires a showing of need
for new transmission projects that may be difficult to make without firm commitments from
generators. Of course, the regulatory requirements can be changed to accommodate economic
development as a basis of need. Eminent domain is another matter. Eminent domain seizures
could be at risk of court challenges if a landowner were to convince the court the public
purposes of the line were speculative.

The issues confronting merchant plants are different than those faced under traditional utility
procedures, where generation and transmission were planned, financed and built together.
Generation developers either must absorb the risk of building new transmission capacity or
convince some other party to absorb the risk for them.

Western Governors Association Transmission Study. In the spring of 2001 the WGA asked the
utility industry and the Committee for Regional Electric Power Cooperation (CREPC— an
organization of western states' public service commissions and energy offices) to study the
need for new transmission in the Western United States. A working group of experts modeled
the transmission grid and the likely growth of demand and new generation, and concluded that
little new transmission (somewhere less than $2 billion over a 10 year period) would be needed
beyond that already planned or under construction. This was a result of mostly natural-gas-
fired new generation planned for locations close to loads or well serA/ed by existing transmission
capacity. At the request of the Governors the group also studied a "fuel diversity" scenario in
which half of new capacity was coal-fired generation or wind generation. This scenario resulted
in a need for approximately $12 billion in new transmission capacity, including construction in
Montana of a new 500 kV line to the West Coast and a new 500 kV line to Alberta.

The Western Governors Association then requested a study of how to finance new transmission
lines, and the resulting report discussed two alternative proposals. The first was an "interstate
highway" model in which all electric customers in the west would share in the costs of all
transmission in the west, regardless of use. This model envisioned transmission expansion to
eliminate most or all congestion. The second is a model in which the beneficiary pays: regional
financing of reliability improvements, utility financing of load sen/ice improvements, and
generation and customer financing of capacity expansions to eliminate congestion.

Each approach has advantages and disadvantages. The interstate highway model would avoid
the need to determine the relative merits of different possible lines and simply eliminate all
congestion. It would make a great deal more capacity available and could encourage the
development of resources in places previously difficult to build. For Montana, it would make it
easier to develop coal and wind resources. On the other hand, it would require agreement by
all states and all utilities to spread the costs to all ratepayers. There is no existing agency with
the authority to require such spreading and there is unlikely to be universal agreement to
spread these costs without such an agency. The interstate highway approach could also result
in overbuilding the transmission system, for example to alleviate congestion that may be
minimal or that could be more cheaply addressed in other ways.

The "beneficiary pays" model is currently implementable and reflects the way transmission is
currently financed for certain types of lines, such as lines needed for reliability and lines needed


to serve growing utility loads. It results in a closer correspondence of benefits and costs than
the interstate highway approach, and could make siting easier by reducing controversies over
need. On the other hand, if future benefits are uncertain it could make financing difficult, and it
would not provide the benefits to Montana coal and wind developers unless they were willing to
pay the costs of needed transmission. Further, proponents of the interstate highway model are
skeptical that the beneficiary pays model will result in the timely construction of new
transmission capacity.


Chapter 3: Natural Gas in Montana:
Current Trends, Forecasts and the
Connection with Electric Generation

Many of the electricity generation plants proposed for Montana are planning to use natural gas.
At the same time, natural gas is a major source of energy for Montana's homes and industries.
This paper lays out the history and current trends in natural gas use in Montana. These are set
in the context of the U.S. natural gas industry. Montana is part of a continental gas market, with
prices and availability set more by events outside than inside Montana. As electricity generation
around the country comes to rely more on natural gas, the price and availability of gas are
already moving in ways Montanans have not previously experienced.

1. Natural Gas Supplies for Montana and the U.S.

Alberta is by far the largest source of natural gas for Montana. The next largest source is in-
state wells mostly located in the north-central portion of the state. Supplies from the other
Rocky Mountain states represent only a small portion of total in-state usage and continue to
decline from historic levels.

Future changes in supplies from in-state development and other states are uncertain at this
point. Coal bed methane (CBM) may eventually increase the portion of gas that comes from the
Rocky Mountain states, especially Colorado and Wyoming, but the peak of that production is still
a few years off. CBM development in Montana has not yet become significant, due in part to
difficult environmental issues, and is still in the permitting stage. The future extraction of
existing gas reserves along Montana's Rocky Mountain Front also is uncertain at this point.
Alberta's natural gas supply will likely remain the largest source for Montana in the years to

Montana actually produces about as much gas as it consumes, but the bulk of that is exported.
In 1999, Montana produced 61.6 billion cubic feet (bcf) and exported 51.8 bcf total to North
Dakota, South Dakota and the Midwest. The north-central portion of the state accounted for 80
percent of Montana's production, and the northeastern portion of the state another 11 percent
(MBOGC 2001). In-state production has been increasing in recent years (Figure NGl, below).
Because most of it is exported, however, increases or decreases in natural gas production in
Montana may have little impact on Montana consumers.

