U-1034-99 Penning Testimony.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
INTERMOUNTAIN GAS COMPAN
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Case No. U-1034-99
PREPARED TESTIMONY OF REED PENNING
Q. Please state your name, business address and position with
Intermountain.
A. My name is Reed Penning. My business address is 555 South Cole Road,
Boise, Idaho. I am a Vice President of Intermountain Gas Company.
Q. What has been your experience in the natural gas industry?
A. I joined Fish Service and Management Corporation in 1956 as a Cathodic
Protection Inspector. In 1957 I joined Intermountain Gas Company as a
warehouseman in Twin Falls. I have held various positions with
Intermountain in operations, gas measurement, gas control and gas
supply. In October, 1974, I was elected a Vice President.
I have attended Washington State University, Boise State University and
Idaho State University, the University of Wisconsin, the AGA Rate
Course and I am a graduate of the Stanford Executive Program.. I have
testified before this Commission and the Federal Power Commission.
Q. Would you briefly describe your responsibilities.
A. I have overall responsibility for engineering, production and
distribution, gas measurement, gas control, peak shaving facilities,
gas supply and the Company's position and presentations before the
FERC.
Q. What is the purpose of your testimony in this proceeding?
A. My testimony will review the background and development of the
Company's gas supply, and its relation to the Company's changing
markets and the Company's proposal to reduce its contract demand
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requirements with Northwest Pipeline so that we can most economically
and effectively deal with these changing conditions.
Q. Mr. Penning, since approximately 84% of the Company's cost to serve its
customers is in the cost of gas, could you give us some background on
Intermountain's gas supply and its present status.
A. Contracts under which Intermountain purchases gas from Northwest
Pipeline all terminate October 31, 1989. This includes our Firm
Service Contract, the ODL Contract for 1,630,000 therms a day resulting
in an annual volume of 594,590,000 therms, our contract for Jackson
Prairie Storage in the amount of 239,000 therms a day and an annual
volume of 8,611,000 therms, and our contract with the Plymouth LNG
plant in the amount of 720,000 therms per day with an annual amount of
7,705,000 therms. Substantially all of Intermountain's gas supply has
been supplied by Northwest Pipeline and its predecessor, El Paso
Natural Gas Co. and Pacific Northwest Pipeline. The pipeline was
originally designed to be fed from two main sources, that from the San
Juan Basin in the Four Corner Area in the south and from British
Columbia, Canada through Sumas in the north. Subsequently Pacific Gas
Transmission built a pipeline down from Alberta to service San
Francisco. That provided another source of supply from Canada into the
pipeline systeni. Fields such as Big Piney and other areas in the Rocky
Mountains feed the pipeline from the Rocky Mountain area. This results
in Intermountain being in an enviable position of having more than one
source of supply flowing in more than one direction. We have the
capability of receiving gas from British Columbia, gas from Alberta,
gas from the Rocky Mountains and gas from the San Juan Basin. The
disadvantage is that the southern sources alone, under the present
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pipeline system, could not adequately serve the northern portion of the
system if the Canadian sources were lost.
Q. What volumes have been received from these various areas?
A. Exhibit 1, Page 1 shows the different sources of supply from which
Northwest Pipeline receives its gas and the change in the amount of
volumes derived from these sources during the past few years. This
Exhibit is from the Northwest Pipeline Gas Balances Exhibit showing the
gas balance in 1980 in Column b and the proj ected gas balance in 1983
in Column d. You will notice that there has been an expansion in the
Rocky Mountain gas (other) and the San Juan gas and a decline in the
Canadian gas purchases. Exhibit 1, Page 2 shows the change in Canadian
Supply. During the past few years the supply of natural gas had been
split with 65% of the gas serving the system coming from Canada and 35%
of the gas coming from the U.S. However, with the 1978 Natural Gas
Act, the resulting increase in exploration and production in the U. S.
and some looping on the main pipeline, that situation has changed to
that in 1981, 50% of the gas came from Canada and 50% from the U.S. In
1983, the ratio should change further so that 55% of the gas will come
from domestic sources and 45% from Canadian sources, as is shown in
Exhibit 1, Page 1.
Until 1980, the reserve amounts of allocated the pipeline were
approximately 50% Canadian and 50% domestic. However, in the last
couple of years that has changed to where the reserves are
approximately 65% domestic and 35% Canadian.
