Legislature(2003 - 2004)
06/16/2004 08:34 AM House BUD
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
JOINT MEETING
JOINT COMMITTEE ON LEGISLATIVE BUDGET AND AUDIT
SENATE RESOURCES STANDING COMMITTEE
June 16, 2004
8:34 a.m.
MEMBERS PRESENT
LEGISLATIVE BUDGET AND AUDIT
Representative Ralph Samuels, Chair
Representative Mike Chenault (via teleconference)
Representative Mike Hawker
Representative Beth Kerttula
Representative Reggie Joule - alternate
Senator Gene Therriault, Vice Chair
Senator Con Bunde
SENATE RESOURCES
Senator Scott Ogan, Chair
Senator Tom Wagoner, Vice Chair
Senator Fred Dyson
Senator Ralph Seekins (via teleconference)
MEMBERS ABSENT
LEGISLATIVE BUDGET AND AUDIT
Representative Vic Kohring
Senator Gary Wilken
Senator Ben Stevens
Senator Lyman Hoffman
SENATE RESOURCES
Senator Ben Stevens
Senator Kim Elton
Senator Georgiana Lincoln
OTHER LEGISLATORS PRESENT
Representative Les Gara
Senator Gretchen Guess
COMMITTEE CALENDAR
^ALASKA NATURAL GAS PIPELINE ISSUES/PIPELINE COSTS & TARIFFS
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
Presentations By:
MARK MYERS, Director
Division of Oil and Gas
Department of Natural Resources
DAN DICKINSON, Director
Tax Division
Department of Revenue
MARK HANLEY, Public Affairs Manager
Anadarko Petroleum Corporation
GARTH SALISBURY, Managing Director
JP Morgan Chase and Co.
NANCY ROHMAN, Vice President
JP Morgan Chase and Co.
WILLIAM BENHAM, Vice President
Regulatory Affairs
BP Energy Company
DAVE McDOWELL, Director, External Affairs - Gas
British Petroleum (BP)
TONY PALMER, Vice President
Alaska Business Development
TransCanada Corporation
WILLIAM WALKER, General Counsel
Alaska Gasline Port Authority;
Attorney at Law, Walker & Levesque, LLC
RIGDON BOYKIN, Special Counsel
Alaska Gasline Port Authority;
Attorney at Law, O'Melveny & Myers LLP
DANIEL IVES, Vice President and Principal
Lukens Energy Group, Inc.
Representing the Alaska Department of Law
ROBERT LOEFFLER, Senior Partner
Morrison & Forrester, LLP
NAN THOMPSON, Commissioner
Regulatory Commission of Alaska (RCA)
Department of Community & Economic Development (DCED)
ACTION NARRATIVE
TAPE 04-6, SIDE A [BUD TAPE]
Number 001
CHAIR RALPH SAMUELS called the joint meeting of the Joint
Committee on Legislative Budget and Audit and the Senate
Resources Standing Committee to order at 8:34 a.m. Joint
Committee on Legislative Budget and Audit members present were
Representatives Samuels, Chenault (via teleconference), Hawker,
Kerttula, and Joule (Alternate) and Senators Therriault and
Bunde. Senate Resources Standing Committee members present were
Senators Ogan, Wagoner, Dyson, and Seekins. Also in attendance
were Representative Gara and Senator Guess.
CHAIR SAMUELS explained that the purpose of the meeting today
and tomorrow is to attempt to educate members of the committee
and the legislature in general with regard to the complicated
issues of the natural gas pipeline and the legislature's role in
approving a contract under the Stranded Gas Act. He noted that
the testimony is by invitation only and questions from the
members should be forwarded to him or Senator Ogan who will ask
the question at the end [of each presentation], if there is
time. Otherwise, the responses to the questions will be
provided to the committee members in writing.
Number 012
MARK MYERS, Director, Division of Oil and Gas, Department of
Natural Resources, specified that he would address the impact of
pipeline costs on royalty payments. He provided the committee
with a copy of the slides he will present. He began by pointing
out that although a producer shipping down a pipeline and a
royalty owner have similar interests, in some way the two are
different. Furthermore, royalties are different than taxes in
that the royalties are based on the lease. Different leases
have different provisions with regard to how royalties can be
calculated and the allowable deductions. The lease is a
contractual relationship that the legislature can't change,
which is unlike taxation that the legislature can change. The
lease provides some stability for all parties.
MR. MYERS explained that the state has two choices with its
royalty share. The state can physically take possession of the
royalty in-kind (RIK) and sell it, which the state does with
much of its oil. Although the state normally takes its oil
upstream and has the purchaser ship the oil, there is nothing
restricting the state from selling it downstream in the market.
The second choice is taking the royalty in-value (RIV), which
means that it would leave [the royalty share] with the producer
who would sell it and the state would receive the proceeds from
that sale minus the deductions. Therefore, if RIV is chosen,
the state receives from the producer the value netted back to
the lease, but the state would incur the transportation costs
and additional costs depending upon the language of the lease.
MR. MYERS specified that the netback equals the destination
value minus the transportation as well as any field/conditioning
costs. In Prudhoe Bay, the state in 1980 reached a settlement
in which the state agreed to pay a certain amount for those
costs. In newer formed leases, the state wouldn't incur either
cost, no matter whether the royalties are RIK or RIV. However,
for those leases formed prior to 1979, DO1 leases, the state
wouldn't incur the costs under RIV but would be required to pay
fuel costs under RIK. The aforementioned is the current view of
the courts. Mr. Myers highlighted that one powerful protection
the state has built into the lease is that the transportation is
the actual and reasonable costs of transportation from field to
market. On the oil side, the state is, on an ongoing basis,
going through the process of determining whether the
transportation costs are actual and reasonable through a
reopener process.
MR. MYERS highlighted the bullet specifying: "Pipeline tariffs
do not necessarily represent the actual and reasonable costs of
pipeline transportation." He characterized pipeline tariff
methodology as an art that can be done in various ways because
there can be a disconnect between the tariff structure and what
is actual and reasonable. The tariffs are a direct reduction
against the royalty value that is netted back to the lease. The
page entitled "Calculation of Royalty Netback Value for ANS Gas"
shows the netback the state would hypothetically receive from
various fields with a destination value of $4.00. He
acknowledged that $4.00 is somewhat arbitrary. The illustration
also assumes that the trunk pipeline tariff from Alaska to the
Chicago market is $2.00. He pointed out that the document
erroneously specifies that the conditioning cost for Prudhoe Bay
would be $.20. The conditioning cost for Prudhoe Bay should be
$.40 and the field cost should be $.20. Therefore, the netback
royalty value would be about $1.65 per thousand cubic feet (mcf)
at $4.00. For Point Thompson, the state wouldn't pay fuel costs
if it was left RIV and there would be an allowable deduction to
move the gas from Point Thompson to Prudhoe Bay, and an
adjustment for the quality of the gas. The result is a higher
netback. The North Slope Foothills lease is an example of a
modern lease in which the gas, a cleaner gas, sells for $4.00
with no BTU [British thermal unit] adjustment and fuel costs.
Therefore, the netback royalty value would be less since the
development costs wouldn't be incurred. He noted that this is
from the royalty perspective.
MR. MYERS clarified that there are two major classes of tariffs.
One class is a recourse rate, which is established by Federal
Energy Regulatory Commission (FERC). The other is a negotiated
rate. Furthermore, the rates can vary depending upon the class
of shippers. Although the rates can't unduly discriminate, the
rates can discriminate based on certain factors. He also
pointed out that firm service versus interruptible service can
have different rates. The interruptible service rate is a rate
that is purchased in the market if the space is available,
although there is no guarantee to ship the gas. Interruptible
service can be more expensive or cheaper. Pipelines that are
later in life typically have a lot of excess capacity, as is the
case in the Alberta system in Canada. In that case, most folks
would purchase interruptible service because of its
availability. However, projects in the earlier stages may not
have much interruptible service, which may mean that much of it
may not be available or it might come at a premium cost. Mr.
Myers explained that in the rate-setting mechanism there are a
number of variations. The allowed rate of return on equity can
vary quite a bit depending upon the view of FERC. The cost of
the debt is a big factor as is the debt equity ratio.
Generally, the rate of return allowed is only allowed on that
capital supplied by the pipeline company itself. Therefore, the
rate of return calculation is only on the amount borrowed. How
the capital is structured will be a major determinant in the
rate structure, he said. The rates are also affected by the
length and method of depreciation.
MR. MYERS turned to the cost of service (COS), recourse tariff,
versus a levelized tariff. The COS tariff, which is a typical
type that FERC would approve as a recourse rate, would start
higher and decrease over time. The aforementioned occurs
because as the asset depreciates there is less and less rate
base in the capital, and therefore the tariff is designed to
reflect that. In negotiated tariffs, it's not uncommon to
negotiate a levelized tariff in which the tariff is the same
throughout the entire period. With a levelized tariff, the
tariff would be lower at first, but later that tariff would be
higher than it would've been under a recourse rate. The
different tariff types provide advantages to different parties.
The state, which doesn't own the pipeline, would want a higher
netback to obtain income early in the project, and therefore a
levelized tariff would probably be the preferable mechanism.
The gas producers under a third-party pipeline ownership would
also prefer a negotiated, levelized, tariff because of the
desire to receive a higher netback earlier. However, the gas
producers who own the pipeline would prefer a recourse rate, COS
tariff, in order to receive the maximum rate of return upfront.
He reiterated that the state may prefer a levelized tariff if
revenue is a priority for the state. Negotiated tariffs, which
are individually negotiated with each customer, have been
permitted by FERC since 1996. Negotiated tariffs can be lower
or higher than a recourse tariff. In the example presented in
Mr. Myers' booklet, the recourse and negotiated tariffs are
approximately equal in year nine.
MR. MYERS highlighted that the COS tariff doesn't follow a nice
downward trend. The COS tariff is only adjusted at points when
someone approaches FERC to request [an adjustment]. In a
general scenario, the initial rate would hold for an 18[-year]
period and then it would drop. If two years later someone makes
a rate case and it takes two years to adjudicate that case, the
adjustment would start at the point of adjudication. Therefore,
[the COS tariff] ends up being a stair step effect that is
dependent upon how often people go before FERC and file.
Generally, the shippers will pay more under the recourse rate.
Mr. Myers returned to the state's perspective and recommended
that in order to receive just and reasonable [transportation] it
will probably be necessary to obtain a pipeline tariff
settlement or the default will be a COS type tariff.
Number 210
SENATOR OGAN asked if any other states have an ownership
position in an oil or gas pipeline. If so, what has been the
experience of those states, he asked.
MR. MYERS answered that he didn't know of any other states that
have an ownership position in an oil or gas pipeline, although
he did know of cases in which states have set up authorities
that have helped finance a pipeline. He noted that states have
taken capacity on pipelines, have bought transport, and have
marketed their royalty shares down stream. He noted that Texas
does the aforementioned.
SENATOR OGAN offered his understanding that Wyoming may have
some sort of ownership in a pipeline recently.
Number 226
DAN DICKINSON, Director, Tax Division, Department of Revenue,
emphasized Mr. Myers' earlier comments that sovereign taxes are
very different than the royalty, which is a contract. He turned
attention to a packet of information labeled "Alaska Natural Gas
Pipeline Issues," and explained that there are four major bites
at the apple on the oil side and the gas side. One is royalty
because most of the development has been on land that the state
owns. Additionally, there is a production tax, which is based
on the amount of oil and gas that's produced. There is a
special income tax that applies to producers of oil and gas.
Finally, there is a special oil and gas property tax. Mr.
Dickinson said that he would address the production tax.
MR. DICKINSON pointed out that the legislature set the rules and
can unilaterally change those rules. Currently, there is a 10
percent production tax on gas and a 12.5-15 percent production
tax on oil. He noted that for the economic limit factor (ELF)
for gas he will use an estimate of about 80 percent. He
explained that the 10 percent is multiplied by the ELF which is
multiplied by the gross value at point of production, which
equals the tax. In contrast to royalty, the gross value at the
point of production includes no upstream costs that are
deductible. Therefore, he likened it to the newly formed leases
under royalty. In order to find the gross value at the point of
production, one must take the value at the destination less the
actual costs of transportation. The aforementioned looks a lot
like the royalty situation, although how the actual
transportation costs are determined is very different.
MR. DICKINSON turned to a document entitled, "Potential
Production Tax Revenue." The document uses a destination value
from $2.00 to $10.00 with a tariff of $2.40 and assumes the
following: 4 bcf (billion cubic feet) per day; 365.0 days per
year; 87.5% non-royalty fraction; 10% tax rate; and 80%
estimated ELF. Multiplying all of the assumptions together at a
$6.00 destination value would result in production tax revenues
of about $367 million. At a $10.00 price, the production tax
revenues will be close to three-quarters of a billion a year.
However, if the price was $2.00 and the tariff didn't cover the
costs, the minimum of $.064 cents per mcf will kick in.
Therefore, if the price drops to $2.00, the tariff would no
longer be relevant and a tax would be collected based on the
$.064 a barrel. The aforementioned situation results in $2.8
million minimum. The tax deduction for the tariff would be
about $245.3 billion a year, except for the cases in which the
tariff is larger than the destination value.
MR. DICKINSON pointed out that there will be some issues with
regard to whether the tariff or some other measure would be
used. The law, AS 43.55.150, specifies that [the state] would
be allowed to deduct the reasonable cost of transportation of
the oil or gas. Furthermore, the law specifies that the
reasonable costs of transportation will be the actual costs,
except under the following circumstances: when the parties of
the oil or gas are affiliated; when the contract for the
transportation of oil or gas is not an arm's length transaction
or is not representative of the market value of that
transportation; when the method of transportation of oil and gas
is not reasonable in view of existing alternative methods of
transportation. If all three criteria are met, the law
specifies: "the department shall determine the reasonable cost
of transportation, using the fair market value of like
transportation, the fair market value of equally efficient and
available alternative modes of transportation, or other
reasonable methods." Mr. Dickinson turned to the part of the
law that specifies: "Transportation costs fixed by tariff rates
properly on file with the Regulatory Commission of Alaska or
other regulatory agency shall be considered prima facie
reasonable". The aforementioned means that the presumption is
that the filed tariff is correct, although that can be
challenged by the department.
MR. DICKINSON pointed out that the legislature has the ability
to set what tax is levied on the gas. He informed the committee
that in 1977 the Supreme Court laid down the rules regarding
what one state can do when it wants to tax the business of a
corporation that has interstate business. The Supreme Court
specified that in order to tax the interstate activities of a
corporation, the tax can't be discriminatory; the tax must be
fairly apportioned to the state; the local activities in the
taxing state must establish a sufficient nexus; the tax must be
fairly related to services provided by the state. Mr. Dickinson
explained, "As you think about the ... tariffs, which is what
this is really about, the irony is you could probably set up a
scheme that treated Alaska and looked at the Alaskan tariff as
something that you could ignore ... whereas you're going to have
to take [into] account the tariffs that are paid further
downstream."
MR. DICKINSON informed the committees that Alberta, Canada, has
a tax that's 1 percent of the gross receipts or 25 percent of
the net receipts. In other words, all the cost deductions of a
project are allowed and after all the costs are deducted there
is a 25 percent tax. However, if the gross receipts are higher,
then that's taxed instead. Therefore, the tariffs, the other
deductible costs, become irrelevant to that calculation. Mr.
Dickinson highlighted the difference between an allowance and a
deduction. In conclusion, Mr. Dickinson turned to the Stranded
Gas Act and explained that "we're" trying to create a contract
which will be used to effect the sovereign's right to tax. The
companies have expressed concern that when they develop a
project with a 20-30 year time horizon, the sovereign will come
in at a later year and effect the economics of the project.
Therefore, the Stranded Gas Act attempts to create a situation
in which the sovereign is restraining its right to tax over some
time period in the hope that there will be a project to tax.
Number 420
SENATOR OGAN recalled the Amerada Hess Corporation case, which
was a very expensive and contentious case that resulted in the
constitutional budget reserve. He asked Mr. Dickinson to review
what was learned from that case.