U.S. natural gas supplies are largely domestic, supplemented by substantial imports from
Canada. About half of U.S. reserves are in Texas, Louisiana and offshore in the Gulf of Mexico.
About a quarter are in the Rocky Mountain states of New Mexico, Wyoming, and Colorado. The
Rocky Mountain states are the most important source of domestic natural gas supply to the
Pacific Northwest. Alaska's North Slope is potentially the largest source of new natural gas
resources for the nation as a whole (U.S. EIA 2001c).


Figure NGl. Marketed gas production in Montana (1950-1999)

Fig. 1. Marketed Gas Production in Montana (1950-1999)


Source: U.S. EIA, Natural Gas Annual Reports, 1950-1999 (Table NGl).

After declining during the 1990s, natural gas drilling in the U.S. picked up dramatically in early
2000 in response to higher prices, only to recently fall off again as prices returned to their
historic levels. Domestic natural gas production, with its large and accessible resource base, is
expected to increase from 18.7 trillion cubic feet (tcf) in 1999 to 29.0 tcf in 2020 to meet
growing domestic demand. Increased production would come primarily from lower-48 onshore
conventional sources, although onshore ^/xonventional production is expected to increase at a
faster rate than other sources (U.S. EIA 2001c).

In 2000, the United States imported 3.6 tcf of natural gas from Canada; 0.5 tcf of this Canadian
supply was imported to the Pacific Northwest. Net natural gas imports are expected to increase
from 3.4 tcf in 1999 to 5.8 tcf in 2020 (U.S. EIA 2001c). Alberta, which contains a significant
share of Canadian supply, sends gas to the West Coast of the U.S. primarily through the GTN
pipeline, which enters the U.S. in Idaho. Alberta sends gas to the U.S. Midwest through the
Alliance and Northern Border pipelines. The Northern Border, which passes through the
northeast part of Montana, is the largest pipeline in the state, though it has no injection points
in Montana. The large Alliance pipeline (1.3 bcf transport capacity per day) runs from the
Edmonton, Alberta area to the Chicago, Illinois area and allows other parts of the U.S. to
compete with Montana and the Pacific Northwest for Alberta's large gas supply (Smith 2001). All
of these Alberta lines also tie in with the large Trans-Canadian Pipeline that runs east to west
across Canada.

It is hard to predict how much natural gas is left for U.S. consumption from North American
reserves. Reserves are constantly being consumed and replaced and the relative rates of


consumption and replacement vary with economic conditions and natural gas prices. The
Northwest Power Planning Council estimates between 2,100 and 2,650 tcf remaining of North
American gas reserves (excluding Mexico). Using these numbers and assuming that U.S. and
Canadian consumption grows at 2.3 percent per year from current levels, estimated remaining
North American resources would satisfy North American consumption for about 40 or 50 more
years (not including imports and exports). The entire world is estimated to contain 13,000 tcf in
natural gas reserves with much of that located in the Middle East (Morlan 2001).

2. Natural Gas Consumption in Montana

Recent Montana natural gas consumption has been around 60 billion cubic feet (bcf) per year.
Future Montana natural gas consumption, excluding that for new electric generation, is
expected to increase slowly at less than 1 percent annually according to utility projections. The
reason for this slow expected increase is illustrated in Figure NG2. Both residential and
commercial gas consumption are expected to grow very slowly, and usage by industry is
expected to stay fairly level. In the 1970's, the industrial sector used much more natural gas
than it does now. The closure of smelters in Anaconda, in particular, contributed to the drop in
industrial usage that occurred in the 1980's.

Figure NG2. Natural gas consumption in Montana

Fig. 2. Natural Gas Consumption in Montana







-Total Consumption


- Electric Utilities


Source: U.S. EIA, Natural Gas Annual Report, 1950-1999 (Table NG2).

With projected new gas-fired electric generation, total gas consumption in Montana is expected
to significantly increase over current levels. The Montana First Megawatts gas-fired electric
generation plant, which is currently under construction in Great Falls, will create a significant
increase in total Montana annual consumption. Average new usage by this plant could be up to
13 bcf per year once the first 160 MW are built. This is about 20 percent of the current total


consumption in Montana. If tiie Silver-Bow electrical generation plant comes on line its
estimated 30 bcf per year would equal almost 50 percent of current total Montana consumption.

3. Natural Gas Consumption in the U.S.

In 2000, the U.S. consumed over 22 trillion cubic feet (tcf) of natural gas, the highest
level ever recorded. U.S. consumption is increasing at a healthy pace, and the Pacific Northwest
is no exception. Three reasons for increased use in the Pacific Northwest are ample, attractively
priced supplies, strong economic growth and increased gas-fired electrical generation. The EIA
forecasts that U.S. total natural gas consumption will increase from the current level of about 22
trillion cubic feet per year to nearly 35 trillion cubic feet per year in 2020 (U.S. EIA 2000).

