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

• Public data on output for Colstrip 1-4 are reported for the entire

facility, not individual units. In this table, the output was allocated

among the partners on the basis of their ownership percentages.

'Distributes power generated at U.S. Corps of Engineers and U.S.

Bureau of Reclamation dams.

^ Northwestern Energy plants were owned by MPC until February

2002.

Source: Table E2



aMW


Percent


940


29.69f


509


16.0


403


12.7


382


12.0


323


10.2


223


7.0


169


5.3


114


3.6


47


1.5


69


2.2


3177


\00.07c



amount of power a plant can
be counted on to deliver to
the grid, net of in-plant use.)
The largest hydroelectric plant
is U.S. Corps of Engineers'
Libby Dam with 600 MW. The
smallest plants supplying the
grid in Montana are a micro-
hydro plant at 60 kW and a
wind turbine at 65 kW.

The only sizeable plants
coming on line in the 1990's
were two built to take
advantage of the federal
Public Utility Regulatory
Policies Act of 1978. PURPA
established criteria under
which, prior to deregulation of
the wholesale electricity
markets, non-utility
generators (or qualifying
facilities— QFs) could sell
power to utilities. The



1-2



Montana One waste-coal plant (41.5 MW) was built near Colsthp in 1990 and the BGI
petroleum coke-fired plant (65 MW) was built in Billings in 1995. These two now account for
about 92 percent of the average production of all QFs in Montana.

Montana Power Company plants, now owned by PPL Montana, produced the largest amount of

electricity on average in 1995-1999 (see previous page; also Table E2). PPL Montana's facilities

accounted for about 30 percent of the total generation in Montana. Federal

agencies— Bonneville Power Administration and Western Area Power

Administration— collectively produced 22 percent of the electricity generated in Montana. The

MPC plants not bought by PPL— Milltown Dam and a share of Colstrip 4— now belong to

Northwestern Energy.

Montana generation is powered almost entirely by coal (54 percent) and hydro (44 percent)
(1995-1999 average. Table E3; see Figure El). Over the last 15 years, about 25 percent of
Montana coal production has gone to generate electricity in Montana. Until 1985, hydro was the
dominant source of net electric generation in Montana (Table E5). The small amount of
petroleum used actually is petroleum coke from the refineries in Billings. Very small amounts of
natural gas and wind round out the picture.

Figure El. Generation by fuel





aher




Petroleum


/^ 0%




2% ^ -


^^




hlydro ^^^^^^^^




\


44% ^^^^^^B




Icoal
h>A°/o



Source: Table E3.

During spring runoff, utilities operate their systems to take advantage of cheap hydropower,
both on their systems and on the non-firm market around the region. Routine maintenance on
thermal plants is scheduled during this period. Thermal plants generally must be run more in
the fall when hydro is low. This pattern is apparent in the graph of operations on Montana
Power's system during 1997 through 1999 (see Figure E2).



1-3



Figure E2. Average output of Montana power plants, 1997-1999 (aMW)




^'^^ <,^ ^^ ^<^' ^^^ ^O^ ^^^ ^^^ c^^^ O^ ^^ <f'



hydro



thermal



total



Source: U.S. DOE, Energy Information Administration, Forms 759 and 860
databases.

4. Consumption

Montanans are served by 38 distribution utilities: 4 investor-owned, 30 rural electric
cooperatives, 3 federal agencies and 1 municipal (Table E9; Maps). (Four of the co-ops only
serve a handful of Montanans.) Two-thirds of these utilities operate mostly or exclusively in
Montana. Some of the distribution utilities also provide power from power marketers, primarily
to industrial customers (Table E8). In 2000, investor-owned utilities made 45 percent of the
electricity sales in Montana, co-ops 25 percent, federal agencies 16 percent and power
marketers 14 percent (Table E8; see Figure E3).

Figure E3. Distribution of 2000 sales by type of utility (aMW)



D Investor-owned B Cooperatives n Federal n Power Marketers




Source: Table E8.



1-4



Sales in 2000 were 14.5 billion kWh. The residential and commercial sectors accounted for
about a quarter each of total sales, and industrial, a little less than half. Sales have tripled since
1960 (Table E6; see Figure E4). Growth was faster in the first half of that period than in the
latter. Since 1990, sales to the commercial sector have grown the most, followed by the
residential sector. Industrial sales have bounced around, but on the whole haven't increased
much. The impact of the 2000-2001 price spike doesn't appear in these data, but it did
significantly and permanently reduce industrial consumption. Future consumption patterns will
be noticeably different than those of the past decade.