MR. DICKINSON explained that the Amerada Hess Corporation case
was specifically about royalties, although there were parallel
tax cases that investigated many of the same issues. He said
that case was fundamentally about value. During the time of the
case there was no transparent market for oil as there is now for
oil and gas. Therefore, he didn't believe there would be
situations in which one huge exporter says the oil is worth $22
while the other says it's worth $35, although there will
continue to be conflicts regarding the exact [amount]. The
other piece [of the case] was in regard to transportation costs.
In the lease that governed the royalty obligation there were no
specifics, which resulted in both sides arguing that they had
met the general statement of principle. From that, one can
learn that it's better to determine [the specifics] beforehand,
to the degree possible. One may hesitate being too specific
when looking at something 10-15 years down the road because one
may not know the factual situation that will be present. Mr.
Dickinson opined that there will always be conflicts, although
hopefully the conflicts can be $10-$30 million conflicts instead
of $100 million conflicts.
Number 477
MARK HANLEY, Public Affairs Manager, Anadarko Petroleum
Corporation, said that he would provide the committees with an
explorer's perspective. This would be an explorer who hasn't
discovered gas already, but does have significant acreage
positions in gas prone areas. Mr. Hanley pointed out that what
he's heard thus far is that every entity wants to do the best
for its shareholders, although there are different motivations.
Therefore, the state needs to understand those motivations, how
they fit together, and whether they are fair or not. Decisions
on the aforementioned will determine whether companies such as
Anadarko explore for gas or not. As has been indicated, the
rules in this game are fairly flexible. For example, earlier
Mr. Myers stated that pipeline tariffs don't necessarily
represent the actual and reasonable cost of pipeline
transportation, which is of concern for an explorer. An
explorer would want the lowest rate possible in order to
generate the highest wellhead, which provides the most economic
ability to explore and make the most money. In general that
would be true for the state as well. However, if the tariffs
don't represent the actual and reasonable cost, he doubted they
would represent [less than] the actual cost. He assumed that
the assumption is that the tariffs would be higher than the
actual and reasonable cost. Therefore, the explorer's position
would be negatively effected. Furthermore, the rates can't be
unduly discriminatory, which he surmised to mean that they can
be duly discriminatory. Moreover, there can be the "black box"
methodology in which the rates are known, but whether those
rates are fair or not isn't known. The aforementioned is a
difficult situation.
MR. HANLEY turned to the question of who makes the decisions on
how these things are set up and said that it depends. Sometimes
the pipeline owners set up things in the tariffs, and other
times it can be FERC as part of the regulatory process, or even
the state can specify that charges aren't reasonable for royalty
purposes. In fact, "they" may be able to obtain a lower
transportation rate. Mr. Hanley reiterated that the rules of
the game are very fluid and there is much ability to change
those rules. Therefore, explorers are going to sit back and
watch.
MR. HANLEY stated, "If there's no gas pipeline, there's no
exploration." He acknowledged that people say there is a lot of
gas out there, and perhaps [Anadarko] could build the pipeline.
However, Mr. Hanley pointed out that 35 trillion cubic feet
(tcf) of discovered gas that is already being produced and for
which there is no exploration risk "and it's challenged getting
this pipeline going." The odds of someone being able to find
another 30 tcf of gas to justify this pipeline is next to nil.
Therefore, it is likely that explorers aren't going to be able
to find enough gas nor would they invest the billions of dollars
to do so. Mr. Hanley related that Anadarko is very supportive
of building a gas pipeline. However, the rate for explorers
needs to be as low as possible, which he believes to be true for
producers as well. As in the case of oil, the farther away one
is from infrastructure, the larger the field needs to be. With
a lower tariff, there will be smaller fields that are economic
and create the chance of obtaining more revenue. Therefore,
generally it's in everyone's interest to have the rate be as low
as possible.
MR. HANLEY turned to the issue of reasonable access terms and
conditions. He pointed out that the Foothills area tends to be
more gas prone and not as liquid prone. Although it's known
that it's a gas prone area, it isn't known if it's commercial
because that wasn't tested. Mr. Hanley informed the committee
that a couple of years ago Northern Economics did a study for
Anadarko with regard to commercial gas development in the
Foothills area. The study goes through the 30-year life of a
gas product in the Foothills area.
TAPE 04-6, SIDE B
MR. HANLEY informed the committees that in Prudhoe Bay alone
there is 35 tcf of gas while the estimate for the remainder of
the North Slope is somewhere between 70-80 tcf of undiscovered
gas potential. In the Arctic National Wildlife Refuge (ANWR)
area and Foothills area, there are [gas] estimates of 8.5-9 tcf.
There is a lot of potential for gas and exploration. With all
that, one might question why a gas line hasn't been built.
However, typically the largest risk in exploration is the
geological site, the underground side. The [risk surrounds]
whether gas will be found; whether there is enough gas to flow
in quantities; and whether the gas will be close enough to
infrastructure to make a commercial gas find. However, the
largest risk in Alaska is the aboveground risk, the commercial
risk, [which includes] the risk of the tariff being too high,
construction cost overruns, legal challenges, permitting, and
price risk. The aforementioned are fairly significant risks,
but the state can come in with fiscal security.
MR. HANLEY addressed the difference between explorers and
producers, which he explained through an example of how capacity
on a pipeline is acquired. This pipeline will be a contract
carrier rather than a common carrier. Mr. Hanley emphasized
that pipeline ownership has no bearing on capacity ownership.
Capacity is allocated during an open season. Typically, the
pipeline owners will set the terms, the tariff, and express
interest. Then an entity can sign up for capacity, which is
typically a 20-year contract. The entity would be committed to
pay for that capacity regardless of whether any gas moves down
the pipeline. Although the aforementioned is a risk, the
benefit is that the capacity is owned by the purchasing entity
and no one can pro-rate that entity out of that capacity. This
is important because explorers are unlikely to explore for gas
before there is some progress indicating that a pipeline will
happen. If the pipeline moved forward tomorrow, the open season
would likely happen in a couple of years. However, it takes 3-5
years for explorers to determine whether they have a commercial
gas find, which means that all of the existing capacity is
likely to be taken by the existing gas holders because they have
the gas and once the terms are known, they can nominate
capacity. Mr. Hanley specified that the expansion tariff rate
and the terms and conditions of the expansion of the pipe are
probably most important for explorers. He informed the
committee that the design of the pipe and how it's set up can
determine the expansion rates. Typically, expansion of a gas
line means adding compression rather than the pipe getting
larger or adding new pipe. Furthermore, the design of the pipe
can determine the terms and conditions as well as the rates of
any expansion. Just adding the compression could result in
initial expansions that should have a tariff rate that would be
lower than the initial tariff. If the gas line is designed [to
allow for expansion], explorers will have some idea that the
expansion will be no more than the existing tariff and will
probably be a little less than the existing tariff. However, he
noted that pipelines can be designed so that every expansion is
more expensive, which is of concern for the explorers.
MR. HANLEY mentioned that tariff terms are as important as
tariff rates. He recalled discussion with regard to a BTU
tariff versus a mcf. He explained that if [there was a change
to a mcf tariff] without having a quality adjustment, one could
find, on a volume basis, that the liquid heavy oils with a
higher BTU content actually do better. Therefore, [the
explorers] could end up at a competitive disadvantage if the
tariff is set a certain way. With regard to expansion, the
terms and conditions can be set such that initial pipeline
owners maintain a right of first refusal on all expansion
capacity. The aforementioned can stymie a competitor who would
have to approach a competitor that has the right of first
refusal on all the expansion capacity. If such conditions are
included in the tariff, it is of concern. Mr. Hanley related
[Anadarko's] view that FERC doesn't have the ability to force
the expansion of a pipeline, which is concerning in a situation
in which the pipeline is owned by the producers who are
competitors of the [explorers].
Number 772
MR. HANLEY clarified that [Anadarko/explorers] want the lowest
tariff possible and typically would prefer a flat line [a
levelized tariff] as presented by Mr. Myers because a number [of
explorers] already have exploration acres. A higher tariff in
the beginning could mean that [Anadarko and other explorers]
couldn't explore for that gas. Furthermore, it's a bit more
costly in the Foothills. He related that Anadarko would incur
costs as far as development and exploration that don't exist at
Prudhoe Bay because the gas has already been discovered.
Because of the aforementioned [Anadarko and other explorers]
will be as challenged, if not more challenged than others. Mr.
Hanley turned to the proposal of 4.5 bcf a day pipe, and pointed
out that a penny a day would mean $45,000 a day or $16.5 million
a year. Twenty cents, which may be 10 percent of the $2 tariff,
can result in as much as $330 million a year. Therefore,
pennies on the dollar make big differences on the netbacks.
MR. HANLEY informed the committees that there is a normal
incentive to have a low tariff with a high netback. However, if
it's a producer-owned pipe and the producers are aligned, there
may be some incentive to shift as much profit as possible to the
pipeline. There may be a producer interested in obtaining a
much higher rate of return on the pipe because the producer
would obtain the profit from that while reducing the wellhead
value, which results in a double benefit. Reduction in the
wellhead value results in the pipeline owner paying less in
severance taxes and property taxes. Mr. Hanley noted that
explorers have a varied interest. However, generally speaking
the explorers want the lowest rate possible and want a pipeline
built. In fact, often the explorers are aligned with the
state's interest in trying to obtain the most revenue and the
highest wellhead value. Many times the explorers are aligned
with the producers, and sometimes the explorers are aligned with
the pipeline owner. Typically a pipeline owner that isn't a
producer isn't necessarily concerned with controlling capacity
and in fact, expanding the pipe and lowering the operating cost
is beneficial to them as well. Therefore, a pipeline owner that
isn't a producer may be more interested in expanding the pipe
sooner than a producer-owned company that may want to utilize
the pipe to control capacity, which allows control of
exploration. Mr. Hanley reiterated that the explorers want a
pipeline to be built, the lowest possible rate, and fair and
reasonable terms. He concluded by highlighting that [the
explorers] believe exploration is good as is competition, and
furthermore the more gas that is put in sooner will result in
more people involved in the pipeline, which should lower the
cost.
Number 827
SENATOR OGAN inquired as to who would be the operating partner
in the areas labeled "Anadarko Partial" shown on the map
provided to the committees.
MR. HANLEY answered that in some areas Anadarko would be the
operating partner and in other areas it would be ConocoPhillips
Alaska, Inc. Generally speaking, in Alpine and to the west in
the NPR-A [National Petroleum Reserve-Alaska] area, Anadarko has
interests with ConocoPhillips, which is the operator. In the
Foothills region, Anadarko has state acres and ASRC [Arctic
Slope Regional Corporation] acres in which Anadarko is the
operator.
SENATOR OGAN highlighted that currently Alaska Oil and Gas
Conservation Commission (AOGCC) has the authority to regulate
the waste of hydrocarbon. Senator Ogan opined that the state
has an interest in which gas is produced first because a company
that owns gas in the Prudhoe Bay unit would want to sell that
gas. However, it seems to be in the state's advantage to place
gas that doesn't interfere with oil production in the line first
because it would mitigate the decline of revenues from the oil.
He inquired as to Mr. Hanley's thoughts on the aforementioned.
MR. HANLEY suggested that a model would need to be run. He said
he would want to support putting in the Foothills gas first
because that's where Anadarko has an acreage position. However,
the state should review it because Mr. Myers indicated that the
state might receive a bit lower netback on [the Prudhoe Bay
unit] gas. He noted that even with a model, there would be some
policy calls. Mr. Hanley mentioned that the ability to get gas
in that pipeline is going to improve oil exploration economics
because when one explores for oil on the North Slope one often
finds gas.
Number 0872
GARTH SALISBURY, Managing Director, JP Morgan Chase and Co.,
clarified that he and Ms. Rohman are financial experts, and
therefore both would focus on the financial aspects of building
a natural gas pipeline. He utilized a booklet entitled "Interim
Hearings: Alaska Natural Gas Pipeline Issues" that was provided
to the committee. He began by specifying that the final outcome
of a gas pipeline will be dictated by a large group of
stakeholders, some of which are listed on page 4 of the booklet.
Mr. Salisbury opined that current market prices certainly would
support building a pipeline.
MR. SALISBURY turned to some of the assumptions he [and Ms.
Rohman] used, the largest of which is project cost. The
projections for the cost and scope of the pipeline vary widely.
For the purposes of this presentation, Mr. Salisbury specified
that he is assuming a treatment plant cost of about $2.6 billion
and a project cost assumption of about $11.6 billion. He noted
that he [and Ms. Rohman] have no opinion with regard to the
actual costs of these facilities, the aforementioned are merely
assumptions. He emphasized that the focus will be in regard to
the relative differences for various financings of any given
costs. Therefore, the total cost for this entire project is
$14.2 billion with a throughput assumption of 4.5 bcf a day.
The project life/term of debt assumption is 30 years, which is a
bit conservative from a project life standpoint, although it's a
bit aggressive from a debt standpoint. The assumption for the
initial term is 15 years. He highlighted that any pipeline
owner would want to block in shipping contracts before the
contract was completed and have an idea of the tariff in order
to obtain financing. The assumed project bond rating for the
entire financial package is an "A". He acknowledged that many
pipeline projects are in the "B," "AA," or "BBB" category, which
[provide] lower rating and higher financing costs. The debt to
equity ratio for the base case will be 60 percent debt and 40
percent equity. The return on the equity will be 12 percent on
the assumption. Furthermore, the depreciation methodology
assumes a straight line for 30 years.
MR. SALISBURY echoed earlier remarks specifying that a number of
factors go into a tariff, as specified on page 7 of the booklet.
Mr. Salisbury said that he would like to isolate the financing
components of the tariff, and therefore he was going to focus on
the cost of the project, a tax rate, contract term/asset life,
and the annual throughput. For purposes of this presentation he
focused on the capital expenditure, the return on the equity,
whether there would be a federal guarantee on the debt, and the
tax status of that debt. He clarified that he is referring to
tax exempt debt rather than the tax status of the pipeline
owner; this presentation will strictly refer to the tax
treatment for the debt that's issued. The presentation will not
focus on the operating and maintenance costs, general
administrative costs, or any additional capital expenditures
made to improve or expand the pipeline.
MR. SALISBURY turned to debt to equity ratios. Generally
speaking, large gas pipeline projects in the U.S. range from 50-
67 percent debt. Therefore, common debt to equity ratios for
pipeline projects range from 50:50 to 70:30 debt to equity. For
this analysis, the range assumed will be 50:50 to 67.67 and
33.33.
MR. SALISBURY went back to page 9 of the booklet regarding
financing assumptions. For a base case, the capital structure
will have a debt of 60 percent and 40 percent equity and the
return on the equity will be 12 percent. It will also be
assumed that the debt issued will be standard corporate taxable
debt and that there is no federal loan guarantee. The
aforementioned will be the base case from which variations will
be taken. He noted that the base case incremental financing
tariff, an average tariff over a 30-year project life, produced
a tariff of about $0.79 MMBtu [one million British thermal
units]. He returned to the debt to equity ratios, which is
outlined on page 11 of the booklet. From the base case
scenario, as the equity component is increased at a 12 percent
return on the equity, the tariff will increase because the
remaining component of that capitalization is at a much lower
cost, somewhere in the 6-7 percent range. Therefore, how this
pipeline is financed and its capital components are going to be
very important. If the equity is increased to 50 percent, the
tariff would be increased to $0.85. The analysis illustrates a
couple of different debt structures, one of which is amortizing
tranches, which produces a lower overall debt cost. The base
case scenario uses the amortizing tranches, and therefore the
debt component is about 6.4 percent under an "A" rating.
Therefore, as the equity component is varied from a high of 50
percent to a low of 33 percent, the range is about $0.9. The
deviation between the equity components is $1.2 billion to $1.5
billion.
MR. SALISBURY moved on to the return on the equity. He
highlighted that FERC allows a specific return on the equity
component in the tariff. The return normally ranges from 10-14
percent. With the base case, the $0.79 tariff is produced.
However, as the equity component is increased to as high as 50
percent and the return on the equity to 14 percent, the
difference in total debt and equity costs over the life of the
project amounts to about $6 billion. Mr. Salisbury stated that
the producers and explorers will be concerned with regard to the
debt to equity percentage and the return on the equity allowed
in the tariff.
