Legislature(2007 - 2008)BARNES 124
05/11/2007 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Presentation: Spencer Hosie, Rick Harper, Don Shepler, Ken Minesinger, Scott Hobbs, and W.h. Sparger: Building and Financing Gas Pipelines | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
May 11, 2007
1:43 p.m.
MEMBERS PRESENT
Representative Carl Gatto, Co-Chair
Representative Paul Seaton
Representative Peggy Wilson
Representative Bryce Edgmon
Representative David Guttenberg
Representative Scott Kawasaki
MEMBERS ABSENT
Representative Craig Johnson, Co-Chair
Representative Vic Kohring
Representative Bob Roses
OTHER LEGISLATORS PRESENT
Representative Mark Neuman
Representative Berta Gardner
Representative Bob Buch
COMMITTEE CALENDAR
PRESENTATION: SPENCER HOSIE, RICK HARPER, DON SHEPLER, KEN
MINESINGER, SCOTT HOBBS, AND W.H. SPARGER: BUILDING AND
FINANCING GAS PIPELINES
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to report
WITNESS REGISTER
SPENCER HOSIE, Attorney at Law
Hosie McArthur LLP
San Francisco, CA
KEN MINESINGER, Attorney at Law
Greenberg and Traurig LLP
Washington, D.C.
BILL SPARGER, Consultant
Energy Project Consultants, LLC
Colorado Springs, CO
DON SHEPLER, Attorney at Law
Greenberg and Traurig LLP
Washington, D.C.
SCOTT HOBBS, Consultant
Energy Capital Advisors
RICK HARPER, Consultant
Econ One Research, Inc.
Los Angeles, CA
ANTONY SCOTT, Commercial Section
Central Office
Division of Oil & Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
ACTION NARRATIVE
CO-CHAIR CARL GATTO called the House Resources Standing
Committee meeting to order at 1:43:19 PM. Representatives
Gatto, Seaton, Guttenberg, and Edgmon were present at the call
to order. Representatives Kohring, Wilson, and Kawasaki arrived
as the meeting was in progress. Representatives Neuman,
Gardner, and Buch were also present.
^PRESENTATION: SPENCER HOSIE, RICK HARPER, DON SHEPLER, KEN
MINESINGER, SCOTT HOBBS, AND W.H. SPARGER: BUILDING AND
FINANCING GAS PIPELINES
1:43:54 PM
CO-CHAIR GATTO apologized for the late start of the meeting and
thanked Gavel to Gavel for broadcasting the meeting. He then
asked Mr. Hosie to begin his presentation.
1:44:43 PM
SPENCER HOSIE, Attorney at Law, Hosie McArthur LLP, a founding
partner of the San Francisco law firm, told members he was asked
to speak about the duty to develop under the Alaska lease form.
He informed members he has been a practicing oil and gas lawyer
for almost 25 years. He began his law career working for the
State of Alaska in the early 1980s on the Amerada Hess case.
Today, his firm runs a national energy and intellectual property
practice. His firm represents a wide range of private and
public royalty owners. He has been the lead outside energy
lawyer for the State of Louisiana for almost a decade in
litigation and regulatory matters. His firm has represented the
State of Hawaii, and worked with the U.S. Department of Justice
in connection with federal royalties in the whistleblower
context. His firm has deep experience in oil and gas matters.
1:46:18 PM
MR. HOSIE said he has personally had the occasion and
opportunity to review millions of pages of oil company documents
over the last two decades. He believes he brings a detailed
understanding of how oil companies assess a capital intensive
upstream infrastructure project: what matters, what doesn't
matter, what gets built, what doesn't get built and why.
1:46:59 PM
MR. HOSIE presented the following information:
To understand the duty to develop, it is important to
understand the nature of the relationship that an oil
and gas lease creates between the royalty owner, which
is the landowner on the one hand, and the oil company
on the other hand because it is a relationship very
unlike a typical commercial arms-length relationship.
The process starts with the landowner that had land
that may or may not have mineral resources on it but
the landowner typically doesn't have the expertise to
explore the property, doesn't know how to develop the
property, doesn't know how to produce any hydrocarbons
found, and certainly doesn't know how to market
hydrocarbons for the best possible price. The
landowner needs a partner and that is, of course, the
oil company.
The oil company has exactly the suite of expertise
that a landowner needs. Oil companies are expert at
development, at exploration, at marketing. And so
what happens is the two get together and sign a very
short contract called a lease. I mean short - I mean
it is two pages, two and a half to three pages long.
It's a very short document given that the relationship
created can last 50, 70, 80 years.
Now the landowner contributes the real estate the
landowner owns. That's what the landowner brings to
the table. For their part, the oil companies
contribute their expertise. They promise to get the
lease in the first instance, to use their expertise to
explore the property, to develop the property, to
produce the hydrocarbons and to market the
hydrocarbons all for the mutual benefit of themselves
and, importantly, the landowner, the royalty owner.
That's how an oil and gas lease works.
1:48:55 PM
In return for promising to use its expertise to
develop and to market, the oil company typically gets
the lion's share of the value of production. In
Alaska, under the largely prevalent lease form, the
oil companies get a full 87.5 percent of the value of
production. The state's royalty share is 12.5 percent
and that, given modern standards, is very low but it
was the norm back when the state's lease form was
drafted in the late 1950s.
But, in return for the lion's share of the value, the
oil company has the obligation to explore, develop,
produce, and market diligently all with the mutual
interests of both the oil company and landowner in
mind. It is a relationship which the courts have
characterized for many, many decades as one of mutual
interdependence. The precise phrase the courts use;
it's a relationship of mutual benefit. They are in it
together and that means that the oil company, after it
signs on the dotted line on the lease, is no longer
free to use its unilateral economic self interest to
make decisions. It's no longer free to say what makes
us the most money and act accordingly.
To the contrary, in making development decisions,
production decisions, it has to take into account the
interests of its partner in this venture, the royalty
owner, the landowner, so it's no longer a commercial
relationship where one party acts according to its
economic self interest alone. That's a critically
important thing about the royalty relationship that is
really quite unique to that relationship and very much
unlike a typical commercial relationship.
1:50:47 PM
MR. HOSIE continued:
Now, oftentimes the economic interests of the royalty
owner and the oil companies are aligned but, every so
often, there comes a situation where the interests
diverge, where they depart. One common place where we
see a diversion comes with development or further
development and here's why. A landowner almost
invariably wants the property developed. A landowner,
royalty owner, only gets paid when the hydrocarbons
are produced, severed, and sold. That's the event
that generates the royalty payment to the royalty
owner so they want the product developed so they can
get paid. Of course that's why they've gone to the
oil company in the first instance - produce this
property for us.