Figure E4. Annual sales in Montana




,# ,# ,^ ^"^ ^"^ <# <.*" ,<# /- # ^c?^



-♦— Residential — •— Commercial



Industrial



Percentage


of sales,


2000


Residential


- 27 %




Commercial


- 26




Industrial


- 45




Other


T




Total


-100%



Source: Table E6.



The cost of electricity didn't change much during the 1990s (Table E7). Throughout that
decade, as in previous decades, electricity in Montana cost less than the national average. In
2000, Montana averaged 4.74 cents/kWh vs. 6.78 cents/kWh nationally. The average price per
kWh for residential customers was 6.5 cents in 2000, up from 5.4 cents in 1990 (Table E8). The
average price per kWh for commercial customers was 5.7 cents in 2000, up from 4.7 cents in
1990. Complete cost on industrials are not available, due to deregulation; however, the average
cost for industrial customers served by private utilities was 4.0 cents/kWh in 2000, up from 3.3
cents in 1990. On average, the rates of cooperatives and private utilities were about the same
in 2000; however, that average masks considerable variation.

Montana residential consumption averaged 810 kWh/month in 2000, about 1.1 akW (Table E8).
This average covers a wide range of usage patterns. Households without electric heat can run
200 kWh to 1,000 kWh per month (0.3-1.4 akW), depending on size of housing unit and
amount of appliances. Electrically heated houses easily could range between 1,800 kWh to
3,000 kWh per month (2.5 and 4.0 akW). Extreme cases could run higher or lower than these
ranges.



1-5



Commercial accounts averaged 4,200 kWh/month or 50 akW per year. Because so many
different types of buildings and operations are included in the commercial sector, it's difficult to
describe a typical use pattern.

Variability in the load and pattern of use are even greater in the industrial sector. The largest
industrial customers are shown in the following table. These figures date before the price spikes
in 2000 and 2001 forced some companies to cut consumption or to shut down.



Large Industrial Electrical Use (aMW)

ASARCO 8.7

ASiMI ~75

Ash Grove Cement 4.6

Cenex 18

CFAC 342

Conoco Pipeline 20.0

Conoco Refinery 27.0

ExxonMobil 27.0

Golden Sunlight 10.0



Holnam


5.0


Louisiana Pacific


7.0


Montana Refining


3.4


Montana Resources


43.0


Montana Tunnels


9.5


Plum Creek


33


Smurfit-Stone


52.0


Stillwater Mining


20.0


Stimson


6.2



Data initially provided from best available sources by Don Quander, Large Customer Group; compiled by
EQC and DEQ. Holnam late last year changed its name to Holcim.

5. Past and Future Changes in Electricity Consumption

During the 1990-2000 decade, residential consumption rose at an average annual rate of 1.5
percent, commercial at 3.4 percent and the overall growth rate was 1.0 percent statewide.
Residential growth tracked population growth, while commercial growth tended to track
economic activity, as measured by the gross state product (see Figure E5). Even though houses
are getting larger, the number of second homes growing and the proliferation of consumer
electronics continuing, per capita use of electricity is not climbing significantly in Montana. As
for growth in commercial sales, one can expect that to continue slow with the slower economy.

As electricity prices go up, growth in consumption should slow. In the last decade, Montanans
saw little change in the price of electricity in real terms (as adjusted by the consumer price
index; see Figure E6), with prices actually declining toward the end of the decade. In spite of
all the news stories about rising rates due to the energy crisis of 2000-2001, only about one-
quarter of the Montana load had been exposed to market prices by the start of 2002. The
entire impact of increased prices on consumption has yet to hit.



1-6



Figure E5. Amount of growth in residential and commercial electricity sales,
population, economic activity in the 1990's




^o ^'9n ''9n 'S>n '^n ^S>n 'S>n 'S>n. '^n ^^o ^Q



So ^^. ^^^ ^OPn ^^^ ^^<. ^^x^ ^^> "^O^ '^'9,



"V



V



â– ^ ^J>



^ 0/^ c/^ 0/^ ^^



%



population



economy x res . sales



com. sales



Note: The swings in 1999 and 2000 commercial sales may reflect data problems due to

deregulation.

Source: U.S. Department of Commerce, U.S. Census, Population Estimates Program

and Bureau of Economic Analysis, Regional Accounts data (real dollars); Table E6.