Q. Please describe Northwest's Canadian gas supply contracts.
A. Northwest has for many years had two gas supply contracts with
Westcoast. The principal contract provides for export of British
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Columbia gas at the international border near Sumas, Washington under
export license GL-41. The other contract provides for export of
Alberta gas at the international border near Kingsgate, British
Columbia under export license GL-4.
The original Sumas contract with Westcoast was executed on December 11,
1954 by Northwest's predecessor, Pacific Northwest Pipeline
Corporation. It has been renegotiated and extended three times. The
present Sumas contract ("Fourth Service Agreement") was executed
October 10, 1969 and amended October 1, 1970 with a primary term ending
October 31, 1989 and continuing from year to year thereafter. It
provides for deliveries of 809,000 Mcf per day up to 281 Bcf annually.
Under the annual averaging provisions of license GL-41, Northwest is
entitled to take up to 295 Bcf annually through the remaining term of
the Fourt Service Agreement.
The Kingsgate Contract with Westcoast was executed by Northwest's
predecessor, El Paso Natural Gas Company, on September 23, 1960 and
amended July 6, 1979 with a term ending October 31, 1989. It provides
for deliveries of 151,731 Mcf per day and up to 52 Bcf annually.
Deliveries under the Kingsgate Contract are limited by Westcoast i s
export License GL-4, which authorizes exports at contract levels
through October 31, 1984, but requires a 25 percent reduction in daily
quantities and annual quantities each year thereafter through October
31, 1987, at which time the export authorization terminates.
In addition to these two longstanding export contracts under licenses
GL-41 and GL-4, on December 1, 1981, Northwest conditionally acquired
the interest of El Paso under an agreement dated July 20, 1979 between
Westcoast, as seller, and El Paso, as buyer, providing for sale and
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delivery of an additional 60,000 Mcf per day at the Sumas delivery
point. The El Paso Agreement also expires on October 31, 1989. The
National Energy Board of Canada previously authorized the export of the
additional 60,000 Mcf per day pursuant to the terms and conditions of
license GL-41. El Paso's assignment to Northwest is conditioned upon
the implementation of a November 12, 1981 amendment to the Fourth
Service Agreement.
In the November 12, 1981 amendment to the Fourth Service Agreement, it
was agreed by Northwest and Westcoast, subject to certain conditions,
that: (1) the El Paso Agreement would be consolidated into the Fourth
Service Agreement; (2) a 65 percent annual load factor commitment would
be applied under the Fourth Service Agreement; and (3) as volumes at
Kingsgate decline after October 31, 1984 as a result of the provisions
of export license GL-4, certain volumes authorized unde~ GL-41 will be .
shifted from Sumas to Kingsgate to maintain minimum daily deliveries at
Kingsgate at 100,000 Mcf per day through October 31, 1989.
The minimum annual volume obligation relating to the 65 percent load
factor will be computed in each year by multiplying 65 percent by the'
annual volumes available during the next five years under license GL-41
and dividing that product by five. To the extent that there are less
than five years of export volumes remaining during any given year, the
minimum annual volume obligation will be reduced proportionately. The
amendment is conditioned on the obtaining of requisite regulatory
approvals of the new firm sale to Texas Eastern Pipeline Corporation
and/ or Transwestern Pipeline Company.
On January 14, 1982, Northwest entered into an agreement for the firm
sale of up to 325,000 MMtu per day (with 25,000 MMtu of that amount
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subject to availability of system supply) to Texas Eastern Pipeline
Corporation and/or Transwestern Pipeline Company. To allow Northwest
to make a daily firm sale of the volumes indicated above, Northwest
will be required to provide for the expansion of the Clay Basin Storage
Field in Utah by an additional 240,000 Mcf per day. Northwest will
then utilize the additional daily deliverability of the 60,000 Mcf per
day under GL-41 from Westcoast acquired from El Paso on December 1,
1981, along with the expansion of the Clay Basin storage to meet the
requirement of this contract on peak days. This use of storage will
enable Northwest to utilize the annual volumes available from Westcoast
without substantially increasing the need for daily deliverability from
Westcoast. Application has been made to the Federal Energy Regulatory
Commission for approval of this firm sale to Texas Eastern/Transwestern
which is proposed to commence on October 1, 1983, and continue through
October 31, 1989, and from year to year thereafter. The entire
transaction is based upon the availability of Canadian gas supply under
Westcoast's export license GL-41.
