20010308Reply to First Production Request.pdf

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EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
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555 SOUTH COLE ROAD. P.O. BOX 7608 . BOISE, IDAHO 83707 . [phone] .:F?\~:~?J-6097
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March 8 , 2001
i' "i;'! F I' ! Ie
J lUii ' CU;i(~iSS;U4
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
P. O. Box 83720
Boise, ID 83720-0074
RE:Overview & Analysis of Gas Purchasing Policies and Gas Supplies
tPUC Case No.'s tNT-01-1 & tNT-00-
Dear Ms. Jewell:
Pursuant to Order No. 28578 of the Idaho Public Utilities Commission ("tPUG") under Case No.
tNT-00-Intermountain Gas Company ("Intermountain ) was "directed to prepare and
submit an analysis of its gas purchasing policies and gas supplies" and was further ordered to
analyze the cost effectiveness of its relationship with its gas suppliers and gas purchasing
policies, and file results of that analysis with the Commission ..." Additionally, as part of IPUC
Case No. tNT-01-, the First Production Request of the Commission Staff addressed
several key gas purchasing and gas supply issues. Although the requested information took
the form of several specific questions , Intermountain believes the Staff's questions , as well as
the Commission s directive, can best be addressed by way of the following overview and
analysis.
First of all it is important to note that Intermountain developed its gas purchasing philosophy at
the start of open access opportunities in late 1985. That philosophy has been consistently
employed and utilized since that time and continues today. The general philosophy and
position was that Intermountain would directly purchase its core market gas supplies from
selected suppliers under the following parameters:
All supplies purchased would be firm gas supplies
Supplies would include a diversified portfolio across all supply basins thus allowing the
capture of lower prices that naturally occur in a market competitive environment
All supplies would be from reliable, credit worthy suppliers
Suppliers providing flexibility would be given first preference
All supplies would be market responsive and economically priced
The residential/commercial market served under Intermountain s sales rates is a 100% firm
requirements market, temperature sensitive and subject to significant daily swings in its
requirements. The parameters outlined above, together with the discussion throughout the
rest of this overview, points out that Intermountain s gas purchasing philosophy results in
virtually no risk of service interruption to this important market segment.
Overview & Analysis of Gas Purchasing Policies and Gas Supplies
Page 2
March 8, 2001
In the First Production Request identified above it was suggested at Item 4 (c) that
Intermountain recently chose to be 100% dependent on the "spot" market for its gas supplies.
A point of clarification is that Intermountain has never in the past, nor currently, neither relied
heavily or on 100% of its gas supplies from the spot market. The spot market is a type of
natural gas supply typically purchased on a month-to-month , or even day-to-day basis, to help
balance load requirements for such demand volatility induced by such things as weather.
Such supplies are not necessarily firm , nor expected to be available on a long-term basis.
Over the past 16 years, Intermountain total gas supply portfolio has consisted of
approximately 80% longer-term , firm gas supplies and 20% month-to-month index priced
supplies (these supplies are generally considered firm once committed to for the month).
Additionally, one must look at Intermountain s gas purchasing philosophy in conjunction with its
firm transportation diversity decisions and resultant capacity availability on Northwest Pipeline.
Of Intermountain s over 186 000 MMBtu per day of firm transportation rights on Northwest
Pipeline, approximately 60% of these rights require gas to be sourced out of Canada from both
British Columbia and Alberta and 40% of the rights require gas to be sourced out of the United
States Rocky Mountain region of Colorado, Wyoming, Utah and the "four corners" area. While
supply and transport capacity diversity is important to capture the lowest cost supplies as
mentioned previously, it is also important to remember as Intermountain approaches the
heating season of November through March , this option is not necessarily a reality. This is
due to the fact that the firm transportation rights on Northwest Pipeline carry primary receipt
point locations such that, at peak demand times, Intermountain has no choice but to buy its
gas supplies from the supply basins in Canada and the US to match its receipt point locations.
To attempt otherwise would only result in supply interruption.