Figure E6. Cost per kWh, 1990-2000 (2000 cents)



8.00
6.00
4.00
2.00

0.00



)*-



-5K-



-*-



-^



-^



â– *-



=^



=^




1990



1992



1994



1996



1998



2000



Residential



Commercial x Industrial x All Sales



Source: Table E7.



The increased prices due to deregulation and the California price spikes hit the customers of
Flathead Electric Cooperative and "choice" customers served by MPC (now NWE) distribution
lines. MPC customers who had moved to choosing their own power supplier included most of
the large industrial load, some commercial customers and a few residential customers. Flathead



1-7



residential and small commercial customers have seen their rates jump from a base fee of $15
per month and $0.0392/kWh at the start of 2000 to $16 and $0.0622 in October 2001. That is
a 53 percent increase in the cost of electricity (assuming an average consumption of 800 kWh
per month). Energy costs paid by choice customers served by the Montana Power (now
Northwestern Energy) distribution system aren't published, though rates are known to have
dropped back down. However, typical bills for Northwestern Energy's default customers, who
consume about 40 percent of the electricity sold in Montana, went up July 1 by 10 percent for
residential customers and 18 percent for most commercial customers; other customer classes
also saw rate increases of varying amounts.

In addition, another large portion of Montana's electricity use was exposed to market prices,
albeit in a fashion different from Flathead customers and MPC choice customers. Bonneville
Power Administration (BPA) bought back the contracted deliveries it had promised Columbia
Falls Aluminum Company (CFAC) and the other aluminum plants in the Pacific Northwest. This
buyback offer, which was accepted by all the aluminum smelters, provided BPA with needed
power at a lower cost than it could purchase on the open market. For CFAC, reselling the power
gave a better profit than could be obtained by smelting aluminum. The shutdown, which
reduced Montana consumption by about 340 aMW, lasted over a year with the first potlines
reopening in January 2002.

There are no statewide forecasts for future electricity consumption. The rising prices of
electricity combined with an economy that has slowed since the early 1990's suggest the
growth in electricity consumption will be slower this decade than the last. Improved efficiency
also could reduce loads significantly (see Section 6). Finally, if the trend over the last few
decades towards warmer winters continues, as reported by the Climate Prediction Center,
National Weather Service (http://www.cpc.ncep.noaa.gov/charts.htm), Montana's electricity use
will decline further.

In the absence of forecasts, only scenarios of future growth can provide a sense of the range of
future consumption. First, one could assume that the 1990's pattern would continue, with
residential and commercial sectors continuing to grow at a combined average rate of 2.4
percent per year and industrial load not dropping. Second, one could assume, as MPC did in its
Tier II filing before the Public Service Commission, that non-industrial loads would grow at 1
percent per year and certain industrial loads (ASARCO, MRI and Golden Sunlight) would be lost
and not replaced. Finally, as a worst case one could assume MPC's Tier II scenario, plus that
the yearlong shutdown of CFAC reoccurs and becomes permanent. These scenarios produce a
range of possibilities, from an optimistic 260 aMW increase to an extremely pessimistic loss of
336 aMW.

Possible Increases in Statewide Load by 2010

Scenarios aMW

The 1990's continue: 260

MPC's Tier II: 33

Tier II minus CFAC: -336

While these are only scenarios, and not predictions, the range does suggest minimal need for
net additions of generation resources to serve increases in Montana loads. To be economically

1-8



viable, any substantial addition to generation resources in Montana will need to sell to out-of-
state markets or to displace existing in-state resources. Therefore, any new generation would
need 1) to offer the price and have the transmission access to compete in out-of-state markets;
2) to offer a better package of prices and conditions than those resources currently supplying
Montana loads; or 3) to be conceded a Montana market by existing resources choosing to take
higher profits by selling out of state.

6. Potential for Efficiency Improvements

Cost-effective energy efficiency improvements plausibly could meet much or all of the net
increase in statewide load over the next decade. There are no comprehensive estimates of the
potential for efficiency improvements. However, analyses that have been done and the load
reductions seen during the electricity crisis in 2000 and 2001 suggest that significant potential
exists. Better estimates of the potential in Montana might come from the Northwest Power
Planning Council's Fifth Regional Plan. DEQ is assisting Council staff with the efficiency
estimates and may be able to report on those estimates in the November supplement to this
chapter.

Efficiency improvements reduce both cost and risk. First, they can reduce the total cost of
energy services. For customers, they reduce the monthly bill. For providers, they postpone or
eliminate the need to acquire more expensive resources. Second, efficiency improvements
reduce exposure to electricity price volatility. By reducing the need for electricity, especially
peak-hour electricity, such improvements provide a hedge against the impacts of expensive
upswings in price.

