Legislature(2003 - 2004)
07/28/2004 10:00 AM House BUD
| Audio | Topic |
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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
LEGISLATIVE BUDGET AND AUDIT COMMITTEE
SENATE RESOURCES STANDING COMMITTEE
July 28, 2004
10:00 a.m.
MEMBERS PRESENT
LEGISLATIVE BUDGET AND AUDIT
Representative Ralph Samuels, Co-Chair
Representative Mike Chenault
Representative Mike Hawker
Representative Beth Kerttula
Representative Reggie Joule
Senator Con Bunde
Senator Gene Therriault
SENATE RESOURCES
Senator Scott Ogan, Co-Chair
Senator Tom Wagoner
Senator Fred Dyson
Senator Ralph Seekins
Senator Kim Elton
OTHER MEMBERS PRESENT
Senator Gretchen Guess
Senator Gary Stevens
Representative Harry Crawford
Representative Les Gara
Representative Beverly Masek
Representative Ethan Berkowitz
Representative Paul Seaton - via teleconference
Representative David Guttenberg - via teleconference
Representative Bill Stoltze
Representative Lesil McGuire
MEMBERS ABSENT
LEGISLATIVE BUDGET AND AUDIT
Representative Vic Kohring
Senator Lyman Hoffman
Senator Lyda Green
SENATE RESOURCES
Senator Ben Stevens
Senator Georgianna Lincoln
COMMITTEE CALENDAR
Alaska Natural Gas Pipeline Issues/Access to Original Pipeline
and Expansion Capacity
Presentations
In Need of Access: Alaska's known and potential gas resources -
David Houseknecht, Research Geologist, US Geological Survey -
Mark Meyers, Director, Division of Oil and Gas, Alaska
Department of Natural Resources (DNR)
Original and Expansion Capacity: What volumes, when, on what
terms and at what price - Joe Marushack, Vice President,
ConocoPhillips, and Pete Frost, Director of Regulatory Affairs,
Gas & Power Marketing Group, ConocoPhillips, on behalf of
Producers BP, ConocoPhillips and ExxonMobil
Access to Capacity for Producers and Explorers Without an
Ownership Interest in or Effective Control of the Pipeline -
Mark Hanley, Manager, Public Affairs for Alaska, Anadarko
Access to Capacity for Alaskan Communities - Charlie Cole, Board
of Directors, Alaska Gasline Port Authority
Letter from James Whitaker, Mayor, Fairbanks North Star Borough
State Revenue Issues of Gasline Expansion - Larry Persily,
Special Assistant to the Commissioner, Alaska Department of
Revenue
Access to Capacity for Alaskan Utilities - Anthony Izzo,
President, Enstar Natural Gas Company
Access Under Current Law v. Access Under Proposed changes to
Federal Law - Bob Loeffler, Senior Partner, Morrison & Foerster,
for Alaska Department of Law
Volumes, Timing, Terms and Price of Access with 36", 48" and 52"
Pipelines - Eric Watson, Project Manager, Alaska Gas
Development, Enbridge, Inc.
The Array of State Tools for Improving Access - Marty
Rutherford, Deputy Commissioner, Alaska Department of Natural
Resources
ACTION NARRATIVE
TAPE 04-13, SIDE A [BUD TAPE]
CO-CHAIR RALPH SAMUELS called the joint meeting of the
Legislative Budget and Audit Committee and the Senate Resources
Standing Committee to order at 10:00 a.m. Senate Resource
Committee members present were Tom Wagoner, Fred Dyson, Ralph
Seekins, Kim Elton and Co-Chair Scott Ogan. Legislative Budget
and Audit Committee members present were Representatives Mike
Chenault, Mike Hawker, Beth Kerttula, Reggie Joule, Co-Chair
Ralph Samuels and Senators Gene Therriault and Con Bunde.
Senators Gretchen Guess and Gary Stevens and Representatives
Bill Stoltze, Les Gara, Beverly Masek, Harry Crawford and Ethan
Berkowitz were also present.
CO-CHAIR RALPH SAMUELS announced that this meeting is the second
in a series of three interim hearings on the issues surrounding
the gas pipeline.
CO-CHAIR SCOTT OGAN said the decisions the Legislature would be
making in the next months regarding the natural gas pipeline
were the most important ones it would be making in the next
couple of decades. He noted that statute allows the Legislature
30 days to consider a negotiated settlement once it is
submitted. So, it's important to do this work during the
interim.
CO-CHAIR SAMUELS said the first segment is titled In Need of
Access. He welcomed Dave Houseknecht and Mark Myers.
MR. MARK MYERS, Director, Division of Oil and Gas, Department of
Natural Resources (DNR), acknowledged that the USGS does a lot
of cooperative work on resource issues and that Brenda Pierce,
Energy Coordinator, USGS, is attending the hearing. USGS
assessments are done independent of him, although DNR input is
used. Work in the federal government is focused primarily on
assessing federal lands, but includes state lands and is on-
going.
He said there is a big difference between reserves and
resources. The reserve base on the North Slope is known and
economic. Undiscovered resources is what you think is there, but
don't know for sure. Probabilistic modeling is used for those
resources and has a range of outcomes. The North Slope has a
known reserve base that he is confident exists predominantly in
two fields - Prudhoe Bay and Point Thompson, although there is
undiscovered resource potential elsewhere. Access and expansion
revolve around whether or not there is sufficient gas potential.
He demonstrated in a slide the known reserves in bright red at
around 33 - 36 TCF (trillion cubic feet). The proposed project
size, a 4.5 BCF (billion cubic feet) pipeline is only about a 20
- 22 year supply of gas and is insufficient to monetize a 30-
year or longer project that Alaska would like. If that
undiscovered resource base isn't there, the 4.5 BCF pipeline is
too large. Furthermore, expansion of a pipeline bigger than that
would not be logical or economic, because a 4.5 BCF pipe
expanded through compression-only numbers gets you only 16 - 18
years of life. Then the undiscovered resource is looked at and
the question is asked how much undiscovered resource needs to be
there to justify the project. If 30-plus years is needed, 50 -
60 TCF of gas are needed - a significant amount. However, if
those numbers are greater than 60 TCF, a 5.6 BCF line could
produce for 50 - 75 years. Early expansion of that pipeline
would be important to maximize both the economics of it and
maximize the revenue stream to the state and federal government
and encourage oil exploration overall.
The issue of undiscovered resources becomes the
critical lynchpin if you're worried about expansion,
if you're worried about the economics, in general the
pipeline, but also if you're worried about access
terms.
MR. MYERS said he used $1.50 per MCF netback to the North Slope
for demonstration purposes. A 4.5 BCF netback to the North Slope
would be worth about $2.4 billion a year or about $6.6 million
per day. Expanding to 5.6 BCF by adding pressure to the line
changes the cash flow to $600 million per year or $1.6 million
per day.
What's important from the state's perspective on one
front, at least, is the state will capture part of
that differential. So, early expansion, if the gas is
there, makes a tremendous difference on the economics
of the project and the benefits the state receives....
Also, the earlier you define those reserve bases, the
more secure the project is. It is a lot easier to fund
and back a project that has 30 to 50 years of reserves
than it is for one that has 20.
So, understanding what the resource potential is and
how likely you are to achieve that really becomes the
critical issue on many of things you'll have to deal
with through the Stranded Gas Application process....
MR. MYERS explained that an expansion would lead to an overall
lower tariff on the pipeline for all shippers, initial shippers
and expansion. If the cost of expansion is more through looping
or other means, typically the people expanding the pipeline
beyond that bear the full cost of the incremental expansion.
He said that the ability to expand early is almost required if
the necessary reserve base is there. Exploration can't occur if
gas is stranded for a long period of time, because the economics
aren't there for the company to drill the exploration wells
until there is capacity in the line.
Under the 4.5 BCF/day proposed scenario for Prudhoe Bay and
Point Thompson, the initial gas producer who has the open season
will fill the pipeline for the first 12 years. If it take eight
years to build, there is a 20-year period before any new gas can
come into the line. The state has 10-year leases and companies
simply cannot afford to expend huge dollars upfront and wait 20
years to capitalize their investment.
So, it is a chicken or egg situation, unless the rules
on expansion are clear and that access is available.
Again, that's not an important question unless you
believe the gas resources are really there. If they're
not there, then there is really no issue with
expansion. That's why the technical assessments become
critical.
MR. MYERS believed that the gas resources are highly probable to
be in sufficient quantities for an expanded pipeline to have a
50-year life.
Finally, one of the key things to recognize is there
will be folks who tell you that expansion isn't that
important and that it will happen naturally. Well, it
won't with enough certainty to get the early
exploration going. Again, from DNR's perspective, it's
critical to the state to see that we have good access
terms, that expansion is available for parties that
wish to explore. That confidence, then, leads to
exploration and valuation of state lands and will
ultimately lead to accelerated revenue stream; it will
lead to more oil and gas being produced. Because along
with that gas, a significant amount of oil will be
produced, as well.
SENATOR CON BUNDE asked him to explain why expansion might not
be advantageous for some companies.
MR. MYERS replied:
If you have down-stream markets that can take a
limited amount of gas and you're selling into that
market, you're competing with other gas coming from
the basin. If you own the pipeline and also own the
gas infrastructure, there may be cases where you have
two profit centers and those two profit centers come
in conflict, if there's more gas coming in and
competing with your gas.
So, there are natural competitive forces, that
depending on the ownership and alignment of the
pipeline, make your individual companies' economics
different. I'll just say, if a lot of gas comes off
the North Slope, it could have an effect on the value
of gas say at the Acho Hub. In which case, the
companies that have a lot gas in the Acho Hub now will
see an overall lowering of that gas price for a short
period of time until the market recalibrates, but it
will affect their market position and other gas they
own within other basins that are affected by the same
markets. So, there's lots of complications in here....
He said the state wants all the gas to come because it helps our
economics, but the individual company may have a slightly
different set of economics. Much of today's discussion will be
on the areas in the southern part of the basin that are in the
North Slope Foothills and the NPRA (National Petroleum Reserve -
Alaska).
In addition to known fields at Prudhoe Bay and Point Thompson,
there are unconventional gas resources. Gas hydrates are
basically gas that is frozen in a lattice that sits under much
of the existing infrastructure. Current reserve estimates exceed
that of Prudhoe Bay and Point Thompson combined, about 37 - 44
TCF. He would not talk about gas hydrates today, because they
haven't been demonstrated from an engineering standpoint to be
commercial, although drilling intervals have determined that
they are geologically present.
SENATOR FRED DYSON asked a question about the chart, which Mr.
Myers explained. He said there is a lot more unconventional gas
between coalbed methane and gas hydrates.
MR. MYERS further explained that access and expansion issues
affect other basins on the way to the North Slope - the Yukon
Flats and the Nenana Basin, in particular, whose economics would
be dramatically improved if it could not only serve the local
market for gas, but could have export capacity all through the
gas line. The Nenana Basin has a significant quantity of gas
present; it's a question of whether it's present in commercial
quantities and how it can be maximized. The access issue is
important here in terms of development of rural energy
strategies. Certainly, the best markets are local, but
additional capacity could be exported making the project much
more economic.
The Copper River and Cook Inlet Basins have exploration
licensing that will benefit through access and expansion. A
larger pipeline gives more options for marketing gas in multiple
locations and companies are actively exploring in these basins
specifically for gas.
MR. DAVID HOUSEKNECHT, Research Geologist, US Geological Survey
(USGS), said he would summarize the work it has done to
characterize the resource base of the entire state of Alaska and
the North Slope, in particular. Part of the USGS's mission
responsibility nationwide is to do assessments of undiscovered
and other resources that may be added to the nation's energy
base in the future. The USGS systematically work across the
entire nation with a particular emphasis on federal lands. The
work is restricted to the on-shore and state waters areas and
his colleagues in the Department of Interior, Minerals
Management Service, work in the OCS, the federal off-shore
division. Their work compliments each other.
MR. HOUSEKNECHT emphasized that their assessments are reported
in terms of probabilities. In frontier areas like the North
Slope Foothills, relatively few exploration wells have been
drilled and there is a range of uncertainty associated with
their estimates.
Associated versus non-associated gas is an important concept on
the North Slope, especially. Associated gas occurs in
association with oil, such as a gas cap above an oil
accumulation. Prudhoe Bay has a huge gas cap. Non-associated gas
occurs in the absence of oil and that's what is in the Brooks
Range Foothills.
Worldwide, the largest gas resources and reserves
typically occur in those geologic provinces of non-
associated gas rather than associated. So, it's really
important to understand that we really don't know very
much about the non-associated gas on the North Slope,
because as wells were drilled and non-associated gas
encountered, the companies simply moved on and didn't
delineate those accumulations because they were
looking for oil. I'll come back to that point as we go
along.
MR. HOUSEKNECHT next presented a map of the State of Alaska that
summarized the estimates of undiscovered conventional natural
gas that was prepared by the USGS for onshore in-state waters
and by the Minerals Management Service (MMS) for offshore. The
point to be made is that first he shows a range for each
province. For example, in northern Alaska NPRA he shows a range
of 40 - 85 TCF, which represents a range of 95% probability to
5% probability.
In other words, the USGS says there is a 95%
probability of 40 TCF of conventional, undiscovered,
technically recoverable natural gas resources in the
National Petroleum Reserve in Alaska (NPRA). On the
upside, there's a 5% chance of 85 TCF. So, again, that
range is quite large because of the lack of drilling
data that exists in those gas prone areas of the North
Slope and other basins of Alaska.
The single number listed behind the mean is the
statistical average or expected value of our
probabilistic distribution. So, if you must use one
number, and certainly legislators and the media tend
to use one number whenever they can, we estimate 61
TCF of conventional natural gas that is undiscovered
and technically recoverable in the NPRA, alone.
MR. HOUSEKNECHT summarized that in southern Alaska there are 2
TCF of known reserves in the Cook Inlet and the USGC onshore and
MMS offshore mean estimates add up to about 20 TCF of
undiscovered conventional resources. In central Alaska, there
are no known reserves to date and a mean estimate of about 9
TCF. In northern Alaska, there are more than 33 TCF of existing
reserves and a mean estimate of more than 150 TCF of
undiscovered resources. This shows the importance of the North
Slope in the natural gas resource base of the state of Alaska
and why northern Alaska is really the driver in terms of the
undiscovered resource base under discussion.
He emphasized that the estimates in northern Alaska do not
include the Native lands. That study is under way right now and
will be released later this year.
MR. HOUSEKNECHT said he would give a mini overview of the
geology and exploration history on the North Slope. The white
dots that are clustered along the coastline near the Barrow Arch
are the over 400 exploration wells that have been drilled to
date. That's where the industry has found oil and that's where
exploration has been focused. He also showed the pipeline system
and a subsurface regional feature indicating oil migration and
accumulation during geologic history. Areas where the state and
USGS would agree are more favorable for oil versus gas
exploration are on the northern part of the North Slope. In the
southern half of the North Slope, or the Foothills, there's a
greater probability of encountering gas than oil. The Foothills
province is where the oil industry in the early years of
exploration drilled wells, encountered gas, and said oh, shucks,
this isn't what we're looking for and moved north. For that
reason, there is a lack of drilling data in the Alaska North
Slope Foothills that increase the uncertainty of the estimates
that are made. That's why there is such a wide range between the
95% and 5% probabilities in the numbers he quoted on the NPRA.
The next slide focuses on the nature of the gas resources that
are present. The big red bubbles are known gas accumulations
that have been discovered as a by-product of oil exploration.
Some of the red bubbles have green rims around them and those
represent associated natural gas, occurring either as a gas cap
above an oil accumulation or as dissolved gas within the oil.
The red bubbles with white circles are non-associated gas, gas
accumulations that have been discovered where the exploration
tested gas at significant rates that signify an accumulation is
probably present, but where delineation of those resources did
not take place because the industry was not interested in
natural gas. The only non-associated gas resources that have
been delineated are the relatively small resources or reserves
that have been developed around Barrow for local consumption.
All of those accumulations that have been discovered in the
Foothills have not been delineated in any substantial fashion
and their size is not known.
SENATOR FRED DYSON asked what DST and RFT mean.
MR. HOUSEKNECHT replied that DST means drill stem test and RFT
means repeat formation tester.
As a well is drilled, when the well encounters an
interval of rocks in the subsurface and either oil or
gas shows are detected in the cuttings that are coming
up, the well is sealed off and actually a measurement
of the oil or gas flowing out of the formations in
that interval is measured. So, the DST and RFT tests
are the most direct indication that we have during
exploration drilling of a significant gas or oil
accumulation that may be present.