MR. SALISBURY addressed the issue of tax exemption, with the
focus being on tax-exempt debt, the debt issued to finance the
pipeline, rather than the tax status of a producer or someone
using the pipeline. He directed attention to the graph on page
14 of the booklet, which is a comparison of the 30-year Treasury
rate to the 30-year Revenue Bond Index. As the graph
illustrates, in higher interest rate environments, the relative
spread between taxable and tax-exempt rates is higher. Over the
last 20 years as rates have steadily declined on average, there
has been a compression on the tax-exempt and taxable rates such
that the value of tax-exemption today is worth quite a bit less
than it was 10-20 years ago. On average, the spread between a
30-year taxable bond and a 30-year tax-exempt revenue bond has
been about 50 basis points, one-half of 1 percent. Currently,
the spread is around .3 percent. He noted that there have been
a number of times when the taxable rate has been lower than the
tax-exempt rate. Therefore, there wasn't much benefit to
financing the taxes in that market.
Number 190
MR. SALISBURY provided the committees with a basic overview of
municipal bonds. He explained that municipal bonds are debt
securities that are only issued in the U.S. by a U.S. state, a
local government, or a governmental entity. Municipal bonds are
typically used to raise capital for building roads, schools, and
other public infrastructure projects. He further explained that
the exempt notion is that the interest paid to investors is
exempt from income taxes. Therefore, as mentioned earlier, tax-
exempt rates are generally lower than taxable rates. Since this
tax exemption is considered a subsidy by the U.S. Treasury,
there are strict regulations governing the use of tax-exempt
bonds. Mr. Salisbury highlighted the Alaska Railroad
Corporation's ability to issue tax-exempt debt for a project
like the gas pipeline, which is important and unique. He
specified that municipal bonds are often secured by tax
revenues, although in this case the discussion is about a bond
that is secured by a stream of enterprise revenues.
MR. SALISBURY turned to the reason why investors are willing to
accept a lower interest rate on a tax-exempt bond. He noted
that the value of the exemption is based on the tax rate of the
holder of the investment, which is why certain investors are
part of municipal bonds or not based on their tax rates. For
example, the after tax yield of a 35 percent tax rate investor
who would purchase a taxable bond at 7.5 percent would be 4.88
percent, and therefore, this particular investor would be better
served by buying the municipal bond at 5 percent and paying no
taxes because the net yield is 5 percent afterwards. However,
the average investor who is in a lower tax bracket is better
served by purchasing a taxable bond because his net yield after
paying taxes is higher. Therefore, the investors in taxable
bonds are generally wealthy individuals who are paying near the
maximum tax rates.
Number 234
NANCY ROHMAN, Vice President, JP Morgan Chase and Co., turned to
the value of tax exemption [page 18 of the booklet]. Obviously,
tax exemption can significantly reduce the interest cost and the
debt service on the financing. Historically, tax-exempt debt
has been worth more than it is in the current market. As rates
rise again, there may be a return to normal spread levels where
tax exemption will be worth more. She compared the base case
scenario to a tax-exempt deal and estimated that the tariff will
be reduced.
TAPE 04-7, SIDE A
MS. ROHMAN said that if one were to return to the normal spread
relationship, the value would be $0.04. She then turned to the
advantages of tax-exempt debt, which would include lower
interest costs. Furthermore, tax-exempt debt provides more
structuring opportunities. In municipal finance there is the
concept of "serial" bonds for which the debt can be amortized
quicker over time. Another advantage is the flexible call
options, which is the notion that once the bonds are issued,
municipal tax-exempt debt typically provides more flexibility to
restructure financing. Tax-exempt debt also provides a
favorable "capital charge" and an active "retail sector." She
explained that the corporate market is an enormous market that
is run by sophisticated institutional investors and
corporations. Because of the notion of "Bill Gates versus
Average Joe", there is a very active retail sector in the tax-
exempt market. A retail buyer base is an advantage because when
one prices a deal, one would be dealing with a broader buyer
base. Clearly, the disadvantages of tax-exempt debt are the
significant tax law constraints that accompany tax-exempt debt.
Furthermore, there are fewer "deep pocket" investors with tax-
exempt debt because the municipal industry is a lot smaller than
the corporate industry.
MS. ROHMAN moved on to the Federal Loan Guarantee, which is
discussed on page 21 of the booklet. Section 386 of the Energy
Policy Act of 2003 provides for Federal Loan Guarantees.
Basically, [the Act] says that the guarantee can't be greater
than 80 percent of the total capital costs of the project,
including interest. Furthermore, the Federal Loan Guarantee is
capped at $18 billion and the term of the loan agreement shall
not exceed 30 years. Ms. Rohman pointed out that the Federal
Loan Guarantee pledges "the full faith and credit of the United
States to pay all of the principal and interest on any loan or
other debt obligation entered into by a holder of a certificate
of public convenience and necessity." Although she
characterized the aforementioned language as a sure thing, she
noted that it's not a sure thing. In terms of the amount, the
Federal Loan Guarantee has ranged from $10-$18 billion. She
highlighted that the Federal Loan Guarantee can have a
significant impact on this financing. Since all the pipeline
scenarios call for a debt to equity ratio of less than 80
percent, the pipeline may be able to issue all of its bonds with
a Federal Loan Guarantee. Furthermore, the U.S. government's
strong credit provides the potential for much better financing,
which will reduce interest costs. The tariff with the Federal
Guarantee is $0.78 [as illustrated in the chart on page 24 of
the booklet]. With a $1.00 cost, she estimated $540 million.
She emphasized that this is a ballpark estimate that [would
change] based on the ultimate structure of the deal. "What you
actually achieve in the interest rate savings is going to be
highly dependent on the final structure," she pointed out.
Furthermore, she informed the committees that the Federal
Guarantee should be measured on the effect of the tariff
reduction as well as whether the deal can be accomplished.
MR. SALISBURY interjected that the spread presented is very
conservative. In the real world the magnitude of financing a
$15 billion project the value of that exemption would most
likely be multiples of this.
MS. ROHMAN returned to the booklet, page 25, which discusses the
value of the Federal Loan Guarantee on tax-exempt debt. If the
benefit of the exemption is obtained as is the Federal Loan
Guarantee, the base case would stay in the same spot and the
tariff would be reduced by $.04; it's the combined value of the
two. She estimated a total debt cost savings of $1.8 billion.
Number 072
SENATOR OGAN related a situation in which a state entity is used
to issue tax-exempt debt. He asked if it would be commercially
reasonable or whether there has been precedence for the state to
receive an equity interest in the pipeline in exchange for
making the project more reliable.
MR. SALISBURY replied that there is very little precedent for
state involvement in a natural gas pipeline. However, there are
examples of state entities that have assisted utilities. Most
often all of the benefit garnered by having state involvement
has been passed on to ratepayers/users, such as in the case of
the electric utilities. There isn't a good example in which a
state exemption was utilized to garner profits for the state.
SENATOR OGAN turned to Mr. Salisbury's forecast of interest
rates, and asked if he believes it's important to get the
project financed as soon as practical. He also asked if Mr.
Salisbury feared that rising interest rates would make the
project uneconomic.
MR. SALISBURY opined that JP Morgan believes that interest rates
have been and will continue to increase. However, interest
rates are still very, very low. Even as interest rates rise
over the next couple of years, they won't have the type of
impact on this tariff that many other components do. Components
such as the debt to equity ratios and the return on equity are
much more important to a project such as this.
Number 111
SENATOR DYSON directed attention to page 9 of the booklet, which
he understood to mean that over the projected life of the
project it will cost $14.2 billion just to "rent" the money to
do the construction.
MR. SALISBURY clarified that the $14.2 billion is the total
project cost, which includes the estimates for the treatment
plant and the "A to B" components. He further clarified that
doesn't include the interest component related to the debt.
SENATOR THERRIAULT turned to the chart on page 25 of the
booklet. He asked if the deviation in costs from the base case
of $1.84 billion is a reduction in the total project cost or
just in the financing.
MR. SALISBURY answered that it's a reduction just in the
financing component, the interest costs related to the different
scenarios.
Number 135
SENATOR GUESS, in reference to the chart on page 24, asked if
the financing charge would increase from the base case scenario
to the Federal Loan Guarantee when there is more equal debt to
equity ratio.
MR. SALISBURY replied yes. He added that presumably the Federal
Loan Guarantee is always going to be helpful, but that's related
to the base case scenario of 60 percent debt. If it's 50
percent debt with more equity with a higher return, it will cost
more.
SENATOR GUESS asked, "If you go over from that base case ... on
a 50:50 Federal Guarantee to none, ... am I reading it correct
that the difference between those two is an increase in finance
costs of $715 million?"
MR. SALISBURY replied yes.
SENATOR DYSON recalled the [assumption] that the pipeline costs
would be [$11.6 billion], and asked where the pipeline would
terminate.
MR. SALISBURY answered that the pipeline would terminate at the
Alaska-Canadian border, and therefore he assumes that Canada
will build the pipeline to the Alberta terminal.
Number 166
WILLIAM BENHAM, Vice President, Regulatory Affairs, BP Energy
Company, informed the committees that BP Energy Company is BP's
North American gas and power marketing and trading business. He
explained that in his role at BP he has periodically provided
testimony to the FERC and on occasion before state legislatures
on the subject of gas pipeline tariffs. Therefore, he is
presenting testimony on behalf of BP, ExxonMobil Corporation,
and ConocoPhillips Alaska, Inc., per their request. He
specified that he would refer to the aforementioned three
companies as the Sponsor Group. He said that he would offer a
brief overview of the Sponsor Group's preliminary cost and toll
estimates, the process for establishing a toll and the
allocation of risks, a discussion of the differences between
contract carriage and common carriage, the approval of tariffs,
and a closing summary. He informed the committees that his
primary background is in interstate pipeline ratemaking
procedures, tariffs, and the role of the FERC. However, he
noted that he has limited knowledge with regard to "the Alaska
gas project specifically, and therefore his comments are
designed to provide general insights into accepted tariff
methodology and the role of FERC in establishing gas pipeline
tariffs, as will be required for the Alaska gas pipeline." He
noted that the committees should have a written summary of the
key generic points covering the topics of building, owning,
operating, and transporting gas on a typical gas pipeline
regulated by FERC. The written summary will also review the key
risk factors faced by pipelines, shippers, and producers in
connection with a typical new pipeline project.
MR. BRENHAM paraphrased from the following written testimony
[original punctuation provided]:
Preliminary Cost and Toll Estimates
As has been previously communicated in other forums by
the Sponsor Group, we estimate the total capital cost
of the Alaska Gas Pipeline at approximately $20
billion, in 2001 dollars. This figure would be
somewhat higher in today's dollars, accounting for
inflation since 2001. The figures I'll be sharing
with you will be quoted in 2001 dollars because they
refer back to the joint $125 million feasibility study
that was completed by the Sponsor Group in the 2001-
2002 timeframe. That study evaluated the feasibility
of constructing a pipeline from Alaska's North Slope
to Lower-48 US markets by way of either a Northern
Route or a Southern Route, with the conclusion that
the project was technically feasible, but that the
commercial risks outweighed the potential rewards. As
you and we are very well aware, current State law has
prohibited the State from issuing a Right of Way for a
Northern Route until a Southern Route is built. My
testimony will focus on the Southern Route.
The Southern Route project was estimated to cost
approximately $19.4 billion, with an accuracy of +/-
20%. The components of this cost estimate were as
follows:
North Slope gas treatment plant $2.6 billion
Gas pipeline and compressor stations from the North
Slope to the Alaska/Canada Border $4.4 billion
Gas pipeline and compressor stations from the
Alaska/Canada border to Alberta, Canada $7.2 billion
Gas pipeline and compressor stations from Alberta to
US market $4.6 billion
NGL extraction facilities $0.6 billion
Total capital cost $19.4 billion
The capital cost estimate resulted in an estimated
toll to the market of $2.39/mcf. This toll is merely
a preliminary estimate of a toll that might ultimately
be approved by FERC and the NEB [National Energy Board
of Canada] for an Alaska gas pipeline. The ultimate
toll will not be known for some considerable time, and
better estimates will require more work as the project
is developed.
The Process for Establishing a Toll and the Allocation
of Risks
The process of developing and gaining regulatory
approval of this toll (tariff rate) and having it
approved by the necessary regulatory authorities is
well-established in both the US and Canada. Pipeline
tariff rates are a direct result of the cost of
constructing and operating the pipeline. The actual
formulation of the toll, indeed the entire tariff
structure, (of which the toll is one component) is
subject to well-established regulatory standards, with
oversight provided by the FERC in the US, and the NEB
in Canada.
The rate that gas pipelines will charge for
transporting gas is based on what is referred to as
the "cost of service". The cost of service includes
components such as operating cost, maintenance, taxes,
depreciation and a fair and reasonable return on
capital investment that is consistent with the
specific risks of the project. The return to pipeline
investors, consisting of both return on the equity and
the cost of debt, is determined by the risk undertaken
by those pipeline investors. For example, if a
pipeline investor undertakes a capital cost overrun
risk, that investor might reasonably expect to be
compensated for taking this risk by receiving a higher
return on the equity investment that is made.
Conversely, if a pipeline investor takes no such
risks, the return on equity might be reasonably
expected to be lower.
The specific capitalization structure, which is the
measure of the relative amount of equity and debt
financing, will vary by project, depending on the
project risk and how this risk is allocated between
the pipeline company and those that will be shipping
gas on the pipeline. The capitalization structure
must ultimately be within the guidelines established
by the FERC and the NEB and be acceptable to any
involved financial institutions. The factors which
impact the relative risk of gas pipeline projects
would include such items as:
· the economically recoverable reserves and
deliverability;
· credit risk of customers, (the pipeline
shippers);
· nature of pipeline investment (e.g. arctic,
remote, etc.);
· capital cost and schedule risk allocation between
shippers and pipeline owners, with the degree of
risk depending on how the parties agree to share
these risks, a matter which is first negotiated
by the parties and ultimately approved by the
FERC and the NEB.
For the feasibility study work performed by the
Sponsor Group, which I referenced earlier, the Sponsor
Group determined a toll using assumptions similar to
those that were actually implemented on the Alliance
Gas pipeline, the most recent major US-Canadian gas
pipeline project. This was simply a placeholder, as
it was recognized rates for this line could be
different due to its specific risks. However, for the
Alaska gas pipeline project, the pipeline company may
choose to offer negotiated rates. In this event,
shippers and pipeline owners may negotiate rates and
choose to allocate risks in a different way for this
specific project, with such negotiated rates of course
being subject to regulatory oversight.
I would point out here that a "negotiated rate" is a
term used by the FERC to describe any toll that is not
tied to the maximum toll derived through the cost of
service. "Negotiations" between the parties, in the
traditional sense of the term, are not always
necessary to establish such a rate.
I would further point out that even if the pipeline
chooses to offer negotiated rates, shippers would
still have the option to pay what are called
"recourse" rates, these rates being based on the
approved cost of service.
Both FERC and the NEB have well-established regulatory
processes that balance and protect the interest of all
parties, including consumers. The FERC ensures that
"just and reasonable rates" are implemented, based on
almost 70 years of Natural Gas Act precedent, policy
and case law. However, Natural Gas Act regulation of
interstate gas pipelines differs from FERC's
regulation of crude oil and liquids transportation
established under the Interstate Commerce Act in
several important respects.
Contract vs Common Carriage
Let me briefly explain the difference between the
systems of carriage on gas pipelines versus crude oil
and liquids pipelines, such as the Trans-Alaska
Pipeline System. U.S. liquids pipelines that provide
interstate service are regulated as "common carriers"
pursuant to regulations derived from the Interstate
Commerce Act. Under the common carrier regulations,
shippers are not allowed to contract for specific
quantities of capacity and, therefore, do not pay
related monthly demand/reservation charges - payment
is only for capacity utilization based on actual
throughput volumes. The advantage for common carrier
shippers is that they "pay as they go" on actual
delivered volumes. The disadvantage is that no
shipper is assured of a specific level of capacity
availability. When new oil supplies are tendered for
transportation on a full oil pipeline, available
capacity may be prorated or curtailed among existing
shippers.