The amount of energy efficiency improvements worth pursuing depends on the future price of
electricity. The lower or the less volatile expected future prices, the less attractive energy
efficiency investments are. The higher or more volatile expected future prices, the more
attractive such investments are. Just like any other energy resource, there is a range of energy
efficiency, rather a fixed amount, waiting to be developed.

There are no statewide estimates of the potential energy efficiency improvements, either in
total or by sector. While some of the easiest and least difficult to obtain are in large commercial
and industrial operations, potential efficiency improvements can be found in all sectors. Based
on studies around the country, as well as some in-state estimates, it has been reasonable to
assume potential reductions are in a range around 10 percent. Given how perceptions of the
electricity industry have changed over the last two years, that range may be low.

One of the most cited estimates for Montana is that offered by Northwestern Energy in the
default supply portfolio docket (data request PSC-22— amended, D2001.10.144). NWE
estimated the potential for cost-effective efficiency improvements for customers sen/ed by their
distribution lines, who consume about two-thirds of the non-aluminum plant load in Montana.
The estimates were extrapolations from the more detailed analysis done in MPC's 1995
Integrated Least Cost Resource Plan. NWE estimated an achievable reduction of 98 MW in load
and 87 aMW reduction in energy, using measures with a levelized cost of no more than
$0.035/kWh. The average cost of all measures was $0.023/kWh. For default customers alone,
the totals were 76 MW and 62 aMW, or about 7 percent of current load and 9 percent of sales.

1-9



These estimates do not include any premium amounts the utility — or the customer— might be
willing to purchase as protection against future price volatility.

The reductions estimated by NWE and others can't be compared to the recent reductions
obsen/ed in the Pacific Northwest and in California. The extensive load reductions in 2001 were
short-term responses to a crisis situation. However, the crisis did give an indication of the
amount of flex in electricity use and suggests the magnitude of changes in use that are
possible. Those changes are far larger than had been expected previously.

The Readiness Steering Committee of the Pacific Northwest region studied the impact of
various actions to reduce energy use in the region during the electricity crisis of 2000-2001.
(The committee is an ad hoc group of utility industry, large customer and public agency
representatives that advise the Northwest Power Pool and the region on electricity shortages.)
The committee, in an October 2001 special report, estimated that the total impact of all
electricity demand actions was a reduction by summer of 2001 of about 4,000 megawatts,
almost 20 percent of what loads would have been under normal conditions. These actions
included utility initiated programs, general appeals to the public and the response of consumers
to price increases.

The largest portion of the response came from curtailing industrial production. By July 2001 the
electricity demand of aluminum smelters was almost completely gone, a reduction of more than
2,500 megawatts; operators found it more profitable to resell their contracted supplies than to
produce aluminum. Irrigation customers also reduced their use by an average of 300
megawatts over the May-September irrigation season, in exchange for payment from their
suppliers. About 500 megawatts of reduction came from industrial customers who faced high
market prices. Not all of this reduced use was due to cutbacks in operations; a portion came
from customers beginning to generate some of their own electricity. Another 160 megawatts
came from customers in other sectors who accepted payment from their electricity suppliers to
reduce their consumption by cutting back operations. Demand response to higher electricity
rates charged by some utilities was estimated at about 150 megawatts by July. Finally, while
customers of most utilities were insulated from the high prices in the wholesale market,
expanded conservation education programs, along with the media coverage of the California
shortages, were believed to have caused some reduction in regional loads, though this couldn't
be quantified.

The load reductions seen by the summer of 2001 would not be cost-effective or advisable
under normal conditions. What they do show is the ability of consumers to change their usage
in the face of higher prices, either in terms of what they pay or what they're offered to forego
using electricity. As prices for electricity climb, some improvement in the economy's energy
efficiency can be expected in any event, though not to the extent that could come from a more
formal program of resource acquisition. Difficulties in obtaining information and financing
always will deter some individual consumers from otherwise cost-effective investments.