On the other hand, you could have a situation where a
given oil company, for any number of reasons, might
prefer not to develop a given property, at least not
right now. They might be long in the particular
resource, e.g. long in gas in the West Coast in the
Lower 48. They might be short of cash. They might
have sufficient cash but prefer to spend those dollars
somewhere else, on projects abroad where the oil
company perceives that if it doesn't move development
forward, it will lose the opportunity. The company
may have what's known as a very high internal hurdle
rate, which is a return on investment [ROI] rate that
must be exceeded to green light a development project.
For example, Exxon's return on investment for its
upstream activity in 2005 was 46 percent. It's ROI
across the company in 2006 was 33 percent. That's a
very high return on investment and so there could well
be a situation where a company says you know what?
This might be an economic project but it's not
economic for us because we want all projects to be at
a 30 percent plus return before we go forward. Or a
company might simply be spending its money in other
ways.
1:52:51 PM
Another case in point - in the last two years Exxon
spent $41 billion buying back its stock on the open
market - that's $41 billion in two years. It did that
to keep its stock price high and to keep Wall Street
happy. And I'm not saying that that's an irrational
thing for Exxon to do. From Exxon's perspective
alone, that was probably a great idea because its
stock price is high and Wall Street is happy.
Those are important goals for Exxon but the key point
is this. Once Exxon was in a lease relationship with
the State of Alaska, one going back 30 years, one
under which Exxon and the other producers on the North
Slope have made gargantuan profits from production to
date, Exxon can no longer make decisions based solely
on its own economic self interest. That's not the
proper approach.
And so there's this inherent conflict in development
circumstances. The landowner says listen, we really
want you to develop because that's how we get paid.
The oil company says well you know it's really not in
our interest, at least not right now. We've got other
things we'd prefer to do.
1:53:59 PM
MR. HOSIE continued:
That conflict is solved by the implied duty to
develop. The implied duty to develop can be expressed
very simply, in plain terms. An oil company has an
obligation to go forward with a given development
project if that project is, on its own merits,
reasonably economic - full stop - period. That's the
duty. If a given project is reasonably economic, the
oil company has an obligation to go forward. Why?
Because that's the deal it made to get the lease. It
said I will use my expertise to develop this for you
diligently and, in return, I want the lion's share of
the value of production. That was the deal going in.
And so, if a given project is economic, the oil
company has an obligation to its partner in this
venture, the royalty owner, to go forward.
1:55:05 PM
One analogy I have used that I find helpful in this
area relates to the following. Assume that Toyota is
thinking about putting a new manufacturing facility in
one of five or six Southern states in the Lower 48.
It goes to the five or six states and says listen,
we're ready to spend our development dollars. We're
going to build a manufacturing factory. We're going
to give jobs. We're going to help your tax base.
This is great for you but, tell us, what will you do
for us? That will start, essentially, an auction
between the various states to see which state can put
together the most attractive development deal with tax
incentives, real estate rebates, and job promises, and
educational benefits, and the like.
At the end of the day let's say that Kentucky wins
that contest and Toyota agrees to put that plant in
Kentucky. Let's also say that Kentucky does something
that's pretty shrewd. It says as part of the first
deal, listen Toyota, this is all great, this is all
well and good, but if this first facility is
profitable and there comes a time when you're thinking
about putting a second factory in, you have to build
it in Kentucky.
That is exactly the situation the State of Alaska is
in with its leases. They made the obligation to
develop diligently for the mutual benefit of both the
State of Alaska and the oil companies when they signed
the leases so many years ago. Under that obligation
they don't get to come to the state now and say
listen, we can get a higher rate of return elsewhere
on our money. Or, there might be a more profitable
project in Kazakhstan or Qatar. Or, we'd really
prefer to spend our money buying our stock back. Tell
us, make it worth our while. That is absolutely a
breach of the obligation under the lease form these
companies have done extremely well by.
That's the duty to develop. Now the question arises: well,
all well and good, Mr. Hosie, but is that duty present in
Alaska law and the deal on lease forms?
1:57:13 PM
I can tell you yes, unequivocally and absolutely, it
is. And when was the last time you heard a lawyer say
something about absolutely? It is absolutely present
and here's why.
First, paragraph 19 of the lease itself talks about
further development and specifically says that the
producer oil company has to have due regard and I
quote, "due regard for the interests of the state in
making additional drilling and development decisions."
That's the language of mutual benefit.
Second, this question has already been resolved in
this state. In what was then known as the ANS royalty
litigation in 1989, then Judge, now Justice, Walter
Carpeneti issued a decision looking at the lease form
and which duties were in that document and which not.
In that decision, which was fully binding on the
parties, the state and the oil companies alike, Judge
Carpeneti said that the lease form contained a full
array of duties including the implied duty to develop.
There simply can be no question but that there is a
duty to develop under the Alaska lease form and Alaska
law generally.
And so, the question arises, given that the duty
exists here, what constitutes a breach? What can't an
oil company do? When would conduct qualify as a
breach of the implied duty to develop?
1:58:59 PM
Well, if an oil company looks at a particular project,
be it the Pt. Thomson Unit or a gas line in Alaska,
and if the oil company concludes that that project is
on its own terms reasonably economic but nonetheless
refuses to go forward, that is a breach of the implied
duty - full stop - period. If the oil companies
refuse to do that economic analysis, but instead
refuse to invest because they have an overall national
or perhaps international policy of not spending on
capital enhancements for the following year or five
years, that would be a breach because they have to at
least run the numbers and check to see if it's
economic.
If an oil company refuses to go forward but then if a
third party comes and says, listen we will build it if
you'll sell us your production at a reasonable market
price, if that happens and the oil company says no,
we're not going to build it but you know what? We're
not going to sell it to you either, that would be a
breach of the implied duty. Why is that? Because
effectively they're just bottling the resource up in
the ground. The courts call that speculative in-
ground warehousing. They're warehousing the resource
and that violates every tenet of the oil and gas lease
because it may be in their best interest but it surely
is not in the royalty owner's best interest.
And so, there are cases going back 40 years that say
listen, if they are in-ground warehousing, that is
inappropriate. It's a violation of the lease. You
can't just bottle it up and if they've done that,
that's improper.
2:00:41 PM
CO-CHAIR GATTO noted Exxon does not have a pipeline in some
situations in which to ship resources so, for 20 years, it has
been recycling the gas. He asked at what point the state could
say Exxon is no longer satisfying its duty in that case.
2:00:57 PM
MR. HOSIE explained when the state concludes that a gas pipeline
is reasonably economic, it has the right to make Exxon and the
other producers choose to either build it or let the resource
go. He said the remedy has to be considered. If the state
assumes it has a breach, has a lot of gas stranded and wants a
gas pipeline but the company will not build it, litigation
should not be the first option for remedy as it rarely provides
a happy outcome. Fortunately, a royalty owner has a different
remedy in the breach of implied duty context.
