20010420Reply to Second Production Request.pdf

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EXECUTIVE OFFICES RECEIVED
INTERMOUNTAIN GAS COMPANY FilED
555 SOUTH COLE ROAD. P.O. BOX 7608. BOISE, IDAHO 83707. [phone] . FAX: 2nnf~R 20 AM II:
April 20 , 2001 iDAHO PUBLIC
UTILITIES COMMISSION
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
P. O. Box 83720
Boise, 10 83720-0074
RE:Case No. INT-01-
SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO INTERMOUNTAIN
GAS COMPANY
Dear Ms. Jewell:
Shown below are the Company s responses to the Staff's Second Production Request:
ReQuest No. 15:What is Intermountain Gas Company doing differently this year to reduce the deferral
account and cost of gas purchases to below the approved weighted average cost of gas (WACOG)?
Please include an analysis showing this year as compared to previous years.
Answer: This past year, as with previous years, Intermountain managed its supply and transportation
portfolio in a manner consistent with its overall objectives regarding security, reliability and price.
The market prices for natural gas have continued to rise beyond the W ACOG included in the
Company s current prices.
Northwest Pipeline is bi-directional, which necessitates the procurement of gas supplies by
Intermountain Gas Company from both north and south of the Canadian border. This past winter, the
price differential between Sumas and the Rockies was dramatic. There was up to a $7.70/MMBtu
differential paid for Canadian gas coming out of Sumas as compared to natural gas procured out of the
Rockies. Exacerbating the need to purchase expensive Canadian supplies were the "announced"
periods of pipeline entitlements with Northwest Pipeline. Contractual obligations with Northwest
Pipeline dictate that during periods of announced Operational Flow Orders ("OFO'), Intermountain
must inject gas into the pipeline from its primary receipt points which may result in a larger percentage
of volumes being taken from the more expensive Canadian basins. Such was the case this past winter
heating season. Given this constraint, however, Intermountain maximized the takes out of the Rockies
to help minimize the overall WACOG.
Intermountain s stored gas advantage is unique in the Northwest in that over 40% of Intermountain
normalized annual needs are held in storage. Natural gas held in storage continues to provide
Intermountain s customers with the added benefit of a summer price hedge against the higher winter
prices. Stored gas , after being managed to insure its availability during winter peak sendout periods
has subsequently been depleted to maximize its winter/spring price advantage.
During this period of volatile natural gas prices, regular and frequent meetings are held with our
Administrative Service Agent, IGI Resources, to investigate and discuss the appropriateness of
remaining with indexed pricing vs. employing some other financial tools as noted below.
Reauest No. 16:How does the Company plan to improve price stability for its ratepayers? Please
include all specific information available such as contracts, hedges, etc.
Answer: Intermountain is considering the use of Price Caps on a portion of its purchase requirements
to help insulate its customers from the potential for market price volatility. While "capping" the unit price
per them, Price Caps also allow for the benefit and pass through of declining market prices , should they
occur after the Cap is in place. As with any financial instrument designed to lock-in prices, Price Caps
also carry a price tag. As an example , a winter price cap for Sumas gas would cost approximately
$3.50/MMBtu. This incremental layer of cost would therefore increase the overall WACOG.
Intermountain must employ its judgement in determining whether the costs of these types of tools are
commensurate with the risks of prices going higher. It's important to remember that the market exercise
that allows for these types of financial instruments require a buyer and a seller, each party believing
that prices will move in an opposite direction.
Reauest No. 17:In the letter dated March 8, 2001 , the Company stated that it made decisions not to
secure gas because gas prices were anticipated to go down in 1999 and 2000. Please provide all
meeting notes, memorandums, decision flow charts that include personnel involved, or any other
documentation the Company can provide that outlines the decision process during this time period.
Answer: Again, 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 range. In 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 decade long historical levels. 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 or be indicative of the actual
cash price as that respective forward period became the present. To further demonstrate the unknown
direction of natural gas prices during this past 12 months, Attachment No.6 shows a week before the
unprecedented cash price (Nov.'OO) fly up when even the Futures Prices (a surrogate for the collective
wisdom of the marketplace) were trending down. Extreme judgement is called for during these
uncertain periods. Intermountain believes that in times such as this, a return to market supply demand
fundamentals will ultimately return and judgements should be driven largely on those fundamentals.
Reauest No. 18:Please provide (confidentially, if necessary) any written policies used by the Company
when making Natural Gas purchases.