In contrast, because much gas usage is closely related
to critical end uses such as industrial feedstock,
home heating and electricity generation, and thus
needs the assurance of defined, stable capacity
availability, natural gas pipelines under FERC or NEB
authority operate as "contract carriers". Under
contract carriage, shippers have the opportunity to
contract for a reservation of available capacity on a
firm, non-discriminatory, basis for a specified period
of time. What we call "open seasons" are often used
to ensure capacity is awarded without undo
discrimination to all parties that meet the open
season requirements.
In the context of gas pipelines, the term "open
access" is used to refer to the opportunity to
contract pipeline capacity at specific points of time
under open season processes. Parties who hold firm,
contracted capacity are not subject to proration at
the behest of other shippers, thus guaranteeing that
their production will flow. As additional capacity is
needed to serve new shippers, open seasons are held to
determine the interest and economic feasibility of
adding new capacity.
Pipeline owners and financial lenders desire these
long-term contracts for firm capacity to ensure
repayment of the capital cost of building the
pipeline. Without these commitments, gas pipeline
projects, which by their nature involve a longer
payout than oil projects, could not be financed.
Shippers need the contract quantity commitment to
ensure capacity is available to support their needs.
A shipper's economics are founded on the availability
of the contracted capacity. In exchange for the
pipeline's commitment to reserve a specified quantity
of capacity for a shipper, the shipper agrees to pay a
monthly reservation charge which is due regardless of
whether gas is actually shipped.
The Approval of Tariffs
The FERC and NEB processes offer an opportunity to all
interested and affected parties, such as the State of
Alaska, to actively participate in the establishment
of just and reasonable rates on pipelines in which
they have an interest. FERC staff is charged with
representing consumer interests to ensure that these
rates are established on a just and reasonable basis.
The FERC has outstanding resources and expertise and
is permitted to audit the records of regulated
pipelines.
Any gas pipeline project, including the Alaska gas
pipeline project, can only happen if the expected
tariff rate is acceptable to shippers, pipeline owners
and regulators. Only reasonable, prudently incurred,
pipeline capital and operating costs will be allowed
to be included in the tariff. FERC and NEB procedures
are designed to ensure this happens. In fact, lower
pipeline costs are in the best interest of the State
of Alaska, gas producers and the pipeline company,
provided risks are properly allocated between the
pipeline and the gas producer/shipper. This is
because lower pipeline costs translate into lower
rates that attract shippers to transport gas on the
pipeline, and thus higher wellhead netback prices are
realized, which in turn benefits both the producers
and the State of Alaska. Both producers of gas, and
the pipeline on which that gas is transported, need
the lowest possible costs to create a financially
viable project and a healthy natural gas business in
Alaska, supporting a full pipeline for decades to
come.
Let me just make some final comments about tariff
rates. The tariff rate will be a function of many
factors. Each of these factors has a certain impact
on the actual rate. The chief factor, though, in
determining the rate is the amount of capital cost.
Obviously, the actual capital cost will not be known
until the pipeline is constructed. Those capital
costs are recovered over time as depreciation. It is
too early in the process for the Sponsor Group to
determine how the various factors that recover the
capital cost and provide a return on investment will
be calculated. For example, the debt-equity ratio may
be affected by the existence of Federal loan
guarantees. The depreciation schedule is affected by
its overall impact on the toll over time. The longer
the depreciation period, the lower the toll will be
over time, all other factors being equal. The
allocation of the risk for cost overruns will be the
result of negotiations between the potential shippers
and the pipeline. However, the FERC, following US
Supreme Court precedent, must allow the recovery of
prudently incurred costs even if those costs are in
excess of the estimated costs.
To put it simply, it is still too early in the process
to provide a definitive outline of the method that the
Sponsor Group, or the pipeline entity, will use to
establish a tariff rate.
Summary
And so to summarize, I'd like to offer these closing
comments. First, gas pipeline tolls and tariffs are
established as a direct result of the associated costs
of constructing and operating the gas pipeline. The
Sponsor Group has come up with a preliminary estimate
of what these costs might be. However, if the project
progresses to detailed engineering and project
planning, an effort we estimate would take something
like two years, this cost estimate would be refined
and a more precise basis for the toll defined.
Second, any gas pipeline project can only happen when
the expected tolls are acceptable to all parties:
shippers, pipeline owners and the regulators. These
tolls will reflect appropriate risk sharing between
shippers and pipeline owners. The known resource
availability, proven deliverability, and excellent
shipper credit rating all serve to reduce the risks
for prospective Alaska gas pipeline owners. Project
risks such as cost overruns and schedule delays must
still be better estimated and appropriately allocated
between the parties. How these risks are allocated
will be a key factor in determining the ultimate
pipeline toll.
And third, both the State of Alaska and pipeline
shippers will benefit if the lowest cost pipeline is
the one that actually is built. FERC's and NEB's
procedures are designed to ensure that only prudently
incurred costs are included in a pipeline tariff,
thereby protecting consumers. As I mentioned earlier,
pipeline tolls and other tariff terms and conditions
are established under well established principles that
allow recovery of just and reasonable costs, by both
the FERC in the US and the NEB in Canada. Whichever
group or entity ultimately builds an Alaska natural
gas pipeline, they will have to pursue the same
regulatory process and be subjected to the same
scrutiny.
Number 600
MR. BENHAM turned attention to the document entitled "U.S. Gas
Pipelines - Key Points", which he provided to the committees.
He specified that the aforementioned document provides generic
points that aren't specific to the Alaska pipeline. He
suggested that the committees might want to focus on Part E,
entitled "Key Risk Factors for New Pipeline Projects;". He
noted that these factors can vary with the project and may be
more or less important depending upon the project. Mr. Benham
highlighted the risk for the pipeline, the shippers, and the
producers, which is delineated in the above-mentioned document.
TAPE 04-7, SIDE B
CHAIR SAMUELS asked if one could contract half of the volume and
the other half would be the common carriage.
MR. BENHAM replied no. He explained that under the U.S. system
there will be a series of parties that will have firm capacity
in a pipeline. He posed a scenario in which the parties have
firm capacity in the pipeline and the entire capacity is
contracted out to the firm shippers. In the aforementioned
situation, the firm shippers have a right to utilize all the
capacity for which it has contracted and no subsequent shipper
can enter and take that capacity. However, there may be
situations in which not all of the capacity is contracted or all
of the contracted capacity isn't being used. In such situations
there will be opportunities for other shippers to make firm
contracts for unsubscribed capacity or to come in and transport
on an interruptible basis. Mr. Benham clarified that in US
pipelines there isn't a hybrid design, that is there isn't a
situation in which someone can reduce the capacity rights an
existing shipper has on a line.
SENATOR BUNDE asked if Mr. Benham has any experience with state
or any other governmental equity in pipelines.
MR. BENHAM replied no.
Number 660
REPRESENTATIVE GARA returned to page 2 of Mr. Benham's written
testimony, which specifies that the commercial risks outweigh
the potential rewards of constructing a pipeline. How would
passage of the House's version of the loan guarantee impact [the
Sponsor Group's] view of the feasibility of a pipeline.
Furthermore, if the state sought a 10 percent equity interest,
would the project be viewed as more feasible from [the Sponsor
Group].
MR. BENHAM reiterated that he isn't familiar with the specifics
of the Alaska arrangement, and therefore he deferred to Mr.
McDowell.
Number 679
DAVE McDOWELL, Director, External Affairs - Gas, British
Petroleum (BP), responded that federal legislation and fiscal
incentives would reduce risk for projects such as this.
However, federal guarantee loans alone wouldn't be enough to
reduce risk and result in moving forward to the next phase. Mr.
McDowell indicated that U.S. federal legislation, a State of
Alaska fiscal contract, a clear and efficient green field
regulatory process in Canada, and cost reduction are all very
important. Mr. McDowell, in response to Representative Gara's
second question, said that he is ill equipped to speculate on
the matter.
SENATOR BUNDE remarked, "I don't mind being pioneers, but
somewhere in this world someone's got a equity in a pipeline
that we should learn from."
SENATOR DYSON returned to his earlier question regarding the
location of the pipeline and recalled that [earlier testimony]
has related that the $11.6 million will build a pipeline from
Prudhoe Bay to the Alberta hub rather than to the border.
Number 707
SENATOR OGAN posed a situation in which an explorer doesn't have
gas to offer during an open season, and asked if a producer-
owned pipeline could open a season that's advantageous while
others might not even have gas to nominate to the pipeline.
MR. BENHAM noted that such situations are faced in the U.S. He
explained that generally a pipeline owner in a situation in
which there may be an opportunity to increase through-put in the
line looks favorably on that. If a shipper is a latecomer to
the process, that shipper can gain access by approaching an
existing shipper to determine whether there is any excess
capacity. In fact, he recalled that the FERC and the NEB have
programs that allow existing shippers the ability to release
capacity to a new shipper. However, Mr. Benham highlighted that
the FERC doesn't have any inherent authority to require a
pipeline to expand. Historically, the economic incentives to
expand have been sufficient to ensure that all shippers who want
and need capacity have it available to them. The FERC and the
NEB would always review whether there is concern with regard to
discrimination. Furthermore, there is the Essential Utilities
doctrine that would presumably come into play in such a
situation. Mr. Benham opined that there are various legal and
commercial avenues that would be present to allow recourse to
those markets.
SENATOR OGAN characterized the situation in Alaska as unique
because he believes that the capacity could be filled with
existing supplies for quite a few years, and therefore
potentially shut out explorers and smaller independents from
exploration in the Foothills and other areas. However, the
state has an interest in those areas being developed. He
indicated the need to keep exploring even with the capacity that
already exists. Senator Ogan noted that he wasn't completely
comfortable that FERC will have the same "alignments" the state
would and be as concerned.
MR. BENHAM provided the following analogy with the offshore
pipelines when the sizing occurs to accommodate the expected gas
production. The sizing typically isn't restricted to the
shippers who are ready to produce and ship on the line at the
time the line is to go into service. With the offshore
pipelines, a pipeline owner will generally review the resource
capability in the area to be served by that line. Often, the
line will be sized to meet the needs of those ready, willing,
and able to contract at the time of the initiation of operation
as well as the potential for future throughput. Therefore, he
suggested that a good model with regard to how [Alaska's gas
pipeline] might evolve would be the pipeline network in the Gulf
of Mexico.
MR. McDOWELL reminded the committees that as part of the $125
million joint feasibility study, the large diameter 52 inch line
[with capacity of] 4.5 bcf a day is designed to be expandable up
to 5.5 bcf a day with the addition of compression. "Certainly
the line we're contemplating would be expandable as well, and it
really is in everybody's interest; more volumes mean lower unit
costs. For expansions it makes sense," he said.
Number 790
SENATOR OGAN inquired as to who pays for expansion.
MR. BENHAM answered that if the expansion is one that's viewed
as beneficial to all the customers in the system, the FERC, in
the past, has allowed those costs to be rolled into the existing
costs of the system. Therefore, the rate increment for the new
shipper is actually somewhat dampened because of the spreading
of the costs across the existing system. The FERC has indicated
that when the incremental cost of the expansion is less than 5
percent, it's automatically rolled into the existing costs of
the system. However, if the incremental cost of the expansion
is more than 5 percent, a test reviewing whether the expansion
is beneficial to all the customers in the system occurs. If the
aforementioned test isn't met, the FERC may determine that
incremental pricing is appropriate. Under incremental pricing,
the new shippers would be responsible for the incremental costs
of the expansion or addition to the system. The FERC's policy
on [expansion] is somewhat flexible in that parties are allowed
to show whether incremental cost [increases] or a rolled in cost
[increase] is better. He explained that under the incremental
concept, [FERC] doesn't want the existing shippers to bear the
cost of service that benefits only the new shippers. To the
extent that the expansion of the system includes benefits that
go beyond the services provided to the new shippers, there is
the potential for those costs to be rolled into [the existing
charges]. The impact on the new shipper will be less than it
would be if the new facility was priced on an incremental basis.
Number 835
TONY PALMER, Vice President, Alaska Business Development,
TransCanada Corporation, utilized a slide presentation entitled
"Alaska Gas Pipeline Construction Cost Risks" as he paraphrased
from the following written remarks [original punctuation
provided]:
The Alaska gas pipeline project will be a huge
undertaking requiring the skills and initiative of two
nations to bring to a successful in-service. The
sheer magnitude of the project and its risks means
that no single group can assume the entire project
risk. Like all large pipeline projects, the Alaska
project faces a wide variety of development and
operating risks, including natural gas commodity
prices, gas reserves, customer credit and capital
costs. Given its scale, the Alaska project has the
potential to strain the world supply of steel pipe,
other pipeline materials and construction labour,
particularly if the project is constructed all the way
to Chicago. So, an assessment of capital costs risk
is an appropriate subject for review in this
legislative proceeding.
The question posed by the Committee's agenda seems to
suggest that capital cost overruns on the Alaska
project are inevitable and that the only way to deal
with those overruns is to increase the tariff.
TransCanada does not agree with these assumptions.
First, despite the magnitude of the Alaska project, it
is not a foregone conclusion that there will be cost
overruns. Second, even if there are cost overruns,
such costs do not necessarily have to increase the
tariff.
BACKGROUND
TransCanada is a longstanding developer and operator
of large-scale natural gas transmission systems. We
undertake a systematic process to address major risks
on our pipeline projects. Firstly, in stage 1, we
identify the components of each particular risk. In
stage 2, we quantify the risks using probability
assessment. Finally, in stage 3 we attempt to
mitigate the risks and assign them to the parties most
capable of managing or bearing that risk. I will
focus my comments on construction cost risks today.
In stage 1, although there are a multitude of small
risks that will always occur on major construction
projects, the principal capital cost risks for the
Alaska gas pipeline are project delay and cost
overruns. Under the category of project delay,
subcomponents include legislative or regulatory delay,
environmental delays, competition for resources, and
weather. In the cost overrun category, there are two
broad subcomponents, labour and materials (including
steel, compressors, valves, etc.). I will speak to
how TransCanada proposes to address each of these
categories later in my testimony.
In stage 2, TransCanada utilizes its 50 years of
experience and expertise in the high-pressure natural
gas pipeline business to estimate a range of values
for each quantifiable variable or capital cost line
item. Expert opinions from internal and external
sources such as steel companies, contractors,
construction companies, etc. are solicited and
compared with TransCanada's in-house database on
actual results for other major construction projects
in North America and internationally. Our engineering
teams assess the risk distribution profile for each
variable and determine a probability assessment of the
outcome. We then use computer model simulations to
determine P(10), P(50) and P(90) and expected value of
the quantifiable risks. Then using a TransCanada
economic model, we include these multiple uncertain
variables, each with its own range of values and
probability profile, to determine stakeholders' risks
for overall capital costs.
In stage 3, we attempt to mitigate and /or assign
project risks to the appropriate stakeholders. I will
spend the majority of the remainder of my remarks on
this section as it is the most complex and important
part of the process. There are a number of ways to
mitigate the project delay and capital cost overrun
risks and to assign the remaining risks to
stakeholders. TransCanada believes the Alaska gas
pipeline can proceed now, if project stakeholders are
ready to restructure the project by limiting the
project to the frontier pipeline, using existing
facilities and legislation where available, better
matching of risks and rewards and engaging credible
project proponents to construct the pipeline and
manage the risks.
MITIGATION OF PROJECT RISKS
There are a number of factors, applicable to all large
scale pipeline projects, that can be used to control
capital cost overruns on the Alaska project.
TransCanada conducts detailed engineering studies
including the use of contingencies in our cost
estimations. TransCanada's normal practice is to seek
firm price commitments from pipe mills and contractors
after completing proper planning and logistic
arrangements. Project labour agreements with
contractors are sought to ensure construction is not
disrupted.
The route selection along the Alaska Highway provides
all-weather access to work sites, winter and summer,
to facilitate year-around construction, all subject to
environmental windows. The availability of an all-
weather road will reduce construction time and assist
in logistics for the project.
In addition to these factors, there are several
specific steps that TransCanada recommends be taken to
mitigate the construction cost risks of the Alaska
project.
Reducing the Scale of the Project
Limiting the project to the frontier pipeline would be
a significant step to controlling construction costs
overrun risks by reducing the scale of the project.
Constructing a new pipeline from Prudhoe Bay to
Alberta for approximately US$12-13 billion [2004
dollars that recognize inflation 2001-2003],
connecting to an extension of the Prebuild and using
spare capacity on existing infrastructure would
diversify pipe and labour requirements, allow for a
staged planning process and provide a broader
selection of suppliers to the construction project.