The other thing I will point out here is that among
the exploration wells, I've assigned a color code with
yellow being the most significant test, DST or RFT
indications. A glance across the Slope notices a
significant number of the exploration wells,
especially in the Foothills, have encountered natural
gas shows during drilling, either significant shows in
the tests that we just discussed, or moderate or weak
gas shows indicating more diffuse gas accumulations
that may be present. So, the bottom line here is that
most accumulations of associated gas are up on the
coastal plane near the Barrow Arch and most known
accumulations of the non-associated gas are in the
Foothills farther south, but significant gas shows are
pervasive in the wells that have been drilled,
especially in the Foothills. What the USGS believes
that this really defines is what we refer to as a
natural gas province that has great potential in the
Brooks Range Foothills. I have outlined that province
in yellow on this map.
Data on sizes of accumulations that are known on the North Slope
is taken from the DNR annual report. Prudhoe Bay and Point
Thompson are the largest known reserves at 24 TCF and 8 TCF
respectively. The sizes of the other known accumulations are
also shown. The table on the right shows the possible sizes of
some of the non-associated accumulations that have been
discovered in the Foothills and a couple in the federal
offshore. Size is difficult to estimate, because in most cases
the accumulations have been encountered by a single well or one
or two delineations wells - because industry was focused on oil.
Finally, in terms of known resources, he pointed out new
discoveries in the NPRA. The Alpine play represents exploration
for the type of geology that exists in that field. Lease sales
in the NPRA during the last five years indicate that industry
believes there are significant potential reserves extending
westward across NPRA. The blue areas of the map show where the
USGS has mapped the extent of the Alpine-type geology using
seismic and well data.
Results from new discoveries in that area indicate that
approximately 500 million barrels of oil will be recovered at a
40 degree API gravity (American Petroleum Institute measure for
the lightness or heaviness of oil). Forty-degree oil is very
light or watery as opposed to a thick oil. GOR is simply gas oil
ratio per cubic foot of gas per barrel. Eight hundred is a very
low value. Westward, a test of the discovery at Spark indicated
55 degree oil, a much lighter oil than at Alpine, probably a
condensate (a petroleum compound that is a gas in the reservoir
and precipitates to a liquid at the surface) and a GOR of
10,000. The Rendezvous Discovery reports 60-degree gravity and a
GOR of almost 17,000.
This is an astoundingly rapid increase in the gravity
of oil and the GOR over a very short lateral distance,
and frankly, our scientists are struggling to
understand this.... This does lead to the question -
is the big play, or plays, in the NPRA really going to
be predominately oil or will there be a very
substantial gas resource that...industry been treating
primarily as an oil play.... So, what I'm really
saying here is that there are lots of unknowns and
every well that is drilled and the data from every
well that is released gives us additional information
to help us constrain how much oil and gas may be
present on the North Slope and these results certainly
indicate that there may be more gas present in NPRA
than we estimated just two years ago.
The estimates we've made over the last five or six
years are limited to federal lands. What I'm showing
here are the gas volumes that we estimate to be
present as technically recoverable conventional
resources in NPRA and in ANWR. Bear in mind that we
have not yet released our estimates for the state and
Native lands that are adjacent to the pipeline and
those results will be released later this year.
In addition to the range of numbers listed there, 40 -
80 TCF in NPRA and 0 - 11 TCF in ANWR, these
histograms show you the sizes of gas accumulations
that we estimate to be present.... So, what we are
saying is that the largest accumulations that we
expect in NPRA are approximately the same size as the
known gas reserve in Point Thompson field - pretty
substantial accumulations....
I want to emphasize in red in those little inset maps
in NPRA are the areas we expect the largest gas
resources to exist and the point here is that every
one of those gas plays extends eastward across the
Coleville River and extends all the way eastward
across the stated Native lands to the pipeline
corridor.... So, although I can't give you specifics,
the geology is essentially identical to the NPRA and
it would not surprise me if a few months from now we
are releasing numbers that are in the same order of
magnitude as the NPRA estimates we've made and those
would be in addition to the numbers that I've already
reported to you here this morning.
MR. HOUSEKNECHT summarized that northern Alaska already has
significant reserves that are already known, more than 30 TCF,
and an undiscovered resource base of at least 150 TCF when
combining onshore and offshore estimates. The onshore numbers
will grow significantly when they are released for state lands
later this year. There is also a huge non-conventional resource
base that is not being discussed because of the engineering
uncertainties in its development. A certain portion of the
resources is located within easy access to existing
infrastructures.
Central and southern Alaska, in contrast, have relatively modest
accumulations, but resources that could add icing on the cake to
the resource base in the state.
CO-CHAIR SAMUELS thanked him for his presentation and said the
next question to be addressed was original and expansion
capacity.
MR. JOE MARUSHACK, Vice President, ConocoPhillips, Gas
Development, said his sole objective today is to establish a
common link between the Alaska efforts here and pipeline access
and expansion. He introduced Pete Frost, an engineer for
ConocoPhillips, who knows that mechanical and technical reality
must fit into regulatory and political policy. He has also spent
many years working gas from development to marketing to
regulation; so, he has a broad background into all the issues
inherent in this business. Finally, he is part of
ConocoPhillips' core Alaska gas team and is familiar with
federal legislation and the challenges this project faces - and
is trying to help them overcome.
MR. PETE FROST, Director, Regulatory Affairs, Gas and Power
Marketing Corporation, ConocoPhillips on behalf of BP,
ConocoPhillips and ExxonMobil (referred to as the sponsor
group), offered a brief overview of the FERC's policies dealing
with access to initial capacity, how expansion capacity might be
offered and a summary of the sponsor group's preliminary
estimate and toll estimates. He would also address how FERC's
policies and procedures work to insure that all parties have
equal and fair access to pipeline capacity. His primary
background is in interstate gas pipeline procedures, rate making
and tariffs and the role of the FERC and his comments were
designed to provide insights into FERC's approach in
establishing gas pipeline tariffs and rates as well as its
procedures for obtaining access both for initial capacity and
expansions that will be required of the Alaska natural gas
pipeline.
Interstate gas pipelines are required to operate as
open-access contract carriers. Capacity on the Alaska
pipeline will be offered and allocated based upon
long-established FERC regulations and precedence.
Access to pipeline capacity needs to be viewed in four
contexts:
1. Initial access to a proposed new pipeline
2. Initial access to pipeline expansions
3. Access to pipeline capacity that may become
available because of contract termination or
exploration and
4. Access as a result of temporary or permanent
capacity release
In each of these contexts, any credit-worthy party
that is willing to make the necessary long-term
shipping commitment has an equal opportunity to
acquire pipeline capacity. For those of you who are
primarily familiar with the Trans Alaskan Pipeline
System (TAPS) it is important to remember that the
procedures for allocation of capacity are different
for gas pipelines than for oil pipelines. On gas
pipelines, gas is allocated through an open season
process that allows all perspective shippers to review
the preliminary rates, terms and conditions and to bid
for capacity on the pipeline.
The open season process is instrumental to the
pipeline's ability to establish the economic viability
for the project and to determine the optimum size of
the pipeline. The open season process is designed to
insure nondiscriminatory allocation of pipeline
capacity and significant case law and precedent exists
to insure that no shipper that is prepared to make the
long-term shipping commitment has any advantage in
taking pipeline capacity from another similarly
situated shipper. In the United States, the FERC
oversees this process, which must be open and
transparent.
Although the FERC allows reasonable flexibility in the
design of open seasons, significant precedent defines
the open season process. Typically, open season
processes are conducted as follows:
1. The pipeline will often engage in preliminary
discussions with the marketplace and will
sometimes use non-binding open seasons or
solicitations of interest. This process helps the
pipeline to judge the extent of the market
support and to insure that the pipeline is
neither too large nor too small for the apparent
demand for the transportation services.
2. The pipeline then issues a public notice to
announce its open season. The open season must be
of sufficient duration to allow all interested
shippers an opportunity to respond. The open
season documentation will also outline the rules
under which the pipeline will evaluate its bids.
The pipeline's open season package typically
includes significant information about the
project including receipt and delivery points,
route, timing, services, pro-forma agreements, a
proposed precedent agreement and estimated rates.
TAPE 04-13, SIDE B
3. If there's insufficient capacity to satisfy all
the bids, the pipeline's open season package will
specify the type of tie-breaker that will be
employed to allocate the available capacity.
4. Once capacity has been allocated through the open
season process, the shippers will normally enter
into binding precedent agreements with the
pipeline, which demonstrate the need and support
for the project. The pipeline company uses these
agreements to justify the project at the FERC and
to underpin the financing of the construction of
the pipeline. Pipeline owners and financial
lenders require 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 typical
oil pipeline projects, could not be financed.
Shippers need a contractual commitment from the
pipeline to ensure capacity is available to
support their own needs.
Once capacity is awarded through the open season and
binding precedent agreements are executed, a shipper's
contractual right to the reserved capacity is
protected. A shipper's economics are founded on the
availability of this 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 that is due
regardless of whether gas is actually shipped. A
pipeline must have sufficient binding precedent
agreements or executed transportation contracts prior
to filing its FERC application. If the pipeline
overbuilds, it is at risk for all unsubscribed
capacity and cannot recover those costs from the
contracted shippers.
The open season process is critical to determining the
ultimate capacity of the pipeline. When additional gas
is committed to the project, a larger physical
pipeline may be justified (if operationally feasible),
which may yield economies of scale that benefit all
shippers.
In some unique cases in the offshore Gulf of Mexico,
pipelines have offered a pre-subscription open season
to attract sufficient base volumes to underpin the
pipeline. In these cases, the anchor shippers were
pre-assured access to some of the pipeline's capacity
in the open season consistent with the risk associated
with their large capital investments in related
production facilities. It should be noted, however,
that in all of these distinctive cases any party
meeting the base requirements could be an anchor
shipper and a meaningful portion of the total pipeline
capacity was still made available to any interested
shipper in a non-discriminatory open season. FERC has
approved this anchor shipper concept in order to
facilitate types of unusual project development
requirements.
As proposed, the Alaska pipeline can be expanded to
allow substantial additional capacity. Under FERC
precedent, potential shippers are assured of fair and
equal access to the pipeline expansion capacity
without undue discrimination through an open season.
The current process for the allocation of expansion
capacity is very similar to that described earlier for
the allocation of initial pipeline capacity. However,
prior to the expansion open season, FERC policy
requires that the pipeline poll current shippers
regarding their willingness to turn back their own
capacity prior to the binding open season. An existing
shipper does not have priority or right of first
refusal for expansion capacity, but is treated the
same as anyone else trying to obtain expansion
capacity. All potential shippers must bid on expansion
capacity during the open season and similarly situated
shippers must be afforded the same rates, terms and
conditions. When a project is economically and
technically viable, this process allows a pipeline to
efficiently identify customer requirements and to
implement cost-effective expansions.
It should also be noted that the FERC has very
specific regulations that deal with the relationship
between interstate pipelines and all of their energy
related affiliates. Under these regulations, known as
Order 2004, pipelines may not treat their affiliates
in a preferential manner. These regulations include
strict limitations on information flow, shared
employees and corporate structure. Virtually every
pipeline employee must now be specifically trained in
these affiliate regulations. The penalties for
violation are severe.
If a pipeline is expanded, the resulting rate
treatment is dictated by established FERC policy. The
expansion rates are determined based upon the
incremental costs of the expansion. If the resulting
expansion results in a lower overall rate, then the
cost is rolled in or basically included in the rate
base of the pre-expansion pipeline. In this case, the
existing shippers and the expansion shippers all pay a
lower rate. If the expansion would result in an
increase in rates to the existing shippers who hold
the initial capacity, then the expansion rate will be
incrementally priced. In this case, the existing
shipper continues to pay their previous rate and the
expansion shippers pay a rate based on the higher
incremental costs to expand the system. The actual
costs of an expansion will depend upon the design of
the pre existing facilities and the specifics of the
proposed expansion.
It should also be noted that the proposed federal
enabling legislation has unique and unprecedented
language allowing FERC to require an expansion upon
request if the shipper requesting this service meets
the requirement outlined in the legislation. These
requirements include:
1. No subsidization of expansion shippers by
existing shippers;
2. No adverse effect on the financial viability,
economic viability or operations of the pipeline
and
3. No diminution of the contract rights of existing
shippers to previously subscribed certificated
capacity.
There are other methods of allocating capacity. Any
shipper who is paying the pipeline's maximum rate
under a firm transportation contract that is 12 months
or longer is granted a conditional right to extend its
contract at the expiration of the primary terms. As a
matter of FERC policy, this right of first refusal
(ROFR) exists only at the end of the primary contract
term and allows the shipper the ability to retain all
or a portion of its contract subject to the expiring
capacity if he is willing to pay the pipeline's
maximum filed rate for the greater of one year or the
term offered by a third party. This contract right of
first refusal is not a right to obtain capacity in
either an initial open season or an expansion open
season.
The pipeline is also required to allocate capacity
that comes available as a result of contract
expiration on a nondiscriminatory basis. This can be
done through an open season or by posting the capacity
on the pipeline's public bulletin board. In any event,
the FERC approved tariff will provide the procedures
consistent with FERC precedent and regulations for the
nondiscriminatory allocation of such available
pipeline capacity.
Any method by which a shipper can obtain firm capacity
is by obtaining capacity released by a firm shipper.
This release can be for a temporary term or can be a
permanent release. The FERC has established criteria
that ensure such capacity is allocated to the party
who values the capacity the most (subject to the FERC
approved maximum recourse rate).
As has been previously communicated in other forums by
the sponsor group, the total capital cost of the
Alaska gas pipeline has been estimated at
approximately $20 billion in 2001 dollars. This figure
would be somewhat higher in today's dollars accounting
for inflation since 2001. The figures that 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 2011 - 2002 timeframe. That study
evaluated the feasibility of constructing a pipeline
from Alaska's North Slope to Lower 48 U.S. 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. Because current state law prohibits
the state from issuing a right-of-way for a northern
route until a southern route is built, the cost
estimates have focused on the southern route.
The southern route project was estimated to cost
approximately $19.4 billion with an accuracy of +/-
20%. This 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 [Federal Energy
Regulatory Commission] and the NEB [National Energy
Board] for an Alaska gas pipeline. The ultimate toll
will not be known for some considerable time, that is,
until the pipeline is completed and the actual costs
are known and better estimates will require more work
as the project is further developed.
The process of developing and gaining regulatory
approval of this toll and having it approved by the
necessary regulatory authorities is well-established
in both the U.S. 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 U.S. 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. This cost of service includes
components such as operating expense, maintenance,
taxes, depreciation and a fair and reasonable return
on capital investment consistent with the specific
risks of the project.
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 for both initial capacity and
for expansion capacity. All parties have the ability
to intervene in this process and have the opportunity
to comment on the proposed pipeline's tariffs prior to
regulatory approval. The FERC will consider all such
comments before it approves the pipeline's rates or
specific tariff language. Once these tariffs have been
approved by the FERC, the provisions would generally
be applicable to all shippers. Furthermore, FERC staff
is charged with representing consumer interest to
ensure that these rates are just and reasonable. The
FERC has outstanding resources and expertise and
furthermore, is also permitted to audit the records of
all regulated pipelines.
All parties including the State of Alaska, the
pipeline, gas producers and other shippers benefit by
ensuring that all gas has access to the pipeline on
reasonable terms. Existing FERC policies and
procedures ensure that all parties have a fair and
equal opportunity to access pipeline capacity.
Moreover, these policies and procedures help to ensure
that no one class of shipper can be required to
directly subsidize or guarantee access for another. In
fact, this approach advances the national interest in
encouraging future investment in natural gas
pipelines. FERC recognizes that parties who have the
potential to accept significant risks and make
substantial investments in natural gas transportation
systems will not do so if the benefits can be
transferred to other third parties.
And so, to summarize, I'd like to offer these closing
comments. First, unlike oil pipelines, interstate gas
pipelines operate as open access contract carriers.
This means capacity must be awarded to shippers in a
fair, equal and non-discriminatory manner. These
shippers, however, must be willing and able to make
the necessary contractual commitments to pay for the
capacity. This open access requirement is met on a new
pipeline through an open season. Once capacity is
awarded, a shipper's contractual right to the reserved
capacity is protected. Existing shippers, however,
have no preferential rights to capacity on an
expansion. Further expansion capacity is allocated
under a non-discriminatory open season process similar
to that which is used to allocate the pipeline's
initial capacity. All parties, including the State of
Alaska, the pipeline, gas producers and consumers
benefit by ensuring that all gas has access to the
pipeline on reasonable terms. Among other things, this
means pipelines generally are prohibited from allowing
one class of shippers to directly subsidize another
class or from guaranteeing one class of shipper's
preferential access over another class. In addition,
FERC has regulations that ensure a pipeline owner
operates independently from its other energy
affiliates. FERC Order 2004 recently expanded these
regulations to include all energy affiliates,
including producer affiliates. This concludes my
prepared remarks. I'd be happy to try and answer any
questions you might have.