Answer: Intermountain s General Service Provisions and Administrative Service Agreement's on file
with this Commission contain our written policies. Those , plus the judgements described throughout
these comments, form the basis for our practices. These practices are augmented by the hard data our
annual Load Duration Curve Study provides which is an essential part of our Integrated Resource
Planning process.
Reauest No. 19 Provide an analysis showing the cost and any premium over the physical price of gas
for the possible financial hedge products outlined in your letter dated March 8, 2001 on page 6 (Le.
Price Caps, Price Collars, Portfolio Pricing, Extendables , Participating Options, and IGI Pool
Participation). Please define all of the products and any possible effects of these products to
ratepayers.
Answer: Following is a definition of certain natural gas options which Intermountain and IGI have been
considering. As to these products, all represent financial pricing techniques and the costs associated
with each have been explained. The physical purchase of gas from the supplier must still be done so
as to match the physical and financial sides of the transaction. The premium to be assessed by the
supplier for guaranteeing dedicated firm delivery of gas will be discussed elsewhere in the answers to
this Second Production Request.
Price Cap:
A cap is an option that provides the buyer of the cap the firm assurance that his index price for the
period will never go higher than the cap strike price. Each month the market price for the current month
(the monthly index) is measured against the cap strike price. If the index price is higher than the cap
strike price , the buyer pays the cap strike price. If the index price is lower than the cap strike price , the
buyer pays the index price.
The buyer of the option pays for this assurance in the "premium . The premium is generally paid up
front when the buyer agrees to purchase the cap.
When the buyer purchases the cap, it will be more expensive if the cap strike price is closer to the
current market price. Also, the cap will typically be more expensive the longer the term before the
option expires.
Shown below are three indicative caps for this coming winter for the Rockies (NWP), Sumas and AECO
indices.
For example, a buyer can purchase a $6.30 cap for the Rockies index (Cap Strike Price 3) for this
coming winter. The buyer would be required to pay $1.08 / MMBtu for the assurance that he would
never be charged more than $6.30 from November, 2001 through March , 2002 for volumes
purchases into NWP in the Rockies. The current premium cost for this cap for 10 000 MMBtu/d is
approximately $1.63 million.
Rockies Sumas Aeco
Current Market $5.$ 9.$5.
Cap Strike Price $5.$10.$5.
Cap Premium $1.$ 3.$0.
Cap Strike Price 2 $5.$10.$6.
Cap Premium $1.$ 3.$0.
Cap Strike Price 3 $6.$10.$6.
Cap Premium $1.$ 2.$0.
Price Collar:
A collar is an option package consisting of both a cap and a floor. This option can be structured so that
the buyer pays no premium (costless). The buyer gets the firm assurance that the index price will
never go higher than the cap strike and they avoid the premium cost of the cap. However, the cap
premium is "funded" by the buyer providing a floor for the index price to their supplier. The buyer
price is locked into a range between the floor and the cap during the term.
Shown below are three indicative costless collars forthis coming winter for Rockies Sumas and AECO
indices.
For example, a buyer can purchase a $6.30 cap for the Rockies index (Cap Strike Price 1) for this
coming winter. The buyer would not be required to pay for the assurance that he would never be
charged more than $6.30 from November, 2001 through March , 2002 for volumes he purchases into
NWP in the Rockies. However, the cap is funded with a $5.05 floor the buyer provides to the supplier.
In effect, the buyer guarantees that he will pay between $5.05 and $6.30 for NWP Rockies supplies this
winter.
Rockies Sumas Aeco
Current Market $5.$ 9.$5.
Cap Strike Price $6.$11.$6.
Floor Strike Price 1 $5.$ 9.$5.
Cap Strike Price 2 $6.$11.$6.
Floor Strike Price 2 $4.$ 9.$5.
Cap Strike Price 3 $8.$14.$7.42
Floor Strike Price 3 $4.$ 8.$4.
Portfolio Pricin
Portfolio pricing is a methodical process whereby the buyer determines a time frame (usually 3 to 5
years on-going) over which to periodically lock-in or fix a portion of its annual natural gas usage.
Typically a minimum and maximum percentage of such annual usage is identified such that at certain
points in time the buyer s usage for the multi year time period has been fixed within the minimum and
maximum range. The portfolio is structured such that at the beginning of year one of the period the
majority of that year s usage has been fixed and a smaller percent of each subsequent year s usage
has been fixed. For example, a portfolio of 5 years could be structured such that at the beginning of
year one the following percentage of annual usage would be fixed:
Beainnina of Period
Annual Usaae Percentaae FixedMinimum Maximum
Year 1
Year 2
Year 3
Year 4
Year 5
80%
60%
40%
20%
10%
100%
80%
50%
40%
25%
Extendables:
An extendible is an option package that allows a buyer to lock in a fixed price substantially below the
current market. The buyer gets the discounted fixed price but funds the discount by providing the
supplier the option to extend the term of the sale an additional year at the same fixed price.