TransCanada would propose to retain the pipeline
economies of scale by constructing a 4.5 bcf/d
pipeline designed for cost effective expansion. We
would, of course, be prepared to construct a different
pipeline design should customer needs change.
Use of Existing Infrastructure
Once the new pipeline reaches Alberta, it should
connect to existing Alberta-to-market pipeline
infrastructure, supplementing when and if necessary.
The existing Alaska Highway Prebuild facilities have a
capacity of 3.3 bcf/d to markets east and west of the
Rockies. The current total export capacity of
pipelines from Alberta is approximately 15 bcf/d.
Significant spare capacity is available today and is
expected to be available at that level or higher when
the Alaska project is in-service. Spare capacity on
facilities to remove natural gas liquids is also
available within Alberta. Minimizing downstream new
construction from Alberta by integrating with existing
infrastructure will reduce the competition for
resources thereby reducing capital cost overrun risk
for the project. In addition, the tariff for Alaska
gas on the existing infrastructure will be lower than
it would be on a newly constructed pipeline. For
these reasons, TransCanada believes that Alaskans and
Canadians can achieve a win-win solution by utilizing
that spare capacity and constructing only the
necessary facilities downstream of Alberta.
Use of Established and Tested Regulatory Framework
TransCanada also firmly believes that with a
construction project of this scale and risk level, it
is important to act consistently with existing
legislation and treaties. The use of existing
legislation provides a significant time advantage and
assurance of approvals versus new contested
proceedings. TransCanada's proposed in-service date
of 2012, if a commercial deal is struck by 2005, is
evidence of the efficiency of using existing
legislation and certificates.
Canada and the United States signed a Treaty some 25
years ago setting out the principles for the
transportation of Alaskan gas from Prudhoe Bay through
Canada to the Lower 48. This agreement established
the rights and benefits for each nation from this
project. The Treaty is a fundamental foundation for
the project. Subsequent to the signing of this
agreement, the United States and Canada each passed
legislation to expedite the project, and create a
single window regulatory structure on both sides of
the border. They also granted certain corporations
the right to construct the pipeline in Canada and the
U.S. The Canadian legislation is the Northern
Pipeline Act (NPA) which granted Foothills Pipe Lines
Ltd., a TransCanada subsidiary, the right to construct
the Canadian section of the pipeline. Those
certificates are valid and are in full effect today.
Foothills utilized these certificates to construct the
Prebuild sections of the Alaskan project in 1981/82
and has relied upon the NPA to expand the Prebuild
five times to transport western Canadian gas in
anticipation of the Alaskan project.
The United States Government passed the Alaska Natural
Gas Transportation Act (ANGTA) to facilitate the
construction of the Alaska Highway Pipeline in the
United States. TransCanada and its subsidiaries hold
the ANGTA certificates to construct the Alaskan
section of the pipeline. In recent years, the ANS
Producers have sought enabling legislation in the U.S.
Congress as an alternative to the use of ANGTA.
TransCanada believes that if enabling legislation is
passed in the United States, then either ANGTA or
enabling legislation can be utilized for the Alaskan
section of the project.
It will also be important to leverage the use of
existing rights of way to expedite the project and
avoid cost overruns and project delay. TransCanada
and its subsidiaries were granted the U.S. Federal
right of way in Alaska many years ago and these remain
valid today. On June 1, we reactivated our pending
application for a right of way on State lands within
Alaska. The State has commenced re-processing of our
right of way application and we will continue to
diligently pursue this right of way to create another
valuable asset to advance an Alaska gas pipeline.
TransCanada has indicated that it is prepared to
convey the State right of way to another party subject
to that party successfully commercializing the Alaskan
section of the project and that party interconnecting
with Foothills at the Alaska/Yukon border. Foothills
has held a valid right of way through the Yukon for 20
years. Seeking new rights of way in the U.S. and
Canada can be a time-consuming and costly process and
can increase the risk of capital cost overruns.
TransCanada has had a longstanding relationship with
the First Nations in Canada along the project right of
way. The regulatory proceedings that led to Foothills
being granted its certificates from the Government of
Canada committed Foothills to provide training,
employment and business opportunities to First
Nations. We have communicated the long-term project
benefits to communities along the pipeline and we will
continue to conduct community consultations. We have
commenced signing protocols with First Nations,
including negotiations on participation agreements
with the Kaska, one of the First Nations in the Yukon
and north B.C. TransCanada will negotiate with other
First Nations when they are ready to proceed.
Use of Advanced Technology
For the Alaska gas pipeline project, TransCanada has
selected a pipe platform of 48" and 2500 psig to
transport an initial volume of 4.5 bcf/d with an
inexpensive expansion up to approximately 6 bcf/d.
This pipe platform is optimal for these volumes and
uses a pipe size that TransCanada has years of
experience with and pipe strength of X80. TransCanada
first installed X80 pipe on its system in 1994 and has
since installed several hundred miles of large-
diameter X80 pipe from multiple steel suppliers.
TransCanada is the only pipeline company in North
America that uses X80 for large natural gas
transmission projects.
We have recently installed the world's first X100 line
pipe (next generation of high-strength steel) in 2002
with a second installation in 2004. In early 2004, we
also installed a section of X120 pipe in collaboration
with ExxonMobil. TransCanada has led the development
and installation of high-strength steel and is
optimistic that X100 pipe may be utilized for the
Alaska gas pipeline in order to lower steel and
construction costs.
TransCanada has also led the advancement of large
compressor installations. We have installed a 33 MW
compressor in 2003 on our system in Alberta to test
the size compressors needed for the Alaska Highway gas
pipeline. This size compressor will lower the overall
cost of the project and reduce the number of
compressor stations, thereby reducing the
environmental impact of the project.
TransCanada firmly believes in testing all the major
components to be installed on a project of this scale
before commencing construction. We are a world leader
in both pipe strength and compressor technology
construction and operation. We also have made
significant strides with partners in advancing welding
and trenching technology as well as testing pipe
strength, fracture arrest, etc.
Reliance on an Experienced and Credible Developer
To construct a project of this complexity and scale,
it is important that credible project proponents lead
the construction and operation of the pipeline.
TransCanada believes it has an unparalleled record in
constructing and operating high-pressure, large
diameter natural gas pipelines in cold climates.
TransCanada is a successful developer of mega-
projects, world class in both scale and experience.
This is well-illustrated by our massive system
expansion projects of the 1990s. Our project teams
directly managed large-scale Canadian facility
expansion programs with costs totaling approximately
C$14 billion. These capital programs included nearly
11,000 km (7,000 miles) of large-diameter pipe (30" to
48"), 2,361 megawatts of compression, and 376 custody
transfer meter stations. The work stretched across
the continent. The largest single project was the
C$1.8 billion Iroquois project, carried out in the
early 1990s. It included 1,200 km of pipeline loop
and 17 MW of compression power.
We have designed, constructed and operated pipelines
in virtually every type of topography of the world.
Through almost 50 years of domestic experience and
approximately 20 years of international experience, we
have succeeded in the discontinuous permafrost of
northern Alberta, the jungles of Malaysia, the
prairies of southern Saskatchewan, the mountains of
Chile, and the muskeg and bedrock of northern Ontario.
We operate one of the world's largest fleets of gas
turbine-powered natural gas compressors. Over 90% of
the total compression power on TransCanada's system is
produced from 222 gas turbine drivers, ranging in
power up to 32 MW, with fuel efficiencies up to 40%.
In addition, at certain sites, we operate a number of
electric and reciprocating compressor drivers.
Aero derivative and light-industrial-type gas turbine
units are the current turbo-compressor standard at
TransCanada. This type of unit allows for minimal
outages for heavy maintenance or unscheduled repairs,
due to their modular design and the resultant ability
to change out defective modules at site. Availability
rates of over 96% are typically achieved on the
TransCanada fleet.
The results from a 2001 benchmark study confirm that
TransCanada has been, and continues to be, the lowest
cost provider of safe and reliable natural gas
transmission facilities. Out of more than 1,000 of
the top quartile (lowest cost) projects in NEB and
FERC databases, TransCanada's total installed capital
costs were lower than those of any of the competitors.
In addition to installing these facilities at the
absolute lowest cost, TransCanada's overall project
development efforts have been consistently on budget
and on schedule. During the 1990s, our C$14 billion
capital program was delivered within 0.6 per cent of
the budgeted amount. Our projects were ready for
service generally on or before originally scheduled
dates and in no case did we experience substantial
schedule setbacks. In a world where major project
overruns are not uncommon, we are proud of our track
record of tightly controlling schedule, budget and
risk on all of our major projects. Our success can be
attributed to our extensive project management
experience, our ability to develop effective
relationships with key stakeholders and our
implementation of leading-edge pipeline technologies
such as high-strength steels and mechanized welding.
ASSIGNMENT OF CAPITAL RISKS
Once the mitigation initiatives are implemented, there
will remain residual capital cost overrun risks
despite the best efforts of experienced pipeline
companies, construction companies, regulators,
shippers and governments. However, these risks do not
necessarily result in higher tariffs and lower
netbacks to the shippers or gas or royalty owners.
The original Alaska Highway gas pipeline contemplated
capital cost risk sharing by the pipeline owners.
TransCanada is prepared to share that risk with other
project stakeholders. We believe it is important that
other project stakeholders and beneficiaries including
governments share in capital cost and overrun risks to
ensure an alignment of interests and to minimize the
risks of project delay.
Number 224
SENATOR DYSON, referring to the chart on page 4 of the
presentation, asked if the new pipe would have to go all the way
to Caroline.
MR. PALMER clarified that TransCanada suggests constructing a
new pipeline to Boundary Lake, which is on the border of Alberta
and Saskatchewan, and extending the existing prebuild north from
Caroline, as necessary, because there is spare capacity on the
Alberta system.
SENATOR DYSON surmised then that the green lines on the chart on
page 4 represent what must ultimately be expanded. Therefore,
he further surmised that the Pacific gas transmission line would
have to be expanded in capacity.
MR. PALMER confirmed that if gas is to go to California, it may
need expansion. However, at this point it's difficult to
determine whether there will be sufficient spare capacity to the
market or markets that Alaskan gas will seek.
SENATOR DYSON asked if the same would be true from the portion
from Monchy to Chicago. "That's a alternative that may or may
not need to be built depending on the varieties of the market,"
he surmised.
MR. PALMER replied yes, adding that [in Monchy] the Northern
Border pipeline was built as part of the prebuild, which has
capacity of more than 2 bcf a day. There may or may not be
spare capacity at the time Alaskan gas comes to market, and
therefore it may need to be expanded. In further response to
Senator Dyson, Mr. Palmer clarified that the Foothills
agreements go to the border of the Lower 48, which is Monchy and
Kingsgate. He specified that [the Northern Border pipeline]
runs from Beaver Creek to Monchy, and Kingsgate.
TAPE 04-8, SIDE A
MR. PALMER, in continued response to Senator Dyson, related that
the forecast is that there will be significant increases in
demand for natural gas in western Canada, particularly in the
areas of oil sands, heavy oil, and electric generation. Mr.
Palmer informed the committees that a couple of years ago there
was projected growth in oil sands gas demand to [more than] 2
bcf a day. As a result of improving technology and high gas
process, the aforementioned has been reduced to 1.5 bcf a day.
TransCanada believes that the McKenzie Valley gas will be used
within Alberta, the market from which it will be distributed.
However, he noted that it will increase the pool of gas in
Alberta.
SENATOR DYSON recalled that Premier Cline wanted to ensure that
any northern gas was available for Alberta's value-added
processing. Therefore, he asked if Mr. Palmer anticipated that
Canadian gas will meet Alberta's need for gas as a feedstock for
its petrochemical industry.
MR. PALMER said that today there is a lower quality liquids
stream of gas than there was five years ago, which is the nature
of additional pipelines being built out of the basin to market.
Furthermore, the liquids content in Alberta gas is declining.
Therefore, there is spare capacity at those large plants
identified on page 4 of the presentation. Mr. Palmer opined
that he expected the owner's of those facilities to compete very
vigorously for the removal of Alaskan liquids as the gas passes.
Number 022
SENATOR OGAN related that he has heard from various sources that
[TransCanada's] tariffs are a bit on the high side. Therefore,
he questioned whether TransCanada could be competitive, tariff-
wise, with the proposed bullet line or the other applicants.
MR. PALMER said that he wasn't present today to identify the
tolls that have been discussed with potential customers, as
those are private at the moment. As the development process
proceeds he said he would be pleased to discuss that.
"Fundamentally, we ... believe that we will build the most
competitive, cost competitive, and toll competitive project from
Prudhoe Bay to Alberta.... And we're prepared to do that under
different tariff methodologies that will suit the customer and
the pipeline company." With regard to the tariffs from Alberta
to market, if spare capacity is available it will be the lowest
cost alternative and will give Alaskan gas the most market
diversity, the highest netback. Mr. Palmer pointed out that
from TransCanada's system the gas can either be sold within
Alberta or markets from San Francisco to New York could be
sought. If additional pipes are built from Alberta to market,
those might result in a new single line to a particular market
or they may be expansions of individual pipes. Therefore, it's
difficult to predict the tolls without knowing where Alaskan gas
will go. He noted that after comparing the costs of integration
with existing systems versus a new line, TransCanada believes
integration is a much lower cost alternative as well as a higher
netback alternative for Alaskan gas.
Number 052
SENATOR OGAN commented that it would make some sense that
plugging into an existing infrastructure would result in some
cost savings. He recalled briefings from the Energy Council
during which there has been speculation that Alberta will
possibly export less gas to the Lower 48 because it will require
most of the gas it produces for domestic use. Furthermore, he
recalled reading somewhere that coal bed methane may be 20
percent of the gas that's exported in the near future.
Therefore, he inquired as to the amount of gas that TransCanada
would have to export.
MR. PALMER agreed that Alberta will consume more gas than it
does today. In the [coming] 8-10 year timeframe, he predicted
that Alberta gas will peak and then start to decline, in terms
of supply. The aforementioned is with conventional and
unconventional reserves being produced. He indicated that there
[will be] a very significant demand growth in western Canada for
natural gas. With increasing demand and flat to declining
supply there is less gas to move through the existing pipes.
However, he expected the McKenzie Valley pipeline to be in
service by the end of this decade, which will [increase the
supply]. That gas will be placed in the Alberta pool. Mr.
Palmer opined that Canadian gas will decline significantly, in
terms of supply, over the course of the next decade. Although
the forecast is for unconventional supply to increase, it won't
increase enough to offset declines in conventional production.
Mr. Palmer emphasized that the aforementioned are forecasts,
which can change. Part of the value of integrating into the
existing system is that the decision regarding what pipes to
build away from Alberta can be deferred by a couple of years.
In further response to Senator Ogan, Mr. Palmer said that he
wasn't qualified to answer how much of the liquids can be
removed in Alberta.
The committee recessed until 1:33 p.m. at which time Senator
Ogan reconvened the joint meeting. From this point, Senator
Ogan chaired the meeting.
BILL WALKER, General Counsel, Alaska Gasline Port Authority
(AGPA); Attorney at Law, Walker & Levesque, LLC, informed the
committees that the AGPA was formed in 1999 by the North Slope
Borough, the Fairbanks North Star Borough, and the City of
Valdez. The purpose of AGPA was to cause a gas line to be
built. After formation of AGPA, it applied for and received an
IRS ruling stating that only the income to AGPA would be tax
exempt. While the application process was occurring, AGPA put
together a team to determine the viability of the project. Mr.
Walker showed a slide that illustrated that the AGPA project
consists of one line and two trunk lines. The main line is a
LNG (liquefied natural gas) line to Valdez with a line through
Canada on the Canadian Highway route and a line from Glennallen
to Palmer to tie into the Southcentral gas grid. The goal is to
obtain the maximum distribution of gas throughout Alaska.
