Legislature(2003 - 2004)
09/01/2004 10:03 AM Senate RES
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
JOINT MEETING
JOINT COMMITTEE ON LEGISLATIVE BUDGET AND AUDIT
SENATE RESOURCES STANDING COMMITTEE
September 1, 2004
10:03 a.m.
MEMBERS PRESENT
LEGISLATIVE BUDGET AND AUDIT
Representative Ralph Samuels, Chair
Representative Mike Chenault
Representative Mike Hawker
Representative Beth Kerttula (via teleconference)
Representative Reggie Joule, alternate
Senator Gene Therriault, Vice Chair
Senator Lyman Hoffman
SENATE RESOURCES
Senator Fred Dyson
Senator Ralph Seekins
Senator Kim Elton (via teleconference)
Senator Georgianna Lincoln (via teleconference)
MEMBERS ABSENT
LEGISLATIVE BUDGET AND AUDIT
Representative Vic Kohring
Senator Ben Stevens
Senator Con Bunde
Senator Gary Wilken
Senator Lyda Green, alternate
SENATE RESOURCES
Senator Tom Wagoner, Vice Chair
Senator Ben Stevens
OTHER LEGISLATORS PRESENT
Representative Norman Rokeberg
Representative Paul Seaton (via teleconference)
Representative Bill Stoltze
Representative Les Gara
Representative Bruce Weyhrauch
Representative Ethan Berkowitz
Representative Harry Crawford
Representative Eric Croft
Representative David Guttenberg (via teleconference)
Senator Hollis French
Senator Gretchen Guess
COMMITTEE CALENDAR
^OVERSIGHT ON ALASKA NATURAL GAS PIPELINE ISSUES
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
Presentations by:
JEFF BROWN, Managing Director
Merrill Lynch
BRYAN HASSLER, Executive Director
Wyoming Natural Gas Pipeline Authority (WPA)
GEOFF URBINA
George K. Baum and Company
MARTIN MASSEY, Joint Interest Manager US
ExxonMobil Production Company
ExxonMobil Corporation
RICHARD GUERRANT, Vice President Americas
ExxonMobil Gas & Power Marketing Company
ExxonMobil Corporation
JOHN CARRUTHERS, Vice President
Upstream Development
Enbridge Pipelines, Inc.
TONY PALMER, Vice President
Alaska Business Development
TransCanada Corporation
EDWARD M. KELLY, Vice President
North American Natural Gas and Power
Wood Mackenzie
RICHARD BONE, Director
State Energy Marketing Program
Texas General Land Office
KEVIN BANKS, Commercial Section
Central Office
Division of Oil & Gas
Department of Natural Resources (DNR)
ACTION NARRATIVE
TAPE 04-20, SIDE A [BUD TAPE]
Number 001
CHAIR RALPH SAMUELS called the joint meeting of the Joint
Committee on Legislative Budget and Audit and the Senate
Resources Standing Committee to order at 10:03 a.m.
Representatives Samuels, Chenault, Hawker, Kerttula (via
teleconference), and Joule and Senators Therriault, Hoffman,
Dyson, Seekins, Elton (via teleconference), and Lincoln (via
teleconference) were present at the call to order. Other
legislators in attendance were Representatives Gara, Rokeberg,
Seaton, Stoltze, Weyhrauch, Berkowitz, Crawford, Croft, and
Guttenberg and Senators French and Guess.
CHAIR SAMUELS reviewed Mr. Brown's background in fixed income
investment banking. He noted that Mr. Brown is a consultant to
Alaska's Department of Revenue, Department of Natural Resources,
and Department of Law with regard to financing alternatives for
a gas pipeline.
Number 010
JEFF BROWN, Managing Director, Merrill Lynch, turned attention
to his written remarks that were included in the committee
packet. He paraphrased from the following written testimony
[original punctuation provided]:
nAlaska is a Petro-State with stranded gas. Forget
comparisons to other U.S. states. Look at "Petro-
States" like Qatar or Indonesia.
nGovernment stranded gas owners sometimes take a
measured amount of risk to jump start desirable
projects.
nBuying 100% of the gas at a fixed price and either (i)
committing to ship-or-pay contracts for 100% (on
someone else's pipeline) or (ii) financing 100% of
pipeline would be one option-but it involves a lot of
risk that would have to be carefully managed.
nCommitting to financing an amount of pipeline capacity
that corresponds to the State's working interest in
the gas seems manageable from a credit and economic
perspective.
nThere are lots of different ownership structures and
different kinds of bonds that can be used. Big
differences revolve around tax-exemption and ability
to shield the State from risk.
nThere are many ways to limit worst possible losses
from such an investment, while preserving the fiscal
upside.
MR. BROWN said that he would go through the risks and rewards
from the option of the state owning all of the pipeline to
owning a portion of the pipeline as well as the various
structures by which the aforementioned could occur. He noted
that he isn't going to provide any legal conclusions, but rather
would address [financing] and manageability of economic risks.
He then turned to the topic of what other state's have done and
paraphrased from the following written testimony [original
punctuation provided]:
nNo State in the Lower 48 has sold billions of dollars
of debt to buy/build an international gas pipeline
nBut U.S. States have not shied away from big
infrastructure projects when necessary:
nWyoming Natural Gas Pipeline Authority--$1 billion
bond authorization to increase gas transmission out of
the Rockies (ML is lead manager for this program, and
its Executive Director will testify next)
nNew York State started Long Island Power Authority to
run electric operations in Long Island when LILCO was
going bankrupt (about $8 billion of debt)
nCalifornia Department of Water Resources has spent $5
billion to transmit water from the wet north to the
desert south
nAt the end of the day no other state remotely
resembles Alaska
MR. BROWN addressed the difference between oil and stranded gas
by paraphrasing from the following written testimony [original
punctuation provided]:
nEvery nation or province that has oil and gas extracts
taxes and royalties. Typically a producer pays for
100% of the capital to extract the resource and the
Petro-State puts in zero capital.
nOther than in the U.S. and other countries with big
domestic pipeline systems, gas becomes stranded
because of the enormous fixed, inflexible cost of
building an international pipeline or LNG facilities.
Producers are reluctant to take all of the risk when
they only own part of the gas (i.e., gross production
less royalty and tax).
nPetro-States end up investing capital in the pipeline
or LNG because otherwise they get zero value for their
resource.
MR. BROWN turned to the West Natuna Pipeline and paraphrased
from the following written testimony [original punctuation
provided]:
nPertamina (Indonesia's oil company) leased blocks of
West Natuna to Conoco, Gulf Indonesia and Premier.
nThe three production-sharing contractors, acting as
the West Natuna Group, partnered with Pertamina
(Indonesian state oil company) to build [the] 656 km
West Natuna Transportation System, with ultimate
capacity of 1 BCFD
nThe total pipeline cost was reported to be $1.2-$1.5
billion. Reportedly, the Government of Indonesia's
investment was $400 million relating to PGN (state gas
company) construction of pipeline infrastructure from
Grisik to Singapore.
MR. BROWN highlighted that as a consequence of obtaining the
[West Natuna Pipeline], the gas is shipped directly into
Singapore, which uses the gas to fuel industry needs and power
generation in Singapore. Therefore, the gas was near valueless,
except [Indonesia] created a long-term pipeline that enabled
[Indonesia] to enter into long-term, fixed-volume contracts with
Singapore. However, Indonesia put up the money to "unstrand"
its gas. A similar situation exists in the Middle East with
Qatar, which has a large field. The production in Qatar was
handed off to the Ras Laffan company. The Qatar General
Petroleum Corporation (QGPC) put up approximately 66.5 percent
of the equity, and ExxonMobil Corporation put up the bulk of the
remaining equity. Together that entity borrowed money to build
a couple of LNG [liquefied natural gas] trains to "squish the
gas down into a product." That entity entered into long-term
contracts for volume with the Japanese and the Koreans.
MR. BROWN drew attention to page 7 of his written testimony and
referred to the box specifying "KOREA & JAPAN". Japan and Korea
committed to volumes rather than price, he reiterated. In this
arrangement, the price, commonly referred to as the "Japan crude
cocktail," is [approximately] the price of oil divided by six
per thousand cubic feet (mcf). Therefore, the price in this
arrangement bounces around. If oil prices go below $12,
approximately $2 [per] mcf, the transportation and manufacturing
process is below the breakeven point. Mr. Brown clarified:
"Not only did the government step up and put in money, but ...
put money up as equity in this project where they took commodity
risk; in other words, their investment would be valueless if the
price of oil stayed at $9 a barrel for five years."
MR. BROWN pointed out that both the Indonesia and Qatar example
raise the following questions: How deep are your pockets and
how big is the risk? In discussing the aforementioned issues he
paraphrased from the following written testimony [original
punctuation provided]:
nHow deep are your pockets?
nThe total State unrestricted revenues are about $2 billion
per year
nRating agencies project "total available for appropriation"
of $3.5 billion in 2010
nAlaska's pockets get deeper if gas successfully
commercialized
MR. BROWN explained that the Department of Revenue's bond book
discusses state debt service and capacity being related to a
percentage of unrestricted revenues. The bond book says that it
has typically bounced around 5-7 percent. Therefore, if the
revenues are doubled from a successful gas commercialization,
the state's pockets get deeper. He then turned to the issue
regarding the size of the risk and paraphrased from the
following written testimony [original punctuation provided]:
nHow big is the risk? That depends on how big of a share
you take of the whole enterprise and for any particular
share:
nHow much financing risk you lay off on other participants
through non-recourse debt
nHow much construction risk is laid off through pre-
engineering, fixed price contracts, insurance, completion
guarantees, etc.
nHow much commodity price risk you lay off on other
participants through hedging, fixed price sales
contracts, variable gas purchase contracts, etc.
MR. BROWN specified that the total risk of something that looked
really large and risky could be tempered through the financing,
construction, and commodity price. He then posed an example in
which the state takes all of the risk in a situation in which
there is a really large amount of risk. He clarified that the
following is merely an analysis to give the committees an idea,
not a proposal. He reviewed the following from his written
testimony [original punctuation provided]:
ŒPretend producers would sell gas to State for $1
(fixed price) at North Slope. You sign a 20 year Gas
Purchase Agreement with them
ŒPretend a well-reputed pipeline company will build a
pipeline, with $2 tariff. You sign a 20 year Ship-or-
Pay Contract
ŒPretend you know for sure that over the next two
decades there will be: 15 years when the price in
Chicago will be $6, 5 years when the price will be
$1.50. You just don't know in advance which years are
going to be the ugly years. You don't hedge and all
your contracts are for spot Chicago prices
ŒTwo bad years in a row (i.e., at $1.50 per MCF) loses
you $4.4 billion.
MR. BROWN concluded that either the state would have to be more
careful with regard to all the business deals along the line or
the state would need to consider doing something smaller. With
regard to doing something smaller, he explained that the state
could put up capital corresponding to the amount of the state's
present royalty interest in the North Slope gas. He provided
the specifics of a smaller scale investment as follows [original
punctuation provided with some formatting changes]:
nState Royalty Interest in gas produced on North Slope
is now approximately 1/8th. Equitable argument for
putting up 1/8th of the capital, if deal won't happen
otherwise. If the project costs $24 billion, 1/8th is
$3 billion.
nYou could take your royalty as Royalty-in-Value or
Royalty-in Kind. We'll discuss later that RIK makes
issuing tax-exempt bonds easier.
nIf you put up $3 billion (which gains you market
access for 500 million cf/d of State gas):
na lot (maybe 80%) could be in Revenue Bonds (of a new
State Agency or AKRR), where the State is not on the
hook
n20% remaining ($600 million) as State-supported
reimbursable debt (this means experts forecast that
project revenues will almost always carry the debt,
but the State is directly on the hook, in some fashion
if things go awry for a long period)
Number 256
MR. BROWN turned to the question of how large the $600 million
would be in the context of the overall picture. [The following
information can be viewed in a chart on page 11 of Mr. Brown's
written testimony.] Currently, there is about $359 [million] of
general obligation (GO) that is directly supported by the state,
excluding things such as GARVEE [Grant Anticipation Revenue
Vehicles] bonds. Additionally, the costs for school
reimbursement and state leases brings the total to about $1
billion. The state is contingently on the hook for bonds issued
by the bond bank or the Alaska Energy Authority (AEA) or the
Student Loan Authority, and the total debt reaches about $2
billion. Therefore, adding the $600 million would amount to
approximately a 30 percent increase, which, he opined, isn't a
ridiculously large increase in the total amount of securities
for which the state is directly on the hook.
MR. BROWN referred to page 12 of his written testimony entitled
"Drilling Down to Details on a 1/8th Investment Example," and to
page 13 which pertained to possible business structures. He
posed the following question: "If you only owned part of the
pipeline, how would you do it?" Clearly it would be "dumb," he
opined, to have two pipelines running in the same trench. In a
municipal and private partnership, a typical concept is the
undivided interest structure, which has been described
metaphorically as a pipe within a pipe. The undivided interest
structure is also known as a tenants-in-common structure, under
which the state would own 1/8th of every molecule of the entire
system. The undivided interest structure is common and provides
a physical asset that can be mortgaged, moved around, and sold.
Mr. Brown noted that there is also the option of a limited
liability corporation (LLC) in which the state would contribute
into the pipeline corporation an amount of money that purchases
the state's particular interest. He explained that the
aforementioned option is more like being a partner or
stockholder, in the entire venture, who raises the money
externally.
MR. BROWN turned to tax-exempt bonds. One of the reasons the
state may want to be involved is if the state can issue bonds at
5 percent, for example, and the typical Federal Energy
Regulatory Commission (FERC) regulated pipeline receives a
"weight average cost of capital" of 10 percent. The state's
money would be much cheaper, and if the state can finance with
cheap debt the portion of the capacity that carries the state's
gas, more money would return to the treasury. He specified,
"The money you get is price in Chicago minus transportation
cost," and so if the transportation costs are cheap due to cheap
capital, more money would be "net backed" to the state. He
provided the committee with a summary regarding what makes bonds
tax-exempt under federal law by paraphrasing from his written
remarks [original punctuation provided]:
nAt a bare minimum, to issue tax-exempt bonds the
Issuer has to be a government entity. A governmental
entity would need to own the pipe and use the pipe for
gas the State owns (RIK gas). That is, under ordinary
circumstances, you couldn't finance 100% of the
pipeline tax-exempt and then have the three producers
be the sole shippers under long-term ship-or-pay
contracts
CHAIR SAMUELS asked if the amount of the tax-exempt bond would
only be in the amount of the gas [the state] takes, or in [the
state's] ownership in the pipeline.
MR. BROWN explained that the amount of the tax-exempt bond would
be the amount that [the state] uses. He highlighted that for
utility properties such as gas pipelines, the IRS has many rules
with regard to what is permissible and not permissible when a
government owns utility property. The basic guidance provided
by the IRS is that an entity cannot sign "ship or pay" contracts
for the usage of the pipeline the entity owns. Furthermore,
when the physical gas arrives in Chicago, the transportation
costs are already imbedded in the price and thus the IRS doesn't
want an entity to sign a 20-year fixed-price contract with an
electric utility in Chicago. The aforementioned is viewed as
another way of paying for the pipeline capacity. He clarified
that [the state] can't do a long-term "ship or pay" contract for
the tax-exempt bond portion; [the state] would also be limited
to "sub three years" contracts with nongovernmental entities.
He noted that [the state] can do all it wants with governments
and, for as long is desired, [the state] can do what it wants
with industrial customers.
MR. BROWN emphasized that the state will have to review the
contracts for either shipment or purchase to determine whether
the state can go tax-exempt. He informed the committee that
included in the now-stalled energy bill in Congress is a
provision for $18 billion in federal guaranteed debt. If the
state otherwise qualified for municipal debt, but a federal
guarantee was placed on top of the bonds, the state couldn't go
tax-exempt with those. The aforementioned isn't necessarily a
bad problem because there really isn't much difference between
where the State of Alaska "tax-exempt AA" finances and where
financing occurs with a direct government guarantee from the
United States on a tax-free basis. The aforementioned is even
truer compared to a tax-exempt revenue bond, which would be
fairly expensive because of the risk. However, if a federal
guarantee is placed on it, it becomes significantly lower. He
pointed out that there is a provision in the tax code that seems
to allow the Alaska Railroad Corporation to issue tax-exempt
bonds without many of the aforementioned provisions applying.
CHAIR SAMUELS posed a situation in which the royalty in-value
(RIV) is taken, and asked if that eliminates the tax-exempt
status.
MR. BROWN explained that at that point, the entity that owns the
gas at the wellhead is ExxonMobil Corporation or BP Phillips
Alaska, Inc., and they are shipping their gas through the pipes,
and therefore there is no good reason to call it a tax-exempt
bond. He clarified that the aforementioned is what he has been
advised thus far.
Number 430
MR. BROWN, turning to page 15 of his written testimony, spoke to
the types of bonds available under Alaska law. He specified
that the GO bonds and a Certificate of Participation (COP) are
equivalent to the equity investment that Qatar and Indonesia
make in their pipelines. Theoretically, the aforementioned
would be accomplished through the proceeds of state GO bonds or
appropriation debt, such as the state currently uses to fund the
seafood and food safety laboratory. Both the GO bonds and the
appropriation debt have different requirements under state law.