Shown below are three indicative extendible options for the next 11 months (May, 2001 through March
2001) for the Rockies, Sumas and AECO indices.
For example , a buyer can purchase Rockies gas at a fixed price of $4.35 for May 01 - Mar 02 when the
current market is actually $4.807. The first year fixed price discount of $0.457 is funded when the
buyer allows the supplier (at the supplier s sole election) to extend the term of the sale at the same
price ($4.35) for an additional 12 months.
Rockies Sumas Aeco
Current Market May 01 - Mar 02 $4.807 $7.$5.44
Apr 02 - Mar 03 $4.272 $5.$4.48
Fixed Price if supplier has
the right to extend 1 year
at the same volume and $4.$6.$4.
price
First Year Discount - $0.457 - $1.130 - $0.790
Discount off Average $0.178 $0.227 - $0.289
Notice period for the Extension is any time up to 5 days prior to the beginning of the 2nd Year
Participatinq Options (Double Up):
A double up is an option package that allows a buyer to obtain a discount to the monthly index price.
The discount is funded when the buyer provides the supplier the option to double the volume any day
during the delivery month for any month of the term of the option. The price for any additional volume
is the first-of-the month index price (FOM).
Shown below are three indicative double-up options for the next 11 months (May, 2001 through March
2001) for the Rockies , Sumas and AECO indices.
For example, a buyer can purchase Rockies gas at the Rockies index minus $0.15/ MMBtu. The index
discount of -$0.15 is funded when the buyer allows the supplier (at the supplier s sole election) to
double the volume any day of the month.
Current Market*
Rockies Sumas
$4.807 $7.
Aeco
$5.44
Index discount if bp has
the right to double volume
any day during any month
at the index price
- $0.15 - $0.- $0.
Discount on 1 st tier - FOM less
Price of 2nd tier if sourced
- $0.15 - $0.
FOM FOM
- $0.
FOM
FOM = First of Month Index Price
IGI Pool:
The IGI Pool is a purchasing strategy developed by IGI allowing a customer to manage its price for
natural gas within today s volatile and rapidly changing environment by entrusting the pricing decisions
to the IGI staff of expert traders. It works very simply. The customer chooses up to three pricing
seasons and agrees to dedicate a daily baseload quantity of gas purchased from IGI to a particular
season. The seasons are:
November 2001 to March 2002
November 2001 to October 2002
April 2002 to October 2002
IGI will then solely decide when to execute the various trades which ultimately establishes a final fixed
price for the selected season. IGI then reports its final fixed price for the season to the customer
usually within 30 days of the start of the season. IGI, through its expertise, timing and active
participation in the daily natural gas futures market believes it can develop a fixed price favorable to the
customer without the hassle of constant communication as to current pricing and the "should we or
should we not" decision which often times results in a buying opportunity disappearing. Last year, for
one group of customers selecting our pool option, IGI executed over 100 individual trades which yielded
substantial savings versus the monthly index price and price stability in an extremely volatile market.
The customer, however, must understand that IGI cannot guarantee an ultimate savings versus the
index.
Reauest No. 20:Given the Company s reliance on storage for price protection, please provide a cost
comparison between storage costs (including losses, fuel and any other costs associated with storage
use) as compared to all costs associated with financial hedges.
Answer: Listed below are the current storage facilities to which Intermountain has contractual rights
(data in thousands):
MMBtu
Capacitv
Fixed
Cost
Variable
Cost
Total
Cost
Plymouth LS 771 032 $560 592
Jackson Prairie 092 734 104 838
SGS
Clay Basin 858 343 626 969
AECO 3,460 501 236 737
SoCal 450 513 585
631 123 598 $8,721
100%
Cycling
Cost per
Unit
$3.362
770
678
213
300
$0.750
The Jackson Prairie, Clay Basin and AECO arrangements above are the storage facilities now
managed by Duke and for which Intermountain receives an approximate $500 000 per year reduction in
the above noted cost. Not included in the above summary is Intermountain s company owned LNG
facility located in Nampa, Idaho.
As to the comparison of the above noted storage costs with "all costs associated with financial hedges
such a comparison is not practical as any cost associated with a financial hedge (fixed for floating price
swap) will be embedded within the price quoted by the counterparty. These counterparties do not
charge a separate transaction fee for any such hedges transacted.