As an essential part of the November 12, 1981 agreement, Westcoast
agreed to negotiate an extension of the Sumas deliveries and to seek an
extension from this Board of West coast 's authority to export under
license GL-41 for an additional 10 years commencing November 1, 1989
and ending October 31, 1999. This removes uncertainty in future supply
that would require Northwest to develop other sources of gas supply to
serve its market.
Q. What has been the policy of Northwest regarding dependency on Canadian
gas?
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A. Northwest has stated that its long-term goal is to reduce its
customers' dependency on firm gas from Canada and it has aggressively
pursued the purchase of new gas and the construction of transportation
facilities into areas where new gas fields are located. As stated
earlier there has been a decline in the purchases from Canada and we
expect this to continue to 55% domestic, 45% Canadian.
Q. Would you please explain the history of the past imports from Canada's
northwest from the delivery points.
A. While the overall supply picture has been secure, there were some
problems which arose in 1973, causing severe curtailments for northwest
distributors including Intermountain Gas. One of the problems was
related to Westcoast' s operations. Their pipeline runs through the
Northwest Territory to Sumas, Washington through some of the most
rugged terrain and extreme weather conditions in North America. Often
they would not have sufficient capacity on peak days. Further, in the
early 1970's, the natural gas pricing by the Canadian National Energy
Board (NEB) did not provide adequate profit margin to the producers.
There was also a loss of production from some significant wells in the
Pointed Mountain and Beaver River fields due to water intrusion. This
was further aggravated by the fact that during shortages in the early
70 iS, Northwest Pipeline and its distributors did not have adequate
storage or firm supply of gas available to offset the shortfalls.
These problems culminated during the winter of 1974/75 when the first
severe curtailments occurred.
Q. Would you please explain Exhibit 1, Page 3.
A. Exhibit 1, Page 3 shows Northwest's history of curtailment as a result
of the Canadian supply problems and its effect on Intermountain's
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customers. Intermountain had to curtail its firm customers for the
first time in 1973-74. This curtailment lasted for ten days and
resulted in firm curtailment of 287,000 therms as noted on Line 3 and
4, Column b. In the winter of 1974-75, we received a curtailment of
base supply on a peak day from Canada of 60%. As a result,
Intermountain experienced a curtailment of 34% of its base supply or
553,000 therms as shown on Line 8, Column b.
Curtailment in 1975-76 reached 171 days. Firm curtailment was
increased to 32 days and almost 6.5 million therms as listed on Lines 3
and 4, Column f. In 1976-77, curtailment had dropped to 120 days with
peak curtailment still at 30% of base supply. The 1977-78 season
resulted in no curtailment to Intermountain customers because it was
one of the warmest winters on record. During the winters since
1977-78, there have been no curtailments of Intermountain's customers.
This condition results from improvements of the Canadian pipeline
system, the eventual looping positions of that system, the development
of new supplies from British Columbia, and also the development of
underground and LNG storage on our system.
Q. In light of these problems, what did Intermountain do?
A. Intermountain contracted for the building of two LNG plants to supply
its load. The first was built by the Company near Nampa and was
completed in the Fall of 1974. The Nampa LNG plant has a total holding
capacity of 6,000,000 therms and peak day deliverability in the
Boise/Nampa sub-system at the present 'time of 500,000 therms a day.
The second facility for LNG supply was built by Northwest Pi.peline in
Plymouth, Washington and was completed in the Winter of 1975. Our
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contract provided for maximum vaporization rate of 402,000 therms a day
up to a total seasonal capacity of 3,145,000 therms.
With the increased curtailment, Northwest expanded the existing L8-1
contract in August, 1976, bringing Intermountain's daily storage demand
to 600,000 therms and its annual volume to 6,000,000 therms.
Q. Was there a further change in this contract?
A. Yes. Southwest Gas determined that it did not have the pipeline
capacity to utilize all of its L8 storage allocation and in July, 1977,
Intermountain contracted with Northwest Pipeline to increase its demand
volumes to 720,000 therms and its storage capacity to 7,705,000 therms.