During the past 16 years of the open access environment, Intermountain has gone through
three distinct cycles in its gas purchasing practices. The first cycle ran from 1985 to about1991. During this time, negotiating a gas purchase contract with a supplier was a very
cooperative effort between buyer and seller, often taking as long as 60 - 90 days to complete.
If a fixed price arrangement were desirous, buyer and seller could easily work toward a
mutually agreeable price during the negotiation timeframe. Additionally, it was quite easy to
incorporate daily take flexibility within the contract without any resultant price implications from
the supplier. Also during this time frame our agent, IGI Resources, Inc. ("IGI"), purchased the
gas supplies directly from the supplier, at the direction of Intermountain , and then resold such
supplies to Intermountain at zero profit. This arrangement began at the onset of open access
due to the administrative and operational ease that resulted. However, Intermountain and the
IPUC agreed, in 1990, that this arrangement no longer seemed proper as the IPUC preferred
Intermountain to directly hold all of its gas supply contracts in its own name. Accordingly, IGI
transferred , or assigned all such term gas supply contracts to Intermountain and all future
contracts negotiated by IGI on behalf of, and at the direction of Intermountain , were entered
into directly between the supplier and Intermountain. IGI continued in its role as fuel manager
and administrative service agent under contract with Intermountain.
Overview & Analysis of Gas Purchasing Policies and Gas Supplies
Page 3
March 8, 2001
In April of 1990, the NYMEX Natural Gas Futures contract was established. About 1992, this
futures contract, together with over-the-counter financial derivative products, began to be used
more routinely in the Pacific Northwest by both buyers and sellers. This began the second
cycle in Intermountain s gas purchasing practices , lasting from 1992 to1999. With the ability
to manage one s gas pricing through the use of these financial products (both buyers and
sellers), suppliers quickly became disinterested in negotiating a fixed price arrangement
directly with a buyer. Instead , sellers preferred (and in some cases insisted) that supplies be
priced according to a published monthly index price. The result being that the supplier and the
buyer could independently choose when to lock in a fixed price at the time most desirous to
that party. Usually this would be at different times of the year for the buyer versus the seller.
. Additionally, any number of months, or periods , could be chosen for a price lock by either
party. Also, since a financial derivative type product is a paper form of take-or-pay, suppliers
quickly eliminated any daily flexibility on takes without some form of financial consequence to
the buyer, which could be quite costly. Intermountain , through its agent IGI , began employing
four new strategies in its overall philosophy during this cycle.
Enter into longer term arrangements with its suppliers
Seek shorter term firm supply arrangements to assist in meeting daily swings
Secure more supply basin firm gas storage arrangements
Monitor fixed price availability through the changing gas futures environment
As to the first item , Intermountain effectuated the following long- term arrangements:
Supplier Basin Term Daily Annual Volume
Volume
POCO Canada 05/90 - 1 0/03 000 5,475 000
POCO Canada 11/93 - 10/03 000 825 000
Talisman Canada 11/93 - 10/03 000 555 000
Engage Canada 11/93 - 10/08 500 912 500
Clay Basin US Rockies 05/94 - 02/25 188 662 500
Clay Basin US Rockies 08/92 - 03/09 625 195,000
While Clay Basin is a supply area storage facility, it is shown here as a long-term supply
arrangement and also later as a storage source. Intermountain chose Clay Basin since it
allowed for the purchase of firm Rockies gas supplies and injection during the summer months.
However, depending on the operations of the Northwest Pipeline system, Intermountain can
also, at times , purchase lower cost Canadian supplies for transportation and injection into ClayBasin. It is this flexibility together with the firm nature of the storage that attracted
Intermountain to Clay Basin.
Again, utilizing the services of IGI, Intermountain would periodically review the future monthly
needs of Intermountain typically as to the future winter (Nov. - Mar.) and summer (Apr. - Oct.)
periods under normal weather conditions. The term gas supply and storage injection and
Overview & Analysis of Gas Purchasing Policies and Gas Supplies
Page 4
March 8 , 2001
withdrawal availabilities would then be laid over these monthly needs and any resultant
shortfall would then be mutually agreed to as to being met by either month-to-month spot gas
supplies and/or day gas purchases.