Reauest No. 21:What price is anticipated for storage gas in the next 12 months?
Answer: The typical storage injection cycle is the period of April to October each year. Listed below
are the anticipated cost of Intermountain s storage gas based upon future price quotes as of April 16
2001. Also , as an alternative, the company has listed the cost of a price cap for the same period based
upon such quotes as of the same date.
Sumas Rockies AECO
April Index $5.$4.$5.
May - October Future Quote $5.$4.$5.
April - October Average $5.$4.$5.
May - October Price Cap:
Strike Price (Ceiling)$5.$4.$5.
At the Money Cap Cost per Unit $1.$0.$0.49
Total Cap Cost on a
000 MMBtu per day gas block $920 000 $736 000 $450 800
Reauest No. 22:What steps has Intermountain Gas taken to ensure storage gas is purchased at the
lowest price?
Answer: Request No.'s 22 & 23 both encompass questions dealing with Storage. That being the case
a single answer to both requests is provided below and is included in the response to Request No. 23.
Reauest No. 23:Please provide the information and resulting analysis upon which the Company
determined that it is operating at the optimum level of storage for its customers.
Answer: The analysis of Intermountain s storage adequacy is actually an on-going process which is
reviewed a number of ways each year. By way of a background summary, Intermountain s storage at
Nampa, Plymouth and Jackson Prairie are actually utilized as peak day storage facilities. These
facilities are quite flexible in operation and provide for a large amount of gas to be withdrawn on a daily
basis. At maximum withdrawal levels , Nampa and Plymouth can be emptied in approximately 10 days
and Jackson Prairie in approximately 50 days. Additionally, these facilities carry firm transportation
rights on Northwest Pipeline which are in addition to Intermountain existing rights. When
Intermountain contracted for its Clay Basin and AECO storage rights it did so with three objectives in
mind. Greater access to lower priced summer gas supplies (these facilities are characterized as supply
basin storage facilities rather than market area); additional winter demand service availability for
Intermountain s growing residential/commercial market and ability to improve Intermountain s annual
take commitment or load factor with its suppliers.
Intermountain s decision on the SoCal storage arrangement was again done in anticipation of a growing
peak day need for its residential/commercial market. The structure of the SoCal arrangement provides
for a city gate delivered gas supply during the period November - February each year. This
arrangement was significantly less expensive then contracting for additional year-round capacity on
Northwest Pipeline.
As mentioned initially, Intermountain s review of its storage adequacy, as well as ensuring the most
economic cost of such storage gas is an on-going process. On an annual basis , a multi-year Load
Duration Curve study is conducted to determine Intermountain s future capacity needs given normal
weather and certain load growth assumptions. These studies are then sensitized to determine changes
to those needs under both a warmer and a colder than normal weather scenario. Additionally, as part
of the annual PGA process and then monthly thereafter as each new month of actual data is received
the estimated monthly system supply requirements are identified and a plan for the optimum sourcing
of gas supply to meet those needs is laid out, including storage injections and withdrawals. On a more
fine tuned basis, as part of IGI Resources' (Intermountain s agent) monthly bid-week process, a precise
plan for Intermountain s upcoming month's needs is developed taking into account such things as time
of year, storage levels, weather expectations near term, regional supply, demand and pricing dynamics
which may effect price and availability of gas supply and upcoming month price expectations for
monthly as well as after-market or day gas pricing. This plan is reviewed jointly by IGI and
Intermountain.
Finally, on a daily basis, Intermountain is in contact with various industry communications and
publications as well as with its agent, IGI to discuss realities, opinions and expectations of the matters
outlined above and how that affects the outlook for Intermountain and insuring Intermountain continues
to secure the most diverse , reliable and economic priced gas supplies for its customers.
Reauest No. 24:Please provide an analysis showing storage injections and withdrawals for fiscal
years: 1996 , 1997, 1998, 1999, 2000 and proforma 2001. Please include the price paid for stored gas
and the market price for gas available on the wholesale market when storage gas withdrawn.
Please see Attachment No 1. Please note on the Attachment that, for the period depicted, over $17
Million in savings has accrued to Intermountain s customers as compared to the applicable indexed
price.
Reauest No. 25:Please provide the names, qualifications, and job descriptions of all natural gas
traders on Staff with the Company.
Answer: There are no "gas traders" on the staff of Intermountain Gas Company. The gas trader
function is included within the outsourced services provided by IGI Resources.
Reauest No s. 26-31:Request's No.'s 26-31 all encompass questions dealing with the coordination
and delineation of responsibilities between the Company and IGI Resources when making gas
purchase decisions. That being the case, a single answer is being provided here which the Company
hopes will satisfy the entire Request No.'s noted above.