CO-CHAIR OGAN said he quoted figures from 2001 and that the
benefits outweighed the risks at that time, but this is 2004 and
he has heard projections at different conferences that the gas
market has changed. He assumed the producers were recrunching
their numbers.
MR. FROST responded that the sponsor group is continuing the
analysis and efforts are under way to define the parameters of
the project and the cost.
REPRESENTATIVE LES GARA said he understands that FERC allows a
fair amount of flexibility in the rules for access. The amount
of revenue the state takes in is dependent on the transportation
costs for the particular amount of gas that gets deducted. So,
gas that is 400 miles away from the main pipeline stem may make
the state less revenue than gas that is five miles away from the
pipeline stem. If there is an open season and two competing
proposals for the same amount of gas are coming from one company
that owns gas 300 miles away and another company whose gas is
much closer and would make the state much more money, he asked
if the state would have some sort of discretion to choose the
access so that legislators could uphold the state's interest in
getting the maximum revenue possible.
MR. FROST replied that the proposed pipeline would be regulated
by the FERC, a federal agency. The enabling legislation includes
a specific provision that requires the FERC within 120 days of
signing the act to promulgate specific open season regulations
that would define how the particular open season process would
be conducted by the Alaska gas pipeline. During the promulgation
of the rule-making all interested parties would participate.
REPRESENTATIVE GARA focused Mr. Frost back to his question of
how the state would choose the company with gas located 5 miles
away rather than 300 miles, because it would make more money
that way.
MR. FROST replied that the open season process by FERC would
have to be conducted in context with existing case law, which
require that all open seasons be conducted on a non-
discriminatory, open access basis. The FERC wouldn't view any
party with a preference in that process. The parties would bid
on the section that's available. No particular source or shipper
has any preference to capacity.
SENATOR KIM ELTON said it seemed that for an initial open
season, the producers would have somewhat of an advantage,
because they have knowledge of where reserves are versus
independents who would make a bid on undiscovered reserves. He
asked him to comment on that situation.
MR. FROST replied that FERC regulations have no requirement on
when an open season is to be conducted. A number of precedents
define how it should be structured - how long it should be open,
how long prior to the opening should the notice occur, etc. The
decision for when the open season takes place is a commercial
decision about when the pipeline feels it has sufficient support
from potential shippers to move a project forward. FERC
regulations and precedents dictate that certain things have to
happen before the application is submitted to it.
When the open season is made, all parties who have an interest
in participating in a open season have an equal opportunity to
bid at the time it is conducted. Different parties will be in a
different position to participate in an open season to develop a
pipeline. To the extent that parties are not able to participate
in one open season, the project sponsors could expand the
pipeline and have an expansion open season. An explorer could
force an expansion under FERC rules at a time later than the
initial open season. The pipeline always has an economic
incentive to expand and many expansions result in a lower rate
for all parties.
SENATOR ELTON asked if it is very likely that an independent
could become an anchor shipper under an undiscovered resources
scenario.
MR. FROST replied:
Maybe. If any shipper has reserves that are known and
confirmed enough to support their desire to
participate in an open season, they could participate
as an anchor shipper. The anchor process is open to
all parties....
SENATOR RALPH SEEKINS asked what he meant by the pipeline, as
proposed.
MR. FROST answered that he was speaking generically. He was
referring to any pipeline with an open season.
SENATOR SEEKINS asked if a gasline from Alaska to Canada to a
hub versus one that went all the way through Canada to the Lower
48 would be treated the same.
MR. FROST replied yes. "The Alaska pipeline will be constructed
under federal regulation and will be subject FERC regulation.
SENATOR SEEKINS said if the sponsor group built the pipeline,
the only advantage for them would be based on making a profit on
the construction and operation of the pipeline.
MR. FROST replied that construction of the pipeline would be
first and foremost to move gas from the North Slope to the
marketplace - to access the market. There is also an expectation
that there will be a separate pipeline corporate entity. "In
that sense it has a profit center of its own."
SENATOR SEEKINS mused if a person owned the pipe himself, he
could see an advantage in keeping construction prices a little
high to keep other people out.
REPRESENTATIVE MIKE CHENAULT asked if it was true that one had
to be an owner to be able to sit at the table and negotiate
rates and if Alaska is not an owner of the project, where would
it be able to negotiate tariff rates, including in the future.
MR. FROST answered the FERC regulatory process allows all
interested parties to participate.
It is the norm for the individual state public utility
commissions and their staff to regularly participate
in these types of proceedings, because of the fact
that the outcome of these proceedings impact the state
and the state consumers. The state of Alaska would
very much have an opportunity to participate in all
regulatory proceedings at the FERC, both initial open
season, initial application, and any subsequent
regulatory proceedings at the FERC.
REPRESENTATIVE CHENAULT asked if it would be in Alaska's best
interest to have more say at these meetings if it was part-owner
of the project versus not being an owner.
MR. FROST replied, "If the State of Alaska is an owner in the
pipeline, then they have a slightly different role. They are not
a user of the pipeline; they are part of the pipeline, itself.
The pipeline, of course, does represent its own interests at the
FERC. And so, the State of Alaska, conceivably, would have two
roles - one role as an owner of the pipelines that would be
proposing applications at the FERC and one in your role as
representing the consumers within the State of Alaska, itself.
CO-CHAIR SAMUELS asked if who builds the pipeline should be
irrelevant to the producers.
MR. FROST answered:
From a regulatory perspective at the FERC, the FERC is
going to view the pipeline as a corporate entity in
and of itself. The FERC doesn't particularly care who
owns this pipeline. All of the procedures, all of the
regulations, all of the case precedent, all of the
judicial case law that has been developed over the
last 80 years in the natural gas industry is going to
apply to that pipeline regardless of who the owner is.
REPRESENTATIVE BETH KERTTULA said that tariffs are affected by
the costs. "If you control the costs, you can control the
tariff."
MR. FROST responded:
There are various aspects of the cost. There are
operating costs and capital costs. Speaking of capital
costs, when the pipeline files its application, the
capital cost will be a major component of the tariffs
that are ultimately reviewed and approved by the FERC.
The FERC has a statutory obligation to insure that the
rates that come out of the application process are
just and reasonable and they take their role very
seriously. There is a whole host of people at the FERC
in Washington, D.C. who tear those costs apart line by
line and argue over literally dollars and cents. Their
role is to insure those costs, all costs, are just and
reasonable. One of the guidelines is to insure that
the costs have not been imprudently incurred.
SENATOR SEEKINS asked if all costs are reasonable, what is the
percentage of return on capital that FERC allows the owner of
the pipeline.
MR. FROST answered that there is no specific number.
It depends on a number of factors, one of which is the
risk associated with the pipeline. The FERC has
recognized a direct link between the riskiness of the
project and the return on equity....
SENATOR SEEKINS asked if he could guess for this pipeline.
MR. FROST replied that it would be within a range of about 12 to
14.5 percent.
CO-CHAIR OGAN observed that one penny's difference cost in the
tariff, if it's higher, lowers the value of the project $155
million over its life.
If that's an accurate figure, based on throughput and
a 30-year life of the project, it equates to - our tax
a royalty on that is roughly 20 percent. Some quick
figuring - that equals a little bit more than $30
million the state will not get for every penny of cost
the tariff goes up.... We obviously have an intense
interest in what those costs are going to be and what
the alignments are going to be, who owns what and who
is shipping what....
MR. FROST replied, "Pipeline rates and associated costs are
always the subject of great debate and scrutiny at FERC. It's
what they do."
CO-CHAIR SAMUELS thanked Mr. Frost and announced that Mark
Hanley would give the next presentation regarding access to
capacity for producers and explorers without an ownership
interest in or effective control of the pipeline.
MR. MARK HANLEY, Manager, Public Affairs for Alaska, Anadarko
Petroleum, said Anadarko is an explorer with an interest
position, being partners with ConocoPhillips, and owns acreage
at Alpine, NPRA and in the Foothills. Anadarko is very
supportive of getting a gas pipeline built. He would focus today
on areas of differences and concerns.
You've heard a few things here and one of the issues
you've heard is that FERC will guarantee - FERC is
your protector. I would only say that we all look at
what are the exceptions to the rules and where can we
be disadvantaged potentially. Part of the problem in
this process is it's all speculation. So, we have to
speculate things that many times they won't all occur.
But, if we don't look at what possibly could occur,
we're not being responsible to our shareholders. I
would say for you folks one of the things is that
you've got to listen to all the parties, but you ought
to have your independent folks. Because I would agree
that generally, the FERC is going to regulate this
pipe; they are going to be the ones that make a lot of
the determinations. So, understanding the rules of the
game...and looking at it from, maybe, the state's
perspective, as well, and saying how can we be
disadvantaged....
MR. HANLEY reminded the committee that a few years ago the state
chose its royalty in kind and actually put out a bid for its
royalty gas. Anadarko bid on it successfully - wanting the gas
so it could go to an initial open season. However, Anadarko
doesn't have reserves right now and is not likely to go to an
initial open season. The three producers really didn't like what
Anadarko did a few years ago - because in the terms of its
contract, it could get capacity and then go out and explore for
the gas. When it found the gas, it could return the state's gas
with certain notice provisions. The state gas would then have to
be carried by the other folks. So, they would get pro-rated even
though they have a contractual right to that capacity.
Anadarko was told from the beginning to not worry about capacity
because the pipeline could be expanded, but when the shoe was on
the other foot, the producers were reluctant to expand capacity
saying that would increase risk to the pipeline.
That sends a message to us. Maybe when they're telling
us it isn't a problem to get it, maybe it is. I don't
know what, but that gives you an example of one of the
concerns that we have about this process when they say
its fair for expansion....
MR. HANLEY moved to the subject of producer owned or
independently owned pipelines and which is better. His general
testimony in the March meeting was that Anadarko doesn't care
who owns the pipe as long as there is fair access terms and
conditions at a reasonable price. But, there's always a natural
tension between the shipper, whose goal is to have the lowest
rate, and a pipeline owner, whose actual goal is to make as much
money as they can. "This is what all the protections are out
there for."
MR. HANLEY read Bob Loeffler's comments in Petroleum News:
What determines how high the rate of return is on
equity is how risky the pipeline is. Pipelines will
argue I'm not an average pipeline. I'm more risky than
anyone else, so I deserve more. Of course, shippers on
the pipeline argue they're not risky at all.
MR. HANLEY reflected:
That's that natural tension.... If the shippers are
largely the owners, as well, you've heard the natural
tendency there - there's an incentive there to shift
your profit as much as possible to the pipeline
system. That's a concern for most of us.
For the state it should be a concern because it
decreases the wellhead value and it decreases the
state's revenue if the profit is taken out of the pipe
instead of out of the gas. For explorers, it means our
costs are higher. So, it's a concern for us. When you
get into a natural system and you're going before FERC
arguing what is that rate of return - should it be
12%, 14.5% - everybody is arguing that this is a huge
risky pipeline. I'm not going to argue that it isn't.
But the tension isn't necessarily there, because if
the big shippers didn't own the pipe, they'd be
pushing as hard as they can to have it closer to a 12%
rate of return, because that's going to mean the
pipeline tariff is lower.
In this case, if the pipeline owners own it, I'm not
sure that the big shippers are not likely to be out
there arguing. In fact, they won't be opposing the
higher rate of return on the pipeline, itself, because
they know that it also helps both competitively as
well as through their overall rate of return, because
the state's picking up about 20% of any increased cost
in that. That's something that doesn't have to do with
the pipeline costs.... I think anybody who is a
shipper would want the pipeline operated at the lowest
cost and not built over cost to try and capitalize
that.
TAPE 04-14, SIDE A
MR. HANLEY related also that the Natural Gas Policy Council
said:
The state must develop a clear and sophisticated
understanding of open season rules governing access to
a contract carrier pipeline and devise strategies to
facilitate access to the pipeline for firms exploring
for or developing new gas discoveries on the North
Slope or Interior basins.
The Legislature also passed a resolution in 2002 that said:
Provisions for access to the pipeline by explorers on
a fair and reasonable basis including a proper open
season with fair and reasonable tariffs and...they and
the state have the ability to obtain expansion of the
pipeline if it's economically and technologically
feasible.
A letter from Governor Knowles to Senator Bingham also states:
Access for new discoveries - is necessary to mandate
that in the event of new discoveries on or around the
North Slope or Interior Alaska. And, whether on
federal or state lands, the owners of these
discoveries will have access to the pipeline in order
to market their gas. It is estimated that undiscovered
gas reserves may be in the order of 100 TCF or more.
Legislation should give the FERC clear authority to
require the owners of the Alaska portion of the Alaska
Highway project to expand the capacity of the pipeline
in order to accommodate all new discoveries. Absent
such a provision, new gas discoveries could be left at
the back of a long [line] of gas awaiting shipment or
worse, indefinitely stranded in place, because, unlike
most areas in the Lower 48 states, one pipeline will
be the sole source of available transportation.
MR. HANLEY emphasized that Alaska is different in that it will
have only one pipeline. Nan Thompson, who was chair of the
Regulatory Commission of Alaska (RCA), said:
A pipeline owned by producers will not have an
incentive to transport gas developed by their
competitors to market.... If the state wants to
encourage competition amongst producers and full
development of its gas resources, we need legislative
authorization for our regulatory agency to evaluate
the economics of the proposed expansion and require
support for an application for expansion at the FERC
when expansion promotes the state's best interest.
A letter from Governor Murkowski said:
We also believe it is in the best interests of the
state for the pipelines to be owned and operated by an
unaffiliated pipeline company assuming that such a
company is able to provide the lowest possible tariff.
MR. HANLEY suggested that there's enough people with concerns
about ownership of the pipeline to urge the Legislature to look
at the issue closely. Alaska is different than the Gulf Coast,
which has competition, because it has a monopoly. Three
producers control 90% of the gas on the North Slope. They have
spent many years jointly working on the project.
To be honest with you, there really isn't competition
for that gas getting into it, nor can there be and I'm
not saying it's their fault. But, when you're at
Prudhoe Bay, BP can't just produce its gas and leave
every body else's in the ground. There's a lot of
legal precedence about overlift, underlift and lots of
problems with that. So, there's going to be an
agreement from Prudhoe Bay owners about what is the
optimal off-take of gas from that field. There has to
be. The same thing at Point Thompson - they have to
come to an agreement among the owners on what's the
optimal amount coming out. When they know that... they
know how much they need to go to the open season and
nominate capacity. It's not a negative thing; it just
shows you they've worked together building the
pipe.... There is one group out there doing this thing
and when you get to the open season, they will say....
typically...it's conducted to determine how big the
pipeline needs to be, what interest there is going to
be out there, are there other people that are willing
to commit so they can size the pipe. To be honest with
you, that's all done. I think they would be very
surprised if anybody other than Prudhoe Bay and Point
Thompson owners...if significant gas came in from
somewhere else.
Whether or not there is an anchor shipper agreement or
whether they can set aside capacity that isn't in
there really isn't the huge issue, particularly in the
initial open season, because frankly, they are the
only ones that have expansion capacity. I think I've
explained to you before, as an explorer, without
identified reserves, and that's us or any of the other
people out there, we can't go to the open season,
nominate .5 BCF a day and make a commitment of $300
million a year, in that range, for 20 or 30 years
without knowing we actually have the gas to put in
there. It's a chicken or egg thing.
The explorers are going to be focused on the
expansion, what the terms and conditions are, if the
pipe is actually built so it can be easily expandable,
how much it can be expanded. What those terms and
conditions are are going to rely a lot on FERC and
others to make sure that we do have that ability.
Again, who is going to look out for our interests? The
FERC is out there looking at this stuff, but I would
say the state has some ability. There is a Stranded
Gas Act where the state can include provisions; they
do have some leverage. I would say our RIK (royalty in
kind) process has not been finalized and we haven't
been actually granted, but I would say don't give up
your right to take your gas in kind. That's one of the
few leverage points you have. I suspect they would ask
you to not do that, but I think as a state, you should
not do that.
When you go back to the ownership of the pipe by a
producer, where is the tension in the system? Let's
just say that the producers own a third each of the
pipe and I don't know what the interests are going to
be, and they control 90% of the gas. If you don't
count the state's gas, it's less, but they are
probably going to carry it in value, well they're a
net owner. Their interests are largely going to be
100% ownership of the pipe, so their interest is going
to be as a pipeline owner. That's the concern.
MR. HANLEY explained that Order 2004 (a) tries to put a firewall
between the pipeline owner and the affiliates. There is an
attempt to not share information, but one must look at the
exceptions. He tried giving the committee an idea of how FERC
balances this.
Order 2004(a) - The commission (FERC) is balancing its
concerns that a transmission provider (the pipeline)
will abuse its relationship with a marketing or energy
affiliate by providing it unduly preferential access
to information about potential expansion plans or new
production areas against the need to facilitate
infrastructure development by allowing the
transmission provider to coordinate construction and
planning with an interconnecting gatherer pipeline or
producers....