One of the main requirements for a GO bond is that it must be a
capital improvement, which is subject to much interpretation in
Alaska. The key is that GO bonds would be the lowest cost at
about 4.25 percent tax-exempt.
MR. BROWN then moved on to revenue bonds of the pipeline project
for which the state isn't on the hook, which he estimated to be
approximately 5.25 percent today. For the project portion, the
state could issue revenue bonds with a "moral" obligation, such
as the state currently does with the bond bank. Using revenue
bonds with a moral obligation means that the bondholder has two
sources of money as follows: the source of money from the basic
revenues produced by the project, and a promise from the
governor that if the reserve funds are depleted, the governor
would ask the legislature to fill the reserve fund. Although
the aforementioned is a standard mechanism in Alaska, it
increases the ratings and lowers the cost.
MR. BROWN reminded the committee of the earlier-mentioned
example of the LNG project in Qatar for which, depending on the
variable prices for oil, one would either break even or not.
The same would apply for this project, he said. He then turned
to page 16 of his written testimony, which read [original
punctuation provided with some formatting changes]:
n4.1 BCFD delivered Chicago at 1080 Btu/cf
nTotal Project to Chicago = $24 Billion (inflated plus
capitalized interest). To AECO would be less.
nState Share = 1/8th or $3 billion
nFinance 80% with Revenue Bonds= $2.4 billion
nOf that $2.4 billion, $2.25 billion could be Federal
Guaranteed (being our share of $18 billion max as was
provided in last version of Energy Bill)
nSo another $150mm would be non-Guaranteed Tax-Exempt
Revenue Bonds
nThe balance of 20%=$600mm might be:
nGeneral Obligation Bonds (subject to various
restrictions), or
nAppropriation debt similar to C.O.P.'s
MR. BROWN, turning to page 17 of his written testimony, reviewed
the numbers for a bad year. He highlighted that the pie chart
exemplifies the debt structure, which is a total of $3 billion.
The flow chart on the right of page 17 begins based on the
assumption of a horrid price - $1.25 for gas in Chicago - in
order to create insufficient funds. The DNR would receive $1.25
in mcf multiplied by the state's share, which produces $253
million. After paying the operations costs, the revenue debt,
and the federal guaranteed revenue debt, only $18 million is in
the treasury. He pointed out that the debt service on
appropriation debt would be about $47 million. Therefore, from
a commercial point of view, the state will have to find money
from other sources in order to cover the appropriation debt. He
acknowledged that technically, the money is all going into the
general fund (GF) and commingling with other things.
MR. BROWN moved on to page 18 of his written testimony, which
reviews a good year in which excess money from selling gas is
large and available for other programs. He noted that these
figures use the prevailing gas price of $5.00. At that price,
the state would receive about $1 billion in revenues and the
same tariffs as in the bad years would need to be paid. After
paying for transportation expenses [revenue debt and the federal
guarantee], $47 million has to be paid out to cover the
appropriation debt. Therefore, $728 million is free and clear
and available to expend on other things. Mr. Brown said,
"Another way to say it is you could've actually just gotten rid
of all the debt in that year, all that appropriation debt."
MR. BROWN concluded by relating that Alaska is in a position
analogous to other countries that have stranded gas.
Furthermore, there is a maximum ceiling with regard to the
amount of risk that can be taken that's not laid off in terms of
project financing. Moreover, it's clear that there are many
alternatives by which the state could reasonably finance an
investment such as this. He noted that the central forecast
case is somewhere around the $3.50 price point in Chicago for
the time period of 2012. Mr. Brown said, "To me, the good end
... of the distribution of prices looks pretty lovely and the
bad end does not look to me like it would sink you in a year.
... So, to me, as a finance guy, I see nothing wrong with
continuing to explore this."
Number 589
SENATOR ELTON related his understanding that the state will
incur debt costs prior to operations and the potential of
profit. Therefore, he requested that Mr. Brown discuss the
aforementioned gap and how much it will take to carry the state
until operations begin and profits may or may not materialize.
MR. BROWN answered that's probably a matter that can be
negotiated between the state and the producers. Mr. Brown
recalled that in the public and private project financings that
he has worked on, the private entity often has more access to
the early capital.
SENATOR SEEKINS referred to Mr. Brown's scenario in which the
state would have actual ownership interest in the physical
pipeline. Senator Seekins noted that the FERC will allow up to
a 14 percent return on the investment in the tariff and he
surmised that the state would share in that return. He asked if
that has been "netted out" in these numbers.
MR. BROWN clarified that the numbers he has provided are actual
cash operating cost numbers not derived from a FERC model.
Therefore, under a FERC model, presumably there will be one
tariff that's charged by the entire the pipeline. He noted that
his scenario doesn't include a typical FERC 10 percent "weight
average cost to capital" return. If it was built into the
numbers, the tariff of $235 million would be significantly
larger, possibly $400 million. Furthermore, the state pipeline
agent ... [tape changed mid sentence].
TAPE 04-20, SIDE B [BUD TAPE]
REPRESENTATIVE GARA related that during the legislative session
he spoke with one of the company officials, who indicated that a
10 percent state interest in the project would make the project
more economic for the company. Representative Gara asked if,
since Mr. Brown is assuming a 12 percent state interest, the
committees could surmise that there is some analysis that a 10-
12 percent state interest will make the project more viable for
the private entities owning the remainder of the project.
Representative Gara also asked if Mr. Brown had any concerns
with regard to engaging this project later in time, keeping in
mind the possibility of a rising interest rate environment.
MR. BROWN addressed the latter question, and informed the
committees that when he advises the Department of Revenue,
various interest rate scenarios are run. The ultimate results
are sensitive to interest rates, but the main swing factor is
the price of gas and the competition from LNG during the year
2012. "The gas price swing factor, in terms of breakevens, is
sort of an 'order of magnitude worse than interest rate' within
... the realm of averages [for] the last 10 years," he
explained. In terms of the state's 1/8th interest and whether
it would make the project viable when it wouldn't be otherwise,
Mr. Brown viewed that as a negotiating province of the state
that he shouldn't discuss.
Number 668
SENATOR HOFFMAN directed attention to page 9 of Mr. Brown's
written testimony, and related his understanding that the state
will not take all the risk in this project. However, he
questioned why there has only been review of one scenario at the
low end of the market, $1.50. He inquired as to why there
wasn't review of $3.50 and $5.00 in order to obtain a feel of
the spread between a "$4.3 loss" and potential profits. Senator
Hoffman then turned to the energy bill [at the congressional
level] and the $18 billion federal guaranteed debt, and asked if
there are other, more advantageous avenues the state can request
the congressional delegation to consider. With regard to the
timing of this in relation to the price of steel and interest
rates, Senator Hoffman opined that it seems the near future
would be best for this project.
MR. BROWN, with regard to the issue of timing, confirmed that
the price of steel, like interest rates, is a large driver of
the total capital costs. Therefore, starting the project sooner
would be significantly better than later. However, one doesn't
really know what will happen to interest rates and steel prices
in the next five years. Before the state signed any agreement,
it would want to perform "sensitivities" that incorporated large
steel price increases and high interest rates. With regard to
the energy bill [at the congressional level], the project
guarantee is really helpful. There were hardly any specifics on
the $18 billion debt guarantee; it merely said that the
secretary of treasury will write some regulations. Mr. Brown
informed the committees that from the work he has done on
programs that have involved federal guarantees and federal
loans, he has gathered that the more details specified, the less
ability a subsequent secretary of treasury would have to "gut" a
provision. He agreed that there are many things that Alaska's
congressional delegation could do to help the state in this
venture.
MR. BROWN, in response to a question of why he used the scenario
[with a very large degree of risk], explained that if one is
taking really large risks, the issue isn't in regard to how much
money can be made in a good year; rather, it's "how long you can
stay at the table." He further explained, "It's the absolute
amount of money that you're at risk for if you have a couple of
bad years, and so that's what I was trying to illustrate."
CHAIR SAMUELS asked whether partnering with producers will
result in a conflict of interest.
MR. BROWN related his understanding that the state has two hats,
one of which collects royalties from around the state; the state
is also in a loose partnership with the entities due to it's
ownership for the physical capacity and running of the pipeline.
However, the aforementioned doesn't seem to be at odds with the
goal of extracting all the gas from the land from every other
field within a gathering line distance of this particular line.
He indicated that he is not concerned about a potential conflict
of interest.
Number 751
BRYAN HASSLER, Executive Director, Wyoming Natural Gas Pipeline
Authority (WPA), explained that the WPA ("Authority") consists
of himself, an administrator, and two technical analysts. The
WPA also has a five-member volunteer board that consists of
industry executives. Furthermore, a group of investment bankers
advise the WPA on projects it's reviewing. Mr. Hassler relayed
the goals and mission of the WPA per his written testimony,
which read [original punctuation provided]:
Goals:
> Reduce the price differential for all Wyoming-
produced gas to historic levels of $0.50 or less.
> Increase the market for and market access to
Wyoming-produced gas by 2 Bcf/d in the next four
years. (Currently produces 4.2 Bcf/d of which 4.0
Bcf/d is exported.)
Mission:
> Advance and facilitate all industry sponsored and
supported projects.
> Proactively promote infrastructure development
within the state and Rocky Mountain region.
> Promote efficient utilization of existing
infrastructure in a cost effective manner.
> Promote development of Wyoming's mineral resource
base in a systematic, streamlined and environmentally
responsible manner.
> Utilize $1 billion bonding authority to build or
cause to be built infrastructure projects that will
enhance state netbacks.
> Promote development of an energy resource base that
is in the nation's best interests.
MR. HASSLER said:
Based upon what you see in the "potential gas"
committees' study and National Petroleum Council
studies, you need every bit of gas that you can
produce, not only in the Lower 48 and development of
the resource base within Wyoming, but you also need
Alaska natural gas and LNG imports to make this
country ... grow as it has in the past.
MR. HASSLER explained that the WPA is a corporate body within
the guise of the state, and therefore the WPA is an independent
body that is legislatively mandated. However, the WPA isn't a
body within the political infrastructure within the State of
Wyoming, and this is critical with regard to state investment in
internal improvement projects. The WPA was established in July
1, 1979, after the giant over-thrust fields were discovered, and
Wyoming had limited infrastructure in terms of moving production
out of the state. The purpose of the WPA is to plan, finance,
construct, develop, acquire, maintain, and operate pipeline
infrastructure within and without the state of Wyoming. One of
the major attributes of the WPA is its $1 billion bonding
authority. "We can move a tremendous amount of gas over
relatively short periods, ... at a very attractive tariff and a
billion dollars of bonding authority if we were to serve as a
conduit financer for a number of projects in development, [and]
would develop probably three or four ... projects under a
traditional 'debt to total capitalization' type structure," he
highlighted. He reviewed the other major attributes of the WPA,
as specified on pages 3-4 of his written testimony [original
punctuation provided]:
•Use of bond proceeds immediately after the sale of
the bonds rather than after completion of project
construction.
•Permits the Authority to sell or lease capacity.
•Statutes allow the Authority to lend the bond
proceeds to other parties.
•Authority can charge fees for the use of Authority's
facilities including pipeline capacity.
•Authority can conduct hearings to obtain data,
identify markets for Wyoming natural gas and be an
advocate before FERC.
•Statutes allow the Authority to acquire natural gas
supplies to fulfill its capacity commitments.
MR. HASSLER pointed out that some revisions were enacted in
Wyoming's 2004 legislative session. Those revisions are as
follows:
Provides the Authority access to pipeline capacity for
its own purposes.
Permits the Authority to have an undivided interest in
pipeline assets.
Allows conduit financings by the Authority.
Clarifies the purchase of the Authority's bonds by the
State treasurer.
MR. HASSLER reviewed the similarities between the Alaska Natural
Gas Development Authority (ANGDA) and the WPA by paraphrasing
from the following written testimony [original punctuation
provided]:
Similarities:
1) Both the ANGDA and WPA were established to promote
the development of their respective State's natural
resources.
2) Each was designed to be self supporting.
3) The Authorities can take an ownership interest in a
project.
4) Each Authority can issue both tax-exempt and
taxable bonds.
Differences:
1) WPA does not need legislative approval to issue
bonds.
2) WPA is limited to $1 Billion of bond authorization.
3) WPA can not provide a moral obligation pledge.
4) WPA operations are funded by a state loan.
Number 854
SENATOR THERRIAULT asked if number four in the above-specified
differences refers to the WPA's yearly operating expenses.
MR. HASSLER explained that the original loan to the WPA was
approximately $280,000, which was granted in 2002. The board
operated without any permanent staff until last May when he was
hired. He emphasized that [the WPA] has been very conscientious
in terms of where money has been appropriated and how that money
has been utilized. In the last biennium, the legislature
authorized the issuance of another $1.7 million loan to the WPA
[after reviewing] the WPA's carefully prepared budget, which
specified what projects it was reviewing, the resources the
state might have, and the incremental increase of staff
necessary to put together pipeline infrastructure projects
inside and outside of the state.
MR. HASSLER said that the WPA intends to be self-supporting and
pay back the loan the state has given it. He clarified that the
WPA has five years to pay back the loan, which was issued with a
4 percent [interest rate], and explained that part of the
reasoning behind [the State of Wyoming] loaning the WPA money
and allowing it to be a body corporate is that it allows the WPA
to have a direct investment in the pipeline infrastructure
projects while simultaneously promoting such projects without
circumventing constitutional issues within the state.
Number 894
MR. HASSLER returned to his presentation and highlighted the
pictorial map on page 6 of his written testimony. He explained
that the numbers in the circles represent a potential
recoverable resource base. He highlighted that Opal, Wyoming,
is a major supply hub with approximately 1.5-1.7 bcf through
three to four plants that are active in that area of the state.
As the pictorial illustrates, the bulk of the pipeline
infrastructure within the Lower 48 is built to access Texas,
Oklahoma, and Louisiana in order to move those gas supplies into
the Midwest and the East. The pictorial also illustrates the
major trunk line out of Alberta, Canada, which is associated
with the NOVA system, TransCanada systems, and the Alliance
pipeline. "When you look at infrastructure within the west,
it's very anemic for the potential resource base that you see
here," he highlighted.
MR. HASSLER turned to the question of why one would establish an
authority. The Governor of Wyoming has said that the WPA
[should be established in order] to develop the resource base
within Wyoming and help [the state] achieve pricing parity with
other portions of the country. Mr. Hassler relayed that over
the last few years, the largest problem Wyoming has faced is low
gas prices, which were due to growing supplies and lack of
pipeline infrastructure to move gas supplies out of the state
and the region. As the [graph on page 8 of WPA's written
testimony] illustrates, in 2002 prices dipped on a monthly basis
at close to $1. In the winter there is some pricing parity with
the NYMEX [New York Mercantile Exchange] equivalent because of
the tremendous swings in terms of the utilization of gas within
the Rocky Mountain states. For instance, Denver consumption in
the summer averages 200-250 million cubic feet (mmcf) a day.
However, on a peak day in the winter, Denver consumption can
reach in excess of 2.5 bcf a day. The Salt Lake City market has
similar characteristics. Therefore, consumption with the Rocky
Mountain states increases in the winter, which limits the need
for pipeline export capacity. He noted that during the summer
of 2002, there were daily reports of prices of less than $.25
mmcf on certain days, when there were constraints on the
existing export infrastructure.
MR. HASSLER turned to the question of the cost of the limited
infrastructure to Wyoming and mentioned that it amounted to $130
million-plus in federal and state royalties and severance taxes
in 2002. He reminded the committees that in 2002, the NYMEX
prices were much lower compared to today's prices. In March of
2003, the "opportunity cost" due to the lack of export capacity
from the region approached $1 million per day. Furthermore, the
cost of limited infrastructure led to stalled investment in
development of mineral resources because producers can't be
attracted to a resource base that has very little value. From
the State of Wyoming's standpoint, low prices and the lack of
development of the resource leads to limited ability to predict
revenues with certainty and fund those projects the state finds
necessary to fund. Moreover, growing supplies in Wyoming also
lead to the need for export capacity. He pointed out that the
graphs on pages 11 and 12 illustrate what is happening in Kansas
versus Wyoming, and Oklahoma versus Wyoming. The graph on page
11 illustrates that Kansas production has declined by almost 1
bcf a day over the last 10 years, while over that same 10-year
period, Wyoming production has increased by over 2.3 bcf [as
illustrated on the graph on page 12]. The graph on page 12
further illustrates the loss of productive capacity in Oklahoma,
which, over the last 10 years, amounts to almost 2 bcf a day.
Therefore, there is a real need for incremental supplies to
backstop declining production in some of the most productive
areas of the country. Wyoming's 2.3 bcf a day is representative
of Wyoming's productive capability over the last few years and
of the need to develop incremental export capacity.
MR. HASSLER then addressed the critical success factors for
resource development. He explained that the study the WPA
performed last year attempted to illustrate what limits markets
from entering and requesting incremental capacity to access a
cheap, long-lived, reliable supply resource base. The study
further looked at what limits producers from making commitments
to incremental pipeline capacity to fulfill long-term capacity
commitments and continue to develop, grow, and explore the land
base. He informed the committees that access to lands in a
timely manner is a critical function associated with producers
stepping up with capacity, especially in a state such as Wyoming
that is heavily endowed with federal lands and [considers] the
environmental impact associated with assessing the impact of oil
and gas development on those federal lands. There has been a
tremendous lag in the development of the resource base because
of the environmental impact, he noted. Mr. Hassler pointed out
that price, timing of regulatory approvals, gathering system
capacities and pressures, transportation export capacity,
capital efficiency, and public acceptance are all variables that
can limit or accelerate the development of pipeline
infrastructure as well as the resource base.