Answer: Intermountain performs an assessment of long-term (one to five year) natural gas demand on
a regular basis. This demand forecast is presented in aggregate form as well as a Load Duration Curve
that examines the daily gas requirement needs during the winter and shoulder month periods. The
demand forecast is viewed in light of the available transportation , storage, and contracted gas supply
resources to identify any deficits in the available delivery or supply volumes. Supply resource deficits
typically take the form of 1) base load deficits that can be supplied with annual supply contracts, 2)
shoulder month deficits that can be met with a combination of storage and seasonal supply contracts
and 3) needle peaking deficits that, although generally met with storage , may require short-term or spot
market purchases. Acting as our Agent, IGI Resources is directed by the Company to solicit on
Intermountain s behalf the necessary supply resources to meet any projected deficits. As previously
more fully delineated to this Commission, all resource options are procured consistent with the
Company s overall objectives regarding security, reliability and price. Once the supply portfolio is in
place, it must then be managed on a day-to-day basis matching the supply to the daily needs of our
customers. The Company s Gas Control Department provides IGI with a "one month ahead" look at our
anticipated demand. This forecast embodies the aforementioned Load Duration Curve as well as the
latest outlook for the weather. Resources again matches this shorter-term demand forecast against the
contracted supplies already in place to determine if existing supplies are adequate, whether or not
additional short-term supplies are necessary, opportunities for off-system sales, and opportunities for
short-term transportation acquisitions or releases. Additionally, a daily requirements forecast is
performed and transmitted to IGI which fine tunes our daily gas needs and incorporates the most up-to-
date weather outlook.
This systematic approach to procuring supplies to meet projected needs, given in summary fashion
above , occupies the talents and direction of a team of individuals at Intermountain Gas Company. Ron
Ernest, Manager of Gas Supply, Michael P. McGrath, Director of Market Services and Regulatory
Affairs, Michael E. Huntington , Vice President of Marketing and External Affairs and acting Gas Supply
Officer, N. Charles Hedemark, Executive Vice President and Chief Operating Officer, and William C.
Glynn , President, all have a direct involvement in the process. This team of individuals insures that no
gas supply contract, either long-term or short-term, is consummated without due diligence as to it's
need or the related aspects of security, reliability and price. Daily pricing information is prepared by the
agent and sent to the Intermountain team of professionals and regular meetings are held to review the
appropriateness of remaining with indexed pricing vs. employing some other financial tool as noted
above.
Reauest No. 32:Please provide confidential copies of all of the Company s existing gas purchase
contracts.
Answer: The Company and Staff agreed that the voluminous gas purchase contracts, the same
contracts as reviewed each year as part of the PGA Audit, will continue to be made available for
inspection at the Company s office at 555 South Cole in Boise.
Reauest No. 33 Please provide the anticipated price (unit price and total contract amount) for gas
purchased under these contracts for the next 12 months.
Answer: As shown in the response to Request No. 40 , Intermountain Gas Company anticipates filing
its next PGA sometime during May of this year. Included as part of that filing will be the anticipated unit
price and total contract amounts for purchases under its existing gas supply contracts.
Reauest No. 34:Please provide the annual quantity of gas purchased at index prices , the actual index
price, and any adders.
Answer: As was discussed in Intermountain s answers to the Commission s First Production Request
with the maturation of the natural gas futures contract (NYMEX) and the development of the over-the-
counter financial derivative market, producers began to sell their gas only at monthly indexed based
pricing. As such , over the past three years, essentially 100% of Intermountain s gas supplies have
been purchased at a first of month index price. Attached to Intermountain s answer to the
Commission s First Production Request was a schedule which details the monthly index for Sumas and
Rocky Mountain deliveries to Northwest Pipeline. Summarized below is the index price for the last 12
months and the approximate premium to index which Intermountain has paid the supplier for the
assurance of "firm" gas supply delivery throughout the years.
Sumas Rockies AECO
Index Premium Index Premium Index Premium
April 00 $2.$0.$2.$0.$2.603 $0.
May 743
June 257
July 727
August 296
September 3.45 3.41 633
October 587
November 664
December 13.352
January 01 14.104
February 387
March 208
Reauest No. 35:Provide the Company s load projections in aggregate and by customer class for the
next 12 months.
Answer: PI"ease see Attachment No.
Reauest No. 36 Provide the Company s market price projections for natural gas for the next 5 years.