This was an increase of 120,000 therms in demand capacity and an
increase of 1,614,000 therms in storage capacity. At that same time
Intermountain lost almost 50% of its SGS Contract for 1978. The new
contract reduced Intermountain's demand volume from 276,509 to a total
of 141,331 therms or a reduction of 135,178 therms. The capacity
volumes were reduced from 10,636,189 to 5,088,000 for a reduction of
5,548,189 therms. These reductions were more than three times the
additional supply volumes picked up in the in the L5 service.
Q. What was the net effect on Intermountain and its customers of the LS
expansion and cost and storage cost for Fiscal 1979 compared with
Fiscal 1978?
A. The result was a reduction of storage cost to Intermountain and its
customers. The annual expansion cost of LS-l was 1,569,346. Because
of the expansion of LS and as a result of lengthy negotiations between
distributors and Northwest and the owners of the Jackson Prairie
storage project to reduce the cost of Clay Basin and Jackson Prairie,
there was a reduction in cost of the ODL and SGS rates of $1,998,183.
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Q. Has there been a change in pricing structure of gas to Intermountain
since the curtailments in 1973-74?
A. Yes. First there has been a shift in the cost of gas, as shown on
Exhibit 1, Page 4, between Canadian and domestic gas. In 1973,
Canadian gas cost 1.5 times the cost of domestic gas. In 1976, that
ratio peaked at 3.8 times domestic gas and as domestic prices started
rising in 1 9ì7, this has been reduced to 2 times by April, 1982. As I
mentioned earlier, one of the problems causing the declining gas
deliverability by Canadians was due to the producers not recieving
enough money to give them a fair return. Therefore they quit
producing. The Canadians recognized the problem but at first they
split the increased revenue between the federal and provincial
governments. leaving the producers with nothing. The natural result
was no increase in production or drilling. After a short time the
Canadians recognized their error and started to pay more to the
producers, resulting in an increase in drilling. The stated policy of
Canada is that the cost of OPEC crude oil imported into Canada is the
most appropriate basis for the determining value for nRtural gas
exports on a Btu equivalent in U.S. dollars. Exhibit 1. Page 5 shows
the dramatic increase in the cost of gas from Canada and the
corresponding cost of OPEC crude to Canada. The Exhibit shows that the
cost has leveled off in the last year.
Q. Does it make sense to put pressure on Canada and encourage British
Columbia to lower the price by reducing our purchases?
A. This has been done as shoWn on Exhibit 1, Pages 1 and 2. British
Columbia , Westcoast, Northwest and the distributors have met several
times to discus$price and volumes. British Columbia and Westcoast
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would like to change the price and sell more gas. The problem is that
British Columbia and Westcoast do not make the decisions. The federal
government of Canada does and there are many options öpen to it. There
are several pipeline applications right now before the NEB and FERC to
import gas from Canada. The application of Westcoast and Northwest is
just one of those. We have an advantage to a certain extent in that
British Columbia gas is somewhat isolated by the Canadian Rockies, but
there are several proposals before the British Columbia Energy
Commission which include building a pipeline to Vancouver Island,
building a petrochemical industry, building LNG plants and exporting
LNG to Japan. Once the large investments are made in these
alternatives, natural gas from British Columbia will be diverted to
them. This will be true even if such a use of the gas is not optional
in the economic sense because the huge capital investments will already
have been made and the Canadian government will have to protect them.
If that occurred, the customers of Northwest would have to obtain
substitutes for natural gas, and that market would never again be
available to Canada. It is exactly this rational that causes Saudie
Arabia to hold down OPEC prices and prohibit the Cartel's more radical
members from further increasing oil prices. The Canadians do know,
however. that Northwest could not adequately serve the northern portion
of its servicenrea without Canadian gas at the present time.
Exhibit i, Page 6 shows the changes in the demand and commodity charges
for gas. The increase in the commodity price of gas to Intermountain
and the way in which it can buy its gas economically has changed
dramatically. You will note that in 1973, 41% of the total cost of gas
to the Company was in the demand charge and the commodity charge
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We have come full circle in the early 1980' s. Instead of running out
of gas, as was predicted in 1978 when reserves appeared to be only
about five years, we now have an abundance of gas well into the next
century. The philosophy;of the:~ERC has therefore changed again and
they are now changing the balance between the demand and commodity.
The demand chatge is being raised and the commodity charge is being
lowered. This provides advan~ges toO us which may enable us to attract.
new industrial customers or encourage existing industrial customers to
add to their load.
At this time the characteristiêî;""ôf the load are changing dramatically.