In the early 1990', as part of its annual supply and demand planning process, Intermountain
normalized annual requirements for system supply approximated 20,000 000 MMBtu
annually and , with an expectation to grow at a rate of 3-5% each year, could reach 25 000 000by the year 2000. (This expectation actually occurred as well.) Intermountain s growing
market is comprised of residential/commercial customers that are highly weather sensitive
have extremely poor annual load factors , and are subject to significant daily swings in th~ir
overall gas requirements. In order to be able to serve this growing load in the most efficientand cost effective manner, Intermountain decided to pursue additional firm storage
opportunities.
At the time , Intermountain s total storage availability was as follows:
FACILITY CAPACITY (MMBtu)
Nampa LNG 500 000
Plymouth LS 720 000
Jackson Prairie 000 000
To satisfy this objective , Intermountain entered into the following long-term storage
arrangements:
FACILITY CAPACITY (MMBtu)
Clay Basin 150,000
Clay Basin 625 000
Aeco 900 000
Aeco 750 000
SoCal / PITCO Exchanqe 450 000
This brought Intermountain total storage capacity to over 12 000 000 MMBtu and thus
provided the necessary physical ability to meet a growing, low load factor and highly volatile
residential/commercial market requirement. Intermountain believes it must have this level of
storage capacity to most effectively and efficiently manage the needs of its core market.
Financial derivative transactions alone cannot work since , as mentioned before , they represent
take or pay arrangements and thus do not allow the load following capabilities of storage.
Storage is Intermountain s largest single supply management component. It allows for the
meeting of significant daily swings in the core market together with management of take
requirements inherent in its physical gas purchase arrangements. Furthermore , storage acts
as a natural summer gas price hedge. Additionally, the Duke Storage Agreement, which
essentially transformed a traditional storage supply into an economically attractive winter
Overview & Analysis of Gas Purchasing Policies and Gas Supplies
Page 5
March 8 2001
supply source, provides Intermountain s customers with an additional annual savings of
approximately $492 000. IGI consummated this agreement with Duke Energy as part of its
fiduciary responsibility to Intermountain and did not receive any incremental financial benefits
for doing so.
With the producers demand for 100% annual and daily take requirements, in exchange for
advantageous pricing, additional storage was the correct answer, as it allowed for injections of
firm gas supplies in the summer and withdrawals during the winter. This allowed
Intermountain to (1) meet its objective of satisfying the supplier s take requirement while
attaining the most cost effective supply and (2) better serve the growing residential/commercial
load.
As can be seen from the attached analysis of rolling twelve-month spot prices, Intermountain
and the consuming industry in general had enjoyed very low prices in the Pacific Northwest
from 1988 through 1995. Knowing that gas prices generally follow a wave pattern of high'
and low s over a multi-year cycle, Intermountain believed in mid-1995 that the potential for a
rise in gas prices was now more likely than earlier, and through IGI researched what prices
could be locked in for a multi-year forward period utilizing financial derivative products.
Through this research it was believed that a fixed price in the range of $1.40 per MMBtu for the
gas commodity could be attained for up to 4 years. Accordingly, Intermountain and IGI met
with the IPUC staff to explain how these financial derivative products worked and that
Intermountain was in fact considering utilizing them for the first time in fixing its future natural
gas prices. In November 1995, Intermountain actually effectuated several financial hedges
which provided a fixed price lock on approximately 70% of its annual gas supply requirements
through June of 1999, at an average price of $1.42. As hindsight would suggest, and , as in
fact recognized by the IPUC in previous Orders, this decision provided significant gas cost
savings versus the going market prices , as well as price stability to Intermountain s customers.
The third cycle in this discussion begins in mid-1999 and continues to the current date. This
time frame has been marked by natural gas pric~s at previously unimaginable and certainly
unforeseen levels. Additionally, the day-to-day volatility in natural gas futures prices was
equally unimaginable and unforeseen.