Therefore, the commission clarifies that transmission
also includes an interconnection to facilitate gas
transportation service. Thus, discussions between a
natural gas transmission provider and an energy
affiliate to provide an interconnection or expansion
for the energy affiliate would be covered by the
transaction-specific exception.
MR. HANLEY translated that to mean that there is a transaction
specific exception to the rule that says you can't have
conversations out there. They say that interconnecting entities
may discuss the location, practicality and cost of potential
interconnections with an affiliated transmission provider. The
purpose is to encourage the transmission provider and
interconnecting energy affiliate to work together to develop
additional infrastructure to facilitate development of
production.
There are exceptions to the rules.... If they do that,
they have to record the meeting, they have to keep a
transcript of it, they have to keep it for three years
and they have to make it available to FERC. This is
all intended to make sure that nothing goes wrong.
The Order of 2004 had a discussion about whether a non affiliate
could voluntarily consent in writing to allow a transmission
provider of the pipeline to share the non affiliate's
information with the pipeline owner's marketing affiliate. He
didn't know why he would want to get them information that they
could share with their own affiliate, but it was allowed and
says:
Several commenters, including indicated shippers,
urged the commission not to adopt the voluntary
consent provision. They argued that it is anti-
competitive, because even if a shipper agreed to
disclose the information, the consent may not truly be
voluntary, because the transmission provider could be
exercising market power.... That's the normal tension
that occurs in these things....
BP argues that the commission should eliminate the
voluntary consent exemption in the natural gas area.
There is no business reason why a customer would allow
the transmission provider to share that customer's
information with a transmission provider's marketing
or energy affiliate.
According to BP, transmission providers could coerce a
customer to consent. Therefore, the consent is not
truly voluntary. So, these are the comments. So, when
people say am I being paranoid, I would just point to
an example like this and say....
This is a very complex field. There are lots of things
that are out there. There are companies who are
shippers who have very legitimate concerns about the
pipeline companies and the power that goes with both.
MR. HANLEY concluded by urging the Legislature to watch the
terms and conditions closely.
REPRESENTATIVE LES GARA said he also had concerns about letting
FERC control the state's destiny, but asked assuming the state
is skeptical that FERC will get us the best price for
transporting gas, what can the state do to ensure the lowest
possible transportation price.
MR. HANLEY again pointed out leverage in the Stranded Gas Act,
but he didn't know if it was significant. The state needs to
understand and participate in the FERC process.
REPRESENTATIVE MIKE HAWKER asked if he had any immediate concern
that the state is abrogating its responsibility or is he being
cautious.
MR. HANLEY replied that he is being cautious. One provision in
the Federal Energy Bill says within 120 days of its enactment
the commission shall promulgate regulations governing the
conduct of open seasons for Alaska natural gas transportation
projects, including procedures for the allocation for capacity
and the regulations shall include the criteria and timing for
any open seasons, promote competition in the exploration,
development and production of Alaska natural gas and for any
open season for capacity exceeding the initial capacity provide
the opportunity for the transportation of natural gas other than
from Prudhoe Bay and Point Thompson. That's part of the federal
package that includes preliminary judicial review, expedited
permitting, etc. It also has a provision specifically allowing
FERC to force an expansion of a pipe.
CO-CHAIR SAMUELS announced a recess.
CO-CHAIR OGAN called the meeting back to order at 1:15 p.m. He
said that he would be chairing the afternoon portion of the
meeting and the next subject to be discussed would be access to
capacity for Alaskan communities by Charlie Cole.
MR. CHARLIE COLE, Board of Directors, Alaska Gas Pipeline
Authority, said he wanted to talk about the Gas Act's provisions
at Fairbanks.
I have to say preliminarily that I have some
hesitation about speaking critically, you might say,
about an item of legislation that passed the
legislature by a vote of 20 - 0 in the Senate and 38 -
0 in the House. Obviously, any bill that passes the
Alaska Legislature with votes like that has strong
support and is viewed by informed legislators as good
legislation for this state. So, with that caveat and
that reservation, I want to speak a little bit today
about the effect of that bill as I see it on Fairbanks
and other Interior communities and in a sense,
communities down river.
One, Alaska is cold and Fairbanks is, on occasions,
very cold. It is one of the restraints on growth that
we have in Alaska and we'll always have in Alaska - is
the cold weather. With that given, low cost economic
energy is vital for the economic development of,
certainly, Interior Alaska and, as we have seen, how
vital and how beneficial that has been to the
Anchorage area. But, Fairbanks has not had that
benefit and Fairbanks continues to struggle
economically as respects quality of life for the high
cost of energy there.
So, if one looks to the future of Fairbanks, if
Fairbanks is going to have any economic growth... it
must have cheap economic energy to offset the costs of
living there.
The second given is that these Alaska resources should
be primarily for the benefit of Alaskans. Isn't that
what Governor Murkowski said? He said one of the
fundamental purposes of the use of these resources of
Alaska should be to benefit Alaskans.
Senator Seekins would know at times in Fairbanks when
it's 50 degrees below zero, we have people there who
buy 50 gallons of fuel oil to heat their house, to
keep it from freezing, because that's all they can
afford, if you can believe that. One of the givens for
the Fairbanks community is we really need gas. There's
only one place we're going to get that gas and that's
off this gasline, if it's ever built. Presumably, it's
going to be built.
Also, if we want to keep the military bases in
Fairbanks - you know those base closure proceedings
come up every once in a while. One of the criticisms
we talk about keeping Eielson and Fort Wainwright
there is how much it costs to keep those bases open.
If we're trying to reduce the defense budget, maybe
we're trying to, I'm not really sure that we are, but
if we are, we've got to reduce the cost of power and
heating at those bases. So, that should, in my view,
be given as a policy.
So, what did the Stranded Gas Act do for Fairbanks in
that regard? Given I think those unanimous policies -
lets just read what AS 42.06.240 says in that
regard.... starting with section (f).
In addition to the other requirements of (a) through
(e) of this section, the provisions of this section
shall apply to a certificate of public convenience and
necessity for a North Slope natural gas pipeline
carrier or a person that will be a North Slope natural
gas pipeline carrier under this chapter.
(1) The person making the application shall dedicate a
portion of the pipeline's initial capacity sufficient
to transport the total volume of North Slope natural
gas that has been committed by the producers and
shippers of North Slope natural gas to tendering for
intrastate firm transportation service at the time
that the operation of the North Slope natural gas
pipeline commences.
(2) Upon receipt of the certificate application under
this subsection, the [RCA] shall issue a public notice
inviting prospective intrastate shippers of North
Slope natural gas to file a request for service. A
request for service submitted by a shipper in response
to the notice issued under this paragraph must include
a proof of the shippers commitment to use the North
Slope natural gas pipeline for intrastate firm
transportation service, specifying the volume of North
Slope natural gas that the shipper will tender for
initial intrastate firm transportation service.
(3) In its review of an application submitted under
this subsection:
(A) For the purpose of evaluating the total volume of
intrastate transportation of North Slope natural gas
to be accepted for initial intrastate transportation,
the [RCA] commission shall determine the total volume
based upon written commitments to tender North Slope
natural gas for intrastate firm transportation service
continuously for a period of not less than three years
after the operation of the North Slope natural gas
pipeline commences as follows (the RCA has to
determine the total volume based upon written
commitments (before the certificates of public
convenience and necessity are issued and before
pipeline construction begins - day one):
(i) Each request for service by an intrastate shipper
that is a public utility, as that term is defined by
statute, for the purpose of furnishing natural gas for
ultimate consumption within the state by its customers
that individually consume an average annual volume of
less than 20 million standard cubic feet of gas per
day shall be supported by a written commitment by the
public utility that sets out the utility's best
current estimate of the average annual volume that the
utility will require during the three-years period.
MR. COLE emphasized that a written commitment gives the sense of
something that is binding and obligatory, but after reading the
next sentence, it may not mean contract.
(ii) Each request for service by an intrastate shipper
that is not a public utility, as that term is defined
by law, and each request for service by a public
utility for the purpose of furnishing natural gas for
ultimate consumption within the state by a customer
that individually consumes an average annual volume of
20 million or more standard cubic feet a day, that
purchases North Slope natural gas from a North Slope
natural gas producer must be supported by one or more
contracts for the purchase of the North Slope natural
gas on a take or pay basis that extends for a period
of not less than three years after the operation of
the North Slope natural gas pipeline commences.
MR. COLE explained that means that anybody who wants this
natural gas, if it is not a public utility or it is a public
utility with more than 20 million standard cubic feet per day,
you have to reach a contract now to buy natural gas from the
carrier on a take or pay basis. Fairbanks has no natural gas
distribution system or facilities for converting natural gas to
electrical energy; so, who in Fairbanks would enter into a
contract like this, he asked. He didn't know how such a project
would be financed and supposed that it would be impossible.
CO-CHAIR OGAN interrupted to say that LNG is being shipped from
the Matanuska Valley to Fairbanks at $7 per thousand CF and it
wouldn't take too much to set up a turbine to turn the natural
gas into electricity.
MR. COLE responded that it wouldn't be very practical to enter
into a contract now without knowing what rates the RCA will set
and approve as just and reasonable. Fairbanks needs a whole
distribution system for homes to be heated and no one knows what
that would cost and no one would finance it. However, he noted
that was only part of the dilemma. The next section says:
(iii) The RCA may consider peak volume specified in
written commitments of the North Slope natural gas
producers and purchase contracts; and
(B) The commission shall set out in its order granting
a certificate of public convenience and necessity the
total volume of intrastate North Slope natural gas
that the North Slope natural gas pipeline carrier
shall accept for intrastate transportation.
MR. COLE said that means the certificates of public convenience
and necessity shall say the total volume of intrastate gas may
not exceed the volume substantiated by written commitments and
contracts that comply with the requirements of the chapter.
Commitments have to be in place, then the RCA in the certificate
of public convenience and necessity says, "You've got to send
out X, but you can't ship any more for intrastate
transportation."
He emphasized that it gets worse:
If the North Slope natural gas pipeline carrier wants
to transport gas in excess of the amount set forth in
the statement of total volume of the pipeline
carrier's certificate of public convenience and
necessity, the pipeline carrier may apply for
authority to transport more.
MR. COLE explained that means the carrier has to see if it can
get authority to do that.
We're looking at a gasline that's going to potentially
be running by Fairbanks for the next 30 years. How are
we ever going to, for example, entice anyone else to
come to Fairbanks and utilized this natural gas for a
petrochemical facility? What about supplying natural
gas to Fort Wainwright? Converting those bases? And
how are we going to furnish natural gas to Eilson Air
Force Base? Once, ten years down the road, it then
becomes up to the gasline to decide whether they want
to increase the intrastate capacity for Fairbanks. And
I'm not talking just about Fairbanks and Eilson and
Fort Wainwright, I'm talking about Tok, I'm talking
about Delta Junction on the way down the Highway, but
I'm also talking about the development of propane
facilities to be able to ship propane down river to
these other communities. I mean, once you do this,
[it] is locked in. Then it's up to the pipeline,
itself, to decide whether it wants to increase the
capacity - and that's over the next 10, 20 or 30 years
or maybe 50 years.
This is legislation, which I think is ill-advised, if
I may say. That's a little strong for people who voted
58 - 0; I realize that. But, I think for the reasons
I've given you, this Legislature should take a look at
it and decide whether it needs to be revised. Probably
90 percent of what you hear in these hearings you have
no control over. It's under the control of FERC. This
is something you can do something about - to encourage
economic development, to improve the quality of life
in the Interior, the Interior villages and down the
highway and down river.
SENATOR BUNDE asked if he anticipated that the gas the state
would sell in-state, because it's in the state's best interest
to get the highest return, would be at the same price as the gas
sold out of state, less the cost of transportation. He didn't
see any incentive to not increase capacity for Fairbanks if the
state would get the same net return.
MR. COLE responded:
Why would you allow that decision to be made by the
pipeline, itself? I think one of the vices of this is
for the next 30 or 40 or 50 years, as long as this
gasline is there, it is the pipeline, itself which
makes the decision. Does it want to apply to the RCA
to increase the intrastate capacity? We shouldn't, in
my view, allow that decision to be made by the
carrier. The decision should be made by either the RCA
or by others and not grant it exclusively to the
pipeline. They can stifle the developments of
Fairbanks and the Interior and the villages and down
river for the next 50 years by simply saying if the
North Slope natural gas pipeline carrier wants to
transport more, it can file the application? Why do we
give them that exclusive right?
SENATOR BUNDE responded that a phrase comes from Fairbanks
legislators fairly often - "A stranded gas tax would encourage
them to be friendly to Fairbanks."
TAPE 04-14, SIDE B
MR. COLE responded that he would like to talk to the people from
Fairbanks who voted on this.
SENATOR SEEKINS said he wasn't there during that conversation,
but he wants to talk to Mr. Cole before the legislation passes.
He also said that take or pay contracts are pretty standard in
the natural gas industry and you generally need some of those on
hand to show banks that you can borrow the money and repay it.
MR. COLE replied:
Senator, this is a small infinitesimal amount of
capacity of that line [BREAK IN THE RECORDING]....
It's not a major accommodation to the pipeline carrier
when you consider the consequences to Fairbanks. I
tell you, Fairbanks is going to dry up and blow away
over the next 30 or 40 years if somehow we don't
reduce the cost of energy there. This is a barrier to
that - plain and simple.
SENATOR SEEKINS noted for the record that all the new
construction in his area is being heated by Fairbanks natural
gas and their distribution system continues to expand there,
even though they are bringing in LNG.
MR. COLE said his statement proves his point of the crying need
for cheap gas in Fairbanks. He repeated:
It's a crying need and why do we want to initiate, by
legislation, barriers to that development, our policy
should be the opposite. We should enhance it and
further.
Let me talk take or pay contracts. The problem with
take or pay contracts is when you have the situation
you have in Fairbanks. Sure, I can see Enstar taking a
take or pay contract. It has the distribution system,
it has the industrial development here to do it; I
mean that's a no-brainer. But, we're talking about
Fairbanks, which has none of that. We're starting from
scratch. We shouldn't put that burden on the people of
Fairbanks to have a take or pay contract when they
don't know the price of it; they don't know how much
it's going to cost to develop the distribution system
in Fairbanks; they know nothing.... The problem is
that it's going into the unknown. The problem is
peculiar to Fairbanks.
REPRESENTATIVE HAWKER said he wasn't in the Legislature when
this bill was adopted and said, if Mr. Cole's suggested remedy
of repealing the Act would happen, there would be no statutory
requirement for capacity dedicated to intrastate transportation.
MR. COLE replied:
Not to totally repeal it, of course - to repeal this
particular section and revise it with something a
little more balanced for the need we have in the
Interior. There could be, with expert testimony, the
amount of intrastate capacity that needs to be
reserved and then, within a given period of time or in
segments over a period of time, if it's not used
within that period of time, then it reverts. You see,
I'm looking for 30 and 40 and 50 years. We look, too
often, I think, to today and tomorrow and the next
three years, but I'm looking for three generations of
Alaskans.
REPRESENTATIVE HAWKER asked if he had this conversation with any
of the major players who are proposing pipelines to solicit
their support.
MR. COLE replied emphatically, "No."
REPRESENTATIVE GARA said he was trying to understand the
disincentive for the pipeline owner to let gas be delivered in
Fairbanks.
Is it, if they are going to carry a full load of gas
from the North Slope down to Fairbanks, they make more
money by bringing it all the way down the pipeline
than they do in just charging to drop it off at
Fairbanks and that's the disincentive you're worried
about?
MR. COLE replied that he hadn't spoken to prospective pipeline
owners on what they are worried about.
I would imagine they would want to make commitments
down-line and they don't want to have to be monkeying
around with this relatively minute capacity in
Fairbanks. I can understand their incentives and their
needs. I just think that we need to tinker with this a
little bit to allow Fairbanks and the Interior
communities to have the incentives.
I went down to Tok a couple of years ago and we had a
hearing there. They said, 'What's in this for us? We
want gas here, too.' This gives them essentially no
opportunity to ever have gas. Not today or tomorrow,
but to ever have gas. That's one of the problems that
I see. It's sort of shortsighted and I think it's not
unreasonable to ask the producers, the owners of this
gas, to make these accommodations for the best
interest of Alaskans.
SENATOR THOMAS WAGONER said Ninilchik has some new discoveries
and it has the same scenario - a small community and the people
want the gas, but the problem is do they want to pay for a
station to depressurize that gas down to a lower pressure and
pay for the infrastructure that it takes to distribute that gas.
Do they want to do an LID (local improvement district) for 10
years?
MR. COLE responded that his sense is to give the people of this
state the benefit of warm houses and a quality of life that
other people in the Lower 48 enjoy.
We're right there on the line and we can't get it?