2:02:01 PM
MR. HOSIE continued:
That remedy is that the oil company must surrender the
resource back if it says a project is not economic and
it will not go forward. He pointed out the discovery
wells were drilled in Point Thomson 30 years ago.
Point Thomson has not produced a drop of oil or cubic
foot of gas. Instead, 30 years of studies have taken
place. The oil companies have told the state
repeatedly that Point Thomson is not an economically
feasible project and have said they will not go
forward with a gas line until the state compromises
its economic position to improve their economics.
In my understanding, that's what they've said to the
state repeatedly. I've seen language like that in the
Point Thomson plans of development - the annual plans.
In that situation they have said they are not going
forward and they cannot say that, yet [they] continue
to hold the resource indefinitely. Why not? Because
they are just bottling it up in the ground and they're
speculating with the gas and warehousing it until, for
their own reasons, they think the time is right.
Maybe that's five years, maybe it's 10 years, maybe
it's 20 years. Maybe it's after they burn through the
900 trillion feet of gas they're producing in Qatar.
I don't know when they are willing to do it but what
we do know is that they sure aren't willing to do it
today.
2:03:43 PM
MR. HOSIE continued:
I read an op Ed piece by Representative Doogan a
couple of weeks ago. He said you don't have a
pipeline because Exxon doesn't want you to have a
pipeline and I think that's exactly right.
So the remedy isn't to charge off into litigation.
It's not your job to compel them to honor their
obligations and build a pipeline and, honestly, does
the state want an unwilling partner in a project like
this? No. Just make them choose. If they really
don't think it's economic, they have to give the
resource back. And then you can go to other oil
companies that perhaps have a greater need for gas
today as against 10 years from now or may have a
greater need for reserves, e.g. Shell. Shell would
love to have a deeper reserve base - e.g. Chevron.
Chevron is working hard and spending money all over
the world to increase its reserves. Different
companies have different positions and different
needs. The royalty owner has the right to get the
resource back if the first set of producers won't move
forward on it and see if you can't get another group
of producers to commit to build the project in
concrete and specific terms.
2:05:01 PM
Now what do we know about North Slope development and
the duty? As I said, we know that the producers have
said that right now it's not economic to go forward.
That's been, as I understand it, the entire
justification to ask the state to give some economic
concessions. Help us make it economic. It's not
economic without help.
Well, two things on that. First, if that is true,
they have to give the resource back and second, I know
at least that that's not what Exxon really thinks.
And here's how I know.
There are detailed accounting standards that govern
how an oil and gas company reports reserves for its
SEC filing purposes - SEC is the Securities and
Exchange Commission - for annual reports and quarterly
reports. They are called financial accounting
standards and they are promulgated by the FASB or
Financial and Accounting Standards Board. Financial
Accounting Standard 19 governs how an oil company
accounts for exploratory drilling costs on properties
that are not yet proven and not in production. That
accounting standard changed on April 4, 2005. The new
standard said the following. Oil company, you
continue to capitalize, that is carry on your books,
these expenses but only if you have no substantial
doubt that the project is economically viable and two,
economically viable under today's market prices and
with today's technology.
Let me say that again because it's important. I am
specifically quoting paragraph 31(a) of FASB 19-1,
promulgated April 4, 2005, "An oil company can
continue to ...capitalize development costs only if it
has no substantial doubt that the project is economic
and (b) economic based on today's market prices and
technologies."
2:07:28 PM
MR. HOSIE continued:
Exxon reviewed that new accounting standard in May and
June of 2005, and on July 1, 2005, reported that it
had decided that Point Thomson was not a project with
substantial doubt as to its economic viability based
on 2005 technology and market prices. There is a one-
line footnote in their 10K for 2005 that says they've
adopted new accounting and when you look at the new
accounting, that's what you see they have to have
done.
So this was not a decision made lightly. SEC
reporting for oil companies, especially given the
Shell debacle of some years ago, is something they
take very seriously and are careful about. So, Exxon
will have looked at the economics, it will have talked
to its outside auditors, Price Waterhouse Cooper -
PWC. There will be paper going back and forth and
Exxon would have determined and convinced its
auditors, who had to sign off on this, that Point
Thomson was not a project with substantial doubt about
its economic ability.
That is inconsistent with what Exxon was telling the
state right there and then and even this past couple
of months. I've read testimony where Exxon officers
have said, you know, this project is not economic
without help from the state. If they really believed
that was true, they could not have taken the SEC
accounting they took. They did not - forgive me for
being blunt - they did not mislead the SEC. They
truly think it's economic but what they were doing
with the state was negotiating. These are people that
negotiate for a living. It was a negotiation. It
wasn't actually accurate when they said it's not
economic. It was just a negotiating position.
And so it's really important that the state
understands that these are negotiations and, you know?
Sometimes they are positions and sometimes they are
negotiating postures. You have to be careful to take
what you are told with a grain of salt.
2:09:21 PM
And so, I thought that was a significant discrepancy
between what Exxon was telling the state and what it
was telling the SEC, the investing public and Wall
Street.
2:09:34 PM
MR. HOSIE stated his final point, as follows:
It's easy to talk about these oil companies as sort of
a shapeless, faceless, "they;" some sort of monolithic
they. They are not that. They are different
companies. Exxon behaves, thinks and acts one way.
Chevron is a very different oil company. It has
different needs and desires. ConocoPhillips is very
different too. It's very important, I think, for the
state to understand that even though these companies
are terrifically good at presenting a unified face to
the state, internally they may have sharp
disagreements about what is proper, what is not, and
what should be done. It's important in dealing with
them to keep that in mind.
Thank you. That's all I have but I would be delighted
to answer any questions, Mr. Chairman [that] committee
members have.
2:10:22 PM
CO-CHAIR GATTO announced the members present: Representatives
Guttenberg, Edgmon, Seaton, Gardner, Wilson, Kawasaki and Buch.
2:10:53 PM
REPRESENTATIVE EDGMON asked if the term "reasonably economic" is
well grounded in case law and federal law.
MR. HOSIE said it is. He explained that to be "reasonably
economic," it is not the state's obligation to take all the risk
out of the project. The oil companies accepted risk when they
signed the lease and that is one reason they receive 87.5
percent of the value. Regarding what is reasonably profitable,
that is a function of investment rates and rates of return in
the industry in general. That could be 8, 10 or 12 percent.
However, it is not 25, 35, or 40 percent. If the oil companies
have a ROI [Rate of Investment] hurdle that is that high and has
not green-lighted Alaska because it is not screamingly economic,
that is a violation of the lease. He added that all of these
companies have written upstream investment guidelines that set
their investment hurdle rates by region and hydrocarbon. They
will have a hurdle rate for Point Thomson; he believes the state
is entitled to see the hurdle rates if an oil company claims a
project is not economic.