MR. WALKER said that AGPA has maintained the premise that a
world-class team must be assembled, and therefore AGPA met with
the board of directors of Bechtel Corporation in October 1999 to
present the concept of AGPA and explained that a cost estimate
for the project was necessary. Bechtel Corporation put together
a very detailed cost estimate for the project. He noted that
Bechtel Corporation was told that with this project, cost
overruns couldn't occur. Therefore, Bechtel Corporation built
in cost overruns of $1.8 billion and owner contingencies of $900
million. Additionally, the corporation was instructed not to
assume any infrastructure benefits on the North Slope.
Furthermore, 8-10 percent inflation was included as were all the
soft costs, such as interest during construction, line pack,
insurance, et cetera. The aforementioned has resulted in very
complete numbers. Mr. Walker noted that another member of the
team is Taylor-DeJongh, Inc., which, for the third year in a
row, was voted the number one investment banking oil and gas
firm in the world. The information from Taylor-DeJongh, Inc. is
constantly updated to provide the best available information.
The other member of the team is O'Melveny & Myers LLP.
MR. WALKER informed the committees that the Alaska Gasline Port
Authority filed a stranded gas application. However, subsequent
meetings with the state indicated that a protocol agreement
would be more appropriate, which lead to entering into a
protocol agreement and withdrawal of the stranded gas
application. Initially, AGPA looked at only an LNG project. He
explained that the concept is project finance, which is 100
percent financed with a high debt service coverage ratio.
Initially [in 2000], AGPA was advised that the project would
require 1.7 and the first run on the LNG went over that. Since
that time the "Y" line concept has been added in order to share
the costs of the gas conditioning plant on the North Slope and
550 miles of pipe from Prudhoe Bay to Delta, where the "Y" would
take place with roughly three lines to Canada and three lines
down to Valdez and also the leg over to Cook Inlet. Mr. Walker
noted that AGPA has met with Agrium representatives in order to
discuss ways in which Agrium could have access to the gas under
AGPA's concept. He said that there are approximately four
benefits to AGPA's structure, each of which will impact the
tariff. Mr. Walker opined that AGPA's structure will provide
the lowest tariff with the maximum return to Alaskans. In
closing, Mr. Walker highlighted that AGPA has worked with all
parties. He mentioned that the benefit of the IRS ruling of the
tax exemption is huge because it places what would normally be
paid in federal taxes back into the project. Therefore, AGPA's
debt service ratios are phenomenal, as illustrated on page 25 of
the booklet he provided. Mr. Walker specified that the base
case assumes a $3.75 price in Chicago, a $2.75 price with the
LNG in Valdez. Such a base case would return a wellhead price
of $1.48, which he believes to be fairly significant.
Number 236
RIGDON BOYKIN, Special Counsel, Alaska Gasline Port Authority;
Attorney at Law, O'Melveny & Myers LLP, began by informing the
committees that AGPA is not prepared to provide the committee
with a tariff today. However, AGPA can inform the committees of
the implicit tariff within AGPA's structure. He explained that
the assumption is that AGPA would purchase the gas at the
wellhead and sell it to the ultimate consumer. The
aforementioned was in response to being told that the project
cost too much and that there was no market. The only way to
prove whether there is a market is to find a buyer for the gas
and determine what that buyer is willing to pay for the gas.
From a tax perspective, the assumption provides the maximum bang
for the buck. If AGPA owns everything down to the conditioning
plant, more is saved for the ultimate consumer and more is
produced for the producers in terms of netback. Therefore, the
focus is on the netback for the producers at various cost
levels.
MR. BOYKIN turned to the benefits of AGPA. First, there is the
"Y" line, which saves $6 billion in AGPA's particular cost
model. The aforementioned produces significant cost advantages.
Second, AGPA can sell a percentage of the debt on a tax-exempt
basis. He acknowledged that the Alaska Railroad Corporation
(ARRC) bonds may be used on a tax-exempt basis, although it
would require a difficult IRS ruling. Therefore, it was not
assumed that the ARRC bonds could be used. However, as a
municipal organization, AGPA can use tax-exempt debt as long as
the IRS rules on private use are satisfied. Basically, AGPA
believes it could obtain tax-exempt debt for about 30 percent of
the debt that would be used on this project. More than that
can't be used because most of the gas is being used by private
entities rather than municipal uses. The tax-exempt debt is
worth between $200-$400 million a year depending upon how much
is actually used. He also noted that AGPA's income is tax
exempt. Therefore, the mismatch between depreciation, interest
rates, and taxes is eliminated. Mr. Boykin said that most
important is that AGPA is charging economic rent of $370 million
for the use of this structure. He explained that 60 percent of
the $370 million goes to the state, 30 percent to all the
municipalities on a per capita basis, and 10 percent to equalize
energy prices for communities that couldn't take advantage of
the pipeline corridor or other pipeline benefits. "The net-net
of this is unless our project ends up having a huge cost ... it
has to be automatically the lowest cost, implicit tariff because
of these advantages," he remarked.
MR. BOYKIN acknowledged that there are issues that need to be
addressed; such as how should gas from a pipeline such as this
be priced in state. He said there are alternatives on that.
For example, the most normal way to price gas for in-state usage
is to price at the cost or just under the cost of alternative
fuels. Another way, albeit more controversial, would be to take
Chicago prices and subtract the transportation costs to Chicago
and utilize that as the in-state price. He opined that one of
the largest potential benefits is if one can determine a way in
which to have relative cost advantage on gas versus the Lower
48, and this is a potential opportunity for that.
MR. BOYKIN turned to the issue of cost overruns. The simple
answer that most want is that the state or the producers should
handle the cost overruns. However, he didn't believe that to be
viable. Indirectly, cost overruns impact the producers much
more than the state. Mr. Boykin said he didn't believe it would
be typical for the state to undertake backstopping the cost
overrun unless the cost overrun was caused by some action at the
state level. If the construction is parsed into pieces, the
cost of many of the pieces is certain. However, there will be
some pieces for which the cost isn't known as well as the
weather. Mr. Boykin informed the committees that he has
performed some sensitivity studies with regard to what happens
with overruns. On port authority's base case of $1.58 netback
to the producers, a $4 billion overrun reduces the netback to
$1.34. Therefore, he suggested that there's enough in the
netback pricing to allow absorption of some very large overruns.
The $4 billion overrun was on top of $2.7 [billion] of
contingency. Mr. Boykin emphasized, "I think that the
contingencies that you have in these things are very significant
and we all ought to work our tails off to try and mitigate them.
If they do materialize, though, it's not necessarily a project
killer." Mr. Boykin concluded by offering to provide the
committee with the results of different types of inputs that he
has acquired from Taylor-DeJongh, Inc.
MR. WALKER commented that for the first time, Alaska has a
distinct advantage from the market side. The stability of
supply is becoming more important than it was four to five years
ago. A number of companies have suggested that there should be
a premium attached to the LNG from Alaska. He noted that in
most joint ventures the government owns 70 percent and the
private sector owns 30 percent. Therefore, the criticism that a
quasigovernmental industry shouldn't be involved in this project
because that's the typical way it's done. [The tax exempt
status] available from the federal government makes this an
extremely profitable project to all of Alaska. As page 25 of
the "Alaska Gasline Port Authority February 2004" illustrates,
the annual return to the state is $1-$2 billion in revenue.
MR. WALKER mentioned that AGPA participated in a round table
discussion with US Secretary of Energy Spencer Abraham in Los
Angeles. He informed the committees that California consumes
8.5 bcf a day of gas and Alaska reinjects about 6.5 bcf a day of
gas. Secretary Abraham said there has to be a way that this
need and market opportunity can be filled from Alaska. Mr.
Walker acknowledged that although there are issues that have to
be resolved, for once Alaska's proximity and temperature is
advantageous. In fact, the last 90-120 days have been extremely
active and encouraging. He noted that AGPA has entered into one
memorandum of understanding (MOU) on a gas receiving facility in
California. Furthermore, AGPA has met with a number of the
Governor of California's advisors on a number of occasions and
have been advised that the offshore [facilities] "have a leg up"
with regard to the permitting process.
MR. BOYKIN explained that although AGPA is a governmental
entity, it isn't planning on building an infrastructure to
manage construction or operate the facility. The aforementioned
would be contracted out to other parties. If [the structure
proposed by AGPA] were used, the pipeline construction and
operation could be managed by an entity such as Enbridge,
TransCanada, or MidAmerica. Mr. Boykin clarified that AGPA is
trying to create a structure and a situation that produces
significant benefits that can be shared between the producers
and the ultimate consumer. Mr. Boykin then emphasized the need
to take into consideration the value of the liquids that would
be taken down the gas line. In AGPA's model, the liquids are
worth $1.75 billion per year. Furthermore, this pipeline has
recently been made more viable because on the Lower 48 leg it's
now possible to get some contracts on a long-term basis in
Chicago, which wasn't possible as recent as a year ago. He
noted that public service commissions are now pushing utilities
to fix gas prices on a long-term basis and ensure access to gas
on a longer-term basis.
Number 565
SENATOR DYSON related that he is quite impressed by the
evolution of the process. He opined that a hub or manifold
somewhere in the Interior that allows the distribution of gas to
wherever the market dictates is wise. Senator Dyson noted that
he was also impressed by AGPA seeing the need to bring gas to
Southcentral Alaska. However, he expressed surprise that the
major portion of AGPA's plan is the sale of LNG on the Pacific
Rim, [which flies] in the face of other experts saying that LNG
receiving facilities on the West Coast are slim to none and that
the chance to compete against the very low cost LNG will make
Alaska's LNG noncompetitive.
MR. BOYKIN explained that the revenue split between the two legs
of the project is probably 60:40. As for the market, AGPA is
pricing it at $2.75 at Valdez as the base case. The
aforementioned has created a lot of interest around the world.
He related his belief that there will be two to three facilities
on the West Coast, regardless of what others are saying. The
[O'Melveny & Myers] firm is working on three of them and the
clients are spending tens of millions on the permitting process.
However, he opined that those facilities in California will be
offshore. For example, Crystal Energy would use an old
abandoned oil platform brace, he predicted. Many of the
objections about LNG would be satisfied by putting those
facilities off-shore, although he acknowledged that not all
[objections] would be met.
TAPE 04-8, SIDE B
MR. BOYKIN related that those heavily dependent on LNG are
increasingly becoming concerned with regard to the stability of
LNG from some of the countries with much unrest. Also Alaska's
proximity [is advantageous] and could result in LNG swaps. In
response to concerns regarding the Jones Act, Mr. Boykin
emphasized that the ships cannot be produced in the time
required under the Jones Act. Therefore, it is believed that a
number of the provisions of the Jones Act would be waived. He
noted that there has been much support on this from the maritime
unions in Alaska, who have said they would work on this to avoid
the Jones Act becoming an impediment to the development of LNG
and the West Coast.
Number 670
CHAIR OGAN inquired as to how one gets past the [reality] that
the guys with the gas make the rule.
MR. WALKER explained that the first few years of the AGPA was to
acquire a relationship and gas from the producers. The focus
has been to sell the gas to the market so that the price is
known and work all the pieces up to the wellhead, and then make
a presentation to the producers. The goal would be to make an
offer to the producers that they can't refuse because the
economics would be so strong. Mr. Walker opined that with the
structure AGPA has, it will return a higher wellhead than the
producers could achieve on their own and it eliminates as much
risk to the producers as possible. Therefore, "it's basically
to present on a commercial basis, an offer to purchase." The
aforementioned has been done in the past with one producer,
although it was probably premature because AGPA didn't have all
the pieces together.
MR. BOYKIN interjected that as far as he knew no one has made a
bona fide offer to the producers. Until that occurs, the
response [is unknown].
Number 698
DANIEL IVES, Vice President and Principal, Lukens Energy Group,
Inc., informed the committees that he is representing the Alaska
Department of Law. He said he would address the specific
question regarding the agreements that must be reached before
FERC weighs in on tariff issues. To answer that question, he
provided a brief evolution of the natural gas transportation
market and new pipeline capacity planning, specifically focusing
on the open season process. [Throughout his presentation he
referred to a packet of information from the Lukens Energy
Group, which is contained in the committee packet.] He
explained that in the mid 1980s FERC issued Order 436, which
[required] open-access non-discriminatory transportation for
those parties that sought to provide transportation. As Mr.
Palmer mentioned earlier, quite a number of market centers have
been developed in Alberta. The Alaskan gas would come through
the aforementioned area and flow down to Chicago through the
Northern Border Pipeline, the Alliance pipeline, and the Great
Lakes Gas Transmission pipeline. On the West Coast there is the
PGT pipeline, which brings the volumes down to Los Angeles and
San Diego. Mr. Ives highlighted that the opening up of the
pipeline markets has begun to create vibrant market centers.
Market centers typically have interconnections of multiple pipes
and there may also be processing plants and access to gas
storage facilities. All of this is the result of the unbundling
of the sales and transportation of natural gas. Therefore, the
market became very robust as market centers were created around
the country. He mentioned the Henry Hub, which he referred to
as ground zero for natural gas pricing in the Lower 48.
MR. IVES explained that with the issuance of Order 636 the open
access order was taken one step further by requiring mandatory
unbundling of the sales and transportation of natural gas and
related services, such as storage, peaking service, gathering,
and processing. As the market centers evolved, much activity
has occurred with price risk management. Mr. Ives highlighted
that with the implementation of Order 636, all of the pipelines
in the country were required to completely redo their tariffs
and implement the open-access service. The aforementioned
process was managed on a settlement process basis, in which FERC
was very active. He said that FERC has been very active in
regulating the natural gas markets and helping to facilitate the
implementation of its policies. Order 636, he noted, also
provided for a capacity release program in which shippers could
release their capacity. Therefore, the parties, on an open
access fully disclosed basis, could offer up capacity for the
highest bidder.
MR. IVES turned to FERC's Order 637 in 2000. Order 637 simply
provided a number of enhancements to Order 636. For instance,
the scheduling provisions for natural gas were enhanced and thus
provided shippers the ability to fine-tune daily nominations.
Moreover, the order provided enhanced capacity segmentation
rights such that customers could take the contract path from the
wellhead to the burner tip, section it off, and release the
capacity to those wanting to pay for it. Furthermore, there was
increased informational reporting requirements for interstate
pipelines, which resulted in enhanced information for firm,
interruptible, storage, and capacity release transactions and
for the Index of Customers. Therefore, Order 637 provided
enhanced transparency to the contracting process.
MR. IVES recalled the Natural Gas Act of 1938 (NGA), which
provided for the regulation of natural gas companies. One of
the provisions of NGA requires companies to obtain a certificate
of public convenience and necessity (CPCN) from FERC prior to
the construction, extension, or acquisition and operation of
pipeline facilities. Part of the process requires the applicant
to demonstrate the need for the new capacity, which is typically
demonstrated by the evidence of contracts, market studies, and
reserve studies. He noted that the exact process with regard to
determining the need isn't mandated by FERC. Therefore, it's
incumbent upon the pipeline operator or project sponsor to put
together a market study to demonstrate the need for the project
and that it's been offered on a nondiscriminatory basis to all.
MR. IVES proceeded to provide a quick overview of the typical
FERC application process. Typically, the pipeline would hold an
open season to determine a market need, then select a pipeline
route and perhaps some alternative routes. The pipeline would
identify landowners, start easement negotiations, and hold
public meetings with the public and the various agencies
involved. The environmental surveys would begin and ultimately
file an application with FERC. However, FERC has modified the
process such that it has implemented a process to speed up the
certification process by FERC being involved earlier in the
process and working with the companies on a prefiling basis.
The aforementioned, he opined, would be particularly important
in the Alaskan project considering the magnitude, the number of
agencies involved, and the countries involved. The process is
fairly complex, and therefore any help in compressing the
timeline will be invaluable.
MR. IVES moved on to the open season process, which is discussed
on page 8 of the booklet he provided to the committees. He
explained that the open season process provides shippers the
opportunity to express their interest in transportation capacity
on a pipeline. The process is open to all shippers who want to
provide natural gas supplies or take gas deliveries on the
pipeline. He noted that many producers hold firm capacity on
interstate pipelines in order to move the gas from the
production area to the market centers. A number of the "LDC"
type customers purchase gas at market centers rather than at the
production area. He highlighted that the open season process is
held at the discretion of the pipeline. At least one of the
agreements filed under the Stranded Gas Pipeline Act has
mandated an open season process for its application. He
explained that typically the open season projects are posted on
the Internet web sites of the pipeline sponsors. He recalled
one of the Stranded Gas applications that he reviewed, which
required that six months prior to an open season there would be
notice such that the entire world would know about an upcoming
open season. The aforementioned is encouraging. Pages 10-12 of
the Lukens Energy Group booklet specifies what may be contained
in an open season announcement, which may include descriptions
of alternative projects.