Now, what are we missing? I mean, we're right there on
the line - and we can't get it because we can't tell
the owners of this gas you have to make some
accommodations to these Alaskans whose natural gas
you're piping out to the east coast. I don't get it!
CO-CHAIR OGAN said that the gas in Cook Inlet has a lot of
liquids and those have to be stripped out to process the gas.
"Hopefully we'll have a thriving petro-chemical industry in
Fairbanks to get some of those liquids before Alberta gets it
all."
CO-CHAIR OGAN thanked Mr. Cole for his testimony and directed
that a letter from Representative Whitaker be typed into the
record before testimony from Mr. Persily, Department of Revenue
was taken. The letter follows:
July 27, 2004
Senator Scott Ogan
Chair, Senate Resources Committee
Alaska State Legislature
Senator:
Senator Ogan, the request from Bonnie Robson, the
consultant to the Legislative Budget and Audit
Committee for Alaska Natural Gas Pipeline Issues, is
very clear. The subject matter for discussion is to
be: "What is your company willing to offer on access
beyond what is required by law?"
My testimony was going to be and still is as follows:
Current Alaska law provides for a broad policy
directive:
· The Alaska constitution, Article 8, sections 1
and 2 that directs: "It is the policy of the
state to encourage... the development of its
resources by making them available for maximum
use consistent with the public interest." And
that, "The Legislature shall provide for the
utilization, development and conservation of all
natural resources belonging to the state, ... for
the maximum benefit of its people."
· AS 38.35 The Right of Way Leasing Act - "The
natural resources of this state,...and in its
land for transportation of these
resources...toward markets both in and out of the
state are capable of making a significant
contribution to the general welfare of the people
of this state. It is the policy of this state
that the development, use and control of a
pipeline transportation system be directed to
make the maximum contribution to the development
of the human resources of this state, the
increase in the standard of living for all of its
residents, the advancement of existing and
potential sectors of its economy, the
strengthening of free competition in its private
enterprise system and the careful protection of
its incomparable natural environment."
· AS 43.82 Stranded Gas Development Act - "maximize
the benefit to the people of the state of the
development of the state's stranded gas
resources"
Unfortunately, with the passage of HB 290 by the
twenty-first Alaska Legislature in 2000, that broad
policy directive is precluded in that the law puts an
overwhelming burden on local utilities and communities
to commit to purchase for firm transportation a
definitive amount of natural gas without knowing what
their future demands will be, without knowing what the
tariff rate will be or the methodology for gas
valuation will be or from whom they will purchase gas
or even if it will be available.
Further, HB 290 exempts a North Slope natural gas
pipeline from a requirement to serve as a "common
carrier" for anything other than instate use of gas.
There is no realistic provision in law that requires
the owners of a gas pipeline to provide access for out
of state shipping capacity to any other would be
competitor.
Simply put, despite a broad policy directive to the
contrary, it is probably that under existing law,
Alaska's communities will have limited access to North
Slope natural gas. Further, it is probably that would-
be competitors will be precluded from shipping natural
gas, thereby eliminating the potential for a
competitive free enterprise market from which all
Alaska benefits.
Fortunately, timely solutions do exist. When HB 290
passed, it was clear that a time of reckoning lay
beyond; when the legislation would have to be reviewed
and changed. We knew that because, while HB 290 was
the best we could do at the time, ultimately it did
not meet our constitutional obligation. That time is
now. The first set of solutions will require that the
law be changed to provide a more probable opportunity
for community access and competitive access for would-
be gas explorers and producers. A second solution is
public ownership of a North Slope natural gas
transportation system. The Alaska gasline Port
Authority, a municipal entity created in 2000 by an
overwhelming majority of voters and the Alaska Natural
Gas Development Authority, a state entity created by
initiative in 2002, and approved by a significant
majority of voters, are both committed to ensuring
access to any would-be producer and also committed to
providing access to supply for all Alaskan consumers;
be they utilities, industrial or other user groups.
Ready markets exist for Alaskan natural gas. The
supply/demand dynamic is such that the economics of a
project are predictable and positive. Supply at a fair
value must be made available to the project that most
benefits Alaska and Alaskans. It is the Legislature's
constitutional responsibility to ensure that supply at
fair value be made available. That responsibility and
subsequent action may from time to time require a
reasonable legal and commercial confrontation or
negotiation between the Legislature and the major
leaseholders of Alaska's North Slope natural gas:
British Petroleum, Exxon and Conoco-Phillips. A
negotiation or confrontation of this nature between
the state as the owner and the leaseholders is
necessary and healthy. After all, much can be gained
or lost on both sides. The Legislature's
responsibility is to fairly gain a maximum benefit for
the people of Alaska.
N. Jim Whitaker, Mayor
MR. LARRY PERSILY, Special Assistant to the Commissioner,
Department of Revenue (DOR), said he wasn't at the meeting when
he got volunteered for this subject. His comments are not meant
to depress anyone or contradict earlier comments.
All things being equal, collecting state revenues
sooner is better than getting them later. You never
know what the future will bring and, if you need the
cash, you might say that a royalty or a tax dollar in
hand is worth more than two in the ground - especially
for a state that is so dependent on each year's
revenues to pay its bills.
But, on the other hand - the one without the dollar in
its grip - Alaska needs the gasline money even more so
in the future, if declining oil and gas production
continues to cut into our state revenues. A steady,
even longer-term, stream of cash to the treasury may
be better than producing more gas in the early years
and then less gas later on.
Just as the Alaska Oil and Gas Conservation Commission
(AOGCC) is charged with managing reservoirs for
optimal, long-term production, shouldn't we also
consider the optimal term for maintaining the gasline
revenue stream? That's something to consider, since at
this time no one really knows how much gas is
economically recoverable or if and when companies
would be willing to invest in new exploration and
production to prove up those reserves and put them in
the line.
The proposal on most tables is for a gasline that
would move 4.5 BCF per day. With the current proven
reserves from Prudhoe Bay and Point Thompson, that's
about 34 TCF. A full 4.5 BCF a day line would run out
of gas in 21 years. The truth is it wouldn't run at
st
full speed and then hit empty one day late in the 21
year. The decline would start soon after the half-way
point after which the decreased flow would be steep.
The major North Slope producers testified this past
legislative session that the gas flow from 34 TCF
would start to decline after about 12 to 14 years,
leaving plenty of available capacity for new supplies
to move down the pipe.
Looking at projections at Prudhoe Bay and Point
Thompson, a 4.5 BCF project would be down to 4 BCF by
year 15, dropping quickly to under 3 BCF by year 18
without new discoveries to feed the line.
And, yes, there are some additional known reserves on
the North Slope, but not nearly enough to keep a 4.5
BCF line full for 30 years or more, which is what
we've already gotten out of the trans-Alaska oil
pipeline.
It would take closer to 60 TCF of reserves to keep a
4.5 BCF gas pipeline full for 30 years, after which
the flow would turn sharply lower. Consider that
explorers would need to find and develop those new
fields just to keep the line full, much less worry
about expansion.
Notwithstanding all the estimates of how much gas
might be out there, 30 additional TCF is a lot of gas
to find. By comparison, that is more than three times
as much gas as has been discovered in the Mackenzie
Delta. At $4 an MCF, that is $120 billion worth of
gas.
Assuming explorers find that 30 TCF of gas or more on
the North Slope and in the Foothills, does it make
sense to expand the line to move that gas to market as
soon as the engineers and welders can do the work to
boost the pipe's capacity? Or is it better to pace
ourselves for the long term, thinking of those
additional reserves to extend the life of the line
rather than expand its short-term flow? Should the
market decide if and when more gas is needed?
We should keep our eyes on what's important, which is
getting the gasline built sooner rather than later and
do whatever we can to ensure that the gas flows for as
many years as possible. That seems more important than
deliberating expansion requirements now, especially if
it affects the commerciality of the line.
It is natural to assume that as soon as the line is
built, there will be an incentive to explore. No doubt
explorers will find more gas on the Slope. The state's
interest is to encourage exploration to always keep
that line as full as possible. More gas in the line
means lower tariffs, which means more royalty and tax
revenue to the state from a higher wellhead value and
more years of tax and royalty checks. However, too
much expansion early on could lead to lower
utilization of the line later on, meaning higher
tariffs and less revenue to the state in those years.
The pipe should be sized for the long-term efficiency,
not short-term gains.
It also is natural to assume that some of the major
North Slope producers might be motivated to explore,
just as independents will want to find gas once there
is a line to carry it to market. Therefore, the state
should be very careful about creating any mechanisms
to direct expansion capacity to any parties in a
discriminating fashion - while being just as careful
to ensure that the independents are treated fairly,
with full and realistic opportunities to access the
line.
But, in impersonal dollars and cents, as far as state
revenue is concerned, a dollar from a major producer
is as good as one from a smaller independent player as
long as the majors remember where we are.
Having said that, I want to stress that competition at
lease sales is good for the state and, for that
reason, the state should take all reasonable steps to
encourage and promote independents on the North Slope.
It's clear that the independents will play an
increasingly larger role in the state's oil and gas
industry and without access to move their production
to market they and the state would lose. That is
unacceptable.
But getting back to the issue of gasline expansion, we
believe companies' willingness to commit exploration
and production dollars and the market's need for more
gas should control expansion of the line. Let's be
careful not to let any dreams of expansion jeopardize
what we really want, which is the gasline.
The line's tariff structure could also affect the
timing of any expansion. By adopting different methods
for calculating the tariff, the recovery of capital
costs over time, gasline charges can be decreasing or
levelized. Each has its own advantages and
disadvantage for different players and different
times. There are good reasons for each and the state
needs to think carefully about the options and the
effect.
Through a decreasing tariff, where it starts high and
decreases each year as depreciation reduces the line's
cost basis, the project's equity investors recover
their money sooner and, over time, the tariffs
decrease as there is less cost recovery built into the
transportation charge. Lower tariffs could encourage
independent exploration, but not until those years of
the higher initial tariff have passed. Also, under a
decreasing tariff the state's take is less in the
early years because of the higher tariff as a
deduction against royalties and production taxes.
That's a trade-off for the lower tariff and higher
state revenues in later years.
A declining tariff also lowers the owners' production
tax bills early-on assuming the producers are the
owners, which back-end loads the fiscal system, a goal
of the Stranded Gas Development Act. Because of the
time-value of money, this could help the economics of
building the project. The owners would pay less taxes
early on, because of the higher tariffs, but would pay
heavier taxes as the tariff drops in the later years.
So, you could say a decreasing tariff with heavier
upfront depreciation might be good for a producer-
owned line and could be good for new producers if they
come on line in the project's later years, but bad for
those independents if they want access in the earlier
years.
If a third party owns the pipeline, a decreasing
tariff would put a burden on the majors as the early
gas pays higher tariffs to pay off the pipeline. This
could hurt their economics.
A levelized tariff, which is the other option, spreads
out the burden of paying off the pipeline equitably
over time among all parties. Regardless of the project
owners' tax depreciation schedule, the cost recovery
is levelized for the life of the project, meaning the
tariff is the same in year 1 as in year 20. This would
eliminate any burden on early producers to pay a
higher tariff, but also would mean the later producers
would not see any tariff benefit from a more heavily
depreciated line.
Independent producers that come on board at any time
in a levelized tariff project would pay the same as
the majors. This would be better than a decreasing
tariff for independents that feed gas into the line in
the earlier years of the project.
And, as you heard at last months' hearing, there also
is the issue of rolled-in or incremental tariffs for
any expansion capacity. What's important to remember
is that the entire issue of tariff structure may be
subject to negotiations under a Stranded Gas
Development Act contract where the state can negotiate
fair access for all parties and help ensure that the
line stays full for a long time.
SENATOR BUNDE asked if he recommended one of the three options
he just presented on tariffs.
MR. PERSILY said he was sure tariffs were being discussed in
Stranded Gas Act negotiations and he had only been on the job
for five weeks and didn't want to pronounce what the state's
recommendation is.
CO-CHAIR OGAN said one of his concerns about revenue is the
effect of the draw down on gas on oil revenues. Currently the
AOGCC can regulate the waste of hydrocarbons, but not the
economic waste of drawing down a large amount of gas in units
that would affect oil production and, ultimately, revenues.
MR. PERSILY said he knows that the AOGCC is looking at that.
CO-CHAIR OGAN noted that there were no more questions and that
the next subject for discussion was access to capacity for
Alaskan utilities by Anthony Izzo, Enstar Natural Gas Company
saying that it is the sole gas distributor to Anchorage, the
Mat-Su Valley and Kenai Peninsula. He said there is a lot of
discussion in his area about whether there will be a spur to
service the Valley.
MR. ANTHONY IZZO, President, Enstar Natural Gas Company, said it
has been serving its Alaskan customers for over 40 years. He
accompanies his comments with a slide presentation. The first
slide showed a fuel cost comparison. Gas was the cheapest. The
second slide showed Enstar's pipeline infrastructure; the third
slide showed a graph of the Cook Inlet gas supply from 1958 -
2002 and projects out to 2022, when it drops off significantly.
A fourth slide showed a graph of consumer's use of Cook Inlet
gas.
MR. IZZO explained that Enstar's supply strategy, as it sees
production dropping off at the end of the decade, has been two-
fold.
We need to contract for additional supply. The reason
it's significant is that we've moved clearly from an
excess supply market. Back decades ago - in our
business we call it overhang - there was a lot of gas
available and the demand was much lower and so the
contracts at the time were all indexed against prices
of oil. It made sense if oil prices were up, the
economy was doing well, your natural gas bill went up.
If oil prices were down, the economy was down, your
natural gas prices for home heating and business use
were down. We were not able to secure additional
supply using that model - going back just a couple of
years ago. So, what we clearly identified is the fact
that we've gone from an excess supply to a supply and
demand market.
The second strategy was to clearly identify what
really is left in the Cook Inlet - is there potential
for additional discovery and can the existing reserves
be expanded? What is the real situation from our
perspective in terms of North Slope gas?
MR. IZZO presented more slides that graphed Enstar's gas supply
from different fields and explained:
With the new strategy, understanding that this was
going to be a supply and demand market, we had to look
at how we contracted for supply very differently. The
good news you'll see on the chart here is that we're
now filled up to 2007 and what you see in green is
what we refer to as the Unocal contract. It's not
indexed against the price of oil; we couldn't get
anybody to go and look for that. It's indexed against
a trailing average of the Henry Hub. I guess simply
put, it is indexed on Lower 48 prices. What we were
able to do was to use a trailing 36-month average.
We did not want to subject Alaskans to the volatile
price swings in the Lower 48. There have been times in
California where natural gas prices would be $20 and
then it's $6 and then it's $10. We didn't want that to
happen because on a monthly or quarterly basis, bills
would be changing; you couldn't plan or budget. It was
just not something we found acceptable. So, the
average allows us to, once a year, make the adjustment
to the Regulatory Commission of Alaska and then it
gets passed right through. The consumer pays for it
and it gets passed through Enstar directly to the
producer.
So, the good news is that we've got some investment
going; we've spurred some exploration. That gas in
green right now costs $4.39. Our weighted cost to the
consumer is $3.11 and in the Lower 48, they're paying
about $6. So, we're less, but prices will increase. As
the Unocal gas makes up more and more of our
portfolio...we move away from most of the supply being
indexed against oil prices, which are up by the way,
which means that gas prices will go up next year. But,
we will be more and more connected to that Lower 48
pricing mechanism. Unocal has spent about $110 million
in looking for new supply and there has been some
success we're very pleased about.
Step number two is to determine what is really in the
Inlet and what are the options...to serve half the
state's population in this region. The final report
was released July 6; this was done by the Department
of Energy as a result of a federal appropriation to
the DOE's Arctic Energy Office in Fairbanks. A local
firm in Anchorage actually did the work, brought in
outside expertise when needed, and worked with all the
various utilities and producers.
There are three observations...in the report that I
think are relevant. One is potential reserves growth,
two is new exploration and what is the potential and
three, North Slope gas to Cook Inlet.
MR. IZZO explained some of the graphs that showed the gas supply
line dipping below the demand for power generation and home
heating in 2012. His real concern is, looking at fields that are
dedicated for just power generation and home heating, that line
intersects in 2009.
In terms of reserves growth now, DOE looked at it and
said well, we have these existing fields in Cook
Inlet. What's the potential if those were to be
expanded - if modern technology was used and you enter
those fields? So, this is highly speculative. They
just used models from other fields around the world
that were just as mature.... You might be able to get
another 1.5 TCF out of there. Applying some of their
information, they came up with a cost of about $.5
billion...to expand those reserves....
What that would look like is a slightly more
optimistic slide on the next page. If 1.5 TCF were
found in those fields at $500 million, we could be
looking at a line that doesn't dip down below until
the end of the next decade. And so, it's not a sure
thing by any means and there's no guarantee that
trying to increase those reserves will actually result
in this, but a best case scenario is for $.5 billion,
that it might buy us some time to get us through most
of the next decade.