2:12:57 PM
REPRESENTATIVE WILSON asked if Mr. Hosie said the oil companies
were posturing for the purpose of negotiating. She said when
the state set up its "must haves" in Alaska Gasline Inducement
Act (AGIA), the oil companies said meeting those conditions
would be impossible for them to do and claimed, via radio
commercials, the state was not allowing them in. She questioned
whether they cannot get in or do not want to get in.
MR. HOSIE answered what they said was just another piece of a
larger negotiation. An oil company wants a deal that is the
most economically beneficial for it. He said he would not
assume that they maintain the position that the "must haves" are
deal breakers for them, but he does not assume they will be
excluded. What the Legislature has done is sparked an open
competitive process, which is a good thing. If, at the end of
the day, the state forces the larger oil companies to commit to
developing or relinquishing the leases, he believes the
companies will not give the leases back.
2:14:51 PM
REPRESENTATIVE BUCH asked the name of the state's lease
agreement.
MR. HOSIE replied it is named the DL-1 lease agreement; DL for
Department of Lands and 1 because it was the first lease draft
created in 1959 by a lawyer who worked for Chevron.
2:15:26 PM
REPRESENTATIVE BUCH asked for the name of the document he
referred to earlier dated April 4, 2005, regarding an oil
company's statement and position.
MR. HOSIE said he referred to several essential documents. The
first is a 2005 10K annual report. It contains a category in
the financial footnotes for suspended well costs and it
specifically refers to Point Thomson. In it Exxon says it is
not expensing Point Thomson costs; it is continuing to carry
them as a capital asset. It then cites the new accounting
standard, FAS 19-1, particularly paragraph 31(a). That
paragraph states what had to be included to take that accounting
treatment. FAS 19-1 was a new standard that says, under
paragraph 31(a), "no substantial doubt"; about the economic
viability of Point Thomson. If [Exxon] told the state that
Point Thomson was not economic, that accounting treatment was
improper. He noted the inconsistency between what [Exxon] told
the FCC and what it told the state is what he wanted to impart
to the committee. He stated:
The final point on that, it's less a new accounting
for them because they were capitalizing all along.
What was new was the new accounting standard that made
them ask and answer this question; specifically in
that April, May, June 2005 period. That was new.
They looked at it. They said we have no substantial
doubt about economic viability and they took the
requisite accounting benefit thereafter.
So again, the 2005 annual K - the 10K, the annual
report, FAS 19-1, and particularly paragraph 31(a)
therein.
2:17:48 PM
CO-CHAIR GATTO said he could imagine Exxon telling the SEC the
project is viable at a 12 percent profit but telling the state
it is not profitable below 33 percent and both statements would
be accurate.
MR. HOSIE said they would be accurate had Exxon conceded to the
state that the project was reasonably profitable with a 12
percent return, but would not go forward without the state
taking action to increase the return to 35 percent. He felt the
negotiation would have been different had Exxon conceded that.
Instead Exxon told the state it needed help because the
economics were not viable.
2:18:54 PM
REPRESENTATIVE SEATON asked if the same filings apply to the
other participants in Point Thomson or whether they just apply
to the operator.
MR. HOSIE said BP and Exxon took the same accounting in 2005.
However, very recently BP wrote down its investment in the Point
Thomson unit, probably as a result of the unit agreement
litigation. ConocoPhillips didn't call it out, most likely
because it did not have enough money invested to make it
pivotal. He thought Exxon is the largest investor in Point
Thomson.
2:20:00 PM
CO-CHAIR GATTO asked if the landowner and Exxon have an agreed-
upon understanding of the term "specific clarity."
MR. HOSIE thought perhaps not. Exxon has been famous for high
grading its investment. It wants to drive its ROI up every
year. Its ROI is currently twice the average in the oil and gas
sector. That is a sound business strategy because Wall Street
loves it and Exxon's stock price remains strong. Exxon spent
$41 billion buying back its stock, which means that money is no
longer available for upstream development. He pointed out that
Exxon could easily decide to not go forward unless a project
meets its own internal hurdle guideline.
2:21:44 PM
REPRESENTATIVE GARDNER asked if the state could request, through
discovery, documentation of Exxon's internal hurdle if the case
is in court, or whether a better way to get that information
exists.
MR. HOSIE said the state would certainly have the right to see
the documents in court. However the state may have subpoena
powers as part of the process to move the gas line forward. He
believes if the state made such a request, it would be difficult
for Exxon to say it needs help economically but cannot show the
state its own studies. The state and Exxon are in this together
and Exxon has obligations.
2:22:55 PM
REPRESENTATIVE GARDNER asked who should make the request.
MR. HOSIE said he believes DNR, and said DNR should request
copies of specific documents directly from senior Exxon
officials.
2:23:13 PM
CO-CHAIR GATTO recalled reading [Exxon's worldwide] annual
report in which the following caption caught his attention: Our
Enormously Profitable Alaska Operation. He said he suspects
that backing off from an enormously profitable operation is not
a good idea. As a result, Exxon will wait. Alaska's gas is
enormously profitable, in which case Alaska is broke but Exxon
is happy.
MR. HOSIE said he thought that is exactly what Exxon is doing:
waiting the state out.
2:24:09 PM
CO-CHAIR GATTO thanked Mr. Hosie for his testimony and said he
clarified the topic of the "duty to develop" for committee
members. He asked Mr. Hosie to send copies of the 10K report to
the committee electronically.
The committee took an at-ease from 2:24:46 PM to 2:30:07 PM.
2:30:08 PM
CO-CHAIR GATTO asked Mr. Minesinger to present to the committee.
2:30:32 PM
KEN MINESINGER, Attorney at Law, Greenberg Traurig LLP, told
members he would address FERC and antitrust issues, specifically
how AGIA addresses the competitive problems associated with a
producer-owned pipeline. He stated the following:
FERC and antitrust issues are critical to understanding
AGIA and how it fixes the core problems that would be
associated with producer ownership of the pipeline that we
all hope to be built.
2:31:40 PM
Specifically, and I have a slide presentation ... we're
going to address four competitive issues. First we're
going to look at the competitive problems associated with a
producer-owned pipeline. Second, we're going to look at
how AGIA's "must have" provisions work toward fixing those
problems. Third, we're going to discuss why those "must
have" provisions in AGIA are critically necessary to fix
those problems. Finally, we're going to briefly discuss a
question that has arisen, the question being if an
independent pipeline happens to win the AGIA license and
holds an open season, what anti-trust implications are
there, if any, if the producers don't show up to the open
season and don't bid for capacity on this pipeline.
2:32:34 PM
Before we go into those issues, I'll just tell you a little
bit about myself. I've represented several major
interstate natural gas pipelines and other clients before
the FERC, including the largest natural gas pipeline in the
United States. I've represented these clients in FERC rate
proceedings, certificate proceedings involving the
construction of major pipelines, and in some of the largest
market power proceedings at FERC in the last several years.