MR. HASSLER continued with [page 14] of his written testimony,
which is a schematic that illustrates pipeline capacity moving
out of the State of Wyoming, which consumes about 200,000 mcf a
day within the state and exports about 4 bcf a day in natural
gas produced outside of the state. Therefore, Wyoming is not a
consumer of natural gas but rather an exporter of natural gas.
He highlighted the Kern River pipeline, which was initially put
in place in 1992 and allowed for export of natural gas supplies
to California. That original pipe had roughly .9 bcf a day in
capacity. In May of 2003, the Kern River pipeline was "looped"
and was able to provide for export of almost an additional 1 bcf
a day of supply from the state. The schematic also highlights
the El Paso Cheyenne Plains project and the WBI [Winston Basin]
Grasslands project, which Mr. Hassler reviewed for the
committees.
SENATOR LINCOLN recalled that one of the critical success
factors was public acceptance and access to the lands. She
asked if any of the lands are Indian lands.
MR. HASSLER answered that the central portion of Wyoming, the
Wind River Basin, has a large reservation, and , as the pipeline
moves into Montana, there are Indian lands there as well. In
further response to Senator Lincoln, Mr. Hassler specified that
the individual producers with concessions negotiate the
provisions regarding access to those lands for oil and gas
development activity. Pipeline companies that want to move
those supplies [on Indian lands], in conjunction with the
producer, will negotiate with regard to how those supplies will
be moved.
SENATOR LINCOLN asked whether the ability to access the gas
could be one of the provisions that the tribes request.
MR. HASSLER replied yes, but noted that there is very little
industrial activity within Wyoming. Therefore, he suggested,
most of the natural gas and crude oil discovered and produced
from tribal lands is looking for a market elsewhere, and, thus,
[the tribal entities] are probably seeking to achieve the
highest export price possible for the product developed on those
lands.
MR. HASSLER returned to his presentation and highlighted that
Wyoming is endowed with many existing and developing pipelines
out of the state. Once El Paso Cheyenne Plains is "in project,"
Wyoming will have promoted almost 3 bcf a day of export capacity
from the state. He then turned attention [to the graph on page
15 of his written testimony], which illustrates the spread
between NYMEX prices at $9.00 and Wyoming prices at $5.00 that
narrowed substantially once "gas on gas" competition within the
region is eliminated and the capacity is exported to the market.
Mr. Hassler moved on to the revenue facts [as specified on page
16 of his written testimony]. He informed the committees that
Wyoming receives 50 percent of the royalty on gas produced on
federal lands, and approximately 75 percent of the lands in
Wyoming are federal lands. Wyoming also receives approximately
7 percent of the value received from all production of the state
from a severance tax assessment. He noted that he hasn't
included the value of royalties from state lands, which amount
to two sections per township and range, and value created by ad
valorem taxes. He explained that he's attempting to illustrate
what developing incremental infrastructure within the state can
do for the state from a revenue standpoint. Mr. Hassler
provided the following [written] example:
Wyoming receives 50% of Federal Royalties =
approximately 6.25% of Federal lands. Assume 100% of
production comes from Federal lands.
Wyoming receives approximately 7% of the value
received from all production in the State from
severance tax assessment.
Wyoming's current saleable production is approximately
4.2 bcfd.
Wyoming's revenue share of production is approximately
4.2 bcfd X (.0625+0.07) = 556,500 Mcfd.
At gas prices of $2 per MCF, Wyoming could expect to
receive $1,113,000 per day in natural gas revenue. At
$4 per Mcf, Wyoming could expect to receive $2,226,000
per day.
MR. HASSLER noted that if a 7 percent ad valorem tax is
included, the state has ownership value in excess of 20 percent
of the production.
SENATOR HOFFMAN inquired as to the life expectancy of the gas in
Wyoming; that is, "How long do you see between $1 and $2
billion?"
MR. HASSLER referred back to page 6 of his written presentation,
which refers to 170 trillion cubic feet (tcf) a day, and
informed the committees that "we" are producing approximately
1.3 tcf a year from the state. At existing production rates,
there's a 170-year reserve life. Mr. Hassler offered:
To get into an efficient cycle, we believe that
because of the tremendous resource base, if we can get
access to lands, get producers to develop the resource
base in an environmentally responsive manner, ...
there's a very real thought process that we can grow
production from the state substantially, relative to
where it sits today. As I indicated, we think we can
go from 4-4.2 bcf a day to 6 bcf a day over the course
of five years if ... we are successful in promoting
the resource in an environmentally responsible manner
and ... working with the environmentalists in terms of
developing that resource base.
MR. HASSLER pointed out that if Wyoming's resource base is
reviewed relative to where Alberta, Canada, is, Wyoming could be
able to produce 10-12 bcf a day of natural gas resource over the
next 10 years. However, some of the resource sits in
environmentally active areas in which there are problems with
regard to surface access and water discharge. Mr. Hassler
returned to [page 17] of his presentation and highlighted
projects that the WPA has reviewed [and which are being
forwarded], such as the Cheyenne Plains Project, the Jackson
Hole Project, and the Rock Springs Project. He relayed to the
committees that the WPA has found that before such an entity
"swings for the fences" it would be appropriate to get the
investment banking team and the bond council working on a
smaller project with which it can work through any difficulties
in terms of issuing bonds. The Rock Springs Project is such a
project for Wyoming.
Number 172
GEOFF URBINA, George K. Baum and Company, informed the committee
that for the Halliburton Rock Springs Project, it will be the
first financing for the WPA, and the project is a "taxable
lease" revenue bond. [Referring to page 19 of the WPA's written
presentation], he indicated that the WPA will be involved in
this project by issuing bonds to do the take-out financing. He
explained that with this project, a limited liability company
(LLC) signed a lease with Halliburton, and a short-term
construction loan was taken out with permanent financing. The
aforementioned, he noted, is typical of pipeline financings that
are performed in the corporate world. The only difference is
that this is lease revenue as opposed to revenues resulting from
a tariff or shippers selling gas to the end market.
MR. URBINA turned attention to page 20 of the WPA's written
presentation, which reviews state financing tools available to
build pipelines. With regard to the option of conduit
financing, Mr. Urbina pointed out that such financing was used
to build the marine terminal for the Trans-Alaska Pipeline
System (TAPS) in Valdez. The City of Valdez issued the bonds
for the aforementioned project. With the Halliburton project,
the [Wyoming] state treasurer was involved as an investor of the
bonds. He noted that Wyoming has the Mineral Trust Fund, a fund
similar to the Alaska permanent fund. The [Wyoming] state
treasurer considered the Halliburton Rock Springs Project worthy
for many reasons, including [the ability to purchase the bonds
at a competitive rate]. Furthermore, this project develops a
tax base in Rock Springs, which he characterized as a boomtown.
MR. URBINA highlighted the state financing tool of a "stand-by
bond-purchase" agreement. He explained that such an agreement
can occur when there is no market for the bonds, and the state
can purchase/hold the bonds while the bankers try to find a
market for them. The aforementioned is a way in which the state
can provide liquidity or credit.
MR. HASSLER interjected that constitutionally, Wyoming can't
provide certain [financing tools]. The State of Alaska will
have to determine what fits [for Alaska].
TAPE 04-21, SIDE A [BUD TAPE]
MR. URBINA indicated that [the stand-by bond-purchase agreement]
has been performed under the state umbrella. He then turned to
the debt service reserve fund (DSRF), which he likened to a
parent co-signing for his/her child's automobile. Ultimately,
the financial institution will come after the DSRF if there is a
default on the bonds; this is similar to when in-kind
state/federal gas is used or there is a moral obligation pledge.
Mr. Urbina turned to the option of state ownership of the
[pipeline], which is the riskiest and should be reviewed on a
number of levels [as specified on page 21 of the WPA's
presentation]. If the state were to be involved in financing a
portion of the pipeline or buying capacity, then 25-50 percent
of the RIK revenues go to the permanent fund while the remainder
goes into the general fund. There could be "opportunity costs"
related to the [portion going into the general fund] because the
legislature may want to fund other projects.
MR. HASSLER summarized that [the WPA] is serving as a common
conduit to promote development infrastructure within and outside
of the state from a natural gas and resource development
standpoint. However, he noted that [the WPA] has the authority
and ability to propose pipeline projects in the event that
industry doesn't come forward and get the job done.
Number 029
MARTY MASSEY, Joint Interest Manager US, ExxonMobil Production
Company, ExxonMobil Corporation, informed the committees that in
his position he is responsible for the commercialization of
ExxonMobil's gas resource in Alaska. Mr. Massey paraphrased
from the following written testimony [original punctuation
provided]:
Today I have been asked by ExxonMobil, BP and
ConocoPhillips to provide testimony to you on behalf
of those three companies on the topic of possible
State ownership in the gas pipeline project. Joining
me today is Richard Guerrant. Richard is Vice-
President Americas in the ExxonMobil Gas & Power
Marketing Company. He has been involved in worldwide
natural gas marketing for 20 years. Richard will
provide testimony on behalf of all three companies on
industry trends of natural gas and natural gas liquids
commonly called NGLs.
Before I turn it over to Richard, let me begin with a
few remarks on State ownership in the gas pipeline
project. As you know ExxonMobil, BP and
ConocoPhillips submitted an application under the
Stranded Gas Development Act in January of this year.
That application was accepted and the producers, now
referred to as the Sponsor Group, and the State are
now in negotiations on a fiscal contract. The Governor
and his staff have indicated an interest in evaluating
the State taking its gas in kind and owning an
interest in the gas pipeline project. This approach
has the possibility of providing greater alignment
between State and Sponsor Group interests. It would
also facilitate the State's use of its gas to meet in-
state demand as well as provide a source of revenue
should the State decide to make the investment. At
this point we are in the early stages of discussion
with the State and both the Sponsor Group and the
State are currently evaluating this possibility.
However, much work remains to be done regarding the
feasibility of this approach and it is premature to
draw any conclusions at this time. Since this is a
part of the current negotiations, it is not
appropriate to comment on specifics that are being
discussed. However, the Sponsor Group is encouraged
that the Governor and the Commissioners are focused on
negotiating the fiscal contract with the Sponsor
Group.
Number 079
RICHARD GUERRANT, Vice President Americas, ExxonMobil Gas &
Power Marketing Company, ExxonMobil Corporation, paraphrased
from the following written testimony [original punctuation
provided]:
North American Supply and Demand
First, I will discuss the gas supply-demand outlook
for North America, and how Alaska gas fits into that
picture. I will also address the fundamental market
forces that influence how gas markets work. Lastly, I
will cover the marketing of NGLs.
It is difficult to accurately forecast the supply,
demand and price future across North America given all
of the potential scenarios. In 2003, the National
Petroleum Council (NPC) completed a comprehensive
review of the outlook for North America gas supply and
demand through 2025. The study had been requested by
the US Department of Energy and has received much
attention and praise for clearly describing the gas
supply/demand challenges facing North America. The
NPC study was prepared by a broad cross-section of
industry representatives including ExxonMobil that
chaired the Supply Committee. An important point for
this committee to understand is that the NPC study
highlighted that the North American market could
accommodate Alaska gas.
Starting with the existing supply picture, in 2003,
the US produced about 50 Billion Cubic Feet of gas per
Day (BCFD) with Canada contributing 17 BCFD and
Liquefied Natural Gas or LNG imports supplying an
additional 1 BCFD. This total supply balanced demand
of about 62 BCFD in the US and 6 BCFD in Canada.
After supplying its local demand, Canada exports about
11 BCFD to the United States.
Looking forward, the North American supply outlook has
been described as a treadmill in which new supplies
are needed to offset the decline of existing
production. Production from existing wells in North
America declines at about 16 BCFD each year and
requires continued new drilling and exploration to
offset this decline. The recent high prices in North
America have encouraged substantial drilling activity
such that drilling rig counts are now reaching the
highest levels in the last decade. Unfortunately, due
to the maturity of North American producing fields,
both reserves and production rate contribution per new
well have declined in recent years. The NPC Study
Outlook is that North American production will remain
broadly flat to slightly declining over the next two
decades. The geographic mix of supply will change
somewhat as growth in production from the Rockies and
deep water Gulf of Mexico will be offset by declines
in the lower 48 states, Gulf of Mexico shallow waters
and Western Canada.
Number 107
Demand for gas in North America has grown from 63 to
68 BCFD over the past 10 years, and the NPC forecasts
that demand will grow an additional 20% to 85 BCFD by
2015 driven in part by annual US GDP growth of 3% per
annum. Steady demand growth is forecast in
commercial, residential and industrial sectors. The
residential and commercial sectors accounted for over
one-third of the US natural gas consumption in 2002.
These sectors are expected to grow by 1% per annum in
the NPC study. In part, this is driven by demographic
growth with new residential construction heavily
weighted to natural gas heating. In recent years,
approximately 70% of newly constructed homes installed
gas heat. But the main driver of gas demand growth in
North America is expected to be gas-fired power
generation. Approximately 200,000 megawatts of gas-
fired generation are projected to be added by the end
of 2005, representing a 31% increase in total
generation capacity and a 290% increase in gas-fired
generating capacity versus 1998. The result is that
gas demand is being driven higher as North American
electricity requirements grow with the economy.
In 2015, as I mentioned, NPC estimates North American
demand of 85 BCFD with indigenous supply of 68 BCFD,
leaving a gap of 17 BCFD. The NPC expects that this
gap will be filled by a combination of new Arctic gas
supplies from Alaska and the Mackenzie Delta, in
addition to significant increases in imports of LNG
and higher cost indigenous production. The NPC study
predicts that long-term prices will be driven by the
cost of these major new supplies, and constrained by
competition from alternative fuels such as oil, coal
and nuclear. The clear conclusion from the NPC work
is that North America can accommodate significant
supply additions from a variety of sources including
Alaska gas.
Gas Transportation, Pricing and Marketing
Next, I would like to briefly discuss how Alaska gas
would likely enter the North American market. The gas
would be transported through a large diameter, high-
pressure pipeline across Canada and perhaps continuing
on to Chicago. This pipeline would pass through the
heart of the Western Canadian Sedimentary Basin which
produces about 95% of Canada's gas production. Alaska
gas could be consumed in Western Canada or transported
to other Canadian and U.S. Markets. Five major
pipeline systems currently exist in Alberta and
British Columbia to take gas to markets in Canada and
the Lower-48. These pipelines feed border crossings
with capacity of about 12 BCFD where gas is
transferred to Lower-48 pipelines flowing ultimately
to markets in the Midwest and on the East and West
Coasts. In order to determine which market the Alaska
gas will ultimately serve, we need to discuss market
pricing and pipeline infrastructure which I will
address next.
The key participants in the gas market include
suppliers, transporters, and obviously buyers.
Suppliers include hundreds of producers and marketers,
and buyers include thousands of industrial consumers,
power generators, and local distribution companies.
With the large number of market participants, and the
significant number of sales transactions, North
America is the largest and most liquid market in the
world, and has proven very efficient at matching
available supplies to market demand. These
participants primarily buy and sell gas on a month-to-
month basis, with a small portion of longer-term
arrangements, and some daily trading to manage short-
term production and demand variations.
There is a benchmark gas price - the 'Henry Hub'
price, which is similar in nature to the crude oil
benchmark prices like West Texas Intermediate. Like
West Texas Intermediate, gas is traded on a futures
market, the NYMEX, and also trades on physical markets
at specific trading points throughout North America.
Near the end of each month, deals are arranged between
buyers and sellers and these trades help set the price
for the following month's gas deliveries. The very
large number of transactions and multiple participants
provide an efficient market, which yields a
competitive market price for the product.
An important attribute of an efficient and competitive
North American gas market is the high degree of price
transparency. For more than a decade, industry trade
publications have published price indices for
physically traded gas on a daily and monthly basis,
and have recently expanded their reporting to include
details on number of trades and volumes. These
published indices represent actual sales transactions
at about 100 locations across North America.
Prices at these locations vary by region. The
difference between the regional prices reflects the
market's valuation of transporting gas between the
regions to meet demand. In regions with excess
transport capacity, the price difference may be less
than the actual cost of transportation. In regions
where capacity is tight, the price difference may
exceed the actual cost of transportation. These
pipeline balances can be further impacted by seasonal
demand fluctuations.
Since deregulation beginning in the mid '80s, the
North American gas market has evolved into a mature,
liquid and transparent market. Consequently, we have
well established market mechanisms, which allow
suppliers to sell all their production at a market
price, similar to other commodities.
Natural Gas Liquids
An additional consideration in marketing Alaska gas is
the salability of the gas in meeting downstream
pipeline and market quality specifications. Field gas
production can contain water, CO, Sulphur, and other
2
compounds. For Alaska gas, it is expected that most
of these impurities would be removed on the North
Slope.
In addition to methane - the primary component of
natural gas - field gas production also includes
varying amounts of ethane, propane, butane and
pentane. Currently, the majority of butanes and
heavier NGLs are removed on the North Slope, added to
TAPS, and moved with the crude through the pipeline
system. As a result, the gas to be moved on the
Alaska Gas Pipeline will contain a light mixture of
NGLs, primarily ethane and propane, which will still
need to be extracted so that the remaining natural gas
can meet gas pipeline and market quality
specifications.