In the early 1970' s a large portion of our industrial complexes
switched to coal based on long-term contracts under which the price of
coal is fixed. The only escalators in the contract are the cost of
transportation and the cost of labor. Therefore, it is very unlikely
that we will ever get these customers back. At the present time, as
you know, there is difficulty in the ammonia industry which appears
long-term. We have effectively lost up to 220,000 therms a day or
22,000,000 therms annually in sales to those customers using gas to
produce ammonia. Consequently, it appears to us that, under current
conditions, we may have a surplus contract demand or surplus storage.
We are reacting to this situation by reducing contract demand. As
previously stated, the relationship between demand and commodity cost
is changing and we think it will continue to change as the pipeline
puts more of their fixed costs on the demand charge. Another factor is
that the characteristics of our load are changing considerably. In the
past, industrial use was a large proportion of our load. Most of our
industrial customers operate at a much higher load factor than the
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residential customers who are almost totally temperature sensitive in
their load. If the load continues to change from industrial to
residential use our base supply needs will change further. Therefore,
retention of storage and reduction of contract demand makes more sense
as far as operating flexibility and economics are concerned because it
is the residential customers that are going to be our big base load in
the future. The characteristics of our residential load are also
changing. The average residential customer uses approximately 700
therms a year compared to 1,400 therms a year seven years ago.
Therefore, with a contract demand annual volume of 594,590,000 therms
based on a daily contract for 1,630,000 and annual volumes of
242,774,661, we can add 500,000 new residential customers without
straining our system.
There is a difference between what has taken place in our area and what
has taken place in the Seattle and Portland areas, in that our load has
reduced signifi.cantly through the displacement of coal and that load is
permanently displaced. On the coast, most of their load has been
displaced by oil which is a very volatile market, either up or down
depending on what happens on the world energy markets. Our losses to
long-term coal contracts is, however, permanently gone.
Q. What will be the future demand requirements of customers on your system
and will you be able to meet that demand?
A. The Company has already experienced significant conservation and the
new gas appliances and equipment coming onto our system will continue
that trend. Existing furnaces on our system serving some 80,000
customers probably average between 55-60% efficiency while almost all
of the new equipment used for replacement and new housing construction
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has an efficiency range in the area of 80-95%. This will result in
further reductions in energy use per customer. Taking into
consideration our load at the present time on a normalized basis and
putting that on the design parameter with the storage we have available
we can easily add an additional 50,000 customers without any problem
with the reduced contract demand that we are proposing.
Q. What reduction in contract demand are you proposing?
A. We have notified Northwest Pipeline that we wish to reduce our ODL-l
contract demand by 500,000 therms, therefore reducing our contract from
1,630,235 to 1,130,235 therms effective October 1, 1982.
Q. What would the savings be if this was accomplished?
A. The potential annual savings by this reduction, as shown on Exhibit 1,
Page 7, could be as high as $4,220,000. This Exhibit notes the effect
of reduction in contract from 1,630,235 to 930,235 therms a day.
Column (b) shows the annual volume reductions and columns (c), (d) and
(e) the annual demand charge savings under the United Formula, the
Seaboard Formula and the Modified Seaboard Formula. Current rates are
set pursuant to the United Formula dnd Northwest Pipeline has proposed
the Modified Seaboard Formula in its currently pending rate case before
FERC.
Q. Why aren't these reduced costs reflected in this case?
A. All of our contracts with Northwest continue to October 31, 1989. We
cannot arbitrarily reduce these volumes. Northwest is attempting to
place these volumes with the other distribution companies. If the
other customers do not nominate for these volumes, there is a
possibility Northwest could sell these volumes off system. Therefore,
at this time it is not known if these volumes can be placed with
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another company or the amount. It is the intent, when and if we are
able to reduce our contract, we would file this adjustment in a
tracking filing.
Q. Isn't there some risk in reducing contract?
A. As is evident by my testimony, the Company has made moves in the gas
supply area based on the facts available at that time and on reliable
forecasts. Like it or not, our industry is dramatically affected by
actions taken in Washington, DC, Saudia Arabia and Ottawa, Canada. Any
action taken now can be second guessed with perfect hindsight at a
later time. We feel, however, that there is only a minimal risk in
reducing our contract demand at this time.
Q. Does this conclude your direct testimony?
A. Yes, it does.
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