I've also served as the chairman of the Antitrust Committee
of the Energy Bar Association, and I've worked on numerous
antitrust matters involving natural gas pipelines and other
energy companies and I think bring a unique FERC and
antitrust perspective to this issue.
2:33:26 PM
MR. MINESINGER continued:
Let's first talk about the competitive problems with a
producer-owned pipeline. I would just say, first, we
address these issues in detail in a memorandum that we
prepared for LBA - actually two memoranda: one in 2005 and
one, the most recent one, is December 21, 2006. It's
posted on the LBA website if you want to read about this in
even more detail.
The main competitive issue that we discussed in the memo
that we wanted to talk about today is one of vertical
market power. A producer-owned pipeline would own both the
pipeline and the gas and, as a result of that vertical
integration, would have an incentive not to ship gas
produced by competing producers. The analogy I like to use
- folks are probably tired of hearing me say it, is -
imagine you have three railroads and there's one bridge
across the Mississippi River. If one of the competing
railroads buys the bridge, whose rail cars will have an
incentive to let across that bridge first. It's going to
have a clear incentive to let its trains go across and
discriminate against its competitors. That's what we're
dealing with here.
The disincentive that a producer-owned pipeline would have
could manifest itself in several ways. First, expansion,
as we'll see, would have a disincentive to expand the line
to serve its competing producers. There would be access
and discrimination problems. They would have an incentive
to find ways, sometimes subtle, to discriminate against its
rival producers. It would also have an incentive to delay
the project, to not move forward with the project in order
to perhaps avoid flooding the market with not only its gas,
but gas from its competitors.
And finally, the vertical relationship could facilitate
collusion between the three producers. When I use the term
producers today, I'm referring to Exxon, BP and Conoco.
2:35:50 PM
CO-CHAIR GATTO announced the committee would take a break to
address a technical problem.
The committee took an at-ease from 2:36:05 PM to 2:37:15 PM.
2:37:15 PM
MR. MINESINGER continued his presentation, as follows:
So let's talk about the vertical market power issue just a
little more. It's important to recognize that this isn't
just theory. This is something that the U.S. Department of
Justice, the Attorney General, in 1977, found to be a major
issue. In '77 the Attorney General stated it would be in
the interest of producer owners to resist future expansion
of this pipeline and discourage future entry into Alaskan
gas production by others. Why? Because the producers'
market power could be reduced by discovery and development
of new fields by other producers in this state.
The Attorney General also stated a producer-owned pipeline
would seek to restrict access and throughput to take
monopoly profits. As a result, in '77, the Department of
Justice recommended a complete ban on producer ownership of
this pipeline.
Now, several years later, the Reagan Administration
revisited the issue. And while they didn't recommend a
ban, they issued what is sometimes called a conditional
waiver. Essentially what they said was we might permit
producer ownership but only if the producers can convince
FERC that antitrust issues will not be a problem.
2:38:43 PM
REPRESENTATIVE GARDNER asked if the Department of Justice ban
recommendation applied to all pipelines or just the Alaska
pipeline.
2:38:53 PM
MR. MINESINGER informed members it applied to an Alaska natural
gas pipeline to the Lower 48 states.
CO-CHAIR GATTO clarified it is a monopoly pipeline, which sets
it apart.
MR. MINESINGER agreed the Alaska natural gas pipeline represents
a very unique situation.
2:39:09 PM
REPRESENTATIVE WILSON asked if once the pipeline is up and
running, the first expansion usually lowers the tariff. She
questioned whether that has any relative significance.
2:39:45 PM
MR. MINESINGER said there are a variety of ways in which the
producer-owner could resist the expansion of the line. One way
is to simply delay. The FERC process takes a long time and the
uncertainty about rates and when it will be built can really
impact an explorer that is trying to bring its gas on line. He
add it is important to note that the FERC chairman stated in
2005 that those antitrust issues are still valid and will be
addressed by FERC in any certificate proceeding.
2:41:10 PM
MR. MINESINGER said it is also important to note that precedent,
both at FERC, the Federal Trade Commission (FTC), and the
Department of Justice since 1977, is consistent with the
Attorney General's initial concern. A number of cases at all of
those agencies involve vertical market power and a series of
FERC orders seek to address this issue and recognize it is a
problem. He noted the producers cannot disagree with this
point. When [the producers] participate in other pipeline
proceedings, they complain about the same issue. He read the
following quote from a BP filing:
The problem with an affiliate acquiring capacity on its
affiliated pipeline is related to the pipeline and its
affiliate in the aggregate accruing the ability to exercise
market power. It relates to the combined incentive of the
affiliate and the pipeline to withhold capacity.
He explained BP is saying, in other words, to exercise market
power by discriminating against competitors. That is not a
point subject to any reasonable dispute.
2:42:08 PM
MR. MINESINGER noted that this is an extreme situation because
no pipeline in the Lower 48 states exists that has similar
vertical market power issues where such a small number of
producers would own the pipeline. He pointed out that is
contrary to some of the testimony he heard while watching Gavel
to Gavel. He said that testimony was simply incorrect.
2:42:53 PM
MR. MINESINGER continued his presentation:
Unlike the 1977 DOJ opinion, AGIA takes a different
approach. Let's talk about how AGIA addresses the
competitive problems that would be raised by a producer
pipeline. AGIA does not advocate a ban. AGIA takes a
middle ground approach, similar to the Reagan way in that
AGIA invites applications by all parties, including both
producers and independent pipelines. So, to answer your
question Representative Wilson, AGIA absolutely seeks the
producers to submit an application and includes them in
this process. But instead what AGIA does, it attempts to
fix the competitive problems that would arise if you had a
producer-owned pipeline and simply didn't have these "must
have" provisions that are in AGIA.
Let's go through those provisions briefly. Problem one, as
we've discussed, there would be an incentive by the
producers not to expand the line to serve their
competitors. AGIA directly addresses that. It requires
that the applicant commit to expand this line in reasonable
engineering increments and on commercially reasonable terms
that encourage exploration and development of natural gas
in this state.
2:44:20 PM
So AGIA directly speaks to the, perhaps, prime issue of the
competitive problem with a producer owned line. Note here
that contrary to what prior testimony has asserted, natural
gas pipelines are not common carriers. They are not. They
are contract carriers and it's an important difference.
Common carriers must, like oil pipelines at least in
theory, must serve all comers. If there's more demand than
capacity, they serve all on a pro rata basis. Everyone
gets a piece of the pipeline.
Gas pipelines however, are contract carriers. What that
means is if new shippers come along and want an expansion,
the only way they can get capacity is by expanding the
pipeline or by obtaining capacity that the existing
shippers perhaps don't want and want to relinquish. With a
producer-owned pipeline, the producers would have control
over both of those avenues of obtaining capacity. They
could try and resist expansion and they certainly would be
under no obligation to release their capacity to their
competitors.