In early 1999 , as Intermountain began preparation of its 1999/2000 annual PGA application
natural gas prices were still relatively low in the $1.50 to $1.70 range , yet natural gas futures
quotes for the winter of 1999/2000 and beyond were well above historical levels. Winter
quotes were in the $3.50 to $4.00 range while annual quotes were in the $2.00 to $2.50.
reviewing the industry in general , and the relative supply and demand mix, nothing
fundamental pointed to a reason(s) for gas prices to be so significantly above recent historical
levels or as adjusted for inflation. Additionally, since natural gas futures contracts traded by
pure speculators and investment funds versus actual market participants had grown from
some 5% in the early 1990's to over 25% now, gave additional concern and disbelief that the
current future price quotes would sustain themselves. As such , Intermountain chose not to
Overview & Analysis of Gas Purchasing Policies and Gas Supplies
Page 6
March 8 , 2001
lock any pricing for the 1999/2000 winter or beyond at the time. A review of spot gas prices for
the April 1999 to April 2000 time frame shows an annual average gas price of $2.30 to $2.40.
Again in early 2000, as Intermountain prepared its 2000/2001 PGA application, natural gas
future price quotes were significantly higher than recent history with no real change in gas
industry fundamentals or perceived supply and demand mix. However, in its initial application
Intermountain did incorporate a gas commodity price increase for the upcoming PGA year of
$2.86 versus the filed rate of $1.83 and again chose not to lock in any prices at the time
believing a price downturn could occur in the ensuing months. However, beginning in June
2000 a dramatic price increase occurred from the $2.70 range of May to $3.65 in June and
$4.00 in July. At this time , Intermountain looked at futures prices for the winter period of Nov.
2000 through February 2001 and again saw unbelievably high quotes above $5.00. In August
2000, prices fell to approximately $3.07 and Intermountain chose not fix any prices at the time
believing a price downturn may be occurring. However, just as was experienced in the electric
industry in the Pacific Northwest, natural gas prices reached previously unimaginable levels.
Since no one would have predicted gas prices to rise above the $10.00 level , when it reached
the $5.00 to $8.00 range a decision to lock any prices at that time surely seemed unwise.
However, October and November prices reached the $4.50 plus level and then an
unprecedented increase to the $9.00 to $14.00 range occurred in December. In fact , daily gas
prices traded in the $40.00 plus range during December and January. While much of these
higher winter prices were mitigated by Intermountain storage management practices
Intermountain was still compelled to file its "out-of-period" PGA to recover certain of these gas
cost increases.
At this writing, Intermountain continues to review several alternatives to managing its future
natural gas prices charged to its customers. While continuing to look at current quotes for
future gas prices on a seasonal , annual and multi-year basis , Intermountain is also researching
other structured pricing products including but not limited to:
Price Caps
Price Collars
Portfolio Pricing
Extendables
Participating options
IGI Pool Participation
However, one must always remember the fundamentals of these products. That is that the
buying of any of these price fixing products has both a cost, and the belief by the selling party,
that the price of the commodity is going to move in the opposite direction that the buyer of the
fixed price product believes the commodity will move. This market exercise and these
judgment calls will always have a "winner" and a "loser.
Overview & Analysis of Gas Purchasing Policies and Gas Supplies
Page 7
March 8, 2001
It is important to again note that amidst this backdrop of an evolving natural gas marketplace
Intermountain s customer s have continued to benefit from agreements consummated through
Its administrative agent , IGI Resources: $37 million in savings as a result of segmented
pipeline capacity, $32 million in the acquisition of discounted interstate pipeline capacity, and
over $6 million in savings resulting from financial hedges entered into during the late 1990'
copy of the current Administrative Service Agreement between IGI Resources and
Intermountain Gas Company is attached hereto. A question has arisen as to whether or not
this Agreement was in any way effected or modified pursuant to the recent sale of IGI to
Energy Company. The answer to this question is no. Intermountain is contractually bound bythe same Terms and Conditions of the attached Agreement, which is why it has been
unnecessary to formally consider, at this time, other administrative service providers.