NGLs are removed by gas processing plants, with the
saleable natural gas moved onto market via pipeline.
The extracted NGLs are then transported to an NGL
fractionator where they are separated into their
components -- ethane, propane, butane and pentane.
The North American NGL market currently consumes about
3.3 million barrels a day of these products.
The ethane is primarily used as a feedstock to
chemical plants, which convert it to ethylene for
further use in making plastic products like plastic
bags, milk bottles, toys, etc. The pricing of ethane
is primarily linked to natural gas. The propane
feedstock has multiple uses: first, as a feedstock to
chemical plants to make propylene, a building block
for plastics used in the production of food packaging,
auto parts and carpeting, and second as a residential
and commercial heating fuel principally in rural areas
not supported by a natural gas pipeline
infrastructure. Butanes are typically blended into
motor gasoline to enhance the fuels performance
characteristics. Pentanes are also used as chemical
plant feed or in the production of motor gasoline.
The prices for propane and heavier NGLs are linked to
crude and other oil products.
In addition to the facilities required to remove the
NGLs from the natural gas stream to meet pipeline
specifications, substantial markets and petrochemical
infrastructure, including pipelines, fractionators,
chemical plants, storage and complex refineries are
required to consume the NGLs. As with natural gas,
the infrastructure and demand for these products is
primarily available starting in Alberta and markets
further south. Western Canada and Chicago have about
15 billion cubic feet per day of existing gas
processing capacity. Current Alberta chemical plants
have the ability to consume about 270 thousand barrels
a day of ethane with the resulting ethylene and
polyethylene production primarily sold into the Great
Lakes region. In addition, western Canada also
provides pipeline infrastructure to move excess NGLs
to Lower-48 markets.
The need to adequately process Alaska gas to meet
market and pipeline specifications is a key part of
the project, and there are adequate markets and
infrastructure in Canada and the Lower 48 to handle
the volumes of NGLs in the Alaska gas.
Number 204
Summary
I'd like to now summarize my remarks regarding the
North American natural gas and NGL markets:
· First, as detailed by the NPC Study, the supply /
demand balance in North America signals the room for
additional supplies, such as Arctic gas, LNG, and
higher cost indigenous production in the next decade.
· Second, the North American gas market is a mature,
liquid market with well established mechanisms to
ensure suppliers can sell all their product at a
transparent and competitive market price.
· Third, the NGLs will need to be removed to achieve
downstream pipeline specifications, and the best
approach is to take advantage of existing
infrastructure close to available market for the
products.
Before closing, I would like to point out that it will
take a combination of factors for an Alaska gas
pipeline project to be commercially viable. Those
factors include a fiscal contract with the State of
Alaska, U.S. federal enabling legislation, a clear and
predictable regulatory process in Canada, a
significant reduction in project costs, and a market
outlook that is sufficiently encouraging over the
projected life of the project.
Number 237
CHAIR SAMUELS asked if ExxonMobil's competitors, when it sells
the liquids or the gas itself, are BP, ConocoPhillips Alaska,
Inc., Texaco, and Chevron. He further asked if ExxonMobil sells
[the liquids or the gas itself] to a broker or is in a situation
in which the company is "vertically integrated" and in charge
throughout the process. Chair Samuels posed a situation in
which the State of Alaska owns a lot of gas, and asked if the
state would be competing with some of the largest corporations
around on something that [such companies] have done throughout
their entire existence.
MR. GUERRANT reiterated his earlier testimony with regard to the
fact that there are many, many participants in buying and
selling gas. There are buyers who want to purchase gas directly
from the producer or owner of the gas. There are also marketers
who want to purchase gas from other producers and resell it.
Furthermore, there are producers who sell their product; there
are also producers who buy and sell. Mr. Guerrant explained
that ExxonMobil Corporation has a diversified slate in which
most gas is sold on short-term contracts, which range from daily
to monthly to yearly. ExxonMobil Corporation has very few long-
term contracts because today's customers in the marketplace
aren't willing to sign up for long-term contracts. With regard
to the type of customers to which ExxonMobil Corporation sells,
Mr. Guerrant specified that it sells to a portfolio of
customers, including local distribution companies (LDCs),
industrials, and marketers. Mr. Guerrant posed a situation in
which each of the producers and the state is taking its gas in
Chicago. In such a situation there will be plenty of
opportunity to sell. He noted that the mechanisms regarding how
the market works are well established, although the key to that
is the governance. "The buyers need the gas; ... they will be
wanting to buy the gas from you," he added.
MR. MASSEY relayed that the state has the option to determine
how it wants to handle the sale of its gas. The state could
develop such expertise internally and sell the gas itself, or
the state could contract out that responsibility. He echoed Mr.
Guerrant's comment that in the current market, there are plenty
of buyers for gas and well-established indices upon which to
sell it.
MR. GUERRANT said that the state will develop its own expertise
at some level, depending upon how far downstream the state goes.
Number 291
SENATOR ELTON remarked that ExxonMobil Corporation's testimony
was fairly dismissive of any discussion regarding advantages to
the state's owning or not owning a portion of the pipeline. He
asked if the ExxonMobil Corporation representatives could
provide the committees with even a hint on that matter.
MR. MASSEY apologized and reiterated that ExxonMobil Corporation
is in negotiations with the state on this topic. From a broad
viewpoint, though, the advantage is that if the state takes
ownership in the pipeline, the state and the sponsor group would
be aligned. Furthermore, if the state elects to take the gas
in-kind, it can use it as it sees fit, such as meeting in-state
demand. Moreover, if the state elects to invest in the
pipeline, the state will receive the revenues from that
investment. The reason the discussion isn't occurring in a more
detailed fashion is that it would depend upon the deal made with
the state. Mr. Massey informed the committees that ExxonMobil
Corporation is encouraged with the discussions it's having with
the state now.
SENATOR ELTON pointed out that a deal with the state would have
to be consummated with the legislature. At some point, there
will have to be a discussion with regard to the advantages and
disadvantages of state participation in this pipeline. Senator
Elton said that it would be helpful to hear that there are clear
advantages or disadvantages related to state participation.
Number 334
SENATOR FRENCH expressed concern with regard to the state
obtaining a fair deal for its resources. Therefore, he
questioned where the liquids would be taken out. Currently, the
heavy liquids are being taken out at the North Slope. He
related his understanding that the "somewhat wet gas" will be
shipped to Alberta and the remaining liquids would be taken out
in the Alberta gas processing facilities.
MR. GUERRANT confirmed that the aforementioned is the base plan
because there is existing infrastructure [in Alberta] that is
close to the market and will provide the best value for the gas.
SENATOR FRENCH interjected that there are existing
transportation infrastructures to move the separated products to
market from that point on. He then questioned whether there is
a price difference between the somewhat wet gas that would be
shipped to Alberta and the separated components. In other
words, which is more valuable, the wet gas or the separated
components, he asked.
MR. GUERRANT pointed out that some of "it" has to be taken out
in order to meet the pipeline specifications. There is another
level of extraction, which is primarily the ethane extraction,
that is based on market conditions. After the pipeline
specifications have been satisfied, the amount of ethane
extraction can be expanded or contracted based on the economics
of extraction under the current market prices for ethane.
Therefore, an economic optimization has to be performed in the
marketplace. Mr. Guerrant specified that secondary extraction,
that occurring after the pipeline specifications have been
satisfied, occurs in order to obtain more value for the product
stream than it would have if left in. The aforementioned, he
explained, is why he mentioned the gas processing capacity in
Alberta that could be utilized. That economic optimization will
ensure that the maximum value for the product is obtained. In
further response to Senator French, Mr. Guerrant specified that
all involved will have such decisions to make. The first
decision will be in ensuring the gas meets the pipeline
specifications, then the question is regarding how deep of a cut
does one make to obtain the best value for all the players. The
aforementioned is usually done on an individual-entity basis,
although each individual involved will optimize the stream based
on the marketplace.
Number 399
REPRESENTATIVE HAWKER echoed the concerns expressed by Senator
Elton and then turned to Mr. Guerrant's closing comments
regarding the factors necessary to have a commercially viable
project. He recalled that Mr. Guerrant's testimony relayed the
need to have "a clear and predictable regulatory process in
Canada" and asked if that statement implies that such a process
doesn't already exist in Canada. Conversely, is that statement
acknowledging that Alaska has a clear and predictable regulatory
process? He also recalled that Mr. Guerrant's testimony
suggested that "those factors include a significant reduction in
project costs". Does this mean that under the current
anticipated cost structure by the sponsor group, this isn't a
feasible project? he asked.
MR. GUERRANT confirmed that predictable processes are necessary
for permitting, in both the US and Canada. The US federal
enabling legislation allows that predictable process. Although
there is knowledge with regard to how the National Energy Board
(NEB) does its pipeline permitting, fitting this all together
must come to fruition in an orderly fashion in that specified
cost estimates are met as well as the desired economic benefits
and value for the gas are obtained. Mr. Guerrant said that more
of an understanding of the Canadian side of the project has to
occur.
MR. MASSEY opined that the sponsor group has been clear that
today, the project isn't commercially viable. One of the things
within the control [of the sponsor group] is to try to be able
to drive down the costs of the project, and much effort amongst
the sponsor group is being expended to that effect. For
example, both BP and ExxonMobil Corporation have spent a great
deal of money and effort to commercialize a higher strength
steel, which would allow the [sponsor group] to not have to
purchase as much steel in the pipe to make this project occur.
Much progress has been made in that effort as test lines have
been put in place in one of TransCanada's systems in order to
test this high-strength steel technology. Mr. Massey reminded
the committees that this is a huge, complex project that no one
has done. Furthermore, as the situation moves closer to
building such a project, the costs increase, and therefore the
cost reduction items have to be in place in order to offset the
increases.
Number 472
REPRESENTATIVE ROKEBERG recalled Mr. Guerrant's testimony
regarding well-established mechanisms, price transparency, and a
high degree of confidence in those. He asked if, in the
negotiations between the sponsor group and the administration,
it will be necessary to adopt/use any of the benchmark pricing
in dealing with a contractual agreement with the state.
MR. MASSEY specified that it would depend upon the structure of
the project. If the project is a royalty in-value structure in
which the sponsor group pays the state cash, the sponsor group
will have to determine the value of the gas. The value of the
gas can be determined in a variety of ways, including benchmarks
or actual revenues based on the sale of the gas. If the project
is under an ownership structure and the state basically sells
the gas, then some of the need to determine the value of the gas
will be eliminated. The aforementioned is the topic of the
current discussions with the state.
REPRESENTATIVE ROKEBERG expressed concern with regard to the
presentation from Mr. Massey and Mr. Guerrant in relation to the
[sponsor group's] high degree of confidence in the transparency
of gas pricing in the US. He inquired as to whether the FERC
study on the matter of transparency has been completed. He
noted that as a member of the Energy Council, he has been privy
to studies that have indicated there are substantial problems
with the published prices, plats, and other publications.
MR. GUERRANT opined that over the past two to three years, there
have been questions with regard to price transparency that have
primarily been related to entities that have financial problems
and have had players that have inaccurately reported things into
indexes. Work was done with the FERC, which performed an
extensive investigation along with the Commodity Futures Trading
Commission (CFTC) and other jurisdictions. He offered his
belief that improvements made to the indices, particularly
revolving around the number and volume of trades for each sale,
have provided the industry more confidence that the indices
work. A survey was performed and reported to the FERC, and this
survey rated the confidence in the indices at 7-8 on a scale of
1-10. However, he acknowledged that some indices are more
liquid than others; for example, one of the most liquid
transparent indices in North America is the Alberta index. The
Henry Hub index is a physical trading point as well as a NYMEX
regulated trading point. He characterized the Henry Hub index
as a very valid index. In summary, Mr. Guerrant shared his
belief that the difficulties with regard to price transparency
are past and everyone feels good with regard to the indices. He
surmised that sending the signal to the industry that those
misreporting will pay the price has made a major improvement
with regard to governance procedures. Still, the FERC and the
industry continue to monitor this issue.
Number 597
REPRESENTATIVE GARA noted that many in the legislature want to
access gas for in-state uses such as for the spur line to
Valdez. Therefore, he inquired as to [the sponsor group's]
thoughts on such access. He recalled testimony that [the
sponsor group] doesn't believe this project is commercially
viable at this point. However, he noted, the governor says that
he will make an announcement with regard to a preliminary deal
in September. Therefore, he requested follow up on this
project's commercial viability. Representative Gara also
inquired as to whether [the sponsor group] has any hesitance in
selling its gas [on the North Slope] to an entity that believes
the project is commercially viable.
MR. GUERRANT began by pointing out that "we all want to try to
monetize and sell this gas". Furthermore, he said, [the sponsor
group] recognizes that the in-state demand issue has to be
addressed.
TAPE 04-21, SIDE B [BUD TAPE]
MR. GUERRANT then turned to Representative Gara's question
regarding [the sponsor group's] propensity to sell gas to an
entity that believes this project is commercially viable. He
said that [the sponsor group] would entertain any realistic
proposal. However, realistically, those who own the reserves,
the state and the project sponsors holding the lease, are those
who can take the risk to get the gas to the first liquid market
point. After the first liquid market point, it's a different
matter. Mr. Guerrant opined:
I think we'll all listen ... to any proposal ... any
party brings to the table. And if they add value and
they're durable [and] ... they can [actually] deliver
what they say they can deliver ... and [it] doesn't
[put] undue risk on all of us ..., we'll consider
that. But ... I haven't really seen those kinds of
opportunities in all of the projects that I've worked
on, that ensure that you get the right value. Those
are things that you've got to be careful in ...
considering because they may not be durable. ... In
other words, ... someone coming in and [saying] that
they [will] build and [then] buy your gas ..., that's
a difficult issue to consider because you don't know
what the value [is]. If you're down in the
marketplace, you know what the cost [is]. We can ...
build the pipeline to the first market point to where
we know that there's a very liquid transparent market
there. We know what the value of that is, and that's
what you want to make sure that you're getting full
value for.
Number 028
MR. MASSEY turned to the question regarding whether the project
is commercially viable. He reiterated that since the sponsor
group has completed its study, it has held the position that the
project isn't commercially viable. "It doesn't mean we're not
trying to make it commercially viable - we are," he relayed.
Trying to make it commercially viable is the subject of the
negotiations occurring with the administration. Furthermore, he
said he is encouraged by the governor's comment that there will
be something in September. However, there's a lot of work to do
to reach that point. Mr. Massey mentioned that it's probably
within the [sponsor group's] control to make this project
commercially viable. He also mentioned that the sponsor group
would like to reduce the cost, and so much work is going on in
that vein. Mr. Massey concluded with the following:
Just because we say it's not commercially viable
doesn't mean we're not trying. We've got a lot of gas
resource up there. We've got indications from the
market that it can accommodate Alaska gas if we can
get the cost down at the right level, ... make it get
into the market at a good economic rate. So, the
conditions are right to try to make it happen, and a
large part of it hinges on the negotiations we have
right now with the state.
SENATOR DYSON asked about in-state sales.
MR. MASSEY said that one of the advantages of the state taking
an ownership position in taking its gas is that it will have gas
available to meet in-state demand and divert [the gas] to
wherever it wants, and that will depend upon where the best
value for the gas lies.
MR. GUERRANT concurred and suggested starting at a baseline in
which there is review of getting value from the marketplace and
then backing up to review what things can be added to the
project in order to create more value for the various parties.
The study is complete and there is a plan, and therefore he
suggested that now is the time, through these discussions and
negotiations, to improve on the plan.
Number 059
SENATOR LINCOLN shared her frustration regarding the points
stated in the last paragraph of Mr. Guerrant's written
testimony. She questioned what a "significant reduction in
project costs" would entail. The example of using high strength
steel as something that could reduce costs isn't under the
control of the state. She asked what [the sponsor group] wants
the state to do that would significantly reduce the project
costs and is something over which the state has control. She
then turned to extracted NGLs and commented that the best value
certainly isn't going to be in-state in Alaska. She surmised
that when [the sponsor group's] testimony refers to rural, it's
probably referring to rural America rather that rural Alaska,
and therefore she didn't think in-state uses would meet the
"bottom line" for the sponsor group. Senator Lincoln recalled
the following testimony: "In a market outlook that is
significantly encouraging over the projected life of the
project." She inquired as to the "projected life" that the
sponsor group would envision.
MR. GUERRANT said that the NPC study was one of the most
comprehensive studies that has been done. That study provided
the sponsor group and the entire industry with a much more
encouraging view about the need for the future supply.
Furthermore, the study extended into 2025, and has provided the
sponsor group with the encouragement to start this process.
With regard to in-state demand, Mr. Guerrant said that the
sponsor group recognizes that that is something which has to be
discussed and addressed in order to develop an acceptable
package. When there is a full view of the project, there will
be a discussion regarding how to make the project actually
happen.
MR. MASSEY said that he is as frustrated as Senator Lincoln is
in regard to the continuing need for these items to be
discussed. He stressed that for three years it has been his job
"to try to check one of these off the list." However, that
hasn't been achieved yet. Mr. Massey said that there needs to
be a catalyst to get this project going. The one thing that is
within the control of the sponsor group is the negotiation of
the fiscal contract with the state. If the aforementioned can
be negotiated and an agreement that the project is commercially
viable can be achieved, it will provide great momentum for the
project. So with regard to what Alaska can do, Mr. Massey
suggested negotiating a fiscal contract.