MR. IVES pointed out that an alternative in the open season
process would be a nonbinding letter of interest. A pipeline
would "pre-float" the open season process and letters of
interest are sent out for response. After that process, the
full open season process would occur. He noted that new
projects are typically conditioned on the pipeline's ability to
timely obtain FERC certification without material modifications
to the project and upon completion of the construction. The
aforementioned indicates the need to have the regulators
involved at all levels and very early in the process. He turned
attention to page 15, which has an example of rates from an open
season document for Kinder Morgan. The example illustrates that
the open season was shopped with various alternatives for
various levels of interest. He noted that economies of scale
could be seen in the chart. He also noted that FL&U rates, the
fuel use and unaccounted for gas, can be a significant factor in
the era of $6 gas. The aforementioned plays into the
construction of the pipe and whether one would put in more pipe
or more compression.
MR. IVES moved on to precedent agreements, which is an interim
contract that is a legally binding contract with terms,
conditions, penalties for nonperformance, and mandates for
performance. The ultimate mandate is that when FERC issues the
certificate on terms that are generally consistent with the open
season, the shipper will ultimately sign a service agreement at
the various rates and quantities for the various receipt and
delivery points. Typically, the precedent agreement outlines
what the shipper wants, the path, the quantities, the agreement
to enter into a service agreement, and the pipeline's agreement.
Mr. Ives pointed out that there are "conditions precedent" that
must be done. The pipeline must obtain rights-of-way for the
route on acceptable terms and conditions, FERC's approval with
the issuance of a certificate by a date certain upon terms and
conditions consistent with the precedent agreement.
Furthermore, the pipeline's board of director and the shipper's
board of director must approve entering into the project and the
service agreement, respectively. The shipper must also satisfy
credit requirements, the standards for which have tightened
significantly. Moreover, the project must remain economically
viable. Precedent agreements also include efforts and timing,
termination rights for the shipper and the pipeline, a
termination fee, and other provisions. The ultimate goal is to
have a project that's approved with the shipper under the
service agreement under the pipeline's tariff. He mentioned
that a precedent agreement would typically include force
majeure, assignment, a most favored nations clause, governing
law, and notices.
MR. IVES highlighted that the precedent agreements typically
mirror the pipeline service agreement. In reviewing the project
and whether to authorize it, FERC reviews the firm commitments
by the shippers pre-construction and pre-certification in order
to determine the market interest in the project. Furthermore,
FERC may also have market studies done in order to review the
global market versus what specific shippers are willing to
purchase. The FERC may also review the supply end of the market
as well in order to determine whether the project is well
supported in that area. One of FERC's conditions in the filing
process is that the pipeline or sponsor must file the agreements
in support of the project as one of its exhibits.
MR. IVES turned to FERC's policy statement. The FERC did have a
presumption for the roll-in pricing of expansions of pipelines,
assuming they didn't go above a 5 percent limit. In 1999, FERC
changed its presumption from roll-in pricing to incremental
pricing, which essentially left the pipeline responsible for the
cost of new capacity if it weren't fully utilized. With respect
to project enhancements, if the incremental rate exceeds the
recourse rate, then the incremental rate is charged. However,
if the incremental rate is less than the recourse rate, the
recourse rate is charged and the project is rolled in. If
nothing bars the aforementioned, he expected that policy to be
applied to the Alaskan project as well. Mr. Ives pointed out
the board's goals and objectives for certificate policy, which
are listed on page 23 of the Lukens Energy Group booklet.
MR. IVES moved on to page 25 of the Lukens Energy Group booklet,
which discusses the certification process. He informed the
committees that 18 CFR [Code of Federal Regulations] provides
the basic regulations for FERC and Part 157.6 describes the
general content of applications for each project. He explained
that essentially one would file a mini rate case. Ultimately
one would show who would pay and under what rate schedules, and
the contracts that support this. Certain information regarding
the applicant and landowners. Mr. Ives related a story that
illustrated that FERC is very interested in what [the average
citizen] thinks about running pipes. He pointed out that page
27 specifies the exhibits are required to be filed with each
application. Exhibit I, market data, would contain the
requirement for the contracts and the market studies to be filed
as evidence that the project is bona fide. Exhibit P contains
the tariff and all the effective rate schedules. Exhibit P will
also provide information relating whether the proposal of a new
rate is the result of negotiation, a cost-of-service rate, or
the involvement of discounting. One must also consider the
competitive factors and was the rate made available to all
similarly situated customers. Therefore, Exhibit P is fairly
comprehensive. In addition to FERC's traditional filing
process, FERC has recently adopted the National Environmental
Policy Act (NEPA) prefiling process in which FERC and the
related agencies will be involved much sooner. He noted that
many of the landowner relationships and the environmental
scoping studies will be started much earlier in the project; the
government will be brought in early to expedite the process,
identify the critical issues, and determine how to resolve
those.
MR. IVES directed the committees to page 34 of the Lukens Energy
Group booklet, which has a timeline. The timeline illustrates
that under the expedited process, the order is issued much
earlier. In this case, about six to seven months are shaved off
the process. Furthermore, the scoping studies are conducted
much earlier in the process. Under the expedited process, FERC
is involved in a much earlier stage of the process. After going
through the entire process, FERC has wide latitude with regard
to setting the terms and condition of the certificate. The FERC
will review and analyze the application and supporting
information. The FERC may require the applicant to make changes
to the project such as alternate routing in order to ameliorate
environmental and/or landowner concerns. Other changes may be
in regard to configuration and sizing, based on variance in
routing or design load, or rates to reflect the final costs.
Moreover, FERC may require that there be a rate-refresher after
a certain period of time, which has typically been three years.
Number 233
SENATOR BUNDE turned to the timeline and surmised that the
worst-case scenario would result in a two-year process whereas
an expedited process would be a year process. He assumed the
aforementioned would relate to a typical pipeline. However,
Alaska's project would be a large project that he didn't guess
would be typical. Senator Bunde inquired as to the time
involved in actually dealing with a project the magnitude of
Alaska's project.
MR. IVES agreed that Alaska's project is of a large scale and
scope. One of the factors that helps expedite the process is
that this project would predominantly deal with the operations
within one state versus multiple states. Furthermore, he
related his understanding that FERC intends on being involved in
this project early.
TAPE 04-9, SIDE A
Number 0001
MR. IVES highlighted that there have been agreements signed by
Canada and the United States that will promote cooperation
between the two countries in terms of expediting the project.
Furthermore, he opined that any enabling legislation may put
FERC under considerable pressure, either by law or by inference,
to speed their process. "So I think you're going to see a 'all
hands on deck' effort by the [FERC]; I do have a certain amount
of confidence in them, having worked with them for a number of
years," he said.
SENATOR BUNDE remarked: "But in the worst-case scenario, two to
three years."
MR. IVES replied: "Yeah, I think you're right."
Number 0015
ROBERT LOEFFLER, Senior Partner, Morrison & Forrester, LLP,
offered the following:
Before I get to the assigned topic, I want to pick up
on the Senator's last question. I had the privilege -
or "misprivilege" - in 1974 or [1975] of going to the
first of 18 months of hearings on the Alaska gas
pipeline. To give you an idea of the speed of FERC at
the time, it took one day and a half for all the
attorneys to enter their appearances - that was just
the token. Because of that, Congress intervened
before to pass legislation - the Alaska Natural Gas
Transportation Act of [1976] - and, indeed, the
federal energy bill, and there's consensus on the so-
called enabling provisions, provide essentially for a
two-year process.
Indeed, FERC is required to grant the certificate
within 60 days, the completion of the impact
statement. So if that legislation passes, Congress
has provided a solution to what otherwise can be a
slow process; if the legislation does not pass, [the]
FERC has taken steps to improve the process from the
late 1970s - much needed steps. ...
Number 0049
MR. LOEFFLER turned to the range of permissible methodologies
that the FERC might apply in setting tariff rates for an Alaska
gas pipeline. He specified that he is going to speak generally
about the methodology and standards the FERC uses to set gas
pipeline rates. He pointed out that in the appendix, there is
material from a sample rate case at FERC. There is also a
hypothetical illustration and a range of results in a large
number of recent FERC cases that will provide some parameters.
However, with Alaska everything's a little bit different, which
is also true [with regard to how] FERC [deals with Alaska]. The
magic standard is that of ANGTA and many other regulatory
statutes, which is that the rates have to be just and
reasonable. However, there's a lot of flexibility in those
standards. He recalled when TAPS started operation, there was a
huge controversy regarding the proper way to set the rates on
TAPS and that controversy continues to this day. The good news
is that gas pipeline rates are set on [a] standard utility
ratemaking basis, which is "original cost" ratemaking. Still,
there are a lot of details, which have some real dollar
consequences with regard to what happens in Alaska.
Number 0062
MR. LOEFFLER emphasized that there are different regulatory
regimes for oil pipelines and gas pipelines. For oil pipelines,
dual jurisdiction exists. Therefore, the Regulatory Commission
of Alaska (RCA) sets rates for shipments inside Alaska while
FERC sets rates for shipments that go into interstate commerce.
However, for gas pipelines FERC sets the rate for the gas that
goes from Prudhoe Bay outside Alaska, and the rate for any gas
that's taken off in Alaska, as long as that gas travels on the
main pipeline. Mr. Loeffler remarked that the committees have
probably noticed a relative absence of discussion related to the
role of the RCA [because its] role will not correspond to what
it was for the oil pipeline. He noted that "there's established
[U.S.] Supreme Court law on that: ... once the FERC is in
there, it's in there comprehensive on any rate that goes for the
main pipeline, whether that gas is taken off inside or outside
Alaska. There's a second consequence: for an oil pipeline to
go into business or to exit the business, you do not need
permission from the FERC, [but] for a gas pipeline you do."
When TAPS started out, the FERC didn't have any process that
corresponds to what there will be for the gas [pipeline]. For
gas pipelines, one applies to FERC, which regulates the size and
pressure of a gas line as well as whether it serves the public
interest. Furthermore, [FERC] has a huge environmental impact
process. "It's a comprehensive form of regulation," he
remarked.
Number 0089
MR. LOEFFLER specified that gas pipeline regulation is the
"bread and butter" of what the FERC does. "They really don't
like to do very much with oil pipelines, which was one of the
problems," he commented. Therefore, one must remember this
framework when thinking about fighting the last war, which is
the TAPS war, and fighting the wars that are to come on the gas
[pipeline]. Mr. Loeffler pointed out that the [U.S.] Supreme
Court has said that the FERC has very broad discretion in
ratemaking; there's no single formula or combination of formulae
for determining just and reasonable rates, although the original
cost is the overarching thing. However, that's not true for oil
pipelines, and therefore, again, there's a difference in the
two.
Number 0093
MR. LOEFFLER remarked that the objective is to strike a balance
between rates that protect consumers from excessive rates, and
those that reward investors for the risks of investing in the
pipeline. In the [Hope Natural Gas] case, the [U.S.] Supreme
Court teaches that the rates should attract capital to the
regulated enterprise and allow it to earn what other projects
facing the same risk do. Furthermore, rates are set "in the
first instance" by the pipeline rather than FERC. Therefore,
the pipeline puts out a set of proposals and will file proposed
rates in the open season. The FERC reviews [those], and
certainly the pipeline cannot depart wildly from FERC precedent
in figuring out what the rates are. Again, one must remember
that there's considerable leeway in how a project will design
and negotiate its rates with its proposed shippers. Mr.
Loeffler returned to a point that Mr. Ives made regarding when
the FERC approves the facilities. When FERC grants a
certificate of public convenience and necessity, it does a mini
rate review. He explained that FERC expects to have a rate case
sometime [in the future], and therefore rates are set in line
with FERC precedent. However, there's a lot of discretion in
that FERC precedent and one doesn't get to litigate rates until
later in the process.
Number 0139
MR. LOEFFLER turned to the details in setting rates, and said
that it's basically a cost-plus system. The rates are designed
to recover the operating costs, depreciation, taxes, and return
on capital investment. This process is called, "calculation of
a cost of service, or revenue requirement." He mentioned the
revenue requirement set forth in appendix A. He explained that
the rates are designed to allow a pipeline to recover all the
costs as well as an opportunity to earn a return on the invested
capital. However, most of the energy in ratemaking is spent on
the following three things: determining the return/profit
component; the depreciation; and the rate design. He explained
that the rate of return calculation is basically one in which
the commission is trying to determine the "overall cost of
capital" the enterprise should receive. In order to determine
the return, the cost of capital is multiplied by the rate base,
which is the property devoted to public utility service. The
rates are designed to capture all that return, he noted.
Number 0161
MR. LOEFFLER moved on to steps [necessary to achieve a rate].
He turned to [one of the steps] the capital structure of the
asset, that is the percentage of the asset that is debt and the
percentage that is equity put in by the investors. Once that's
determined, the cost of each class of asset must be determined.
He remarked that it's fairly easy to determine the amount of
debt of a pipeline. Preferred stock goes into debt, he noted.
Mr. Loeffler explained that to determine the return on equity,
the earnings of other pipelines in the industry are reviewed and
used to set up a proxy or standard. After the pipeline entity
argues about what [constitutes] the right proxy group, the right
year, and the right factors, then a proxy reference point is
established. A proxy reference point is really a range of
returns. However, then the pipeline entity argues that it's not
an average pipeline, but rather more risky and thus deserves
more. The shippers, on the other hand argue that the pipeline
entity isn't risky at all and thus the pipeline entity should
earn less. "That's the nature of the fight," he said. The
FERC, since at least 1998, has used this discounted cash flow
methodology, which is referenced on page 9 and in appendix B.
The proxy idea is to review what investors in pipeline stocks
expect to earn. The FERC has gone to a method that is sort of
front-weighted, which places more weight on recent earnings than
long-term earnings because everyone's more anxious to earn money
these days.
Number 0181
MR. LOEFFLER maintained that selection of the proxy group is not
a science: there's a lot of argument that goes into how you do
it. Appendix [C] is a list of about 60 cases, which highlights
that the rate of return on equity has ranged from 12.38 percent
to 14 percent. Mr. Loeffler said he expected there could be
some point of contention between the state and any pipeline
project regarding what is considered the appropriate rate of
return on equity. He pointed out that in the early 1980s, when
the Alaska gas pipeline last made its way through the FERC, it
created an incentive rate of return mechanism to try [to]
control costs. The center point of that was a 17.5 percent rate
of return on equity. However, that was during a time when all
returns were at [a] historic high; long-term U.S. government
bonds were at 15 or 16.25 percent. Although that's not today's
environment, it's one reference point that he was sure someone
will mention. He recalled that in the TAPS rate case, there
were many arguments that it was the "first of it's kind, cold
and dark, it deserved a particular sort of return." Mr.
Loeffler said that when FERC analyzes the risk, it looks at
various types of risk such as the risk during the construction
period, the operating period, and the financial risk relating to
capital structure. The aforementioned is reviewed in order to
determine the right number for the risk. Whether the project is
[project] financed or financed off the balance sheet is
important when determining the correct rate of return or the
overall return on capital for a pipeline. Mr. Loeffler
explained that project finance means that it's essentially the
earnings from the pipeline that will support the debt. Project
financing is very common in real estate as well as in pipeline
projects.
Number 0216
MR. LOEFFLER explained that typically a project-financed
pipeline will borrow 70-80 percent of the cost of a project.
The last time the gas pipeline went through, it was a "75
percent debt:25 percent equity" structure, he noted. He related
that debt almost always costs less than equity. Therefore, if
one has a lot of debt in the capital structure, the amount of
the return that is assigned to debt is large and the overall
amount of the return is less. On the other hand, if one has a
huge amount of equity, it receives a higher rate of return,
which "tends to drive up a pipeline." In reviewing pipelines
that weren't project financed recently, one finds capital
structures in the industry of 50 or 60 percent equity, which
isn't atypically. However, in reviewing project finance, one
finds much less. Although there's no universal rule as to
what's acceptable, it makes a big difference in the return
element. Therefore, a critical decision to ask is, how will
these projects be financed: project financed with a lot debt;
or financed on a recourse basis with a lot of equity?