In terms of new exploration, they found some good
news. I thought it was some good and some not so good.
They believe that based on the profile of the
endowment in the Cook Inlet, the Department of Energy
thinks that there could be 13 - 17 TCF additional in
the Inlet and that's great. The concern I have is that
once they put some analysis to the cost and we looked
at the protected lands, we looked at the cost onshore
versus offshore, they found that if you could find 50
percent of that potential gas - again, you're throwing
the dice, in my view.... if you found half of it and
if it were on land, then the investment required there
would be $5 billion to $6 billion. That would
certainly buy us a decade or two. The concern I have,
again, is the economics.... It would have to be
competitive and be passed through to the consumer.
Now, out of my own business interests, what are the
alternatives? The alternatives, if it isn't natural
gas, there's fuel oil, there's propane, there is
electric, but you're talking about three, four, five
and six times as much. You're talking about half the
state's population in terms of the economic impact.
That does not include what it would cost to convert,
what it would cost to put in tanks, to convert
furnaces, etc.
The last observation I'll share with you from my
perspective was the North Slope pipeline ideally did
have the potential to moderate prices in Southcentral
Alaska. One thing that Enstar knows and that I'm here
to share with you is that prices are going to
increase. That's a conclusion. I know they will go up,
because I couldn't get anybody to go and look for gas
unless it was economic to go and look for it. So, the
traditional model of all this extra gas and we'll sell
it to you at a stranded gas prices. It just didn't
work any more. So, they'll go and look, but we could
end up by the end of the decade paying more than they
do in the Lower 48. It still might be less than the
next alternative, but it's not a good situation.
I was very encouraged that the DOE found that a spur
could provide a $1 per MCF advantage over the Lower 48
pricing and that that could result in some energy
intensive industry and some economic development....
What we're showing here is that gas from the Slope
down into the Lower 48, if it cost $2.58 - $3.00 MCF,
that using the various models, conservatively the DOE
believed that it could be, in comparison, $1.50. So,
we could enjoy $1 MCF reduction or a lower price
compared to the Lower 48, which could mean with our
deep water access and logistical advantages here in
Alaska, that we could have an economic advantage. It's
not a choice of paying whatever the tariff might be
from the Slope to Anchorage versus paying the $2 that
we've been paying for years for gas over the decades,
because those days are gone. It's going to be at some
point in the next few years, we're going to be paying
more than the Lower 48, because we're technically not
connected to them. But, for producers to economically
go after the additional supply, it's the over-ripe
fruit story. The low ripe stuff has been picked....
The conclusions are that I believe from Enstar's
perspective that access to Slope gas is absolutely
critical. As I stated, I believe that prices will
continue to rise because we're in this supply and
demand market. That has clearly shifted in my world.
We could enjoy a 20 - 25 percent price advantage over
the Lower 48, which, I think, instead of being
concerned about an economic decline associated with
declining reserves, we could be looking at some
potential economic boom in terms of energy intensive
industry. To determine what that is, we have requested
a phase-two appropriation to study energy intensive
industry, what that might be and to also look at some
conceptual engineering for a connection from Anchorage
up to Fairbanks or Delta Junction. I've got my
commercial blurb at the end and now it's time to focus
and I'm preaching to the choir. That concludes my
presentation.
SENATOR WAGONER asked if Enstar is still considering a spur
line.
MR. IZZO replied that it is.
That is very real and is in the forefront of our radar
screen in the future. We believe that we have obvious
interest in wanting to stay in business and wanting to
be profitable, wanting to earn our rate of return
that's allowed, but we have found that with the
declining reserves in Cook Inlet that our interests
are similar and parallel with the economic interests
of this region. So, I would use the example of
building a house. I don't think any of us, if we were
building a home, would wait until the framing was up
to pull out the yellow pages and find an electrician
or a plumber. We'd have the estimates; we would know
what it would cost. We'd have it ready to go and
that's how we view the spur line - is that we need to
know what that is and we are currently working such
that we can do the responsible thing and be prepared.
REPRESENTATIVE GARA asked of the gas pipeline owner's incentive
not to allow a spur to Cook Inlet:
If they fill up the pipeline from the North Slope down
to Tok, and then dump off a certain amount of gas in
Tok, then that they're carrying a less than full
pipeline from Tok all the way down to Chicago and
therefore it makes the transportation in the remainder
of the line less efficient? Do they have a
disincentive to allow the spur because of that and
also because it eats into the amount of gas they get
to charge to pipe from Tok down to Chicago? Is that
the disincentive or does the pipeline not work that
way? Two, do you agree with Attorney General Cole that
we have to take another look at the law to make sure
that we guarantee our ability to have the spur lines
in the state?
MR. IZZO agreed on his first point. Various interested parties
have expressed concern to him directly that constructing a
pipeline with X capacity and then finding themselves in a
situation where only 75 percent or so of that capacity can be
met from Tok or Delta Junction on south. My response to that has
been more around what the needs of this community are as I know
them.
TAPE 04-15, SIDE A
MR. IZZO explained that when the interested parties hear of the
need for power generation and, potentially, some industrial use
and home heating, which is much less than 1 BCF per day, the
reaction has been one of reassurance. To Representative Gara's
second point, he said he did not hear Mr. Cole's presentation,
but, "The legal nature and critical need of a spur line in my
view is something that we should do every bit of due diligence
possible. So, if there's any doubt that we may have access, I
would encourage the legislature or any responsible party to look
at that."
CO-CHAIR OGAN suggested that Mr. Izzo review Mr. Cole's
presentation, which has some very good points about Fairbanks'
st
concerns with the take and pay concept in HB 290 of the 21
Legislature.
REPRESENTATIVE CHENAULT said Mr. Izzo talked about the price of
new gas from Unocal being $4.39, which is based on some sort of
sliding scale at the Henry Hub, and he projects the price will
go up because of the price of oil. He asked him how he is tying
the price of oil back to the price of gas when it is based on a
sliding scale at the Henry Hub.
MR. IZZO referred to the slide of the gas supply in 2003 and
said he refers to those contracts as legacy contracts. Those
have been indexed, for some time now, on the price of West Texas
sweet crude between May 1 and June every year. Based on that
index, prices will change in the following calendar year. He
continued:
So as we've moved into where we are here in 2004, 24
percent of my supply is with the Unocal contract.
That's indexed against the trailing average of Henry
Hub. The remainder is still indexed on the price of
oil so what's happening currently is within this
transitionary period, is the price of oil is up. That
is putting upward pressure on rates. As the prices are
sustained at high levels in the Lower 48, that drives
that average up over the 36 month trailing period....
CO-CHAIR OGAN responded:
Once we indexed to the Henry Hub, the consumer prices
went up quite a bit based on that - is what's going to
have to happen to have people looking for gas, which
we do have finally for the first time ever. People are
leasing for the sole purposes of looking for gas in
Cook Inlet and that was just something that happened
with oil before that.
REPRESENTATIVE HARRY CRAWFORD said that he and Senator Bunde
attended a NCSL conference and heard a presentation by the
producers, during which they talked about the energy supplies in
the country over the next 25 years. They said they don't even
book the North Slope gas supplies in because they expect those
supplies to be stranded for another 25 years. He asked Mr. Izzo
what will happen to Enstar if that gas supply does not come off
of the North Slope.
MR. IZZO said Enstar has been undergoing a very aggressive
program. It has and continues to meet with producers on an
ongoing basis. Enstar believes it is responsible to determine
what it will take to spur exploration. It would continue as it
has and, although there is a certain amount of uncertainty about
the future compared to 20 years ago. He then said he does not
subscribe to the 25-year theory. He believes that with free
market forces, this is something that can happen. He has
discussed that question with his peers throughout the country
and has asked, at Western Energy Institute Board meetings, how
many of them would have a difficult time getting a long term
supply approved at $4 or $4.50 by their commissions and everyone
had jumped up. He said he sees the need for some reassurance of
supply and, to some degree, it is a national security issue. He
said because of the volatility his cohorts are experiencing,
they would embrace the ability to reserve capacity. He said the
true test would be the number that would line up if there was an
open season.
MR. IZZO said this has been discussed for almost 35 years and he
is asked what is different now. As he looks at half of the
state's population that could see declining reserves, he sees
how that is directly associated with Alaska's economy and yet,
Alaska is the richest resource state in the Union. He thinks
with the confluence of those factors and free market forces,
this is a very viable project.
CO-CHAIR OGAN noted that every expert on energy supply and
demand trends who spoke to the Energy Council in the last year
and a half factored in the availability of Alaska gas and that
beyond the year 2020, the United States will have to import 20
percent of its gas from foreign LNG sources even with 4.5 BCF
from Alaska. He asked Mr. Izzo to visit the Mat-Su Borough and
relay his views on the gas supply.
Co-CHAIR OGAN announced an at-ease from 2:30 p.m. to 2:45 p.m.
Upon reconvening, he asked Mr. Loeffler to testify. He informed
members Mr. Loeffler is a senior partner of Morrison and
Foerster LLP specializing in energy matters and has represented
clients before FERC for more than 30 years. He has been advising
the State of Alaska on oil and gas pipeline issues since the mid
1970s.
MR. ROBERT H. LOEFFLER, Morrison and Foerster LLP, gave the
following testimony.
In my June 2004 testimony to the committee, I
discussed the general methodology and standards that
the FERC utilizes to set gas pipeline rates. Mr. Ives
of the Lukens Group discussed access issues associated
with initial pipeline capacity, in particular FERC's
open season process. Today I want to address another
pipeline issue that looms potentially large and
important, namely, the law that governs expansions of
an Alaska Gas Pipeline after it is initially sized and
built. I will first address the law on expansion as it
stands today and then turn to the provisions of the
Energy Act of 2003 that for the first time gave the
FERC the power to order expansion.
Based on information provided in the various Stranded
Gas Act applications, the Alaska Gas Pipeline could be
sized to carry anything from 2.6 to 5 BCF per day,
with expansion capability designed in of up to 6 BCF.
Any expansion would be accomplished not by replacing
the original pipe with larger diameter pipe, but
rather by adding additional compression - that is
additional compressors at existing stations or
building new compressor stations - and/or looping.
That is adding smaller diameter pipe parallel to the
main pipe in particular places. The question is
whether the Alaska Gas Pipeline owners can be forced
to expand the pipeline in the event they do not
voluntarily agree to do so. Under current law, the
short answer is no. Let me explain that.
We have to turn to the Natural Gas Act [NGA] and it
does not use the word expansions. Instead, it
prohibits enlargements but gives the FERC the
authority to order extensions. Simply stated, while
the FERC has the power to order extensions or
improvements, it does not have the power to order
enlargements to pipeline facilities.
What's the difference? It turns out there's no bright
line, but the courts and the FERC have interpreted
this language in a manner that treats expansions as
prohibited enlargements. It took awhile after the act
was passed in 1938 for the courts to get to this and
by 1949 the courts were saying, literally, the act
nowhere defines these terms and it's somewhat baffling
to determine when and under what circumstances an
extension or improvement of facilities ceases to be
such and becomes enlargement.
The commission could see that in court way back in
1949 that it does not have the authority to compel
enlargement by a natural gas company of a pipeline.
Yet I think the language of the court is instructive.
It says in light of section 7(a), we are compelled to
conclude that Congress meant to leave the question
whether to employ additional capital enlargement of
its pipeline facilities to the unfettered judgment of
the stockholders and directors of each natural gas
company involved. So, what you're dealing with is
really the belief that private people are building a
project and you cannot force them to put more money
into a project if they don't want to. And that really
is the standard under existing law.
Very recently the commission reaffirmed this position
and said it has the authority to order a pipeline to
construct new interconnects or [indisc.] connections
are made, but it also said that it cannot compel
pipelines to expand capacity on their systems.
Interconnects are literally the physical connection
between two pipelines - if you wanted a lateral coming
in or a lateral going off - that's an interconnect.
And even there where it does have authority to order
interconnects, the commission said in this particular
case, 'The Commission emphasizes that this new policy,
which relates only to the construction of new
interconnections, does not require a pipeline to
expand its facilities, to construct any facilities
leading up to an interconnection, or even to construct
the interconnection itself....' This modified
interconnection policy seeks only to ensure that when
pipelines respond to requests for interconnections,
they do so in a manner that causes no undue
discrimination and furthers the commission's policies
favoring competition across the national pipeline
grid.
Well, in short, a state and any private party who
wanted expansion would be in a tough position to rely
on the existing law to get an Alaska gas pipeline
expanded by the FERC. The good news is that Section
375 of the so-called Alaska Natural Gas Pipeline Act,
which is the subtitle of the Energy Policy Act of
2003, would grant the FERC the authority to order
expansions subject to certain conditions. The bad
news, of course, is the legislation is languishing in
Congress.
Section 375, if it becomes law, would be the first
time the FERC has been given the power to order
expansion for any pipeline. This represents the
recognition by Congress of the unique circumstances of
an Alaska gas pipeline, and namely that it is likely
to be the only road to market for North Slope
resources. This provision was fashioned after much
discussion and compromise of present and future North
Slope producers, pipeline owners in the Lower 48,
would-be pipeline owners of Alaska and the State of
Alaska. Some urged that the FERC be given greater
powers for expansion; others urged that there be no
change at all. As you will see by reading the
language, FERC's new powers do not extend to
interstate gas pipelines in the Lower 48. This is a
solution for an Alaska gas pipeline and only for that
pipeline.
I'm going to quickly go through critical terms. The
way it works is that one or more people would have to
request the FERC to order the expansion of the
pipeline. Before it could do so, it would have to
satisfy eight conditions and they're stated at page 8
of my testimony. The first condition deals with the
rates - will they be rolled in or incrementally priced
for expansion - make sure rates do not require
existing shippers to subsidize expansion - find that a
proposed shipper will comply with the tariff that
exists as of the date of the expansion - find that the
proposed facilities will not adversely affect the
financial viability of the project - find that the
proposed facilities will not adversely affect the
overall operations - find that the proposed facilities
will not diminish the contract rights of existing
shippers to previously subscribed capacity - ensure
that all necessary environmental reviews have been
completed - and find that adequate downstream
facilities exist outside of Alaska to deliver the
Alaska natural gas.
Now I want to comment on some of the details of these
provisions that could affect the issues the committees
are concerned with. The language of this new provision
does not mandate how expansion capacity will be priced
by the FERC. It gives the FERC power to use either
rolled in price treatment or incremental price
treatment. This is an issue of consequence to
unaffiliated explorers because they want to know what
the cost of transportation on an expanded pipeline
would be.
A parallel provision requires that the rates for
expansion capacity not require that existing shippers
subsidize expansion shippers. Of course, what's a
subsidy rise in the eye of the beholder? In some
circles what is called a subsidy is viewed as an
entitlement or a natural right by others.
Today, under existing law, the FERC has a clear policy
on how expansion should be priced. It's changed its
policy a number of times but its most current policy
is that an expansion should be paid for by those
demanding the expansion unless there is a system-wide
benefit. A system-wide benefit would mean that when
the costs of the expansion are rolled into the
existing costs of operation, the costs of
transportation for all is lowered. This is technically
possible in some circumstances depending on
engineering and throughput matters. If, however, the
average transportation cost increases due to the
expansion, then the expansion shippers, under current
policy, would pay a different and higher rate to ship
on expansion space. The rationale, simply put, is that
those who cause the expansion should pay for it.
Informed observers have noted that there is a 'heads I
win, tails you lose' aspect to this policy. If
expansion lowers the cost per unit for everyone, then
those causing an expansion lose that benefit to the
system as a whole. If, on the other hand, expansion
costs are higher per unit than they were before, the
expansion shippers are forced to bear the higher cost.
Time will tell how this works out on an Alaska gas
pipeline and I repeat that the legislation tosses that
issue back to the FERC saying it can use either
incremental or rolled in pricing.
There are other limitations in Section 375 worthy of
mention. Parties in the legislative process were
concerned that expansion not affect the financial
underpinnings of the project. Certainly the language
in Section 375(b)(4) would give financial
institutions, who presumably will loan vast sums for
this project, a voice in any expansion proceedings at
the FERC. Similarly, the rights of those who have
already contracted to ship on the pipeline are not to
be diminished by any mandated expansion. I suspect
that this means, at least, that there cannot be any
reduction in existing shippers' shares of initial
capacity.
Two other aspects of Section 375 are worthy of
comment. First, the FERC is required to examine
whether there are adequate downstream facilities,
mainly outside of Alaska, for new gas that would be
shipped through the expanded facilities. This stands
in marked contrast to the process spelled out for
certificating the pipeline in the first place under
this new statute. There Congress directs the FERC not
to look at whether adequate downstream capacity
exists, but to presume it. Second, subsection 375(c)
requires that the party who requests an expansion at
FERC execute a firm transportation agreement within a
time to be set by FERC, a reasonable time, after an
expansion order issues or lose the expansion rights.