2:45:48 PM
MR. MINESINGER continued:
Also on the expansion issue, AGIA - another one of its
"must haves" states that the AGIA pipeline must hold open
seasons for expansion capacity every two years to determine
whether there is interest in expanding the line. Again,
AGIA directly speaks to the expansion issue.
Another problem related to the expansion issue. Suppose a
producer pipeline says okay, we'll expand but they'll do it
only on terms that are owners'.
2:46:13 PM
One of the key ways that AGIA addresses that is through the
rolled-in rate requirement. Here we're assuming a
situation where the expansion would cause rates to
increase. Were you to have incremental rates that would
cause the explorers to pay significantly higher rates in
many cases than the existing shippers, they'd be at a
severe competitive disadvantage. AGIA, again, tries to
strike a middle ground by requiring rolled-in rate
treatment of expansion costs up to a 15 percent increase in
the existing rates, trying to reduce again the barriers to
entry, if you will, faced by competitors. These rolled-in
rates are consistent with FERC policy in Order 2005, and
with the federal law, [Alaska Natural Gas Pipeline Act of
2004] ANGPA, that mandates that FERC use rate criteria
which promote exploration, development, and production of
Alaska's gas.
2:47:29 PM
Another problem we mentioned is discrimination and access.
In this case a producer-owned pipeline really is
indifferent to having high transportation rates for the
pipeline. Why? Because they're just paying money from one
pocket to the other. They own the pipeline. They really
are indifferent to how high the rate gets, except - except
that that rate, if they can keep it high, adversely impacts
their competitors. It acts as a disincentive to explore
for more gas. AGIA directly tries to help address that
problem by requiring certain things that tend to lower the
rates in this pipeline system, mandating a 70/30 debt to
equity ratio, for example, which has a significant downward
effect on rates, as opposed [to] if you use a thicker debt
to equity ratio. And there are other provisions in AGIA
regarding cost overruns and so forth, which also help in
this area.
2:48:31 PM
REPRESENTATIVE BUCH asked if, on the current oil pipeline in
Alaska, the tariff is set and maintained and gives the producers
the advantage of not only creating higher competition with their
competitors, but also reduces at the wellhead the amount that
they pay the state. He asked if that is addressed and whether a
natural gas pipeline is different in that regard so that the
state has a royalty accomplishment.
2:49:22 PM
MR. MINESINGER said it is addressed in that the provisions being
discussed, such as the 70/30 debt to equity ratio, would tend to
drive the tariff rate down, which would increase the wellhead
price and the state's royalties. It essentially gives the state
an opportunity to avoid some of the problems experienced in
connection with the TAPS oil pipeline.
2:49:52 PM
MR. MINESINGER continued:
One other problem would be the problem of delay. AGIA
requires that the AGIA pipeline hold an open season within
36 months and it requires the pipeline to also do certain
things by a specific date certain. It must initiate the
FERC prefiling process and file for a certificate by a
specific date certain. A producer pipeline, in addition,
would be required to sanction this project within one year.
So, AGIA would not permit a producer-owned pipeline to
simply sit back and delay this year after year after year.
It requires a specific timeframe for going forward, as
opposed to some amorphous, you know, vague, optional
promise of when they can go forward.
2:50:48 PM
Let's talk briefly about why these "must haves" are
critically important, to the extent we haven't already.
You know, some have suggested in prior testimony why not
simply rely on FERC regulation. FERC regulates interstate
pipelines. Why isn't that enough - some of the flexibility
that we heard in the debate over this bill.
I guess it gets back to something Mr. Hosie said in a
different context and, to quote from President Reagan, it's
a matter of trust but verified. The state here has an
opportunity to provide an additional line of defense. FERC
regulation exists, sure, but why not provide an additional
line of defense against some of these clear competitive
problems?
TAPS - we've discussed that example. The state has already
seen what can happen when you have a producer-owned
pipeline that lacks the incentives a normal pipeline would
have to increase throughput through the line and serve
other shippers. In TAPS, that situation, there have been
numerous complaints by other producers that they've been
discriminated against and there are examples of other
producers that have simply exited the state because of what
they perceive as just not a fair deal on that pipeline.
AGIA gives the state a chance to avoid repeating that
problem.
It's also important to recognize the FERC process - it
exists, yes, but it can be a long, difficult litigation
that you'd be facing for a producer to try and force
expansion of the line or bring some sort of discrimination
claim or so forth. AGIA takes that uncertainty out of the
equation and says look, producers you have to expand this
pipeline and so forth.
Producers, it's worth noting, are currently appealing Order
2005, which is FERC's regulation involving this project.
They're challenging the regulations that would facilitate
the expansion of this pipeline so there shouldn't be any
doubt that if you simply rely on FERC, you're in for a
long, drawn out fight that AGIA would help to avoid.
2:53:18 PM
I would also note, before we move to the next slide that
yes, you have all sorts of existing laws that seek to
prevent anti-competitive conduct. FERC and the Natural Gas
Act is one example but there are others, antitrust laws,
for example. Simply having those laws though doesn't
prevent necessarily companies from - they're going to try
and evade those laws sometimes. Just to cite one example,
one of these producers has been alleged and one of their
key employees has admitted to trying to manipulate the
entire United States' propane market. Simply having
antitrust laws on the books that provide for treble damages
and criminal penalties didn't prevent it. And so, why not
try and build in an extra line of defense here in AGIA by
mandating some of these things that are important to the
state's interests.
2:54:24 PM
MR. MINESINGER said the final issue he would touch on concerns
what would happen if the producers do not bid in an open season.
He continued:
Assume you've got an AGIA licensed pipeline. It's an
independent line and clearly the producers, they have the
gas, they have the leases currently. But, what if they
just don't show up and bid for firm transportation
capacity? You have to have firm commitments generally to
build a pipeline.
I guess my answer to that is it depends on how the question
is posed. If you have an agreement between the three
producers not to bid in an open season, you would have a
very serious antitrust issue. It would raise very serious
issues of collusion under Section 1 of the Sherman Act.
That having been said, I think it's premature to go much
further than that. I think we need to wait and see how the
open season plays out, see first how the AGIA licensing
process plays out and then evaluate the facts at that time.
Then the state can determine - other interested parties can
determine whether further investigation is warranted into
whether there is any antitrust issue in that scenario, FERC
issue, or perhaps some other type of issue that would be
raised by effectively withholding those gas supplies from
the market.
2:55:56 PM
In closing, I'd just like to say AGIA really charts a
middle ground here between the two extremes of banning
producer ownership in this pipeline, as was recommended by
the Attorney General in '77, and then on the other extreme,
simply negotiating a deal, in private, exclusively with the
three producers.