Answer: Following are the natural gas future price quotes for the next 5 years based upon quotes
received April 16, 2001.
Sumas Rockies AECO
May - October 2001 $5.$4.$5.
November 2001 - March 2002 10.
April - October 2002 4.48
November 2002 - March 2003
April- October 2003
November 2003 - March 2004
April - October 2004
November 2004 - March 2005
April - October 2005
November 2005 - March 2006 4.45
April- October 2006
Reauest No. 37:Please provide the Company s annual natural gas purchase projections for the next 5
years including quantity, price and WACOG.
Answer: See following graph.
Intermountain Gas Company
Annual Natural Gas Purchase Projections
(MMBtu
FY01 FY02 FY03 FY04 FY05
955 356Purchase Requirements 935 156 331 913 798 509 338,434
While the future price quotes noted above in response to Request No. 36 are market indicators of
future prices , it remains the Company s judgement that prices for years 2-5 will be less than these
prices and be closer to $3.00/MMBtu.
Reauest No. 38:Please provide an update of actual purchases shown on the Intermountain Gas
WACOG Calculation spreadsheet from the most recent PGA filing.
Answer: Please see Attachment No.
Reauest No. 39:What is the expected deferral amount for the next 12 months under current regulatory
conditions?
Answer: Intermountain anticipates its deferred gas commodity costs (uncollected commodity costs)
which will be included as part of its upcoming PGA will approximate $50 Million. This deferred amount
should extinguish pursuant to a favorable Order from this Commission allowing for its recovery.
Reauest No. 40 When does Intermountain Gas anticipate its next PGA filing will occur? What does the
Company anticipate that increase will be?
Answer: Intermountain anticipates filing its next PGA sometime during May of 2001. Intermountain will
be requesting an increase due mainly to the large amount of uncollected deferred gas costs as well as
an increase in the embedded WACOG. The exact magnitude of the requested increase will be shared
with the Commission within the next several weeks.
Reauest No. 41:Please provide any studies performed by the Company or its agents determining the
best natural gas supply portfolio with respect to both reliability and price.
Answer: Please reference the analysis and discussion provided as part of the Company s March 8th
transmittal.
Reauest No. 42:In the January 1996 Integrated Resource Plan (IRP) the Company recognized
potential problems with supply from Sumas. The Company stated that the percentage of future natural
gas supply from Sumas will be reduced from a high of about 63% to approximately the following:
Sumas
Alberta
Rockies
20%
40%
40%
Based on the Company s March 8 letter the Company s current supply portfolio is:
Location Dail Volume Annual Volume
Sumas 28.48.
Alberta 16.
Rockies 62.35.
What were the assumptions made and analysis performed to determine the above
supply portfolio?
What situations changed that caused the Company to move away from the direction
stated in its 1996 IRP?
How does this new portfolio provide optimum price and reliability for Idaho ratepayers?
How would ratepayers have been affected if the Company had achieved the 1996 IRP
goals?
Answer: It is the Company s belief that the Commission Staff may have misunderstood the information
and data that was presented in both its Integrated Resource Plan and the March 8th transmittal to the
Commission. This misunderstanding, the Company believes, has led to an "apples to oranges
comparison by the Staff of the information portrayed in these documents. The data referenced from the
IRP represents the Company s firm contract demand rights at the various supply basins for firm
transportation on Northwest Pipeline s mainline transmission system. In other words , of the projected
contract demand total of 198 000 MMBtu s per day, 20% or approximately 41 000 MMBtu per day are
for deliveries from Sumas. The data referenced from the March 8th letter referenced only the
Company lonq-term supply contracts in place which is not the total supply ultimately purchased during
the year, as the Company does purchase additional monthly indexed based supplies as well.
Reauest No. 43:What is the availability of longer term (greater than 2 year) fixed price contracts?
Answer: The ability to fix the price of natural gas purchases over longer periods (greater than 2 years)
is readily available through most counterparties actively involved in natural gas futures activity in our
region here in the Pacific Northwest.
Reauest No. 44:What are the typical terms included in fixed price contracts?
Answer: This question has two answers. One relative to the physical side of the deal (the actual
purchase of gas from the supplier) and the other relative to the paper or financial side of the deal (the
financial derivative transaction).
As to the physical side of the transaction, suppliers will usually want a 100% load factor commitment
with certain gains or losses for non-compliance being passed on to the buyer. The gas will typically be
priced monthly equal to the published monthly index for the receipt point of gas delivery. The supplier
will also command a premium to this published index as a cost for his guaranteeing firm delivery 365
days a year and dedicated to you as the buyer. If the supplier is willing to back off the 100% load factor
requirement he will likely require a higher premium to index for doing so.