This, in plain language, is a put up or shut up
clause. The expansion order becomes void unless the
parties who sought the order sign a binding contract
to ship on the expanded capacity.
There are other requirements in the proposed
legislation concerning non-adverse findings on
financial, economic, and operational grounds. On their
face, these provisions appear to provide fertile
ground for an opponent of expansion. They certainly
invite litigation.
In the end, the proposed legislation allows, but does
not mandate or require FERC to order an expansion.
That's a better situation than the status quo but it's
not perfect. I do not have to be a prophet to make the
observation that in granting expansion rights to the
FERC for, and only for, an Alaska Gas Pipeline, the
legislation would lay a careful path with several
potential hurdles to clear. How high those hurdles
will be is left to the informed discretion of FERC.
Based on everything else connected with this project,
the first time around and again now, I would not
expect the expansion proceeding to be short,
uncomplicated, and uncostly. Nonetheless, the power to
order expansion would exist for the first time. That
alone will influence how parties approach expansion on
a voluntary basis because the prospect of involuntary
expansion lurks in the background.
I'm going to add a couple of points that are not in my
prepared testimony that I thought would be of interest
to the committee. If you recall, in June I commented
on how the legislation would require the FERC to adopt
quickly to situations that would govern open seasons
on an Alaska Gas Pipeline. These regulations would not
apply, that is they would not apply to any mandatory
expansion of the pipeline. For reference, that's
Section 373(e)(3). They would apply only to
involuntary expansion of the pipeline. The rationale
of Congress, I suspect, is that an expansion order
would be sought by a specific shipper or group of
shippers that had been unable to convince the pipeline
to expand voluntarily. In those circumstances, those
seeking expansion would have to convince the FERC to
order this one-of-a-kind expansion and they would be
responsible for signing binding contracts for the
expanded capacity. Thus this appears to be a different
kettle of fish than the normal allocation of capacity
and open season process. FERC still might want to hold
some kind of open season to see if anyone behind those
seeking expansion also desire capacity in the event
this pipeline is expanded. But it's not required to.
It's [indisc.] from the normal open season
requirements and we have to wait and see how the FERC
interprets these provisions.
Second, the legislation also addresses access for in-
state users. In Sections 375(g), Congress requires the
applicant for FERC authorization under the Natural Gas
Act, to demonstrate that the holder has conducted a
study of Alaska's in-state needs, including tie-in
points along the Alaska natural gas transportation
project for in-state access. I believe the state would
expect the study to cover access at least two to three
points along the pipeline route in Southcentral
Alaska. Second, the special provision in Section 373
uses language that addresses access for royalty gas.
That provision requires the FERC, after a hearing, to
provide reasonable access to the State of Alaska for
shipment of the state's royalty gas for the purpose of
meeting local consumption needs within Alaska. The
language is specially designed to ensure that Alaska
royalty gas could be used for in-state needs. The
absence of new federal legislation does not
necessarily mean there will be no expansion
requirements for an Alaska gas pipeline. As I
indicated a few moments ago, the expansion language in
the pending federal legislation reflected a consensus
that was reached among interested parties. These
parties thought they could live with the expansion
concept in specific conditions attached there, too. It
would appear there would be no insurmountable obstacle
to interested parties contracting to the very same
terms contained in the proposed legislation, or even
different ones. It is a fair bet to say that the
existence of the compromise language, whether adopted
or not, will also provide a framework for voluntary
expansion negotiations.
The ongoing Stranded Gas Development Act contracting
process could serve as one vehicle to ink an expansion
agreement. Another contracting opportunity will arise
in the negotiations attendant to the various ownership
agreements. If the state is not a pipeline owner, its
interests will probably not be directly represented in
those ownership negotiations.
Would FERC honor such contractual agreements? I see no
reason why the FERC would reject an agreement that
required the owners to seek expansion authorization
from the FERC after negotiations in the event that
certain agreed upon conditions or events were to
occur. So long as FERC remained free to make its
normal certificate inquiry about the public interest,
I think it would likely applaud rather than disapprove
a voluntarily reached expansion agreement.
That concludes my presentation. I appreciate the
ability to do this by teleconference and I'd be happy
to entertain any questions.
SENATOR WAGONER asked if there is any chance of action being
taken on the Alaska Gas Pipeline Act before the November
election.
MR. LOEFFLER said there is a slim chance it will be brought up
as a rider or on a special basis, but only a slim chance.
SENATOR WAGONER asked his opinion of action after that time.
MR. LOEFFLER said he believes it will come up again in the same
exact form because a lot of people worked long and hard to
compromise and there is no known opposition to the enabling
provisions that contain this expansion authority.
CO-CHAIR OGAN asked what the best-case scenario is.
MR. LOEFFLER said the best case would be if something happened
before the November election. He believes it is much more likely
that something will happen next Spring, but no one knows who the
president will be or who will be in Congress.
CO-CHAIR SAMUELS asked Mr. Watson to testify and informed
members that Mr. Watson is the Project Manager for Alaska Gas
Development for Enbridge. He is actively involved in all aspects
of project assessment and currently leads the coordination of
market participation on behalf of Enbridge. Prior to his
employment at Enbridge, he spent 10 years directly involved in
the Canadian energy industry, most recently as the vice
president of corporate development for a leading solution
provider to the North American energy industry.
MR. ERIC WATSON, Project Manager, Alaska Gas Development,
Enbridge, reminded members that Enbridge has proposed a measured
approach in its Stranded Gas Act application. It includes a 36-
inch pipeline design, which contrasts with the 48 and 52 inch
pipelines proposed by other parties. Enbridge views the 36-inch
design as a better economic alternative to meet the pipeline
needs. He asked to delve into that topic today and describe some
of the factors that will drive the volumes and how that will
impact the pipeline design and, inevitably, the cost of
delivery. He began:
For the benefit of those who could not attend the June
hearings, I will spend 30 seconds just as a quick
overview of who Enbridge is, just in case you don't
know about the company. We operate the world's longest
crude oil pipeline system. We have assets in excess of
$13 billion, a stable A credit rating, lots of cash in
the bank and, as it relates to the Alaskan project,
gas now makes up 40 percent of our earnings. Included
in that is a 50 percent ownership in the Alliance
pipeline, which is one of the major transporters of
natural gas and liquids for the Chicago market and
also the owner and operator of Canada's largest LDC,
serving over 1.7 million customers in Ontario and
northern New York State. So, we also have a bit of a
market perspective on the other end as well.
As you may be aware, we're pursuing a greenfield
project through FERC and the NEB. We are the only
pipeline company with extensive experience in
continuous and discontinuous permafrost construction
operations [indisc.] pipeline. We have the most recent
cross-border, large-diameter, high-pressure, rich gas
pipeline experience, which is more than likely to be a
similar scenario to the Alaska pipeline. We've
participated in both study and field trials in Alaska
to examine the practice of trenching in permafrost ...
As I mentioned, we also have a market perspective
through ownership in Canada's largest LDC.
As I mentioned at the outset, we're focused on a
measured approach that reduces the risk of the project
and aligns the interests of the stakeholders. I want
to clarify that a measured approach doesn't
necessarily mean a phased approach and that we are not
stuck or bent on 36-inch as the only solution. We
believe it is a potentially viable solution, depending
on the volumes and timing of the volumes that come out
of Alaska and that's really what I want to look at
today. Based on what happens with these volumes and
these timings is really going to drive the economics
of this project and within that 36-inch is an option
that we should still be looking at. So with this,
we're seeking to add value within the project by
working closely with other stakeholders in a
collaborative and cooperative manner. Given the size
of the project, we believe that not only the producers
will have a role in it, but there will be other
parties that are needed to also make this project a
success and take on the substantial risk that it
presents. We need to maximize economic opportunities
for Alaskans and continental North America - I put a
couple examples, such as steel supply and local labor.
We'll get into a little bit of perhaps some of the
benefits that a 36-inch line might mean to North
America and Alaska versus the alternatives. Investing
resources into local communities and First Nations
groups is something we've done in the past with all of
our projects. The last point is fully leveraging
existing infrastructure only to the extent that it
reduces costs, minimizes tolls, and maximizes netbacks
for Alaska gas.
During the last hearing we presented on the supply
outlook within the Western Canadian supply basin and
how it was starting to ramp down after 2015 and what
the available ex-Alberta hub take-away capacity looked
like. We do want to make sure that we reiterate that
while generally an existing pipeline could be a cost-
effective alternative, depending on where the gas is
delivered and a number of other factors that may not
be the most cost-effective, it could call for a new
build as well.
Ultimately, the state and shippers are interested in a
pipeline that's designed to offer the lowest cost of
delivery - whether that's 36 inch or 52 inch. In order
to achieve this, we need to understand a number of
factors that impact the design capacity and ultimately
the cost of delivery. So we've heard a fair bit today
about open season contract commitments. Inevitably,
the project needs to be underpinned by these long-term
shipping contracts and with that, from this process,
that's going to really decide what the volumes look
like and what the contract length is going to look
like and where the gas actually needs to move to. And
from that, we're going to be able to tell what the
best design and what the most economic design looks
like. And you've heard lots before what the rest
includes. Really, it's driving out what the
expectation level of unproven reserves are going to
look like into the future, what people believe the gas
price is going to look like....
One thing we haven't talked about a lot is where the
market is for the gas as well. Is it all in Chicago?
Is it in the Northeast U.S. or is it even in
California as well? It's going to play a role. We've
also spent a lot of time talking about expansion as
well, so we believe that exploration success will
drive out the expansion volumes and the timing beyond
the initially accepted risk. So whatever the market is
going to accept initially, I think is going to be
representative of what they believe can actually be
delivered and then expansion beyond that, depending on
how successful, how much investment is made into the
state in refining resources and start to drive that
expansion. Obviously, as an independent party, from
our own selfish perspective, we'd always be looking at
trying to add capacity for shippers as long as it's
underpinned by a contract.
And the other element that goes with that is the take-
away capacity that is actually available from Alberta.
Obviously we can talk about moving all of these
volumes into the Alberta market, but Alberta is a
large net export market, therefore we need the
capacity to actually move the gas out of Alberta as
well. Based on when we move that gas and how much of
it we move, it directly impacts the economics as well,
whether we're able to use existing pipeline, where
that gas is going, and how much gas we can actually
send out.
And then construction factors - how will the
construction costs be impacted by competitive supply
if this project is, let's say, delayed or it's really
the MacKenzie Valley - what is the labor availability
going to look like? Will there be competition?
So let me just mention, the most important note, and
we've heard it several times today, is that
regardless, the pipeline needs to be underpinned by a
long term shipping contract. Enbridge is currently
working with certain parties within the market,
including our own distribution. We try to align and
see what the feel is for the demand and where that
demand might be and what the overall commitment might
be as well. But, once again, that might get fleshed
out until the open season occurs.
The length and volume of the shipping contracts, as
we've discussed, are impacted by such things as
expected wellhead price, tolls, reserve life and
government relations. Inevitably, if we get into what
drives the volume's timing and design capacity has to
do with our expectation of the reserve...
What I've done is taken three different examples -
practical examples of the potential reserves that the
market may expect and how that flushes out volumes
over service life. If you actually look at what we're
getting or expect or the proven out of Prudhoe Bay and
take the volumes over the different service lives, we
see that it ranges anywhere from 2 to 3.3 [BCF]. Based
on the economics we've run, this drives preferably
towards a dual 36-inch pipeline would actually provide
you with the lowest toll. More reasonably, we're not
going to be looking at just the 24. We've talked a lot
about the 35 area and here we've got a range of the
2.7 to 4.8 [BCF]. This is where you get into a
situation where the economics actually start to
transition as you move up anywhere from a 36
potentially to the 52 inch line. If you actually get
beyond the 35 TCF, and how much risk the market is
willing to take, beyond what's proven into the realm
of the probable, we're looking at volumes in excess of
potentially 5.6 to 9.7, which really goes back to what
was said earlier. If we're delivering all that up
front, a 52-inch pipe is most likely the economic
solution.
TAPE 04-15, SIDE B
MR. WATSON continued.
If you've got a ramp-up that exceeds - and we did it
on the basis of 5.2 BCF starting at 2.6 - as per our
application, you actually ramp that up over a course
of four years or more - once again the dual 36 inch
pipeline from an economic perspective looks more
attractive than the 52. So it all goes back to the
same things you've been hearing earlier. If we send
bigger volumes and we send them earlier, economically
you're looking at a 48 or 52-inch option. If we're
going through a phased ramp-up, or if we're starting
at smaller volumes, the 36-inch becomes more
practical.
CHAIR OGAN asked if Enbridge would build both pipelines
simultaneously.
MR. WATSON said if he is referring to dual 36-inch pipelines,
the model Enbridge used had the [second pipeline] starting two
years later but that will depend on the market commitment. He
stated:
So when we actually modeled it, let's say on the 52 or
48 inch basis, you'd put in all the pipe but you'd
only put in enough compression that you need to start
at 2.6 and then you ramp the compression up. Obviously
you're not going to just - with the line you've got to
put the whole line in first. With the 36-inch option,
you build the first line and then after you're done,
the first line you actually start to go through the
construction of the next line using the same right-of-
way. What that does...is it actually enables you to
actually get gas to market...about one year earlier.
If you use the 36-inch, you're going to get less
volume to market earlier, but you're actually going to
get gas to market earlier and to the extent that it's
a benefit, it's going to potentially prolong the
construction period as well, which is going to be more
revenue for a sustained period on the construction
phase within the state of Alaska.
As we talked about earlier, one thing we obviously
need to do is we need to align it with not necessarily
available ex-Alberta take away capacity, but we need
to understand what the actual take away capacity looks
like and where we're actually shipping the gas to. If
you kind of implant the supply forecast versus what's
available out of the Alberta market right now, and the
right graph there really extrapolates from the left
graph, it shows us when and how much take-away
capacity is available within Alberta - and you'll see
here that up until around 2018, 2019, it's less than
the 5 BCF we're talking about. So what that means is
we're going to need to add new capacity out of Alberta
into specific markets - Chicago, it could be west. It
shows us when and how much take-away capacity is
available within Alberta and you'll see here that up
until around 2018, 2019, it's less than the 5 BCF
we're talking about.
So what that means is we're going to need to add new
capacity out of Alberta into specific markets. It
could be Chicago, it could be west - it's either going
to go one of two ways but regardless, we're going to
need to add new capacity if we're shipping those
volumes when we're expected to actually commercialize
gas within Alaska within the 2012 to 2014 timeframe.
The question becomes is it worth phasing it in,
starting with, let's say, 2.5 BCF per day, knowing
that you've got the ex-Alberta capacity available
there. You can use existing pipe and then ramp up the
volumes, either through compression or through the
construction of another 36-inch line, so that you
start to match the available take-away capacity and
which one of those is cheaper. We don't know that
because you don't know - we've got an idea where the
market is for the gas, but until the open season
happens, until you know what the volume commitments
are like, until you know where you actually want the
gas delivered, we don't also know from the ex-Alberta
perspective where we need to get that gas.
So, in the event that the MPS 36-inch pipe does make
sense and that we're starting with lower volumes and
ramping up over time, some of the advantages of the
36-inch line, one is the greater certainty around the
cost estimates that we have. There are a number of
companies within North America right now that
manufacture 36-inch. There are none that actually
manufacture 48 or 52-inch pipelines within North
America so there's a greater supply risk around the 48
or the 52- inch option.
A big benefit potentially to the state is that we're
in service one year earlier so you're making revenues
one year earlier as well. It's easier to perform
maintenance without service interruption. You're going
to find a more experienced and skilled labor force
that's actually worked with the construction. The big
bang here as well is...more supplies can be sourced
from Canada and the U.S. versus overseas. We're just
going to have a more positive impact on the North
American economy, and potentially within Alaska as
well. We're going to be able to keep more of the
revenue within the state and in the construction
process as well, versus having to go over to Japan or
Germany or Russia.
One of the disadvantages that we talked about is
really just the reduced economy of scale if you're
able to bring on higher volumes right away.
So...just to wrap up some of the key points here...is
that one, and we've heard it all today, is that the
open season volume commitments and ramp-up timing will
drive the most economic pipeline design and we don't
know what that looks like yet. The Alaska to Alberta
volumes and timing need to be matched with the lowest
cost Alberta to market take-away capacity and, as I
mentioned, that may mean existing pipeline or that
could be new pipeline. Alliance Pipeline, which
Enbridge has a 50 percent ownership in, for example,
has .5 BCF of cheap expansion - the cheapest expansion
available into the Chicago market through compression.
Other than that, we need to look at a new build out of
the Alberta market, whether it's through TransCanada,
through Northern Border, or through other options.