A number of changes in energy markets, policies, and technologies have occurred which
explain the increased use of natural gas in the U.S. in the past 15 years (U.S. EIA 2001c):

■ Deregulation of wellhead prices begun under the Natural Gas Policy Act of 1978 and
accelerated under the Natural Gas Wellhead Decontrol Act of 1989;

■ Federal Energy Regulatory Commission (FERC) Orders 436 (1985), 636 (1992), and 637
(2000) separating natural gas commodity purchases and transmission services and
affecting access to shipping capacity;

■ Passage of the Clean Air Act Amendments of 1990 and subsequent regulations affecting
air quality standards for industries and electricity generators in nonattainment areas
favor natural gas, since it burns relatively cleaner compared to coal;

■ Deregulation of the wholesale electricity market. High-efficiency combined cycle
combustion turbine technology, coupled with low gas prices, has made gas the fuel of
choice for conventional electric generation nationwide. Though coal is expected to
continue to be the leading fuel for electricity generation, the natural gas share of total
electric generation is expected to increase from 16 to 36 percent between 1999 and
2020. Over 95 percent of new electric generation in the western U.S. is gas fired;

■ Improvements in exploration and production technologies and reduction in their
associated costs, improving the return for exploration and production efforts;

■ Investment in major pipeline construction expansion projects from 1991 through 2000
adding about 50 billion cubic feet per day of capacity; and

■ Increased imports from Canada.

4. Montana's Natural Gas System

Three distribution utilities and two transmission pipelines handle over 99 percent of the natural
gas consumed in Montana (Table NG5). The distribution utilities are Northwestern Energy
(NWE; previously the Montana Power Company), Montana-Dakota Utilities Co. (MDU) and


Energy West of Great Falls, which uses NWE for transmission. NWE and Williston Basin
Interstate pipeline (affiliated with MDU) provide transmission service for in-state consumers
and, with a handful of other pipelines, export Montana natural gas.

Northwestern Energy is the largest provider of natural gas in Montana accounting for about 60
percent of all sales in the state according to annual reports from Montana utilities. NWE
provides natural gas transmission and distribution services to 151,000 natural gas customers in
the western two-thirds of Montana. These customers include residences, commercial
businesses, municipalities, state and local governments and industry. NorthWestern's gas
transportation system, both long-distance pipeline transmission and local distribution, lies
entirely within Montana. Therefore, it is regulated by the Montana Public Service Commission
and not FERC. The system consists of over 2,100 miles of transmission pipelines, 3,300 miles of
distribution pipelines and three in-state storage facilities. NorthWestern's system has pipeline
interconnections with Alberta's NOVA Pipeline, the Havre Pipeline Company, the Williston Basin
Interstate Pipeline Company and the Colorado Interstate Gas Company. The Havre pipeline also
is regulated by the Montana Public Service Commission.

Northwestern Energy's Gas Transmission System





fiJ\Es Qas Transnission System


Alberta sends natural gas to Montana primarily through Northwestern Energy's pipeline at
Carway where it ties in with Alberta's NOVA Pipeline. NWE's pipeline system runs in a north-
south direction from Carway (top arrow) and Aden at the Canadian border down through Cut
Bank and south towards Helena approximately paralleling the Rocky Mountain Front. Near
Helena, the main pipeline turns west and runs close to Highway 12 and then turns south and
runs close to 1-90 passing near Anaconda. It then turns east towards Butte, still following 1-90.
From Butte, it runs approximately east passing near Bozeman. At Big Timber it turns southeast
and runs towards the Grizzly Interconnect near the Wyoming Border where it connects (bottom
arrow) with the Colorado Interstate Gas line (CIG) and the Williston Basin Interstate/Warren line
(WBI). The NWE gas system branches out from the main pipeline at various locations and runs
to Missoula, Great Falls, Dillon, Livingston and Billings. NWE's natural gas delivery system
includes two main storage areas. The Cobb Storage is located north of Cut Bank near the
Canadian border. The Dry Creek storage is located northwest of the Grizzly Interconnect, near
the Wyoming border.

A majority of NorthWestern's natural gas comes from Alberta. The total NWE system has a daily
peak capacity of 300 million cubic feet of gas (MMcf). The system delivers about 40 billion cubic
feet (bcf) of gas throughput per year to its customers compared with total annual Montana
consumption of about 60-65 bcf. About one half of the total throughput is used by "core"
customers who include residential and commercial business users. NWE has the obligation to
meet all the supply needs of core customers. The other half is used by non-core users including
industry, local and state governments and by Energy West, which supplies Great Falls. NWE
only provides delivery sen/ice for these customers; they contract on their own for their gas
supply. Peak usage occurs on cold weather days when daily demand is often close to peak
pipeline capacity. Significantly smaller amounts are used when the weather is warm (Waterman

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