Should the Company consider an incentive-based PGA mechanism? The incentive-based
PGA mechanisms currently in place in the Northwest and elsewhere prohibits the customers of
the utility from receiving 100% of the benefits derived from lower gas costs and conversely
shields the customer from some amount of gas cost increases. These incentive mechanismshave generally been employed at companies with much bigger balance sheets than
Intermountain Gas Company. For a company our size, absorbing even a small percentage of
deferred gas cost debits could result in an earnings deficit. Intermountain Gas Company
earnings (shareholders) are impacted by today s higher gas costs. Bad Debt costs have
increased and the cost to Intermountain s shareholders to simply finance today s higher
commodity costs could reach $1 000 000.
Intermountain Gas Company appreciates this opportunity to have an open dialog with the
Commission to address the challenges and opportunities inherent in today energy
marketplace. We hope to enhance and continue this dialog as part of our upcoming
discussions with our next Integrated Resource Plan, a Plan which we hope to share with our
customers and this Commission sometime this summer.
Respectfully yours?-L(17
Michael P. McGrath
Director, Market Services
& Regulatory Affairs
MPM/slk
Attachment
MONTH
MARCH
APRIL
MAY
JUNE
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
JANUARY 2000
FEBRUARY
MARCH
APRIL
MAY
JUNE
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
JANUARY 2001
FEBRUARY
IGI ')URCES. INC.
ANALYSIS O. ...ONTHL Y SPOT PRICES
AS REPORTED BY INSIDE FERC GAS MARKET REPORT
FIRST OF MONTH PUBLICATION
CANADIAN BORDER
ROLLINGMONTHLY 12 MONTHINDEX AVERAGE
NORTHWEST PIPELINE
ROCKY MOUNTAIN
ROLLING
12 MONTH
AVERAGE
AVERAGE OF BOTH
ROLLING
AVERAGE 12 MONTH
OF BOTH AVERAGE
MONTHLY
INDEX
50 1.75 1.51 1.76 1.51 1.51 1.76 1.54 1.73 1.53 1,95 1.78 2.00 1.73 1.98 1.91 1.83 1.94 1,75 1,93 1,94 1.87 1.99 1.78 1.97 1.21 1.92 2.18 1.82 2.20 1.50 2.01 2.56 1.90 2,53 1.39 2,07 2.39 1.97 2.39 2,92 2.13 2.86 2.04 2.89 2.2.28 2.15 2.10 2.04 2.19 2.30 2.10 2,19 2.07 2.25 2.
~g,,~~~
~~..~'11P'~~.IriiIII31 2.22 2.36 2.21 2.34 2.73 2,32 2,69 2,30 2.71 2.74 2.38 2.72 2.36 2.73 2,64 2.53 3.65 2.51 3.65 2.07 2.70 3.92 2.67 4,00 2,04 2.77 3.09 2.74 3.07 2.3.45 2.85 3,41 2.81 3.43 2.88 3.06 4.29 2.97 4.59 3.02.83 3.22 4,35 3.10 4.59 3,
13.69 4.17 6.01 3.42 9,85 3,
14.20 5.16 8.76 3.97 11.48 4.1t;"fll~~JI~"~lill~..iIIi~~.
MONTH
JANUARY 1994
FEBRUARY
MARCH
APRIL
MAY
JUNE
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
JANUARY 1995
FEBRUARY
MARCH
APRIL
MAY
JUNE
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
JANUARY 1996
FEBRUARY
MARCH
APRIL
MAY
JUNE
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
JANUARY 1997
FEBRUARY
MARCH
APRIL
MAY
JUNE
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
JANUARY 1998
FEBRUARY
MARCH
APRIL
MAY
JUNE
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
JANUARY 1999
FEBRUARY
IG' OURCES, INC.