Number 129
SENATOR SEEKINS recalled that the sponsor group has said that
there is room for additional supplies of Arctic gas, LNG, or
"higher cost" indigenous production. However, Arctic gas isn't
economically viable, he opined, and so he questions what the
sponsor group is planning.
MR. GUERRANT said that the market side is starting to look
encouraging, such that the [process should move to the next
level], that being the fiscal contract. But first many issues
need to be sorted out in order to determine whether the project
is commercially viable. Once the fiscal contract is in place,
the regulatory issues could be tackled. In further response to
Senator Seekins, Mr. Guerrant confirmed that [the sponsor group]
is looking into other areas as a contingency. He noted that
[ExxonMobil Corporation] has major land holdings and leases in
Canada and the US, and drilling is taking place on the good
prospects. Furthermore, [ExxonMobil Corporation] is involved in
the LNG business and is looking to expand it in the right
markets. [ExxonMobil Corporation] is also pushing ahead with
Arctic gas. Mr. Guerrant highlighted that the NPC study
specified the need to push ahead on all fronts, which is what
[the sponsor group] is doing. The pieces of work for these
projects have to be prioritized, which is what's occurring now.
CHAIR SAMUELS recalled the [Qatar] example and posed a similar
situation in a Western democracy in which the [producer]
partners with the regulatory agency. He inquired as to [the
sponsor group's] experience in other governmental partnerships.
MR. GUERRANT said that in the early days, ExxonMobil
Corporation, Shell, and the Dutch government came together in a
joint venture to monetize the large field in the Netherlands.
In this venture, the parties own [it] throughout the chain, and
this venture has been successful. Recently, ExxonMobil
Corporation and Qatar are expanding the largest natural gas
field in the world, which is the North Field in the Middle East.
He noted that the country of Qatar is investing throughout the
[project]. Mr. Guerrant said that in the relationship with
Qatar, there are more advantages to the joint venture because
the groups have to be aligned as the process proceeds.
Furthermore, all the parties know the value of the product in
the marketplace. And although the aforementioned approach is
difficult, it builds trust. Such an approach is being utilized
with the producers in West Africa. Being aligned with a
government partner is overall a good thing because it allows the
[producers] to know what's going on throughout the life of the
project.
CHAIR SAMUELS announced, at 12:42 p.m., that the committee would
recess for lunch. At 1:30 p.m., Chair Samuels called the
meeting back to order.
Number 227
JOHN CARRUTHERS, Vice President, Upstream Development, Enbridge
Pipelines, Inc. ("Enbridge"), echoed earlier comments stating
that the Lower 48 market is large and growing. He said that
Enbridge recognizes the importance of Alaskan gas to those in
Alaska based on the attendance of these meetings. However, it's
more important for the Lower 48 consumers, who need to play a
role. Although there needs to be greater recognition of that
role, there are significant hurdles to achieve it. In fact,
Enbridge would be one of the players. In order to place
Enbridge's position in context, Enbridge participated as an
owner in the Alliance Pipeline System that moves liquid rich gas
from the western Canadian sedimentary basin to Chicago. The
aforementioned gas has characteristics similar to those one
would see in Alaska gas. Furthermore, Enbridge brings market
perspective to the table in that Enbridge is the owner of
Canada's largest LDC. In that vein, Mr. Carruthers turned to
the earlier concern regarding the viability of the indices. He
pointed out that Enbridge participates in those indices as a
buyer, and characterized the indices as generally a very
sufficient and sophisticated tool, though there has been some
improvement with regard to [the transparency of the indices].
As long as the [indices] are liquid enough, which can be the
case for Alberta and Chicago, it should be sufficient for
[Alaska].
MR. CARRUTHERS noted the following potential end-use shippers:
LDCs, power generators, marketers, large industrial users, and
government as a commercial entity. He then focused on LDCs
since they will be the key [end-use shipper]; as stated in a
Purvin & Gertz study: "LDCs are one of the few market
participants with the creditworthiness, client base, and
commercial interest to encourage investments with long-term
contractual support and/or equity participation. Their support
is required to ensure adequate gas supply in a timely fashion."
Mr. Carruthers opined that the aforementioned summarizes the
issue from a Lower 48 market perspective. He said that there
isn't much argument with regard to the need for gas in North
America. In fact, most studies would say that over the next 10
years, approximately 15 bcf a day of new supply is needed, which
would include Alaska's supply. What's important to note is that
Alaska gas can economically access a lot of the market, the
Midwest and Northeast in particular.
MR. CARRUTHERS turned to who could and who is going to take the
risk on a pipeline. If one thinks of the benefits to consumers
of an Alaska gas project with costs approaching $20 billion, the
benefits to consumers are far more [than the cost]. The NPC
study specified that consumers would see a price reduction of
$.60-$.80 for three to four years after the arrival of Alaska
gas to the market. Therefore, Alaska gas would be positive for
consumers in the amount of approximately $50 billion. He noted
that further studies have supported the aforementioned analysis.
Although Alaska gas would be approximately 5 percent of the
total supply, it impacts all gas. Mr. Carruthers specified that
some consideration should be given with regard to the volume and
the price that can be committed, as well as to contract length,
delivery points, and regulatory acceptance of long-term capacity
commitments. He noted that during the era when there was more
supply than demand, contract lengths were shortened and some
utilities were penalized for having long-term contracts.
MR. CARRUTHERS addressed market participation in supporting and
taking on some of the risk in Alaska gas. Marketers have played
a diminished role and they are unwilling to commit to long-term
contracts. Therefore, sellers would probably hesitate to sell
to marketers on a long-term basis unless they met some credit
hurdles. The LDCs would like to commit to long-term contracts,
but are restricted from doing so by public utility commissions.
In order to commit to a long-term contract, there must be
assurances that those contracts would be supported in future
rate cases. However, there have been cases in which there
weren't assurances and, as a result, there was an economic
impact. Based on today's market, there has been little
willingness to commit to fixed-price commodity contracts. It's
easier to have floating price contracts with the liquid hubs.
The aforementioned is exacerbated by the fact that Alaska gas
remains in the future. "So, you've got the added complexity ...
[of] going into a long-term contract but the first day of that
isn't for a few years, so that does make it even more
difficult," he opined. Even with the FERC's attempts to
streamline, there has been an increase in legal challenges
resulting in delay. However, the energy bill, should it pass,
addresses a number of those issues.
Number 320
MR. CARRUTHERS relayed that Enbridge does see a need for long-
term contracts. Although historically the producers have been
the one to take the position on the pipe, he opined that in this
case there is the potential, because of the significant benefits
to consumers and lack of known long-term resources, for the
consuming end to take a position on the pipeline. The
aforementioned would require a shift in policy. The NPC study
emphasized the aforementioned in the following quote:
New pipeline and storage infrastructure are generally
financially supported by long-term contracts for a
period of ten to twenty years. Companies are less
willing to invest dollars in needed infrastructure if
contract durations for existing or new
pipeline/storage capacity are shortened by the impact
of regulatory policies.
MR. CARRUTHERS said, therefore, that [Enbridge] has been
focusing on whether the regulatory policies can be changed such
that people could take a position. Because Alaska's resource is
large and well known, there isn't the risk that occurs in some
basins in which the gas still has to be found. He further
explained that in Alaska's case, the cost of the pipeline is the
market risk.
MR. CARRUTHERS moved on to in-state market participation, and
informed the committee that currently, Enbridge is actively
reviewing a spur line to Anchorage/Kenai. The spur line depends
upon the quality of gas on the market side, the projected growth
rate, and the existing infrastructure in terms of distribution.
If the aforementioned is considered during the initial
development of a gas pipeline, it could be more economic than if
it is simply an add on. Mr. Carruthers noted that Enbridge will
continue to also look at the Lower 48 market. He expressed the
need to reaffirm that Enbridge believes there is potential for
the market to share a risk in the Alaska gas pipeline by taking
a shipping commitment. Although it makes sense conceptually,
there are many regulatory hurdles that would be fairly time
consuming. "But we do think that does align Alaska and the
producers interests in the pipeline, and we could share risk
more broadly," he said. He noted that Enbridge is reviewing
that very notion to determine the amount of risk it might take
and under what conditions.
Number 365
SENATOR SEEKINS turned attention to the Enbridge slide entitled,
"Alaska Gas is Good for Lower 48 Market". He said he understood
Mr. Carruthers to say that delay in this construction project
raises prices for the consumer in the short-term. Would that be
the case in the long-term, if this project came on-line in two
years, he asked. If so, would it be in the best interest of an
owner of a large supply of natural gas to delay construction of
the project.
MR. CARRUTHERS replied no, adding that one would have to have an
expectation that prices will increase at an even more
significant rate. Mr. Carruthers said that he didn't expect
people to delay [construction]. Furthermore, if prices increase
too highly, demand will go offshore, from which it takes some
time to recover. High prices could also result in fuel
substitution or other "infrastructure builds." Therefore, if
people don't foresee Alaska gas on the horizon, more LNG, coal,
or nuclear may be developed. Mr. Carruthers opined that there
is some risk of waiting too long.
SENATOR THERRIAULT asked if there is anything that the state
controls in its regulatory scheme that could be problematic.
MR. CARRUTHERS reiterated that long-term commitments on gas have
been discouraged. In this era, he said, he believes the utility
commissions need to review things that support new sources of
gas.
SENATOR THERRIAULT posed a situation in which there is more of a
push for new power generation to use natural gas. However,
natural gas isn't tied into long-term contracts, and this
results in price fluctuations. The American consumer is
accustomed to, and expects, a very level price per kilowatt from
the producers. He asked if that dynamic will have to change as
more generation moves over to natural gas, and therefore moves
to more long-term contracts in order to ensure stability.
MR. CARRUTHERS opined that consumers would become more and more
frustrated with the high prices and the volatility, both of
which are [reduced] by long-term secure sources of gas, adding
that Alaska provides the aforementioned.
Number 435
TONY PALMER, Vice President, Alaska Business Development,
TransCanada Corporation, began by reviewing gas prices. He
informed the committee that the long-term forecasts of NYMEX for
natural gas is in the $3.00-$6.00 range and most forecasts
converge near $4.00 after the current price spike subsides. He
then turned attention to a graph on page 3 of his presentation,
which is entitled "Comparison of Recent NYMEX Gas Price
Forecasts." The graph provides forecasts from the NPC Balanced
Future, the NPC Reactive Path, TransCanada, DOE AOE 2004, and
six consultants. Although he didn't believe any party would say
that the prices can never go outside the $3.00-$6.00 range, he
said he would agree that the price would generally converge
within that band. As the graph illustrates, the majority of the
forecasts are in the $4.00 range in 2002 dollars.
MR. PALMER said that gas demand continues to grow, although
current high prices are causing some demand loss, primarily in
the industrial market. The expectation for long-term net growth
continues to be more than 1 percent, and this is significantly
influenced by power demand. He noted that the US and Canada
demand growth from 2003-2015 is in the 15 bcf a day range. The
graph on page 5 of the presentation provides a visual indication
of various forecasts. The graph illustrates that demand has
historically been in the 70 bcf a day range for the last five or
so years, and a common forecast projects growth to 80-85 bcf a
day in 2015.
MR. PALMER focused on the Western Canada gas demand, which is
illustrated in a chart on page 6 of the presentation. In 2003,
the Western Canada demand was at 4.4 bcf a day. Over the next
decade, the primary sources of new demand growth will be
electric generation, minable oil sands, and in situ heavy oil.
There are modest increases for residential, commercial, and
other industrial demands. Mr. Palmer turned to oil sands gas
demand, which is a source of large demand growth. From the
graph on page 7 of his presentation, he remarked, one can see
that [TransCanada] has modified its gas demand in the oil sands.
With the use of existing technology, current growth would range
from volumes in 2003 of just above .5 bcf a day to 2.5 bcf a day
without technological improvements. He noted that there are
initiatives by a number of oil sands proponents to use the
actual bitumen as a fuel source by upgrading it. The graph also
illustrates TransCanada's change in forecast from 2003, which is
significantly moderated from a year ago although it's still
growth.
MR. PALMER moved on to the North American gas supply, and
pointed out that the supply/demand is precariously balanced.
Furthermore, new supply sources are required, but the only
growth basin TransCanada sees are in the Rockies, although there
is some modest growth on the East Coast. Moreover, existing LNG
terminals are operational again and are planning expansions. In
fact, there is either a plan or approval for expansion for about
2.3 bcf a day at the existing terminals, which have capacity of
about 2.5 bcf a day. He noted that the MacKenzie gas is on
track for 2009 in-service. Mr. Palmer directed attention to the
Lower 48 dry production forecast comparison. Over the last
decade, the Lower 48 supply has been in the 50 bcf a day range.
Going forward, the US Department of Energy EIA forecast is very
optimistic in it's forecast of growth toward 57 bcf a day. The
aforementioned forecast is very different from most every other
forecast.
MR. PALMER directed attention to page 10 of his presentation,
entitled "WCSB [Western Canada Sedimentary Basin] Production
Forecast." The graph illustrates TransCanada's predicted
decline from 16.9 bcf a day down to 16.3 bcf a day over the next
decade. Basically, the production would experience a modest
decline, with some replacement of conventional gas with
unconventional gas - coal bed methane. Page 11 of the
presentation illustrates why the Western Canadian supply may be
flattening over the past decade in the 250-275 tcf range for
most every forecaster. Page 12 of the presentation specifies
TransCanada's view of the supply change. The green section of
the graph illustrates that if one takes the WCSB, the Lower 48,
East Coast, and existing LNG terminals plus expansions, it is
fairly steady in terms of overall supply to the market. The
aforementioned combination will be able to supply in the 70 bcf
a day range and modestly decline beyond the year 2015. The
aforementioned leaves an opportunity for new LNG and northern
gas.
MR. PALMER continued with page 13 of his presentation, which
reviews global LNG. Global LNG could fulfill 100 percent of the
supply gap. Clearly, MacKenzie and Alaska gas are competitors
for that market opportunity as is other domestic gas that was
mentioned earlier. The existing [LNG] terminals have about 2.5
bcf a day of existing capacity and expansions in the 2.0 bcf a
day range have been announced. Furthermore, there are proposed
or approved projects for more than 30 bcf a day. TransCanada
believes that those projects have a fixed cost structure
comparable to Alaska gas, but they have scale advantages in that
these [LNG projects] can be built in smaller modules than the
Alaska project. The modules for these [LNG projects] can be
0.5-1.0 bcf a day whereas an economic increment for Alaska gas
is nearer 4-4.5 bcf a day. Mr. Palmer informed the committees
that today, those facilities need liquefaction facilities in the
producing country, [as well as] ships and re-gasification.
TAPE 04-22, SIDE A [BUD TAPE]
001
MR. PALMER continued:
Those issues are being resolved, slowly - some people
would say - but in our view, as more and more projects
get approved, project four, five, and six will be
easier than [projects] one, two, [and] three. The
large stranded gas reserves available worldwide:
you've heard representations from others as to ...
[the] magnitudes of those volumes available to the
market, and they have strong support of their home or
host governments. To show you a forecast - on page 14
- [is] a representation of a number of forecasters as
to the actual magnitude of LNG into the marketplace.
I would point [out] to you that the black line here is
the [U.S.] Department of Energy - they have just over
8 bcf a day of new LNG, and I believe they have only 8
bcf a day ... because they have a very optimistic
Lower 48 market. They have balanced the market, with
the remainder being LNG. You can see that the balance
future for the NPC [National Petroleum Council] also
has both "Mackenzie" and Alaska in this timeframe, and
they have in the order of 9 bcf a day. Other parties
have in the order of 10 to 12 bcf a day of LNG in
their forecast.
The next slide, which is a ... [Federal Energy
Regulatory Commission (FERC)] map published in July
just indicating to you ... [that] at that time, there
were 44 projects proposed or approved in the Lower 48
- that's in addition to the existing terminals with
approved expansions. About 5 bcf a day, today, has
received approval from either the [U.S.] Coast Guard
or the FERC. ... [This is] just a representation of
the compensation in effect in the LNG market and for
the marketplace.
And to wrap up, ... we believe the U.S. and Canada
market opportunities [are] in the 10 to 15 bcf a day
range for new gas sources through 2015. You will see
[that] some parties may have it slightly below 10 and
some parties will have it slightly below 15. And ...
if I were to exclude the U.S. Department of Energy,
most people would be in the 15 bcf a day range -
that's the market opportunity if gas prices are in the
$4 range. Clearly, if you have prices higher or
lower, you change that market opportunity.
"Mackenzie" gas appears on track for about 1 bcf a day
by 2009.
Number 029
MR. PALMER went on to say:
As I said earlier, the new LNG re-gas sites ... have
had approval in the order of 5-plus bcf a day by the
FERC and the U.S. Coast Guard, and that leaves, in our
view, a competition between the Alaska gas pipeline in
the order of [4.5] bcf a day and 25 bcf a day of
additional proposed global LNG projects. Those
projects, in our view, will compete for the remainder
of the supply gap, and if they over or under supply
the market in total, they will affect market prices,
and that will affect demand overall. ...