As to the financial or paper side of the transaction , counterparties will usually require the buyer to have
an ISDA contract in place with them (standard contract for the International Swap Deals Association).
The primary terms of this contract as it relates to financial derivative transactions are (1) any such
transaction represents an immediate "take or pay" arrangement as it relates to cash flow, (2) there is no
force majeure provisions under the ISDA contract and (3) depending on each counterparty s evaluation
of the buyer s creditworthiness, periodical margining may be required on any negative - out of the
money position as between buyer and the counterparty.
Reauest No. 45:What is the Company s evaluation of fixed price contracts with regard to financial and
other considerations?
Answer: As mentioned before in the company s response to the First Production Request, any
decision as to fixing or not fixing a price requires the exercise of considerable judgment. It represents
one entities belief that prices are or likely will rise in the future and protection against such rise is
desired. It can also represent a buyer s desire to stabilize prices at a level that is considered workable
in a particular circumstance. If an entity considers using options such as a price cap then the added
financial cost is the cost of the premium for such a product. One must always remember that the ability
to enter into these fixed price arrangements means the selling party believes the price of the commodity
is going to move in the opposite direction that the buying party believes the commodity will move.
other words, each transaction has a "winner" and a "loser" after it is consummated. Each party, in the
exercise of his judgment, must consider the consequences, if any, for being the "loser" at the end of the
day. Additionally, as more fully delineated in the Company s response to request No. 17 , extreme
judgement is called for during these uncertain periods. Intermountain believes that in times such as
this, a return to market supply demand fundamentals will ultimately return and judgements should be
driven largely on those fundamentals.
Reauest No. 46:How much of the Company s gas is purchased on both firm supply and firm price?
What is the cost for this gas?
Answer: On an annual basis, approximately 85% of Intermountain s gas supply is purchased and
priced on a firm basis and 15% is purchased on a spot basis. The firm price, as mentioned previously,
is typically a first of month index based price plus a premium assessed by the supplier for dedication of
the supply directly to the buyer on a firm basis , 365 days a year.
Reauest No. 47:When did the Company s last fixed price contract expire?
Answer: The company s last fixed price supply arrangement (a financial hedge) ended in June of
1999.
Reauest No. 48:Has the Company considered purchasing natural gas production?
Answer: No. Intermountain Gas Company believes that the pricing and costing complexities of a gas
production business activity would be very difficult for a regulated enterprise to accomplish on a Cost of
Service basis.
Reauest No. 49:Please provide any analysis the Company or its agents have performed regarding the
purchase of natural gas production.
Answer: Please reference Request No. 48.
Reauest No. 50:Acquisition of natural gas resources can be obtained in many ways. One method is
through demand side management. What, if anything, is the Company proposing in this area?
Answer: To encourage energy conservation through the use of efficient natural gas space heating
equipment, Intermountain provides a $200 rebate to those customers who replace an alternate space
heating fuel with a natural gas furnace having an efficiency rating of no less than 90%.
Intermountain continues to make a concerted effort to encourage its customers to conserve the natural
gas resource. Through person-to-person contact with our Customer Representatives, a "web presence
that educates our customers as to numerous "conservation tips , and continued conservation measure
mailings to our customers, Intermountain preaches the conservation ethic.
Reauest No. 51:Could the Company offer ratepayers longer term price stability? If so, at what cost?
Answer: In response to this question the answer is yes , Intermountain could offer its customers longer
term price stability through a number of measures but such activity does not occur without a cost and
the exercise of subjective judgment. A number of transactions can be utilized to "stabilize" price such
as price caps , multi-year fixed prices, etc. These products and their costs have been discussed
elsewhere in the Company s responses to this Second Production Request. At the end of the day the
most significant question is "
. ..
is price stability at today s price levels an acceptable solution for the
Company s customers.
Reauest No. 52:Could the Company offer individual customers supply options such as: 1 , 2 , or 3-year
contract prices, spot market prices, or Company portfolio pricing? If so, what is the anticipated cost of
these programs? If not, why not?
Answer: Intermountain s customers, on an individual customer level , could potentially be offered these
different supply options in an unbundled environment where multiple marketers vie for residential
market sales. As the Staff is aware , where these options have been made available to residential
customers through unbundling efforts in other market areas, many of the competing marketers have
elected to discontinue their participation in these programs. One impediment to marketer participation in
these types of programs are the costs associated with aggregating by "election type" and metering
each individual customer group on a real-time basis in order to balance supply type with demand.