2:56:20 PM
CO-CHAIR GATTO said that sounds like a deal that was put
together about one year ago.
MR. MINESINGER said it does sound familiar. AGIA is right in
the middle. He explained:
Instead of banning producer ownership, AGIA attempts to fix
the competitive problems associated with a producer-owned
line. It invites the producers into the process in a way
that is consistent with the state's interest in promoting
the maximum exploration and development of the abundant gas
resources in this state. It establishes a level playing
field, which all parties involved can compete to
participate in this process.
2:57:03 PM
REPRESENTATIVE BUCH said in 1926, Standard Oil was precluded
from vertical integration so we have come full circle. He
continued:
The federal government - we now in our pipeline through one
of the producers in particular - I know going back to the
Midwest there's BP gas stations everywhere. So, they have
the oil, they have the pipeline, they have the refineries,
they have the gas stations. It would seem to me that times
change, laws change. We're going to have to get FERC to
change one of them in particular to make this all work.
I'm asking you if there's any possibility of looking into
your crystal ball to see if we're going to run afoul of the
federal government somewhere down the road with this again
so that this whole thing just gets mired in a federal
court.
2:58:16 PM
MR. MINESINGER asked if Representative Buch was asking if an
antitrust problem would exist if the producers own the pipeline.
REPRESENTATIVE BUCH replied affirmatively.
MR. MINESINGER said that depends because the antitrust laws do
not impose a complete ban on vertical integration. Vertical
integration can be pro-competitive at times. However, this
situation is extreme where three producers would own 95 percent
of the gas and the pipeline. The state needs to wait and look
at the facts as they develop to see whether a FERC problem
exists. FERC is obligated to ensure that jurisdictional natural
gas and electric prices remain just and reasonable. The
antitrust agencies are tasked with preventing and investigating
collusive activity between competitors and preventing unlawful
monopolization. He said one cannot just say a producer-owned
pipeline would violate the antitrust laws, although it clearly
raises serious, competitive issues. The concerns raised by the
Attorney General in 1977 are valid today. The question is how
one gets at those problems - through antitrust proceedings,
FERC, or AGIA.
3:00:28 PM
CO-CHAIR GATTO asked how many miles of pipelines the producers
own in the Lower 48 states.
3:00:34 PM
MR. MINESINGER said virtually none with small exceptions. For
the most part, the pipelines are independently owned. A very
small amount of the capacity might be owned by a pipeline
affiliate in a few cases but those situations are much smaller
than Alaska's pipeline.
3:01:15 PM
CO-CHAIR GATTO thanked Mr. Minesinger and asked Mr. Sparger to
present to the committee.
3:01:52 PM
BILL SPARGER, Consultant, Energy Project Consultants, LLC, first
congratulated members and said it's a great day for Alaska. He
told members he is a consultant to the Administration's AGIA
team with 35 years of experience in construction management and
project management with two major Lower 48 natural gas pipeline
companies. He has worked on all aspects of pipelines: onshore,
offshore, LNG, compressor stations, process plants, et cetera.
He gave the following presentation:
Very, very briefly from a terminology standpoint,
everything I talk about I'll talk about the project meaning
the Southern Alaska Canada route following TAPS and the
Alaska Highway into Alberta, recognizing that that may not
be the project that goes forward but that's what I'm
talking about.
Like Mr. Minesinger, producers to me [are] the existing
three North Slope oil producers. North America is the
United States and Canada. I leave Mexico out of it for
this discussion.
3:03:41 PM
I'm here to talk about what I call unfounded concerns.
Over the last number of weeks and months, you have heard in
testimony and in print statements that are couched as
concerns or issues that appear to me to be unfounded.
We're going to talk about all four of them so I won't go
through this list because you will see them one at a time.
3:04:09 PM
The first one of these unfounded concerns is that the
shippers bear all of the financial risks of project cost
overruns. That is simply not true. For the last decade in
the Lower 48, virtually all pipelines, the agreements
between the shippers and the pipeline companies are what
[are] called negotiated rates. Negotiated means exactly
what it says. The two parties negotiate what the rate is
and they negotiate who bears what risks and, quite frankly,
in most instances, the pipeline bears 100 per cent of the
risk of cost overruns on the pipeline - in most cases.
For this project I would assume that there will be some
risk sharing in this negotiated rate. I don't know what it
is. It won't be 100 per cent of the risk for the shippers,
nor do I believe it will be 100 per cent of the risk for
the pipeline company, but something somewhere in between.
These negotiated risks then turn into something - Mr. Hobbs
will talk about some as firm transportation (FT).
3:05:33 PM
MR. SPARGER continued:
A good model, and I'll mention this several times, is
Rockies Express. It's a new project. It will probably
start construction next month, 1400 miles, 42 inch
multibillion dollar project. It is being constructed and
the majority ownership is a pipeline company in the Lower
48. One of the producers, Conoco, actually owns 25 percent
of the project but has not executed the project. It's a
minority ownership. And then they ship about 400 million
cubic feet a day. One of the other producers, BP, ships
about 200 million a day, going up to 300 as this project
expands so they know exactly what negotiated rates are.
They are in a negotiated rate situation in Rockies Express
whereby the pipeline bears 100 percent of the cost overrun
risk on the project.
3:06:37 PM
The other unfounded concern is that producers must have
economic certainty and economic certainty breaks down into
three areas. The first is supply, or the upstream side.
This is as certain as it gets. The gas is there. They
know how much they can produce. They understand the
reservoir, recognizing that it may act slightly differently
during ... a gas blow down but, for most projects, when
most people sign up for firm transportation on a new
project, they don't know that all the gas is there. They
haven't drilled all the wells and so they are taking a risk
that they might not find the gas they think they're going
to find. In this case, that risk is just simply not there.
The pipeline, or midstream risk - we've talked about the
negotiated rate on the previous issue and so that is maybe
a little risk but is certainly not 100 percent borne by the
producers or the shippers. And the market downstream risk
is simply what do you get for the product. That is a
normal business risk that all producers take for all of
their products everyday. It's the business they're in. No
one guarantees them what they are going to get in the
future.
3:08:12 PM
MR. SPARGER continued:
The next unfounded concern is that the producers are the
only ones qualified to construct the pipeline. In the
Lower 48 and Canada, producers do not normally construct or
own onshore natural gas pipelines. There are, in round
numbers, 200 plus thousand miles of pipelines in North
America - interstate natural gas transmission lines in
North America. The producers, if they own any, it's
probably offshore and it's a very infinitesimal percentage
of this 200,000 miles of pipe in the ground. You might ask
yourself why don't they own it. Why don't they own it?
Well, Mr. Hosie talked about the rates of return or the
hurdle rates that they want to see. Pipelines simply don't
earn those kinds of rates and the rates are highly
regulated, which is not the business that they want to be
in, hence, pipeline companies who are in that business own
and construct these pipelines.