That's clearly what will happen. We believe that
there will be a "first mover" advantage for those
projects able to get a green light in the near term,
and once those projects are in service, they are long
service projects; they could be expected to supply gas
into the market place for 20 or 30 or more years, just
as "Alberta gas" has served the market for 50 years
and [Lower 48] gas has served the market, now, in the
order of 75 years. These are long service projects
with good gas supply behind them. Mr. Chairman,
that's my presentation, thank you for this
opportunity.
SENATOR SEEKINS surmised, then, that unless Alaska gas is
visible to the marketplace in the near future, it could never be
viable in the marketplace. In other words, the LNG expansion
will fill the demand such that Alaska gas is no longer needed.
MR. PALMER expressed reluctance about characterizing the
situation in that manner. He added:
What I'm saying is that if we're seeking to hit the
market for this project by 2015, ... I believe there's
a competition between this gas and global LNG. And
clearly those projects are competing to attract market
and to obtain sighting and to complete their projects
[just] as Alaska is. And I believe that the parties
that are approved first have an advantage. I'm not
suggesting to you that they are the only ones that can
be constructed, not at all. But clearly they have an
advantage if they're approved by their regulators
[and] ... project proponents and they're going
forward. They, as you've heard other people represent
to you, may affect the way other people will play in
the marketplace.
Number 059
REPRESENTATIVE GARA asked:
At what point in the Stranded Gas Act application
process do you have to have an agreement from the
producers to actually sell the gas to you so you can
decide to build the pipeline? ... At what point can
you not go any further in deciding whether or not
you're going to build a pipeline? By when do you need
to know, in the process, that you'll have gas made
available?
MR. PALMER replied:
TransCanada, at this point in the stranded gas
negotiations, is negotiating in effect what level of
taxation ... the government of Alaska will apply to a
pipeline project. So we can continue with that, and
are continuing to do that. But we need to have a
customer, we need to have a shipper for this project,
to make it proceed. And we'll continue to try to
attract the North Slope producers as well as other
(indisc.) producers to become our customer, or other
parties. And we will reach a point where we will not
be able to proceed any further. We are also, as
you're aware, proceeding to try to obtain the state
right of way; that's also meaningful work that we are
going to continue with because we think that that will
accelerate the project when the commercial deal is
ready to go.
We've also said publicly ... that if there's a
commercial deal [that] can come together in 2005, we
can have a project in service in 2011-2012. But
there's about a seven-year timeframe between reaching
a commercial deal, and by that I mean [having] ... a
customer, and having a project in service. If we do
not complete work like the Stranded Gas Act
negotiations and the right-of-way negotiations, that
would extend that timeframe. I'm contemplating that
we would complete that work by 2005, we hope, and be
in a position to move forward on a seven-year basis if
there are commercial parties ready to sign
transportation contracts with us.
Number 080
SENATOR ELTON asked whether there are things the state can do to
encourage producers to ship gas in a pipeline built by
TransCanada.
MR. PALMER replied:
I would say that the state completing its negotiations
on [the] stranded gas Act items like what royalty take
will be, what you're production take [will be], is a
fair thing to ask - completion of that is something
that is appropriate that the state can do. The state
defining its overall fiscal issues is an appropriate
thing for you to do. And the state, in our view,
needs to consider how best you ... can encourage the
overall project to proceed, and that's everything from
encouraging producers to become a customer on the
pipeline to deciding if the state has the appetite for
any of the risk components you heard testified to by
some other participants this morning.
SENATOR ELTON asked: "Are you avoiding reserves tax on
purpose?"
MR. PALMER replied: "I wasn't avoiding it on purpose. Clearly
... I don't profess to be an expert in what taxing authority the
state of Alaska has, but clearly the state has a number of tools
at hand that it can decide to use. You have everything from
carrots to sticks, and I don't profess to give you advice as to
how best you should do that."
CHAIR SAMUELS asked what the timeframe is of the competitors for
capital dollars on LNG projects.
MR. PALMER offered that it might be a five-year timeframe,
though the issue is really one of, "Can you ... get [sighting]
with access in the Lower 48?" He relayed that such can take a
considerable amount of time - perhaps as long as two years for
approvals of 5 bcf a day - and this needs to be factored into
the timeframe calculations; this project has, if not the
longest, then nearly the longest lead time due to the magnitude
of the project.
Number 120
EDWARD M. KELLY, Vice President, North American Natural Gas and
Power, Wood Mackenzie, relayed that Wood Mackenzie would be
considered consultant number two or three in the previous
presentation [provided by Mr. Palmer]. Mr. Kelly mentioned that
his presentation offers greater detail on some of the supply and
demand factors previously spoken to by other presenters. Gas
prices, now, are responding very directly to oil, and this is
both a psychological and a fundamental reality with regard to
the way markets are working now, he remarked, adding that Wood
Mackenzie expects that linkage to continue, fairly consistently,
due to that fact that there is approximately a trillion cubic
feet of market that can switch from gas to oil products at
various pricing levels.
MR. KELLY said that on the low price side, that's gas to
residual fuel oil, and on the high price side, that's gas to
distillate fuel oil. So either way, if gas moves into those
alternative fuel prices - moves in one direction to compete
against those alternative fuels - it tends to lose approximately
a trillion cubic feet in annual market, and that's a strong
force keeping gas bound in close relationship with oil. In
addition, they're both traded on the NYMEX [New York Mercantile
Exchange], and that creates a strong psychological linkage
factor - excitement in one pit tends to lead to excitement in
other pits. Also, noncommercial interests are trading both sets
of products at once, so there are psychological correlations
there as well. He said that from a fundamental standpoint, for
the next decade or more, Wood Mackenzie doesn't see that
changing a great deal - "there's not so much gas sloshing around
that gas can price consistently below the level of oil
products." With regard to outlook, as goes oil in the next 10,
15, or more years, so goes gas, he predicted.
Number 157
MR. KELLY then referred to page 3 of his presentation, and said
it focuses on the Organization of Petroleum Exporting Countries
(OPEC) spare production capacity, which is set to grow. He
pointed out that in the third quarter of this year, spare
capacity for "OPEC-10" was approximately 800,000 barrels per
day, which is not a lot in the context of a 29-million- to 30-
million-barrels-per-day OPEC production capability. Still
referring to page 3, he pointed out that spare capacity for
"OPEC-10" in the fourth quarter was approximately 2.2 million
barrels per day, and suggested that one could expect spare
capacity to expand a great deal. Geopolitical uncertainty being
what it is, he remarked, oil prices can sustain at high levels
due to psychological factors and the reality of geopolitical
uncertainty; nonetheless, spare productive capacity is set to
increase substantially in the fourth quarter of this year.
MR. KELLY referred to page 4 of his presentation, and said that
as a result of [this increase], the oil price outlook does tend
to decline significantly, beginning in the early part of 2005.
Price outlooks for natural gas, he remarked, assume a long-term,
real, oil price outlook of about $22.75, in 2004 dollars, per
barrel - that's for Wood Mackenzie's West Texas Intermediate
(WTI). At that price level, he noted, the gas price range is
very consistent with that which has been presented by previous
speakers - a gas price of between $3.50-$5.00. This is based on
competing oil products in the end-use market in much of the U.S.
In addition, one must also consider what is on the margin for
supply. He relayed that Alaska gas would not be competing with
LNG so much as with the cost associated with sustaining U.S. and
Canadian production.
MR. KELLY said he concurs with some of the figures provide by
prior speakers with regard to declines in North American
production, adding that the cost associated with replacing 16
bcf per day of North American production essentially sets the
floor price for natural gas. Therefore, if the cost associated
with replacing that amount of production is $3.00, for example,
then a price above $3.00 will encourage the drilling necessary
to get that 16 bcf a day produced. Evidence in the marketplace
now suggests that as prices decline below $4.00, a lot of
activity "came off," which implies very strongly that at that
point, in 2002, the cost associated with drilling many of the
marginal wells in North America was between $3.50 and $4.00 per
million Btu [British thermal unit]. This sets a pretty strict
long-term floor price for gas, he remarked, under current
drilling costs regimes, under current technology, and once the
price declines below the cost of drilling marginal wells, native
supply will decline pretty fast.
Number 231
MR. KELLY, on the issue of risk that Alaska and producers might
face, indicated that residual fuel oil can also be a factor in
setting the floor price - currently that is $3.00 to $3.50 in a
$23 oil environment. Also, the cost of replacing production can
be a factor, as can the type of technology being used. As
technology improves and producers are able to extract more
product, the floor price could decline as a result. He remarked
that Wood Mackenzie is of the view that North American
productive capability can be sustained as long as gas prices
remain high enough to encourage marginal drilling, but that will
require $3.75 to $4.00 gas under current conditions. He noted
that various entities predict a range of Lower 48 production
declines, and Wood Mackenzie is about in the middle of those
predictions.
MR. KELLY detailed some aspects of Wood Mackenzie and the work
that it does. He mentioned that the nature of production and
the location of production will change over time. Also, changes
in location will affect changes in the nature of production.
For example, production could shift from historically defined
conventional reservoirs with better porosity, better
permeability, to unconventional reservoirs, which are
historically defined as relatively tight reservoirs, coal bed
methane (CBM), and shale. These unconventional reservoirs will
make up over 40 percent of U.S. production by the year 2010, he
predicted, whereas current production of these unconventional
reservoirs ranges in the upper 20 percent.
MR. KELLY detailed aspects of the "Rocky Mountains," mentioned
that the obstacles to increasing production are becoming more
meaningful as the opposition to drilling activity becomes more
organized and efficient, recounted some of the efforts put forth
by those in opposition to drilling, and noted that the risk
associated with attempts at increasing production is sometimes
dependant on the pace at which drilling can actually occur. He
also mentioned that almost all of the increase in the "Rocky
Mountains" will be from unconventional sources.
Number 278
MR. KELLY indicated that with regard to Canada and Mexico, there
is similar outlook through 2010 and beyond. Currently, the U.S.
is exporting about 1 bcf per day into Mexico, even at $5.00 to
$6.00 prices, but that should decrease due to Mexico importing
LNG. He relayed that Wood Mackenzie expects the flow between
the U.S. and Mexico to reverse by the year 2010, though this
reversal won't be the result of an increase in native Mexican
production. He mentioned that Mexico's upstream industry is the
most closed in the world; at this point, it is virtually
impossible in Mexico to get effective private investment in
drilling. Mexico's potential to increase beyond 2010 depends on
structural change in the Mexican upstream; if such a change
occurs, Wood Mackenzie's production outlook for Mexico could be
substantially exceeded, and this could provide a critical
increment of supply into the North American marketplace, though
it won't solve the gap.
MR. KELLY referred to page 11 of his presentation, and said that
Wood Mackenzie's view on LNG and Arctic projects is that they
are highly unlikely to fully address the supply/demand gap.
Although the number of proposals has exploded in recent years,
there are a couple of limiting factors that intersect, the first
being the availability of liquefaction capacity on the upstream
end, the second being re-gas permitting capability. Each re-gas
project that's permitted has to have a supply source, but
suppliers aren't necessarily rushing to do business with a re-
gas project just because it's permitted, especially since some
permitted re-gas facilities are expensive. "You've got to have
both to make an LNG value chain work," he concluded. He
mentioned that Wood Mackenzie anticipates that by 2010, there
will be 6 bcf per day of LNG, total, in the U.S. main grid.
MR. KELLY remarked, "Our assumption on Alaskan gas, in our
models, is 2015; that's a modeling artifice ... based on
feasibility." One reason that many are rushing to build LNG
facilities is that the cost basis for delivering LNG into a re-
gas facility on the East Coast varies between $1.00 and $3.00,
so there is a lot of money in the remainder of the value chain.
This [cost basis] already assigns, to the producers, a 12
percent rate of return towards the upstream activity necessary
to get the LNG into the ship. Although doing something similar
on the West Coast is somewhat more risky, it has attracted a lot
of LNG development interest. He mentioned that LNG will
continue to be a seasonal fuel for a long time to come because
Asian and other markets have no storage; since LNG [delivery] in
those regions has to ramp up in the winter and ramp down in the
summer, this leaves a lot of cargoes available for summer
delivery to other places such as the U.S.
Number 356
MR. KELLY said that the supply/demand gap in the U.S. is large
enough that it won't be satisfied only by either Alaskan gas or
LNG, particularly given that the speed at which an LNG value
chain can be built is somewhat limiting. Also, the U.S. gas
market is limited by the number of molecules available to it; it
would be much larger today if there were more molecules
available to it. That limitation won't be overcome in the
future, he predicted; instead, the gap will only get wider. He
also predicted that although there is currently an overbuild of
gas-based power generation facilities, more such facilities will
have to be built beginning in 2010 in order to meet increased
regional demand; he characterized natural gas as the default
source for the majority of those yet-to-be-built power
generation facilities.
MR. KELLY said that this is an organic growth in gas demand that
is dependant on the growth of the economy, though the U.S. is
consuming electricity much more efficiently and is not devoting
energy to industrial usage as much as it had been in the past.
He predicted that economic growth to energy usage will drop to
3:1.6, though regardless of this drop in increasing power
consumption, demand will continue to increase depending on
regional differences and seasonal changes. He went on to detail
some of the uses for gas consumption, for example, in the making
of steel, fertilizer, and paper. Broadly speaking, he remarked,
this year is a strong year for industrial gas consumption,
though it may be the last strong year for a long time to come.
Referring to page 22 of his presentation, he relayed that the
average "Henry Hub Spot Price Outlook" for 2005 is listed as
$5.36 per mmBtu [million British thermal units], though that
depends very strongly on a "$35 oil price."
MR. KELLY said that through 2010, it will be difficult to
sustain gas above $4.00. He spoke of residual fuel oil and
distillate fuel oil, and mentioned that gas gets priced between
those two and that roughly a trillion cubic feet (tcf) of demand
would go away if gas "went below [residual] or above
distillate." Referring to his presentation, he stated:
Longer term. Flat picture for supply. With Alaska,
again, by assumption, coming in at 2015. This
requires, again, that $3.75 to $4.00 minimum kind of
price to sustain a heavy pace of drilling to replace
that 16 billion cubic feet a day each year; that heavy
pace of drilling has to continue to sustain U.S. Lower
48 and Western Canadian supplies, and that's the floor
price setter for much of our gas price outlook - [it]
is the price required to sustain that level of
drilling.
Number 0488
MR. KELLY mentioned that a heavy effort will be required to
sustain Western Canadian production, though there will be a
slight increase in Eastern Canadian production through 2011-2012
due to "Arctic Canada" coming in. He predicted that Mexican
production can increase, though that will depend very much on
the structure of the business. Referring to Mexico, he
mentioned "privatized upstream structure," "multiple service
contract structure," and that Mexico suspects the U.S. of
draining some reservoirs that are co-terminus with Mexico's
portion of the deep water Gulf of Mexico. He concluded that
Mexico has strong incentive to either allow a private structure
or gain the expertise to access its own reservoirs, and
predicted that it will be "a leftist" [government] that will
allow such structural change.
MR. KELLY said that something to be aware of is that
politically, "we" don't like to drill, and yet any of the
anticipated increases that he's mentioned are based on the
premise that drilling will continue. From a geological
standpoint, uncertainty exists in "the deep water," though from
a financial standpoint, "the financial stars have aligned for
producers" and this has resulted in the kind of [drilling]
activity currently taking place. Currently, long-term capital
is plentiful, cheap, and available; this is because, relative to
other sectors of the economy, producing energy is "somewhat hot"
and the investor community is a very trendy and fickle
community. "Right now, it's the best of all possible worlds for
getting capital into the North American upstream, [but] that can
change," he remarked.
TAPE 04-22, SIDE B [BUD TAPE]
Number 001
MR. KELLY, referring to "our" LNG outlook, said that an
impending reality of an Alaskan gas pipeline would make other
markets more attractive to LNG producers and would cause a
slowdown in the increase in LNG deliveries directly into the
North American continent. By the year 2020, the power sector
will reign, he predicted, unless and until an alternative means
of producing electricity is found or until there is a
revolutionary shift in patterns of energy consumption. "We need
the stuff for power generation, and power generation becomes by
far the largest consuming sector by 2020," he remarked. He
mentioned that Canadian demand is similar though Canada has a
strong industrial demand as well.
Number 019
SENATOR THERRIAULT asked what the effect will be of "purchasers"
going to longer-term contracts and whether this has been
factored into possible price stability.
MR. KELLY said it is difficult to foresee that there will be
longer-term fixed price contracts for the natural gas commodity.
He pointed out that when the Enron Corporation fell, the ability
and willingness to take that kind of long-term price risk fell
with it. The ability to "hedge forward" is a real service that
requires a great deal of credit behind it. He predicted that
utilities will hedge a portion of their gas price portfolio in
order to limit [price fluctuations], and mentioned that he'd
received a hedged deal from his competitive service provider in
Texas that he'd taken advantage of. He suggested that [the
state] will have more choice than it will know what to do with
in the sense that some will provide a high fixed price and
others will provide a floating price; the latter is already
occurring at the "small customer" level. He opined that the
ability and willingness to sign long term fixed price deals will
not emerge as a major aspect of the supply business, though it
may be a part of a portfolio strategy for producers and
consumers.