Intermountain Gas Company makes no margin ($0.00 margin) on the commodity cost of gas to its
customers. Marketers must "mark-up" their commodity costs to earn a profit. This mark-up must also
cover the incremental costs associated with monitoring the various customer supply type groups which
has generally rendered the marketer unable to compete against the "no mark-up" regulated utility.
Experience has shown that customer participation in an unbundled environment has normally been
lackluster which has only exacerbated the marketers willingness to participate in such programs.
Customers in these unbundled environments have generally been unwilling to exercise the judgement
and time necessary to follow the market commodity prices and then make an informed, let alone
correct, decision as to their individual supply portfolio option.
Reauest No. 53:The Commission has ordered the Company on several occasions to provide a price
comparison and analysis of equivalent service providers other than IGI Resources. When will the
Company complete the required analysis?
Answer: Commission Order No. 28109 stated: "The Company is also encouraged to periodically test
the waters to determine whether other marketers have the ability to provide similar or better services at
a competitive price.
Intermountain Gas Company regularly seeks (tests the waters) for market intelligence as to who are
providers of the type of services its current Agent provides. This information is obtained in numerous
and periodic ways , Le. trade association meetings, conferences and magazines.
As this Staff is aware , the recent sale of IGI Resources to BP Energy Company, the 3rd largest energy
company in the world, can only serve to enhance the menu of services c;lvailable to our customers.
Services which , in an open market where customers are free to choose their marketing agent, have
been selected by over 90% of Southern Idaho s large industrial customers. Most of the natural gas local
distribution companies in the northwest have , or are currently, using the services of IGI Resources.
Idaho Power Company was recently added as a client of IGI Resources and other LDC's in the nation
have recently added BP as a service provider. No other competitor of IGI Resources provides the
quantity or level of services to the Northwest that IGI does. Intermountain is also currently under
contract with IGI Resources pursuant to our Administrative Service Agreement with them that was
recently renegotiated with them wherein a 20% reduction in the fee was obtained and passed on to
Intermountain s customers. Again, it is important to note that amidst the 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'
Intermountain Gas Company takes very seriously both the directions by this Commission and the
quality and cost of services provided to its customers and will continue to be vigilant in satisfying both of
these important constituents.
Reauest No. 54:How can the price actually paid by IGI Resources be verified to ensure that
Intermountain Gas is paying the same price for the gas?
Answer: All of Intermountain s term and monthly spot gas supplies are under contract directly between
Intermountain and the supplier. After IGI's review of the monthly invoice from these suppliers , as to
accuracy, such invoices are sent to Intermountain and are available at the Company for review. As to
any gas purchased directly from IGI , the procedure for this purchase and related pricing are outlined in
Article IV of the Natural Gas Procurement, Asset Management and Administrative Services Agreement
between IGI and Intermountain.
Reauest No. 55:Did Intermountain Gas, its customers, and/or IGI Resources gain any benefit from
capacity releases or off-system sales in the past 6 months? If so, what are the dollar amounts for each:
Intermountain Gas, Intermountain Gas Customers, and IGI Resources?
Answer: Intermountain and IGI did not receive any benefit from capacity releases or off-system sales
of gas in the past 6 months. Any benefit derived from such activity is a direct pass through to
Intermountain s customers.
Please see Attachment No.4 for an analysis of such activity in the past 6 months.
Reauest No. 56:Provide an analysis showing off-system sales in fiscal years 1999, 2000 and 2001. In
this analysis, please show if the sale was made from contracts or storage , the price paid by
Intermountain Gas (including any cost paid to IGI Resources), the price the gas was sold for , and which
company purchased the gas.
Please see Attachment No.
Reauest No. 57:How are Intermountain Gas Company stockholders affected by the increased cost of
gas?
Answer: The stockholders (owners) of Intermountain Gas Company have been directly impacted by
the increase in natural gas prices. Intermountain s Bad Debt expense is expected to increase this year
alone by at least 100% or $600 000 - $900 000. The increased costs to simply finance today s higher
commodity costs could reach $1 000 000. Additionally, there appears to be a reduction in the
consumption per customer per degree day ($earnings) believed to be caused by our residential
customers response to higher natural gas prices. Several industrial customers have discontinued using
natural gas and have switched to lower priced fuel alternatives reducing the stockholders pre-tax
earnings by approximately $375 000.
Intermountain Gas Company appreciates this opportunity to have this open dialog with the
Commission Staff to address the challenges and opportunities inherent in today s energy
marketplace.
Sincerely,~7~
Director, Market Services &
Regulatory Affairs
MPM/slk