Number 0243
MR. LOEFFLER addressed the question regarding how FERC decides
whether a capital structure is appropriate, that is whether it
has too much debt or too much equity. Basically, FERC reviews
how the project was actually financed. [If the project was]
financed, hypothetically, at the parent company level, as
opposed to the pipeline company level, then FERC will say maybe
it's the parent company's capital structure that should be used.
However, FERC reviews whether the debt was reasonable. He noted
that FERC prefers actual as opposed to hypothetical capital
structures. With a hypothetical [capital structures], "it would
have to construct what it thinks the world should be as
[opposed] to what it is." Although FERC does this sometimes,
it's rare. Now, when you actually go through the math, which
this does, it's sort of interesting because what I did was take
a hypothetical pipeline - million-dollar pipeline - and I have
three cases.
MR. LOEFFLER directed attention to a comparison chart, which
utilizes three cases for a hypothetical pipeline. The project-
financed pipeline is three-quarters debt with lots of money
borrowed from the bank. For the equity-rich pipeline he
proposed that it's a very large, worldwide oil company worth a
lot of money and with very little debt. He also proposed
hypothetically that two of the three companies on the North
Slope are in this position of being an equity-rich pipeline with
only 10-20 percent debt. He explained that he assigned the
project-financed project slightly different equity numbers
because the FERC tends to look at such a project as riskier than
[an equity-rich pipeline project] with the equity of a very rich
company behind it. He explained that [the chart] uses the same
cost of debt. Therefore, the return, which goes into the rate
with the costs and depreciation, before accounting for interest
on the project-financed pipeline, is $95,000. However, the
[return for] the middle of the road pipeline is "about [$]105
and [$]104." Still, one has to deduct, from that return
element, all the money necessary to pay for the bonds.
Therefore, one finds [that] the equity-rich pipeline brings much
more money home to the parent company than the project-financed
pipeline. However, one must [remember that] in one case [the
pipeline owner/investors] used 80 percent of their own money
whereas in the other case [the project-financed pipeline
owner/investors] borrowed three-quarters of the money from the
bank. "So they're the two polar extremes, and that's the point
of my illustration," he said.
MR. LOEFFLER directed attention to a chart that follows his
prepared statements; it lists many rate cases. He said that one
must not take too much comfort in this long list of cases
because Alaska is the largest project to go through FERC, "and
it will set it's own rules." The cases are sorted by whether
the pipelines were project financed or not project financed.
Therefore, one can see, in the last column, that most of the
project-financed pipelines have an overall cost of capital
around 10 percent. The chart further relates the pipelines that
were not project financed but rather financed off the balance
sheet of their owners have a higher return "on that." Although
one would have to adjust for the time of the case and the
particular circumstances of the corporation, it's illustrative
of how the process works at FERC [and] the advantages of project
financing.
Number 0329
MR. LOEFFLER turned to the question of why wouldn't everyone
with the resources put 80 percent of the equity in the project.
He explained that in unregulated businesses, many companies
don't view 14 percent return on equity, which is about as high
as the FERC has awarded in any of these cases, is not as good as
they can do with other investment of their money. Therefore,
some may prefer a project-finance route and thus tie up as
little money as possible in this project.
MR. LOEFFLER said he needed to make a few corrections to his
testimony. He provided the following qualification: "pipeline
companies are allowed to earn this return after taxes, so
there's a step that I omitted." A tax allowance or tax gross-up
(ph) is added on top of the amount of the return so that after
tax, on a hypothetical stand-alone basis, the amount earned is
the identified return. "And there are a lot of dollars involved
in that," he remarked. He then commented on open seasons as
they apply to this pipeline and the [Congressional] legislation
that provides that FERC will adopt open season regulations for
this project, although normally there hasn't been anything that
resembled detailed, open season regulations. He pointed out
that although there are a lot of FERC rulings, they occur after
the pipeline arrives when someone complains that the open season
was unfair or performed incorrectly. If this legislation is
passed, he predicted that FERC would be more proactive. The
FERC will be required to adopt the set of regulations within 120
days of the legislation governing open seasons for this
pipeline, and therefore there will be regulations in advance of
open seasons for this pipeline. He noted that there are other
provisions of the enabling legislation that address such issues
as expansions, lateral service in Alaska, et cetera.
The committee took an at-ease from 3:25 p.m. to 3:45 p.m.
Number 0380
NAN THOMPSON, Commissioner, Regulatory Commission of Alaska
(RCA), Department of Community & Economic Development (DCED),
said she would be offering a historical perspective on what rate
regulation on pipelines has meant under Alaska law, and her
experience regarding regulating pipelines. She began by talking
about the AS 42.06, which sets a standard for rates as just and
reasonable and based on cost. The aforementioned statute states
a clear policy that parallels the policy for rate setting on
pipelines, both for utilities and pipelines across the country.
That statute created a regulatory agency with authority to set
cost-based rates. She related that the reason agencies like the
RCA exist at all is because utilities and, in some cases,
pipelines are monopolies. Therefore, regulation is necessary to
ensure that prices are fair. Agencies such as the RCA are
thought of as a replacement, economically, for the market, which
doesn't exist in monopoly services like utilities. "It's the
responsibility of the regulatory agency in this context to look
at the costs of the pipeline, or the utility, the cost of
building the pipeline, and provide them a reasonable opportunity
to recover their investment," she explained. The agency must
review the ongoing costs and the original cost of construction
in order to determine how the entity can recover a return on its
investment, all of which is factored into the rates.
MS. THOMPSON said, "There isn't a perfect answer to rates."
However, under the law there is a zone of reasonableness for
which there is considerable case law across the country. The
case law specifies that compensatory rates are those that aren't
less than compensatory. In other words, the [pipeline
owner/investors] are allowed a reasonable opportunity to recover
costs "and they're not excessive." Therefore, RCA's role is to
review the detail of the costs and strike the balance. Ms.
Thompson added that AS 42.05 addresses affiliate costs, which is
applied to pipelines and utilities in Alaska. When some of the
costs included in the operations or construction of a pipeline
are incurred by an affiliate, this statute ensures that the
pipeline rates don't include any costs higher than would've been
paid if those same services were performed by a third party.
MS. THOMPSON informed the committees that the RCA uses a formula
to determine rates for a utility or pipeline. Basically, the
return is determined by reviewing the capital structure, the
cost of debt, and a risk adjustment if that's appropriate. That
return is multiplied by the rate base, which is what it costs to
build the asset minus depreciation. Then, the aforementioned is
added to the operating expenses, depreciation, and taxes.
Therefore, a rate case before an agency like the RCA is lawyers
and experts presenting evidence with regard to what the numbers
that get plugged into that equation should be. Therefore, the
RCA uses the formula consistently to ensure that the rates are
just and reasonable. She said, "It's really the determination
of what those different inputs are that's the challenging part
of a rate case." She provided an example. On depreciation,
utility [owners and pipeline owners] are entitled to recover the
costs they put into building the asset. Therefore, questions
arise regarding the time period [of recovery] and the schedule
[of recovery]. The RCA reviews what is going to be fair to the
shippers, now and in the future. If all of the costs are
recovered early in the life of the pipeline, then arguably the
earlier shippers bear more of the burden than the later
shippers. However, if much of the costs are recovered early,
then what incentive will the pipeline owners have, in later
years, to continue to operate the line, she asked. She
highlighted that it's not uncommon for the expected life of a
pipeline to change over time.
MS. THOMPSON turned to the litigation history of TAPS, which she
suggested would probably be a good case to understand while
contemplating the gas [pipeline]. She informed the committees
that when the pipeline was constructed, there was a lot of
dispute regarding what rates would be charged for shipment on
it. The legislature became involved in hearings, and there was
much fact-finding before the RCA. Litigation, in several
different forums, went on for about 10 years when the parties
settled. The aforementioned resulted in what's know as TSM, or
the TAPS settlement methodology. Due to the statute that
specifies the regulatory commission has a responsibility for
just and reasonable rates, it was presented to the agency for
approval. The APUC [Alaska Public Utilities Commission], as the
RCA was named at the time, accepted the TSM. "They didn't
approve it - they accepted it," she emphasized.
Number 0501
MS. THOMPSON added:
They said ..., "All the parties who are here before us
today are telling us this is a good idea, [and] we're
not going to take the time" for whatever reason "to do
the type of analysis we normally do to ensure that the
rates are cost-based; we're going to accept this
settlement [because] the parties agree." It was an
efficiency decision. But they said, "If there's ever
a protest, we're going to have to revisit this ...
because we don't know ... a lot about what we're
approving, we don't know exactly what some of the
numbers are in this settlement, but it's okay because
the parties agree."
MS. THOMPSON related that there was a methodology under which
filings were made annually, with some cost information, by the
TAPS carriers. The rates were adjusted based on those. In 1997
one of the shippers protested and charged that the rates were
too high, and therefore the process began for reexamining [the
methodology]. Eventually, there was a five or six week long
hearing to gather evidence in order to make a decision. She
noted that there were a lot of pretrial motions. Ms. Thompson
said:
But the difficulty in that case, which explains why
the order concluding it was so long and the proceeding
was so complex, was that when the original settlement
was approved, they never had clear pegs for some of
the numbers. The agency had not made a finding, ...
for example, [that] the amount of depreciation [in]
the order was just and reasonable. Nobody knew. They
were ... numbers that the parties had agreed on, but
the agency hadn't done what it was supposed to do ...
[per] the statute in making a just and reasonable
finding.
Number 0532
MS. THOMPSON explained that in order for the RCA to determine
what the rate should have been in 1997 when the protest was
filed, it had to determine how much of the asset the pipeline
had already recovered through rates. Therefore, much of the
testimony in that proceeding was reviewing a lot of detailed,
historic records to determine a fair place to start from. The
aforementioned necessitated deterring how the rates calculated
under this TSM compared to cost-based rates, which was the
directive in the statute. Upon reviewing the evidence to
compare those two types of costs, it was determined that the
[pipeline owners] had a significant opportunity for recovering
more than the costs they had incurred to date. Therefore, the
rates were set going forward.
Number 0571
MS. THOMPSON stated that the biggest adjustment was in
depreciation. The [carriers] argued that what had been
characterized as depreciation, the TSM filings for 20 years,
wasn't really depreciation after all. [The carriers argued]
that they hadn't really recovered as much as they had been
identifying as depreciation over the years, and therefore the
RCA should allow them to recover more. However, the agency
didn't find that argument plausible and decided to use the
amount that the [carriers] had already charged shippers for
depreciation while using straight-line depreciation going
forward. She explained that when the RCA compared cost-based
rates to TSM rates, the TSM rates were 57 percent higher over
that period of time, which was a rather significant difference
between what the settlement methodology produced and what the
RCA thought fair, cost-based rates should have been. Therefore,
the RCA set the rates going forward as it would in any other
rate case. "I think the importance of this case and the lesson
for you when you're considering how the gas [pipeline] tariff
should be set, and I think probably even the carriers would
agree that going through that process is something they would
want to avoid the second time, ... [is that] it was enormously
expensive," she highlighted. In fact, at one point in the
process the carriers were required to file litigation-cost
reports because those are arguably recoverable in rates. She
recalled that the last litigation-cost report was about $14
million, which is a huge sum of money that might have been more
productively spent on something else. "The importance of
process ... is something to think about when you're thinking
about how you might avoid this circumstance again," she said.
She further said:
What that case told us is that as a result of the
commission deciding, "Well, we'll just accept the
settlement because everybody agrees," and they were
under enormous pressure at the time from folks who had
been litigating for 10 years and saying, "Look, we
agree, it's all over, don't look at this," it created
a problem that has taken ... it's successors many
years to live (indisc.) ... [tape changed sides mid-
sentence.]
TAPE 04-9, SIDE B
Number 0643
MS. THOMPSON continued [tape begins mid-sentence]: "... the
settlement methodology produced. The cost based rates were
significantly lower." She remarked that transparency in the
process has been a problem throughout. The RCA makes sure that
services provided on a monopoly basis are at a fair price and
understandable to the public or anyone who has to pay those
rates. However, when things are filed at settlement, often the
settlement documents are not always public. Furthermore, the
pipeline tariffing process is less transparent than the utility
tariffing process. Ms. Thompson related her personal belief
that a public process is often fairer. "Sometimes you need to
have information in order to be able to file an appropriate
protest or in order to be able to certainly put on a good case
before us," she explained. Therefore, the rules need to be fair
and allow potential shippers the opportunity to become involved
in the rate-setting process while providing information about
what they think is fair or not. She encouraged the committees
to ask questions, explaining that reasonable rates are important
because when encouraging development one needs to be think about
who the shippers are in the line right now as well as the
shippers who may be or want to be in the future. She also
encouraged the committees to make sure that the rates are
reasonable so that in the long term, development can be
encouraged.
MS. THOMPSON opined that if she had been on the commission at
the time the settlement was presented, she would've argued that
the commission should've reviewed the settlement under the just
and reasonable standard rather than accepting the settlement
because everyone agreed. "It's always going to be guesswork to
some extent when you're setting rates," she remarked. Under a
normal utility context rates are adjusted every four or five
years or if there's a major change. "You don't have to guess
what the rates are going to be for 20 years, you have to guess
over a reasonable time horizon, which varies with the utility,
depending on what their operations are like," she said. She
noted that the decision in this case is on the RCA's web site.
MS. THOMPSON noted that the other argument/discussion one may
have in the context of gas line rates, is regarding comparison
to FERC and why other RCA's processes are different than FERC.
She explained, "There's one important significant difference
between what FERC does and what we do as a state regulatory
agency and that is most of FERC's pipeline regulatory structure
in the Lower 48 is very different but that's because there's
competition. There's often down there more than one-way to get
the gas to market." However, it's unlikely that there's going
to be more than one gas pipeline from the North Slope, at least
in the foreseeable future. Therefore, some of the market-based
rate-setting mechanisms that FERC uses probably aren't
appropriate in this context because there are no competitors to
discipline prices. She concluded by relating that continued
enforcement of the just and reasonable rate will best ensure
long-term stability in the gas market.
CHAIR OGAN said that previous speakers have testified that
ratemaking is very transparent so there should be no overriding
tariff issues. The FERC would regulate the pipeline while the
RCA would have a seat at the table and play more of an advisory
role. He asked Ms. Thompson what rate-setting mechanism she
would suggest if FERC's process is not appropriate to Alaska's
single gas line.
MS. THOMPSON said RCA's only jurisdiction will be over
intrastate shipments - gas that comes off the line within the
state. The RCA collaborated with FERC on the TAPS case and
others, and the two agencies have signed a memorandum of
understanding to work cooperatively on pipeline issues. She
noted, as an example, the Quality Bank case has been before both
agencies for many years; the RCA and FERC held concurrent
hearings on the case last year. FERC and the RCA have a history
of cooperation that has been somewhat institutionalized. She
said the RCA has no interest in regulating interstate rates.
CHAIR OGAN asked Ms. Thompson to elaborate on her comment that
FERC's regulatory process is designed for the Lower 48 where
competition exists and on how it will consider the Alaska rates.
MS. THOMPSON explained:
What I was trying to articulate was that the
methodologies they use for setting gas pipeline rates
in the Lower 48, not necessarily their jurisdiction
over this line - I don't know how they're going to
regulate this line, whether they will apply a
different regulatory review standard than they do in
the Lower 48 gas pipeline. But in the Lower 48, gas
pipeline rates are set under a very different
mechanism and there's a minimal standard of review, at
least economically, because there are market forces
that operate there to keep those lines reasonable -
there's competition. ... The owners of the pipeline
have incentives that don't exist when there's only one
route to keep the rates low. I don't know what they
will use to set rates for this line. That may or may
not be true. I wasn't trying to draw a comparison
between their regulation of this gas pipeline but more
gas pipeline regulation in general.
CHAIR OGAN thanked Ms. Thompson for her presentation and service
to the state. He then announced that the committee would recess
until 8:45 a.m. the following morning.
[Although the beginning of the June 17th meeting starts on Tape
04-9, Side B, it was placed on a separate tape, Tape 04-9A, for
ease.]
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