MR. KELLY, referring to page 37 of his presentation, said that a
strong catalyst to demand is the fact that a lot of the coal
infrastructure is "old stuff," as are a lot of the oil and gas
steam units. So by the time an Alaskan [pipeline] came on line,
"you're" going to be retiring fairly significant amounts of coal
units, which must be replaced "one for one." Additionally, the
likelihood that there will be a coal shortage east of the
Mississippi River and Illinois/Indiana border is real, so even
if new coal-burning plants are developed, there may not be
enough coal to supply them. Referring to page 39 of his
presentation, he said:
The middle two bars are gas fired, so you've got
another 150,000-plus megawatts of new gas-fired
generation by the year 2020, assuming that somehow we
build 80,000 megawatts of coal-generation. And it
will be very clean-burning coal relative to what coal
is today, but that's a lot of coal, that's a lot of
time, [and] a lot of permitting efforts required.
Number 066
MR. KELLY remarked that "we're stuck on fossil fuels," so any
risk the state might face by taking ownership of a pipeline and
taking royalty in-kind (RIK), or taking a contract position on a
pipeline, would be based on whether "we're" still dependant on
fossil fuel consumption. Currently, he remarked, "we need more
gas, ... and we need more ... than even LNG and Alaska are
likely to provide." He predicted that in real 2004 dollars, the
price will hang above $4.00 until an Alaskan pipeline is brought
online, at which time the price will drop by about a $1 over two
years due to annual declines not being replaced. He concluded
that with regard to the state taking a contract on a pipeline,
or having ownership of a pipeline, it's difficult to see the
state's cash risk as being anything more than minimal unless
there is some significant, fundamental transformation in the way
North America consumes or produces energy.
REPRESENTATIVE GARA asked whether bringing Alaska gas to market
will have a long-term impact on Lower 48 gas prices.
MR. KELLY predicted that after the first four to five years
after Alaska gas comes to market, the price will begin an upward
trend that will continue. In response to another question, he
said, "I wouldn't characterize it as a race between Alaskan gas
and LNG, because it's just difficult to see LNG accumulating
fast enough to drive gas prices down below competing products,
to result in a North American supply that's great enough for gas
to recapture oil-based markets."
REPRESENTATIVE ETHAN BERKOWITZ, Alaska State Legislature, asked
whether any consideration has been given to the role that gas-
to-liquids (GTL) might play in terms of filling markets.
MR. KELLY said that Wood Mackenzie has addressed GTL as a
monetization option for stranded methane pools worldwide. He
mentioned that because the western world is relatively energy
short, there is every incentive to invest in whatever means can
monetize distressed methane pools worldwide, and so GTL will be
used.
Number 0161
RICHARD BONE, Director, State Energy Marketing Program, Texas
General Land Office (GLO), offered a [PowerPoint] presentation
and said that he would speaking about Texas's "take in-kind"
program, public customer gas program, and state power program.
He went on to say:
The take in-kind program ... was started in 1983
through state appropriations bills. The program
operates by taking royalty payments in [the] form of
production instead of receiving monetary payments.
The program then sells the mineral interest, oil or
gas, to customers, either retail customers or
wholesale customers. The program contracts out with
mainline transportation and local distribution
companies throughout the state of Texas. What I mean
by that is, we hold approximately 26 different
contracts with either intrastate, interstate, or local
distribution companies to get service all the way to
the end users.
Natural gas value is established by using ... location
differential pricing points around Texas that are then
equated back to ... Houston ship channel [prices]. In
Texas we have several receipt points for natural gas
... or oil, and ... one of those points is very
liquid, which is Houston ship channel. So basically
we have production in West Texas, South Texas, some in
the Panhandle, and some in East Texas. What we do is,
we've [taken] historical differentials off of each one
of those locations and did a comparison back to
[Houston] ship channel [prices] to try to arrive at a
price for the sale of the product. ...
Oftentimes, the product price is actually lower than
NYMEX. In 1983, state agencies were directed to
reduce their utility cost by buying lower priced gas
that was being produced on state lands - that was one
of ... the effects of the whole bill. [General Land
Office] contracts went into effect in 1985 for state
agencies; in 1985 we had contracts with 33 state
agencies. That included our largest customers which
[were the] Texas Department of Criminal Justice, [the
Texas Department of Mental Health and Mental
Retardation (TDMHMR), the Texas Department of Public
Safety (DPS), and the Texas Department of
Transportation (DOT), among others].
Number 194
MR. BONE, referring to his presentation, said:
This is a list of some of our producers that we
actually have agreements with to take natural gas and
oil from; all these producers are either on state
lands or in what we call the "8(g)" territory, which
is a [common] royalty share territory between Texas
and the U.S. government. [With regard to the] type of
contracts, we use several different types. One is
[an] "interlocal" contract; that's between the General
Land Office and other sister agencies or other state
agencies such as universities.
The second one is [an] interagency, which is between
state agencies. You'll notice there that [it says]
"Last Look" ...; what that means is ... [that] the
General Land Office has the right to look at the
contract prior to it being signed by any state agency
to see if we can get a better deal for them. If they
go out for an open bid and we believe our gas can be
sold cheaper and [transported] ... to them cheaper,
then we have the right to come in and actually bump
the competitive bid and take the business. We do
[North American Energy Standards Board (NAESB)
contracts], which is a standard in the gas business
these days.
One of the questions that was asked of me was who
negotiates contracts for the General Land Office. The
staff has traditionally always negotiated all
contracts for the General Land Office. We more or
less take care of the day-to-day business, we "notice
up" the oil producers for natural gas and oil, we work
with the agencies, we work with our wholesale
customers [and] our buyers of our excess natural gas
and oil, and then, when it comes down to it, we send
it up for the commissioner for signature. ... Who are
our wholesale purchasers? Some of the larger names in
Texas: "Reliant, Houston Pipeline, Energy Transfer,
Kinder Morgan, Formosa, CrossTex, Trammo." "Trammo,
Plains, [Sunco], and Sempra" are our oil buyers -
they're the ones that buy about 750,000 barrels of oil
a year from us.
Number 223
MR. BONE, on the issue of pricing models, said:
Over the last three years, our pricing model has
changed significantly. I was hired three years ago
... and my job at that time was to treat the program
and try to make it more like industry. In other
words, [mirror] ... the current marketing practices
[of] the natural gas business and the oil business.
When I came on board, ... the model we had was,
basically, we would just sell it for a price
equivalent to what we were getting [in] royalty
payments. Part of the legislative appropriations bill
stated that we were actually supposed to enhance that
value - not just take it, but actually enhance it.
The way we did that is through several different
methods. One, we streamlined transportation
agreements all across the state with a network of
pipelines to try to get our gas from one location to
another in a cheaper way, maybe by swapping it from
one location; [for example], ... if we had gas in far
South Texas ... [and] "Kinder Morgan" ... needed that
gas to go into Mexico, then we would ... swap that gas
... [to them and they would] give it back to us at
Katy, which is a more locational sensitive point for
us to get to our customer base.
With that said, we continued to move from there and we
went to a market-based pricing. And what I mean by
that is, ... we actually looked at the market, we
trended what the current marketing companies were
doing in Texas ..., and we really went after that same
type of market. So what you actually have is ... a
state agency more or less competing in a deregulated
market .... We also used ... differential base
pricing points. ... [And] a lot of our product is
competitively priced; in other words, ... we don't
have a lot of our gas exposed to high-risk maneuvers
in the gas market, we're not in the business to
speculate on what it may be ... six months from now.
Our fiduciary duty for the [General] Land Office is
directly to the [Texas] Permanent School Fund, so we
have to be as risk adverse as possible. And the other
... pricing model ... is "request for proposal" [RFP]
pricing: we'll actually go out once a year to sell
our oil. We have some very specific things we do with
our oil; we sell our oil to the four [entities] that
we mentioned earlier, and ... we ... ask them to ...
give us the payment in natural gas at a point that we
request ....
Number 261
MR. BONE, on the issue of annual revenue, referred to his
presentation and said:
You can see that we've grown somewhat. In [fiscal
year (FY)] 02, there was a drop, more or less, in the
market ... for natural gas and oil prices that
somewhat ... put a dent in the program ... [though]
volumes were still up. The percentage point on the
right-hand side of the screen actually represents the
percent royalty versus "take in-kind." In other
words, ... in FY 01 we took 45 percent of our natural
gas in-kind versus [55] percent in royalty. ... Total
gross production for the state of Texas is about ...
150 bcf on state lands. Of that, we take
approximately 15 percent. That's about [an] average
royalty.
[With regard to] annual volumes, you see [that it has]
significantly increased from FY 01: 16 bcf; 788,000
barrels of oil. Our oil program, because of the
reservoir activity in Texas, has ... been dropping
fairly steadily. ... [We're still] doing a lot of
exploration; however, the reserves we're finding are a
lot smaller and they're ... being depleted a lot
quicker. Expected gas for FY 04 is about 36 bcf, so
basically what we've done since FY 01 [is] ... more or
less doubled the size of the program as far as gas.
How do we pay for this program? ... What we do is we
... have an administration fee; we actually charge a
fee of [$.03] ... on every mmBtu of gas that goes
through our program, whether we buy it in the market
or whether we take it in-kind.
In addition to that, we charge a [$.05] per barrel ...
administration fee. What that does is it goes to our
comptroller and then it's redistributed to the general
land office for it's administrative program during the
year, specifically for the state energy marketing
program. [With regard to] state energy marketing
customers, we have a wide spectrum of customers. We
supply gas ... and electricity to city and county
governments, school districts, and other customers.
... From the gas side, we now serve about 587 meters
at 24 universities, 2 school districts, 1 city, 39
prisons, and 18 state agencies. ... I would say we're
the largest supplier of natural gas to public retail
customers in Texas. We sell gas or oil to 10
wholesale companies or oil companies and over 26
pipelines and [local distribution companies (LDCs)].
...
Number 307
MR. BONE added:
In 1986, we took approximately 2.2 bcf of gas, [and]
we saved state agencies over $1.1 million. In 1991,
the legislature expanded the program to give us the
last look that we talked about earlier. In FY 03, ...
the annual volume was 25 bcf, total ... gross revenue
was $119 million, and savings to our ... public retail
customers ... was $62 million a year.
MR. BONE relayed that the state power program was authorized in
1999 by the 76th legislature via a comprehensive electric
restructuring bill. This included authorizing the state power
program to sell electricity via exchanging minerals from state-
owned lands for electricity. He went on to say:
We started that program a full year and a half before
deregulation in Texas; it's been very successful. The
state power program ... began in June of 2000, full
competition started in January of 2002. The mandate
within the [legislation] ... says that we must take
in-kind royalties from state mineral production, maybe
convert it into other forms of energy, including
electricity, for sale to public retail customers. ...
Let me define public retail customers: that is a
city, county, ... school district, ... university, or
other state agency. More or less, any taxing entity
in Texas, we have the right to sell electricity to.
We don't sell electricity to [restaurants, for
example, only to entities] where public tax dollars
are used to pay the bills - that's all we do.
Number 339
MR. BONE relayed:
These royalties are also defined as royalties from
[Permanent] University Fund lands - ... in Texas we
have a Permanent University Fund administered by the
"UT systems," which basically takes control over the
oil and gas on lands that have been granted to the
universities - and also [from] ... the Outer
Continental Shelf known as the "8(g)" and that's the
common area I talked about earlier that's shared
between the state of Texas and the federal government
- it's a three-mile-wide strip on the edge of our
territory.
The program objectives [were], one, to increase
revenues to the [Texas] Permanent School Fund, which
we have done to the tune of about $32 million since
1999 - that has been what we've contributed as far as
electricity proceeds - [and] 100 percent of the
proceeds go directly back to the [Texas] Permanent
School Fund; [two], utility savings to public retail
customers combined with natural gas savings ... -
that's about $62 million in savings for public retail
customers, mainly school districts ...; and [three],
to share the experience of competition in the retail
marketplace prior to and continuing through
deregulation.
What we found ... was that the average retail person
... [doesn't] have the expertise ... to know where the
market's going, what it's doing, [and] what different
product types [are available], so ... we kind of lead
the state agencies and the public retail customers
through that process all the way to contract and
delivery. ... In the last [legislative] session ...,
the commissioner ... was able to have military bases
and federal veterans' facilities added [to the
program]. ... We've successfully ... contracted with
two separate military bases in Texas ... and we're in
negotiations for others at this time.
Number 360
MR. BONE continued:
The state power program originally focused [on] and
currently serves many of the independent school
districts ... and other public retail customers in the
Houston area. ... Today, under deregulation, we serve
customers in all areas that are currently deregulated
by the public utility commission. We had 93 customers
prior to deregulation, we've added [or re-signed] 180
customers ... under the new market value contracts.
... Prior to deregulation, we simply gave the public
retail customers a discount off of their tariff rates;
after deregulation, we actually started competing ...,
through RFP responses, with all the major marketing
companies in Texas. ...
We have to take more gas, every day, off of our state
lands to provide more power to our customers, so we
felt this is a good way to kind of demonstrate the
effect of natural gas on the electric market as we see
it. ... We now serve 238 school districts in Texas -
that's out of 1,040, and out of 1,040 school
districts, only about 550 of them are able to actually
receive deregulated power - 29 cities, 13
universities, 5 state agencies, 40 counties, [and] 30
municipal utility districts.
We're the largest supplier of public retail power in
the State of Texas. [The state] power program has
increased the value ..., by 50 percent, compared to
the monetary royalty payment that we would have
received. [What] that means is, we've actually
increased our earnings on that same monetary royalty
payment by 50 percent over the monetary payment, so
we've actually had what we call an enhanced value. If
we were to [have] put it in the treasury and earned 5
or 6 percent on it, it wouldn't have done anything
like we've done [through the program].
[With regard to electricity, in] FY 01, we had 200
megawatts of power in our program; [in] FY 02, 400
[megawatts]; and [in] FY 03, ... after deregulation
started, we have jumped to 1,200 megawatts. ... You
can almost see the direct result tied back to the gas
page [of the presentation] ..., where we went from
about 18 bcf up..., this year, to 36 bcf. So it's
quite a significant increase and a way for us to ...
market our gas ... to our own customers, be less risk
versed for the [Public School Fund], and ... at the
same time be able to save money for the public sector.
I'd take any questions.
Number 393
CHAIR SAMUELS surmised that Texas's program does everything in
state.
MR. BONE concurred. In response to a comment, he indicated that
the Texas program is competitive with regard to both gas and
oil, and mentioned that the Texas program has a variety of
contract lengths ranging anywhere from two years to four years.
SENATOR LINCOLN asked whether Texas would have lost some of its
military bases if it had not been able have them as public
retail customers.
MR. BONE said that he couldn't speculate on that point, but
noted that having military bases as public retail customers
ensured that they got lower utility costs.
SENATOR LINCOLN asked how much of a savings this generated.
MR. BONE indicated that he would research that issue, and
mentioned that the Texas program was able to sell military bases
"green" sources of power. In response to a question, he said
that from a marketing standpoint, there are five different
geographical points that traded all the gas in Texas, and by
dividing Texas into five geographical areas and taking the
historical data regarding price from each of those areas, the
take in-kind program has been able to calculate a take in-kind
value at each of the five locations. That calculation was then
equated, on a monthly basis, to the value at Houston ship
channel, which was one of the geographical points. For example,
if Houston ship channel gas is valued at $5.00, the value of gas
from another geographical point might be $5.00 minus $.50. In
other words Houston ship channel provides a single point of
reference for the purpose of valuating gas prices. This same
type of calculation is also being used to calculate RIK values.
MR. BONE said that this method has allowed the program to
provide its consumers with cheaper gas and oil then they would
have gotten from competing commercial providers. He mentioned
that since the Texas General Land Office has production and
transportation capabilities, the Texas program affects pricing
from a tariff standpoint.
Number 545
REPRESENTATIVE HAWKER asked whether, because everything is done
in state, the Texas program avoids oversight from the FERC.
MR. BONE said that is correct, and mentioned that some LDCs in
Texas do not allow competition, and so the state is the only
other entity that can provide gas or oil to such areas. He
noted that the state energy program also operates within an
existing grid with regard to [electrical] power, and pays the
same tariff rates as all other competitors. One advantage the
state program has, however, is that it doesn't have to pay state
taxes, and so this results in a savings of approximately 2.5
percent on both the commodity and the wire side of the business.
Therefore, commercial power providers have to automatically
lower their price by 2.5 percent in order to compete with the
state program, though, again, the state program only provides to
a certain segment of the market: the public retail customers,
which are the customers that actually pay their bills with tax
dollars.
REPRESENTATIVE CHENAULT asked where the program's funding comes
from.
MR. BONE reiterated his comments detailing how the program is
self-funded via administrative fees. In response to a comment,
he mentioned that in the Texas program, a lot of the oil is
converted into natural gas because there is no need for oil. In
response to a question, he noted that the aforementioned 50
percent increase in value is strictly a revenue stream, and
reiterated that any money the state power program makes goes
directly to the Permanent School Fund, which only funds K-12
education.
TAPE 04-23, SIDE A [BUD TAPE]
Number 001
The committee took a brief at-ease.
KEVIN BANKS, Commercial Section, Central Office, Division of Oil
& Gas, Department of Natural Resources (DNR), relayed that his
[PowerPoint] presentation would touch on the development and
status of Alaska's current royalty in-kind (RIK) program, on a
couple of royalty contracts that the state has recently entered
into, and on a possible future direction that the state might
choose to go in. He explained that royalty is a share of
production: the ownership of the oil or gas that the state
keeps in a contractual arrangement with its lessees. The state
can choose to take royalty in-value (RIV) or in-kind; when taken
in-value, the mechanism used to calculate the value is subject
to a "higher of" calculation. That [was] the case for Alaska
North Slope (ANS) gas, although through various royalty
settlement agreements and arrangements with respect to oil, that
has changed.