I-IO



Table El. Electric Power Generating Capacity by Company and Plant


as of November, 2001


1












INITIAL




CAPACITY (MW)










ENERGY


OPERATION


GENERATOR


SUMMER


WINTER


COMPANY


PLANT


COUNTY


SOURCE


(First Unit)


NAMEPLATE


CAPABILITY


CAPABILITY


Avista


Noxon Rapids


Sanders


Water


1959


466.2


556


513


Mission Valley Power Co


Hell Roanng


Lake


Water


1916


04


04


04


Montana-Dakota Utilities


Glendive


Dawson


Natural Gas/#2 Fuel Oil


1979


40.5


33.5


42 3


Montana-Dakota Utilities


Lewis & Clark


Richland


Lignite Coal/Natural Gas


1958


70.0


52 3


49.2


Montana-Dakota Utilities


Miles City


Custer


Natural Gas/#2 Fuel Oil


1972


24.5


24 4


28 9


Montana Power CO-'


Milltown


Missoula


Water


1906


32


2.6


2.2


MPC QF - Colstrip Energy Partnership'


Montana One


Rosebud


Waste Coal


1990


41 5


39


39


M PC OF - Hydrodynamics^


South Dry Creek


Carbon


Water


1985


20


2.1




MPC QF - Montana DNRtf


Broadwater


Broadwater


Water


1989


9.7


6


8


MPC QF - ottier hydro^


Various


Vanous


Water


Various


24


-


-


MPCQF-wind^


Various


Park


Wind


Various


0.3




-


MPC QF - Yellowstone Partnership'


BGI


Yellowstone


Petroleum Coke


1995


65.0


57


57


Norttiern Lights Cooperative


Lake Creek


Lincoln


Water


1917


4.5


47


44


PacifiCorp


Bigfork


Flathead


Water


1910


4.2


4.2


42


PPL Montana


Black Eagle


Cascade


Water


1927


21 3


19


17


PPL Montana


Cochrane


Cascade


Water


1958


48.0


52


32


PPL Montana


Hauser Lake


Lewis & Clark


Water


1907


170


16


17


PPL Montana


Hotter


Lewis & Clark


Water


1918


38.4


36


48


PPL Montana


J. E. Corette


Yellowstone


Subbituminous Coal


1968


163.0


160


160


PPL Montana


Kerr


Lake


Water


1938


211.7


180


165


PPL Montana


Madison


Madison


Water


1906


90


90


9.0


PPL Montana


Morony


Cascade


Water


1930


45.0


48


48


PPL Montana


Mystic Lake


Stillwater


Water


1925


10.0


110


11


PPL Montana


Rainbow


Cascade


Water


1910


35.6


370


37.0


PPL Montana


Ryan


Cascadp


Water


1915


48.0


60


60


PPL Montana


Thompson Falls


Sanders


Water


1915


91.0


90.0


90


PPL Montana (50%)


Colstrip 1


Rosebud


Subbituminous Coal


1975


333.0


307


307


Puget Sound Power & Light (50%)
















PPL Montana (50%)


Colstrip II


Rosebud


Subbituminous Coal


1976


333.0


307


307


Puget Sound Power & Light (50%)
















PPL Montana (30%)


Colstrip III


Rosebud


Subbituminous Coal


1983


776


740


740


Avista (15%)
















PacifiCorp (10%)
















Portland General Electnc (20%)
















Puget Sound Power & Light (25%)
















Montana Power Co. (30%)^


Colstnp IV


Rosebud


Subbituminous Coal


1985


7760


740.0


740


Avista (15%)
















PacifiCorp (10%)
















Portland General Electnc (20%)
















Puget Sound Power & Light (25%)
















Salish-Kootenai Tribe


Boulder Creek


Lake


Water


1984


04


04


04


US Corps - North Pacific Division


Libby


Lincoln


Wafer


1975


5250


600


575


US Corps - Missoun River Division


Fort Peck


McCone


Water


1943


1853


209.0


2090


US BurRec - Great Plains Region


Canyon Ferry


Lewis & Clark


Water


1953


50 1


57.6


576


US BurRec - Great Plains Region


Yellowtail


Big Horn


Water


1966


250,0


288


252


US BurRec - Pacific Northwest Region


Hungry Horse


Flathead


Water


1952


428


424


368



TOTAL MONTANA CAPACITY (MW)



5,129 2



5,1732



4,998.6



' Does not include a 10 9 MW waste-wood facility that supplies the Stone Container plant in Missoula, the vanous temporary generators, most of which were in operation
only in the first part of 2001 or the City of Whitefish's 200 kW hydro plant, currently off line but expected to be repaired.
' Bought by Northwestern Energy in 2002.

Source: Western Systems Coordinating Council. Existing Generation and Significant Additions and Changes to System Facilities 2000 - 2010. US Department of
Energy, Energy Information Administration, Inventory of Utility Power Plants in trie US- 1999 (EIA-0095)/1 , U S Department of Energy, Energy Information