So our measured approach is - it's not a phased
approach, we're really just aiming to align the Alaska
volumes, whatever they are, whatever the market's
willing to step up to, what they're willing to take as
far as risk and provide, either, you know, through an
existing or for optimal cost efficiency and market
alignment....
SENATOR WAGONER asked what would happen to Enbridge's interest
in this project if, in fact, the gas liquids were stripped out
in Fairbanks and shipped down the TransAlaska pipeline to be
used for other industries.
MR. WATSON said that would not have any impact on Enbridge's
decision in the project. He noted, "It's really what's best for
the producers, where they're going to get - and the state
itself, or the gas owners, wherever they're going to get the
best netbacks, I think there potentially could be some
resistance from the Province of Alberta itself...." He said
whether it is moved into the Alberta market or not will have no
bearing on whether it's good or bad for Enbridge. He continued:
So if Alaska wants to build a petrochemical industry
up here and the gas and the liquids need to be left
within the state, that's fine, or, if the producers in
the state feel that liquids need to go into the
Province, certainly the infrastructure exists there to
handle the liquids.
SENATOR ELTON asked Mr. Watson to discuss the tension between
access and capacity and those with the proven reserves and those
who may be more dependent on undiscovered resources with a 36-
inch pipe. He asked what happens with a smaller pipeline
transmission system.
MR. WATSON said he does not see a smaller pipeline making it
more challenging to get access. Initially there would be less
access because of the smaller design capacity but the plans
could allow for a ramp up to 5.2 over the course of 3 to 4
years, so that capacity would become available at the same time
as a 52-inch line.
SENATOR ELTON said during testimony by Department of Revenue
staff, members learned they may need to have a discussion on
smaller amounts of gas moving over a longer period of time. It
would seem easier, during an open season for those with reserves
but less capacity to have it easier than those without, because
if capacity is increased over time, that would make it more
difficult for explorers who have to wait.
MR. WATSON said Senator Elton hit the nail on the head when he
said the producers or shippers themselves would decide during
the initial open season because:
You hit a crossover there where the 52-inch line
becomes a more economical choice. It really depends
what the market's willing to step up to initially so
you don't go into the open season and say, okay, we're
proposing a dual 36-inch pipeline. The market comes to
the open season and [you] say, okay, here's the gas we
need within the Lower 48 and then you take that away
and say okay, what's the most economical pipeline
design.... So, to that extent, that's where we're
coming with the measured approach, is that we need to
come in with an understanding of what the market
needs, what volumes they need and really where they
need it as well. Obviously, it's not going to impact
the design from Alberta or [indisc.] from Alaska to
Alberta but also what needs to happen from Alberta to
market as well.
CHAIR OGAN expressed concern about the disadvantages of higher
capital costs, which will translate into higher tariffs, and
questioned whether Enbridge has run any models on the
differences.
MR. WATSON said Enbridge has and [the answer] depends on the
volumes. As you start to shift into lower volumes, that's where
the 36-inch will come up with a smaller capital cost because an
asset will be buried in the ground that is not being utilized.
The other consideration is the ramp-up time. It gets back to the
open season and matching a design that produces the lowest toll
for what's needed in the marketplace. That is why Enbridge is
not saying the 36-inch pipe is the most economic; other
alternatives may be more economic, depending on what the market
needs. He pointed out:
And from our numbers, once you get... over 4 BCF a
day, if you can take that initially, and that's what
the market is willing to accept, that's kind of the
crossover where it becomes more economic to look at
the larger line. If the market's stepping up for less
initially, you've got kind of two factors. If they're
stepping up for a lot less for a long period of time,
the dual 36-inch is more economic. If they're stepping
up for less initially and you've got a ramp-up that
occurs over a period of four more years, the numbers
we used were 2.6 up to 5.2 over the course of four
years, you're pretty much at a break even as far as
the tolls that work out. So, a 48 or 52-inch option
would come up with about the same toll as a 36. A lot
has to do with being able to bring the capacity to
market a year earlier and some of the economic factors
and depreciation as well.
REPRESENTATIVE GARA said it seems counter-intuitive to him that
if Enbridge plans to build two 36-inch pipes, that it would be
as efficient to come up and down the corridor with a crew of
workers twice. He asked Mr. Watson to give an estimate of the
production costs of the dual 36-inch pipe and one 48-inch pipe.
He then said that many people want to be able to tap into the
pipeline to use some of that gas, but Mr. Watson said that would
not impact Enbridge. He questioned how that could not but impact
Enbridge since it would create less capacity after the tap-in
point.
MR. WATSON responded, in regard to Representative Gara's first
question, Enbridge has estimated the cost of construction at
$1.3 billion more to build the dual 36-inch pipe versus the 48-
inch option. He noted from a total capital cost in-the-ground
perspective, it might cost a little more, but there would be
less risk. Regarding the second question, he said his point is
it is the same issue for Enbridge as a pipeline company as it
would be for any other. If gas was taken out of the system at
Fairbanks, that would definitely have an impact on the total
system, but he can't answer what the industry would plan to do
to make concessions for that.
CO-CHAIR OGAN asked if it would be a matter of stationing the
compressors a little farther apart after Fairbanks.
MR. WATSON said a number of things could be done but that he is
not in a position to say what the best alternative would be.
REPRESENTATIVE BETH KERTTULA asked if the dual pipelines would
require two open seasons and two tariffs.
MR. WATSON replied there would be one open season - the dual
pipeline would be a design element that would entail looping the
line. He explained,
Now it depends, if it's not part of the initial open
season for the commitment, then yes, if it was labeled
expansion, you'd certainly have to go back, but I
think the intent would be to include it. If you don't
need the 5.2 BCF a day right now, but you need it in
the four years, you may apply saying okay, this is all
part of it. We're building from 2.6 up to 5 and it's
going to take four to five years longer to build it so
you make that all part of the initial commitment....
REPRESENTATIVE KERTTULA said she understands the arguments but
it seems that right from the beginning, it undersells Alaska's
resource. She explained that she understands the market but it
makes her nervous because Alaska's best interest is to get the
gas up and to the market.
MR. WATSON said it is not the pipeline company that decides what
the reserves are and what the market is willing to take. They
are trying to get more commitment. Building bigger and sooner is
a benefit to his company.
We just want to present that as a potential economic
alternative, if the case happens that the market only
steps up for this or you need a phased approach -
because we also need to look at the economics, as well
as what the tolls look like, not only from Alaska to
Alberta, but what the tolls look like from Alberta to
the market, as well. If we can use existing pipelines
and fill existing pipes, it could reduce tolls or
tariffs from Alberta to Chicago by, who knows, maybe
five or ten cents.... This is just one potential
option.
MS. MARTY RUTHERFORD, Deputy Commissioner, Department of Natural
Resources (DNR), said her presentation addresses both the
regulatory and commercial tools available to the state to
improve access to pipeline capacity, including expansion
capacity. She would discuss the Stranded Gas Development Act as
a key commercial tool giving the state the ability to negotiate
conditions for access along with other contract terms.
Another key tool are the oil and gas lease provisions,
specifically the state's ability to take its royalty
either in value or in kind and our discretion to
switch between these periodically.
On the regulatory front, the state has the opportunity
to influence other policy makers, both the regulatory
and the legislative arms, including Ottawa, Canada and
Washington D.C., also the U.S. Federal Energy
Regulatory Commission (FERC), Canada's National Energy
Board (NEB), which is an independent federal agency in
Canada that regulates several aspects of Canada's
energy industry and the Regulatory Commission of
Alaska (RCA). My comments are organized around the
structure of relationships, specifically, government
to industry, government to agency and government to
government.
So, let me begin with the first category, which is
government to industry. I might note here that the
first category will take the bulk of my time, the
second and third categories will be pretty brief....
As I said previously, and other parties like Bob
Loeffler from Morrison and Forester has said,
negotiations under the Stranded Gas Development Act do
provide significant commercial tools that could, not
necessarily should, include scheduled open seasons for
expansion with, of course, very specific terms that
are fair to all parties. I want to note here, and I
think that Bob Loeffler noted it as well, that
scheduled open seasons are not standard FERC
practices. Another potential Stranded Gas Development
Act tool is our ability to require pipeline design
specifications that are favorable for expansions. For
example, the initial design should allow for efficient
expansion. It should be preplumbed for intake, off-
take and expansion points. These could include:
1) An intake in the Foothills in order to by-pass the
Prudhoe Bay Unit gas treatment plant
2) An intake at Fairbanks for the Nenana and Yukon
Flats Basin development when it occurs as well as
an off-take at Fairbanks for several possible
purposes, including various spur lines, such as to
Valdez in the Cook Inlet, for petrochemicals and
for rural Alaska. I believe that ANGDA has probably
talked about some of the ideas that group is
discussing for providing rural Alaska energy such
as propane shipped in tanks or barges to rural
Alaska and compressed natural gas
3) Future compression stations for expansion purposes
4) Intakes for other gas basins, such as Susitna and
the Copper River Basin.
In addition to requiring open seasons for expansion
and design specs, the state could consider ensuring
through the Stranded Gas Development negotiations,
tariff structures that are favorable to the entry of
new gas. There are known devices that could
assist...rolled-in tariffs, for example, for both
expansion of the main line and for feeder pipelines.
Rolled-in tolls for expansion means that the cost of
expansion are rolled into the existing base rates.
Then, even if the expansion is expensive, the overall
tolls only increase modestly. The effect of this is to
promote exploration and development of new gas. This
is Canada's National Energy Board policy, but not the
usual U.S. FERC policy. FERC's policy provides that
expensive expansion costs are assigned to only those
parties who will use the new capacity, in other words,
the new guy on the block.
When this same rolled-in tolls approach is extended to
new feeder pipelines, such as at National Petroleum
Reserve Alaska (NPRA), and they are treated as an
expansion of the existing main project, then the cost
of bringing new gas to market will also be reduced.
Here again, the effect is to promote exploration of
new gas. Canada has, in one circumstance that we are
aware of, adopted such a policy as this.
Conversely, an incremental tariff structure, which is
the normal approach that FERC assigns to extensions,
and to expensive expansions, is to assign costs to
only those parties who will be using the new capacity.
I want to emphasize that both of these rolled-in toll
approaches could be a very difficult exercise to sell
to FERC, because it is outside their normal policy and
they must approve all tariffs including negotiated
tariffs.
Another example of a tariff structure that could favor
entry of new gas into expansion capacity is a
negotiated levelized tariff rate. The use of a
levelized tariff allows any producers lower costs in
the early years, maintaining this rate over time. This
may improve exploration and development economics.
Conversely, a recourse rate will start off high and it
may be reduced if shippers successfully request lower
tolls with FERC.
One additional point here on tariffs, one means of
improving the use of a recourse rate might be regular
updates of that rate. As you heard at your last
hearing and today, again, the FERC hasn't been
exercising authority under the Natural Gas Act to
require a pipeline company to periodically file new
rates. A shipper can protest rates, but relief is
provided only prospectively, not retrospectively. As a
result, recourse rates paid by shippers on a pipeline
such as this one can often be too high. As well, there
is some incentive for pipeline companies to prolong
litigation. However, if the pipeline company were
contractually required to periodically file new rates
with the FERC, then much of this problem might be
resolved.
The final point I want to make under tariff structures
is that it might be appropriate for the conditioning
plant rates to also be reasonable and transparent.
Again, this could be accomplished either by
negotiations or by making them subject to a rate-
making process.
Moving away from the Stranded Gas Development Act,
another key tool available to the state is the oil and
gas lease provision. That provides the state its
ability to take its gas either in value (RIV) or in
kind (RIK) and our discretion to switch periodically.
This tool could be used to promote explorer access to
early open season. This term of the state's lease
could be used to backstop explorer commitments to
initial pipeline capacity and this was the concept
that DNR invented in the proposed RIK gas sales to
Anadarko and EnCana [USA, Inc.] in 2002. That was
never moved forward for legislative approval or even a
royalty board approval, but we did send it out for RFP
and EnCana and Anadarko did win that. This could allow
explorers to ensure they have the necessary gas
available to fill an open season commitment if there
is insufficient time to explore and develop their own
lease acreage prior to open season. In the interests
of full disclosure here, I want to note that this
proposed RIK gas sale in 2002 was endorsed by
independent explorers and opposed by the producer
sponsor group.
The last two items I would like to briefly note under
the government to industry category are the state's
right-of-way leasing provisions. It is conceivable for
the state to condition a state pipeline right-of-way
approval on reasonable access provisions and we could
encourage the federal government to do the same with
their federal rights-of-way. I must note that we have
not so conditioned any right-of-way such as this to
date.
And finally, using our oil and gas lease terms, it is
also conceivable that we could develop provisions in
new leases that require facility sharing and pipeline
access, but again that would be prospectively, not for
existing leases.
So, moving on to my second category of tools, or what
I call government to agency, the first of these are
the state administration's existing ability to provide
input to FERC on rate cases. This is an opportunity
that the state may avail itself of currently. It
provides no surety that that input is welcomed by the
FERC and as Bob Loeffler mentioned a little bit ago,
under the yet to be adopted U.S. federal energy
legislation, that legislation provides that open
season regulations shall (mandatory) be promulgated by
FERC and, of course, the state will have the
opportunity to affect those regulations to our
benefit. That legislation provides capacity expansion
regulations may (this is discretionary) be promulgated
and it might be possible to encourage FERC to
promulgate these optional regs and if they do to try
to affect that package of regulations to the state's
benefit.
The final issue that I might note in this area, and
I've never discussed it with Morrison and Forester,
but that would be to approach FERC regarding open
season regulations in advance of U.S. federal energy
legislation. If the legislation passed this fall or
early next spring, it might not be necessary, but if
it does not, it is something that I think the state
might pursue.
Another tool available to the state under government
to agency category is the Regulatory Commission of
Alaska's influence with FERC. Under the existing
Natural Gas Act, the FERC may establish a FERC/RCA
joint board for consultation purposes. While this is
currently an option under the Natural Gas Act, it
becomes a mandate under the proposed federal energy
legislation and we have successfully used this device
in the past on at least one tariff structure on the
Alpine pipeline, I believe.
Finally, I think it's appropriate to reiterate the
obvious. A tool available to the state is to maintain
our options for all gasline projects. This includes
LNG, the natural gas pipeline into or through Canada
and other pipelines within Alaska.
My final category is what I refer to as government to
government. Briefly, this category includes the
state's influence on the federal energy legislation
provisions that support access. This influences has
been and continues to be, until passage, extremely
important. Finally, the state has begun to develop
relationships with Canada to encourage favorable
outcomes for design and access of a Canadian portion
of the natural gas pipeline. This can be pursued both
on a federal level in both the U.S. and Canada as well
as in the Canadian provinces and with the First Nation
Tribal entities.
In closing, while I've identified a whole suite of
tools the state has available to it, I also believe
there are a limited number of truly effective tools
that are under the state's direct control. You'll note
I spent more time focusing on the Stranded Gas
Development Act negotiations and the RIK/RIV switching
option because I believe these offer the greatest
leverage to the state. Therefore, it is important that
the state has full knowledge of what they're worth.
That completes my testimony.
SENATOR ELTON asked if the state can condition right-of-way
approval on reasonable access provisions.
MS. RUTHERFORD replied, "I believe that is a possibility, yes."
SENATOR ELTON said that seemed to be a rather bold intrusion
into something FERC has control over. "Would FERC have to
endorse any provisions that were contractually agreed on in a
right-of-way contract?"
MS. RUTHERFORD answered:
FERC has to approve of tariffs, no matter whether they
are negotiated or not. I know they have policies on
open seasons; I don't think they have regulations on
open seasons. I believe they would probably be open to
a negotiated agreement on open seasons for expansion
purposes.
SENATOR ELTON asked if that was included under right-of-way
agreements.
MS. RUTHERFORD responded, "Well no; I think that would be under
the Stranded Gas Development Act negotiations."
CO-CHAIR OGAN plugged the up-coming September Energy Council
meeting in Anchorage with Alberta and British Columbia attending
as official first-time members.
We literally run coast to coast from Canada now - Nova
Scotia and Newfoundland to British Columbia. So, it's
a good opportunity to get to know some of our Canadian
friends and help keep those relationships going.
He thought a pipeline would provide better opportunities for
creating long-term jobs once it was built and gas had gone down
it.
MS. RUTHERFORD agreed that a lot of jobs in the future would be
associated with looking for new gas and trying to fill the
pipeline. "Based upon what USGS said earlier today and in which
DNR concurs, that we feel there are significant undiscovered
resources, more than adequate to fill expansion capacity."
CO-CHAIR OGAN said the AOGCC regulates the waste of hydrocarbons
and DNR deals more with the economic waste issues and asked if
she has the statutory authority to insure the state has no
economic waste.
MS. RUTHERFORD replied, "We believe we do, Senator."
CO-CHAIR OGAN said there were no further questions and adjourned
the meeting at 4:05 p.m.
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