ANALYSIS 0 "ONTHLY SPOT PRICES
AS REPORTED BY INSIDE FERC GAS MARKET REPORT
FIRST OF MONTH PUBLICATION
CANADIAN BORDER
ROLLINGMONTHLY 12 MONTHINDEX AVERAGE
NORTHWEST PIPELINE
ROCKY MOUNTAIN
ROLLING
12 MONTH
AVERAGE
AVERAGE OF BOTH
ROLLING
AVERAGE 12 MONTH
OF BOTH AVERAGE
MONTHLY
INDEX
18 1,87 1.92 1,82 2,05 1.79 1,87 1.78 1,84 1.79 1.98 1.89 1.95 1.85 1.97 1.62 1.87 1.61 1,84 1,62 1.60 1.82 1.60 1.78 1.60 1.39 1.80 1.37 1.77 1.38 1.1.48 1.80 1.46 1.76 1.47 1,1.45 1.78 1.45 1,74 1.45 1.36 1.73 1.36 1.70 1.36 1.18 1.69 1.18 1.65 1.18 1.52 1.66 1.48 1.63 1,50 1.63 1.60 1.61 1.56 1.62 1,1.40 1.53 1.37 1,52 1.39 1.03 1,47 1.06 1.46 1.05 1.4600 1,39 1.05 1.38 1.03 1.97 1.33 1.05 1,34 1.01 1.99 1,28 1.06 1.29 1.03 1.97 1,25 1.14 1.27 1.06 1.85 1.20 0.98 1.23 0,92 1.75 1.14 0.84 1.18 0.80 1.85 1.10 0.96 1,15 0.91 1.96 1.08 1.05 1,14 1.01 1.26 1,06 1.25 1.12 1.26 1.29 1.03 1.31 1.09 1.30 1.1.24 1.01 1.25 1,08 1.25 1.20 1,03 1.19 1.09 1.20 1.15 1.04 1.17 1.10 1.16 1.93 1.04 1.06 1.11 1.00 1.93 1.03 1.05 1,10 0.99 1.90 1.03 1.07 1.10 0.99 1.96 1.04 1.19 1.12 1,08 1,01 1.06 1.23 1.15 1.12 1.01 1.07 1.18 1,17 1,10 1.10 1.08 1.26 1.18 1,18 1.17 1.16 2.29 1.27 2.23 1.55 1.35 3.52 1.46 3.54 1.4015 1.59 4,20 1.70 4,18 1.37 1,69 2.48 1.81 2.43 1.05 1.68 1.39 1.83 1.22 1.11 1.69 1.44 1.86 1.28 1,33 1.73 1.64 1,91 1.49 1.38 1.77 1.48 1,94 1.43 1.22 1.79 1,44 1.96 1.33 1.1.08 1.79 1,38 1.98 1.23 1.19 1.81 1.48 2,00 1.34 1.48 1.84 2.12 2,07 1.80 1.70 1.88 3.00 2.13 2.85 2.1.40 1,71 1.94 2.00 1.67 1.85 1.51 2.05 1.82 1.95 1.~.I'f~iit.i1!i!ta1L.'i,~.~g.i~4~it~_.
1.50
1.64
1.45
1.46 52-1.75
1.69 1.74
IGI''URCES, INC.
ANALYSIS O~JNTHLY SPOT PRICES
AS REPORTED BY INSIDE FERC GAS MARKET REPORT
FIRST OF MONTH PUBLICATION
NORTHWEST PIPELINE
CANADIAN BORDER ROCKY MOUNTAIN AVERAGE OF BOTH
ROLLING ROLLING ROLLING
MONTHLY 12 MONTH MONTHLY 12 MONTH AVERAGE 12 MONTH
MONTH INDEX AVERAGE INDEX AVERAGE OF BOTH AVERAGE
FEBRUARY 1988 No Subscription No Subscription
MARCH No Subscription No Subscription
APRIL No Subscription No Subscription
MAY No Subscription No Subscription
JUNE No Subscription No Subscription
JULY No Subscription No Subscription
AUGUST No Subscription No Subscription
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
JANUARY 1989
FEBRUARY
MARCH
APRIL
MAY
JUNE
JULY
AUGUST 1.12
SEPTEMBER 1.21
OCTOBER
NOVEMBER 1.40 1.21 1.38
DECEMBER
JANUARY 1990
FEBRUARY
MARCH 1.18
APRil
MAY No Spot Avail.