MR. BANKS went on to say:
We can look to how the producers, or the lessees, are
selling oil and gas, compare that to what the market
is, how others in the same field are doing, and [then]
we're entitled, under the provisions of our lease, to
get the highest of those values. The lease also
requires that the producers/lessees assume the
responsibility of [marketing] our oil and gas along
with their own ... share. And I think that's an
important feature to make [note of], because if we
take gas or oil in-kind, ... then it's our
responsibility to market our royalty share.
Why take RIK? ... The commissioner ... may only award
a contract if it serves the maximum benefit of all
citizens. And even in the enabling legislation for
the Alaska Royalty Oil and Gas Development Advisory
Board, which we call the Royalty Board, ... [it
states] that the decision to take royalty in-kind or
in-value falls on whether or not it promotes and
facilitates wise development of our resources and
provides for economic growth and other kinds of
benefits ... within the state.
Number 029
That's an important feature. ... The state develops
this right ... by the arrangements we have with the
lessees in a lease agreement. ... We offer leases for
sale in a closed-bid auction; the lessees agree that
we may take our royalty in-kind or in-value at our
election, [and] ... the only provision that encumbers
that right is that we have to give them appropriate
notice. Under the old leases that are on the North
Slope, that used to be six months' notice. The newer
leases are three months, and, as far as oil is
concerned on leases ... in Prudhoe Bay, it's been
changed to three months as well.
MR. BANKS continued:
So we get a little [bit] of flexibility. As long as
we tell the producers, with appropriate notice, that
we want to take our oil in-kind or switch it back to
in-value, that's something that they have to do. ...
The rules [that] apply to oil and gas, under the
lease, are the same, although, as I've said, various
agreements have been entered into over the years with
the producers that have changed the nomination
procedures for oil. And this has been part of our
leasing program for [40] years - all of the leases
have a [similar] condition ..., you see it in leases
in the Lower 48 as well.
Importantly, it gives us the right to switch from
royalty in-kind [to] in-value, and we regard that as
having value in and of itself. ... If we think that
what we're getting for in-value is too low, for
example, and we think we can do better if we take it
in-kind, ... we can take it in-kind - and sell oil and
gas - and improve our position. If we think that
keeping it in-value is a better deal, ... we can
switch it back to in-value. So that by itself imparts
a certain value to the state in terms of revenues for
its royalties. ...
Number 061
Switching on and off, or raising or lowering the
amount of royalty in-kind, is important to us because
that gives us the opportunity to sell to customers
that the producers might not be willing to sell to -
in-state refineries is a good [example] - and we can
also offer terms that are different than what would be
more normal contracting arrangements. And I'll give
you two examples ... in a moment, but even about 12
years ago we entered a 10-year contract to sell oil to
Petro Star [Inc.] to supply their refinery in Valdez.
They never took any oil under that contract, but just
the possession of our contract and the assurance of a
supply of oil for a period of 10 years was sufficient
to get the financial backing they required to get the
refinery paid for and constructed. And similarly we
offered [Flint Hills Resources, L.P.] a long-term
contract, which you don't normally see in the
marketplace, so that they too could finance ... the
purchase of the refinery. Of course, I believe the
state was able to get a premium for that kind of
arrangement, and also now we have a viable and what I
think will be a fairly good customer in [Flint Hills
Resources, L.P.] at the North Pole refinery.
MR. BANKS, referring to his presentation, said:
Just to give you an idea of what our switching has
been like in the past, this chart shows that at times
we've taken almost all of our royalty in-kind. The
green area represents basically the total amount of
oil that's produced on the North Slope ... since 1979
through 2002, and, as you can see, we've kind of
jumped up and down over time in taking royalty in-
kind. We've offered it in competitive sales, most
often we've sold it to local refineries, and the
situation now, if you were to forecast that out, will
look a bit as it has been in the recent past, where a
little over half of our royalty will be sold to [Flint
Hills Resources, L.P.].
Now, there was a question earlier about whether or not
RIK and RIV are equal, and [whether] the price we
receive for our royalty should be the same. I think
it's a principle that's stated in somewhat elliptical
ways in our regulations and our statute that that
should be a requirement, that when we decide to sell
royalty in-kind, that we should at least get as much
for it as we would have in-value. Arguably, ... we
might even look to court decisions that would have
said the same thing.
Number 082
MR. BANKS, referring to different pages of his presentation,
said:
This chart gives you an indication of how well we have
done. We sometimes miss, we sometimes do better. ...
[This graph] says about the same thing, except in
terms of differentials, that on balance, in the last
25 years of a royalty in-kind program on the North
Slope, we've just about broken even. And that's in
spite of the fact that there were times when we had
contracts that had distinct [premiums] associated with
them. There have been other times when we've just
missed it, most notably when we sold oil to [Alaska
Petrochemical Company (Alpetco)] in Valdez and the
company went belly up and couldn't pay for the oil
that we had nominated and dedicated to them, and [we]
ended up having to resell it back into the market and
... to the producers at a loss.
Now I'll get to the recent contracts. .. As you know,
we brought to you last session the [Flint Hills
Resources, L.P.] oil contract, and, a couple of years
ago, the department negotiated a contract with
Anadarko Petroleum Corporation and EnCana Corporation
- EnCana used to be [Alberta Energy Company Ldt., AEC]
before [it] was purchased by EnCana - and I'll touch a
little bit on the terms of those agreements. All of
our contracts have similar terms, and of particular
importance are the four I've listed here for [Flint
Hills Resources, L.P.]: price, special commitments,
the kind of quantity that we're going to supply, and
for a certain length of time - [term].
Number 099
MR. BANKS relayed:
Flint Hills's price is not what [we] have normally
charged "royalty in-kind" kinds of customers for oil.
The norm had been, since the very beginning on the
North Slope when we first started selling oil to
[MAPCO Alaska Petroleum Incorporated] in 1979, that
the price would be based on what we would have
received for the royalty in-value. ... It specifies,
"You pay us the in-value price." In the Flint Hills
contract, I think owing to the fact that we have a
much better understanding of oil markets now for North
Slope crude then we could ever have had in 1979, we
modeled the pricing term for Flint Hills in a way that
mirrors the same calculation that we make for our in-
value oil, which, in turn, mirrors the calculation
that the lessees themselves use when they sell oil.
So we have a market standard, so to speak, in the way
oil contracts are priced, and the Flint Hills contract
is priced off of an ANS spot price, so it's an index
price - it will follow the market - and we believe
that the term and the calculation that we've developed
in this contract will yield a premium for our oil in-
kind [versus] ... having kept it in-value. Flint
Hills also promised to give us special commitments,
and these are ..., I think, very important but are [of
a] non-monetary value to the state.
In the Flint Hills contract, that included upgrades to
the refinery for it to make clean fuels, ...
voluntarily hiring Alaskans where they could, taking
reasonable efforts to use all of the royalty oil that
they buy for us to make products here in Alaska and to
supply the jet fuel and consumer gasoline market, ...
[promising] to abide by the commitments that Williams
[Companies] had made ... as they [proceeded] to
upgrade the tank farm in Anchorage, ... [promising] to
ship [oil] ... and other products on the railroad, and
... [promising] to promote development of the
international airport in Fairbanks and ... provide
gasoline in Fairbanks and Anchorage at parity.
MR. BANKS remarked:
And while those are non-monetary kinds of values to
the state, it's something that we were able to
negotiate with them. In return for the price and
those kinds of special commitments, Flint Hills
receives from us assurances of a quantity of oil that
basically meets their requirements and with sufficient
flexibility to adjust for seasonality, and we've also
committed to supply them oil for 10 years. And so
under those circumstances, I think we struck a fairly
good deal for the state with Flint Hills.
Number 144
SENATOR THERRIAULT asked for more information about the MAPCO
contract.
MR. BANKS said that there were two contracts with MAPCO. The
original 1979 contract had a "schedule B" pricing mechanism,
which was intended to capture an amount that matched what was
anticipated would be received via the ANS royalty litigation.
He noted that as a result of this mechanism, there was a fairly
close match with RIV but not with RIK. A second contract with
Williams [Companies] - the successor to MAPCO - was signed in
1998 that agreed to RIV plus $.15, and this outright premium had
no restrictions with regard to retroactive calculations.
MR. BANKS, on the issue of the Anadarko Petroleum Corporation
and EnCana Corporation contract, said that after negotiating the
agreement, the department submitted, for review by the public, a
preliminary best interest finding on March 29, 2002. No further
action has been taken on the agreement, however. The two
companies had had concerns about how they could nominate for
firm transportation commitments in a pipeline when they didn't
have any gas to nominate - they hadn't gone out and begun to
explore for it; furthermore, how could they go out and explore
for it if they didn't have the means to transport their gas off
the North Slope. The department saw an opportunity to go about
making arrangements to help them out for a price. The response
from Anadarko Petroleum Corporation and EnCana Corporation
involved a proposed contract that included a price equal to RIV
plus a premium, and a cash option price to exercise a renewal on
the contracts every five years for as long as it took to get the
pipeline built, get their gas into the pipeline, and back out
the state's RIK gas.
MR. BANKS said that the advantage of this type of contract is
that it would give Anadarko Petroleum Corporation and EnCana
Corporation the opportunity to take the state's gas and fill
their pipeline space with it while they proceeded to develop
their own gas supplies; then, upon discovery and development of
their own gas, they would have the option to take the state's
gas off the pipeline and replace it with their gas. At that
point, the state could simply switch back to RIV and benefit
from having two more gas producers on the North Slope with
access to markets for selling gas.
Number 219
MR. BANKS, in response to questions, said that there are FERC
regulations in place that are designed to offer open access
through an open season process, though there are some
shortcomings, since those regulations are designed to work in
situations where there are more competitive opportunities to
move gas from a particular place. Additionally, there are
provisions in the federal energy bill that may improve access
opportunities for folks like Anadarko Petroleum Corporation and
EnCana Corporation. He reiterated his comments regarding
aspects of Anadarko and EnCana's proposed contract.
MR. BANKS, in response to another question, said that the point
the state would deliver gas to Anadarko and EnCana would be the
same place, as yet undefined, where the state would receive its
royalty if it were taken in-value, and it is as yet unknown
whether the state would take gas as royalty before it moves
through the treatment plant or whether it would take it after.
Anadarko and EnCana could then acquire firm transportation
capacity for the state's royalty gas and send it all the way to
the marketplace, wherever that ends up being. The proposed
contract also anticipated that there might be some offtake of a
small volume of gas that Anadarko and EnCana would be willing to
sell back to Alaskan communities if necessary. "It's a kind of
a 'take or pay' capacity agreement, you see; they would commit
to move 350 million cubic feet of gas down this pipeline [and]
if they didn't have it, they'd still have to pay for it," he
explained.
MR. BANKS said it is not an automatic decision that expansion of
the pipeline would occur simply because there are customers
available and looking for it to happen. The FERC cannot require
such an expansion, and so normally Anadarko and EnCana would
have to go to the producers and ask for expansion to take their
new gas; thus the decision would be left up to the producers to
a certain extent - they would have to find that it would be
economically viable to take that gas. Under the proposed
contract, however, it would be the producers that would have to
take the royalty gas back in-value and find space for it, either
by expansion or by backing out their "working interest" gas. He
added, "We tried to accommodate for that eventuality in the
contract by changing the nomination schedule that is currently
embedded in the contracts."
Number 315
MR. BANKS said that under the proposed contract, Anadarko and
EnCana would be required to give the state a much longer lead
time to change the percentage of royalty gas that they were
taking, and if their own gas were to be put into the pipeline in
place of the state's gas, the state would get a two-year
nomination notice period. This would give the producers
sufficient time to make adjustments, to either plan for an
expansion or otherwise accommodate the switch back to RIV. The
proposed contract with Anadarko and EnCana contained commitments
similar to those in the Flint Hills contract, including an
exploration program of $50 million a year, instate preference
for contracting and local hire, and a $25,000-a-year training
program, which would last 10 years and train Alaskans [in the
industry].
MR. BANKS, on the issue of future RIK challenges and
opportunities, said:
I've made two points about royalty in-kind that I
think are important. The fact that we take royalty
in-kind and have historically taken it at the point
where it's delivered to us as in-value, is a rather
important issue. With respect to oil, it's fairly
easy for us to do that because the [Trans-Alaska
Pipeline System (TAPS)] ... is a common carrier. Our
customers have the same access to the TAPS ... as
anyone else, and so they can step up and buy our oil
in Prudhoe Bay or at the inlet of a pipeline and
pretty much be guaranteed the opportunity to deliver
it to their refinery down the pipeline. ... As the
Anadarko and EnCana contract illustrates, that's not
the case for gas, where, if we were to take our gas at
a delivery point upstream of the pipeline - either at
the inlet of the gas treatment plant, or at the outlet
of the gas treatment plant but ahead of the pipeline -
our customers are going to have to find a way of
moving it, [of] taking the gas away to market.
Number 341
The second issue that I think is important is that in
the pricing mechanism for oil, we're now able to sell
to Flint Hills mirroring what we appreciate is going
on in the marketplace. The mechanism of relying on an
ANS spot price, for example, is a very good indicator
of what the market of ANS oil is, and so it's easy for
us to point to that and say, "Here's how we'll index
the price of our royalty oil.'" Gas is not there yet
... because we're not there yet; we haven't begun
delivering gas to Alberta or Chicago or wherever it
may go, and haven't yet established the kinds of
market indicators that we might want to apply to a
royalty in-kind contract. ...
MR. BANKS continued:
[So] where we take the gas and how we price it will
become fairly important. If we take gas at the inlet
of the pipeline, our customers will have to assume the
risks of taking a firm transportation commitment on
the pipeline, and the risk that when they sell gas ...
in the marketplace, they'll get enough to pay for the
transportation charges. The state could, as an
option, assume that risk by delivering ... our royalty
gas at the "ACO" (ph) hub in Alberta and assume the
transportation risk ourselves and, presumably, we
would then be able to charge our customers
accordingly.
So now, as we move forward, we're going to be facing
questions about how much risk the state is willing to
take when it sells its gas, ... are we a "price taker"
as we have been in the oil business for 25 years, or
would we be willing to step out into the marketplace.
If we do [the latter], what kind of marketing
organization do we think ... we would like to develop.
... [Also, we should recognize] that people and
expertise and the functions of a marketing
organization all come with a cost. ... I think those
are the questions [reflecting] where we are right now,
trying to deal with those kinds of issues. If you
have any more questions, I'd be happy to take them at
this time.
SENATOR LINCOLN noted that there were only three months between
the time the final finding and solicitation for offers was
published and the time the contract negotiation with Anadarko
and EnCana was completed, and said this seems like a very short
timeframe. She asked whether such a short timeframe is normal
for DNR.
Number 412
MR. BANKS said that the timeframe has historically been governed
by the motivation of the customers, and the state takes a
passive position with regard to selling royalty. And while the
state will nominate oil when it can and sell it to someone, the
terms of an agreement are designed to strike a balance of risk
that favors the state, for example, by avoiding default risk.
He characterized the aforementioned three months as incredibly
long in terms of how producers and gas suppliers and oil
suppliers behave in a regular market, where deals are done in a
matter of hours depending on the quantity and the term of the
agreement. For example, it might take three to four weeks, at
the outside, to establish a one- or two-year contract between a
producer such as ConocoPhillips Alaska, Inc., and a customer for
oil in California. Those [producers] know their customers,
they're in the business of selling, and, hence, they're much
more nimble in the marketplace.
SENATOR LINCOLN asked whether the aforementioned commitments
with Flint Hills and Anadarko and EnCana regarding Alaska hire
and utilizing Alaska businesses are "set in stone" or involve
certain percentages.
MR. BANKS replied:
In the agreements that we've had and that I'm familiar
with, going back to ... 1990, ... [they] all have some
language with respect to local hire. And ... at this
point, I think, the state, in its role as a
government, can run afoul of constitutional problems
in enforcing some kind of very specific local hire
rule. I suppose [in] a deal between BP and ... Flint
Hills, they could say anything they want about who to
hire, but we can't. And so the agreements have always
stressed, "To the maximum extent possible," or "As
available," and "At times, ... [you] voluntarily will
hire Alaskans." ...
SENATOR LINCOLN asked whether the local hire commitment is
monitored by the department.
MR. BANKS said it is to a certain extent.
Number 467
SENATOR THERRIAULT asked why no further action has been taken on
the Anadarko and EnCana contract.
MR. BANKS indicated that that decision was made during the
previous administration and probably involved a variety of
factors, adding that it was not an uncontroversial issue. "In
the request for comments that accompanied the RFP, the producers
all objected to the RIK sale," he noted, and so the attendant
controversy prompted the parties involved to wait. In response
to another question, he explained that the current contract,
which is as yet unsigned by either party, contains some
provisions regarding timeframes within which the parties could
withdraw.
ADJOURNMENT
There being no further business before the committees, the joint
meeting of the Joint Committee on Legislative Budget and Audit
and the Senate Resources Committee was adjourned at 4:20 p.m.
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