JUNE No Spot Avail.
JULY No Spot Avail.
AUGUST No Spot Avail.
SEPTEMBER No Spot Avail.
OCTOBER
NOVEMBER
DECEMBER
JANUARY 1991 1.45
FEBRUARY
MARCH
APRil
MAY
JUNE
JULY
AUGUST
SEPTEMBER 1.08
OCTOBER
NOVEMBER
DECEMBER 1.40
JANUARY 1992 1.40
FEBRUARY
MARCH
APRil
MAY
JUNE
JULY 1.19 1.15
AUGUST 1.18
SEPTEMBER 1.27
OCTOBER 1.13
NOVEMBER 1.15
DECEMBER 1.95
JANUARY 1993
FEBRUARY 1.56 1.43
MARCH
APRil 68 1.80 1.56
MAY
JUNE
JULY
AUGUST
SEPTEMBER 1.75 1.92 1.85 1.80
OCTOBER 1.75 1.83
NOVEMBER 1.80
DECEMBER
Mofhtt Thomas
MOFFATT THOMAS BARRETT ROCK & FIELDS, CHTD. ""'.1 ~.
Eugene C Thomas Michael T. Spink C Clayton Gill 2Ju i 11:J - 8 r 1'1 .
John W. Barrett Michael G. McPeek Stephen J. Olson
. '_.. '
R. B. Rock Kirk R. Helvie Stephanie A. Balzarini
" : '-
) i
. '
I '
...
Richard C Fields ThomasCMorris DavidP.Gardner ~
': '::
CCJ(jiill:JS!Oi"Robert E, Bakes Robert B. Burns Julian E. Gabiola '-' I \ \... I I
John C Ward James C Dale Paul C SwainstonGary T. Dance Michael E. Thomas John W. KluksdalLarry C Hunter Patricia M. Olsson Elisa G. Massoth
Morgan W, Richards James C deGlee Ray J. Chacko
Mark A. Ellison JoAnn C Buder Dean C Sorensen
Randall A. Peterman Bradley J Williams Bradley J. Dixon
Mark S. Prusynski Lee Radford
Wilt M iffiStephen R. Thomas Michael O. Roe IS
. ~
aft
Glenna M, Christensen David S. Jensen 1907-19 0
Gerald T. Husch James L. Marrin
Ms. Jean Jewell
Idaho Public Utilities Commission
472 West Washington
Post Office Box 83720
Boise, Idaho 83720-0074
Re: Case No. INT-Ol-
Case No. INT-G-OO-
Intermountain Gas Co.
MTBR&F File No. 11-500.290
Dear Ms. Jewell:
::CEI'/ED
:iU::~l
Boise
Idaho Falls
Pocatello
US Bank Plaza Building
101 S Capitol Blvd 10th FI
PO Box 829
Boise Idaho 83701 0829
March 8, 2001
via Hand Delivery
208 345 2000
800 422 2889
208 385 5384 Fax
www.moffatt.com
Pursuant to PUC IDAP A Rules 31.01.01.067, 31 01.01.233 and 31.02.01.005.07 and pursuant
to Idaho Code Section 9-340D and Section 48-801 et seq., Intennountain Gas Company hereby
files its Natural Gas Procurement, Asset Management and Administrative Service Agreement -d.~with IGI Resources. The enclosed Agreement is confidential and a trade secret. We ask that it--
L......,
be protected from inspection, examination or copying by any person other than the PUC staff. "f\~
-. '" .
'--'J' 'Yi'Ii!--:t,-..I.,.j
.......
..J~
~~
Thank you for your cooperation. If you should have questions or comments, please contact
Michael McGrath (377-6168) or me.
Very truly yours
Morgan W. Richards, Jr.
MWR/jrt
Enclosures
BOI MTl :335823,