Because they own and construct all the pipelines, they do
it everyday for a living in North America; companies like
Kinder Morgan, companies like TransCanada, and I can name
many more. I'm just using them as examples. They do this
day in and day out in North America for a living. They
understand the regulations. They understand the
construction techniques. They understand the climate for
purchasing materials and equipment. They simply understand
how to execute these projects.
3:09:47 PM
CO-CHAIR GATTO asked whether El Paso is a pipeline builder.
MR. SPARGER said El Paso Energy Corporation builds pipelines.
3:09:55 PM
REPRESENTATIVE WILSON asked if pipeline companies, since they
usually take the most risk, absorb any overruns and whether that
is adjusted in the tariff rates.
3:10:29 PM
MR. SPARGER explained in a negotiated rate situation, if a
pipeline company overruns the project cost, it earns less on the
money it invested. The negotiated rate does not automatically
increase because costs increased, unless that is part of the
negotiated terms.
3:11:04 PM
DON SHEPLER, Attorney at Law, Greenberg Traurig LLP, told
members he is working with the Governor's AGIA team and brings
FERC experience. He said Mr. Sparger was spot on in his answer.
He clarified the distinction comes down to recourse rates versus
negotiated rates. If one assumes, at the end of the day, that
most, if not all, of the capacity on this pipeline will be
contracted for under negotiated rates, the best example is the
Rockies Express. The pipeline committed to a fixed rate
contract, he believes at $1.10 for end-to-end service. The
recourse rate was higher but would go up or down depending on
the cost of the project. The anchor shippers in that project
signed negotiated rate contracts. Therefore, if it cost Kinder
Morgan two times more than it expected to build the pipeline,
the recourse rate will probably increase but the fixed rate
contracts will remain the same.
3:13:09 PM
REPRESENTATIVE GARDNER said in discussions of who might build an
Alaska pipeline or come to the table with an offer, there have
been a limited number of parties but many other companies are
out there. She asked if Alaska would have a larger number of
interested builders, except for AGIA.
3:13:37 PM
MR. SPARGER said that is possible or a company might partner
with another company with more history in Alaska. It is
difficult for a company with no knowledge to catch up with a
company with years of knowledge, like the producers or
MidAmerica. However, nothing will prohibit a company from
stepping forward.
3:14:19 PM
MR. SPARGER continued with his presentation, as follows:
I'm not trying to say here that the producers are not
capable of building this pipeline because they are capable.
They build pipelines all over the rest of the world,
primarily in places like Africa and the Middle East and
Indonesia. They just don't happen to do that as a business
in North America.
3:14:42 PM
The other unfounded concern is that schedules with
milestone dates drive up the project cost - in other words,
almost a quote that "firm dates are bad." I've heard -
seen - heard it in testimony. I've actually heard some of
you express that concern. Once again, this is simply not
true. Realistic schedules are a project necessity.
Projects without schedules tend to go on indefinitely,
forever. Schedules can and are adjusted as circumstances
change. When the circumstances change so that it looks
like your cost is starting to go up, if you hold to a
certain schedule date, then the company is going to sit
back, step back just a little bit and say, what am I going
to make - what am I going to earn if I make the schedule
date versus what additional is it going to cost me. They
are going to look at economic decisions based on the total
impact to the business. Sometimes the decision is I'm
going to hold the firm date. I'm going to let the costs go
up because the profits, when I get this in service, are so
big that I can afford a little cost overrun. On the other
hand, sometimes the schedule dates are simply moved back
some to try to keep the costs more in line. But the fact
that you have those dates does not, in and of itself, drive
the cost up unnecessarily without other economic
justification.
3:16:41 PM
REPRESENTATIVE WILSON said last year when the Legislature was
reviewing the contract before it, experts that talked about cost
overruns were brought in. They said they researched projects
around the world to find out why some failed and others were
successful. They cautioned legislators to avoid fixed dates
because most of the failed projects failed because they could
not meet a deadline.
3:17:34 PM
MR. SPARGER said he reviewed that information, as well as the
material from an IPA course that state staff attended. He
believes no project management expert would say do not have
dates. He emphasized that unrealistic and unachievable dates
should not be set. He said some of the projects the experts
looked at were not in North America and not executed by pipeline
companies and, more importantly, no one knows how the dates were
set to start with. As an engineer, he is aware that sometimes
dates are set by a company's management and those dates are not
realistic. If the company is not convinced that it should begin
with realistic dates, problems can ensue. He repeated that he
does not believe the experts were advising the Legislature to
start off with no dates because the project will never be
finished.
3:19:33 PM
MR. SPARGER continued his presentation:
Some other unfounded concerns and issues - and I'll very
briefly go through these and I can expand if you want to.
One of the statements is leading edge technology is
required to produce project costs and I think it's just the
opposite, leading edge being technology that is not
commercially available - X 100 or 100,000 PSI yield
strength pipe is not commercially available.
You want to use the best technology that is commercially
available but when you start getting off into leading edge,
you expose yourself actually to costs and overruns and
project delays. If it's not commercially available, that
just simply means nobody has done it before on a production
basis. They may have done it in the lab. They may have
done it on small scale things but they haven't done it on a
production basis. So, I would argue with that.
The other thing that keeps coming up in a lot of the
discussions is mega projects are different. That may be
true for certain mega projects, like the Panama Canal,
things like that. In my opinion, it is not true for
pipelines. A pipeline is obviously a linear project. You
design and build pipelines one mile at a time and the
complexity of it is not tremendously affected by whether it
is 100 miles long or 2,000 miles long. It's the same
pipeline as you go through. There are some differences and
it does mean you have to have more resources. You have to
have more surveyors. You have to have more right-of-way
people. You have to have more environmental people. You
have to have more contractors. But it does not make it
more complex or more difficult to manage. It just makes it
longer and more expensive.
3:21:37 PM
CO-CHAIR GATTO noted repetitiveness would make the project less
complicated and less expensive.
3:21:54 PM
MR. SPARGER said the crew does get faster. He said to lay two
miles of requires a lot of money to mobilize the people and get
them ready to go. There is a learning curve. If the same crew
lays 200 miles, they get better every day.
3:22:20 PM
MR. SPARGER continued:
The other thing is that AGIA - the requirement for a
detailed project description is premature and costly. If
you can't describe what it is you're going to build, how
can you schedule it or come up with a cost estimate? So,
you simply can't respond to AGIA. You can't respond to
what's it going to cost and how long is it going to take
unless you know what it is you're going to build to start
with. You don't have to know all the details. You have to
know how long it is. Are you going to bury it or are you
not going to bury it? How many compressor stations [are]
you going to have? And once again, in North America we
know what the requirements are. We know what the
environmental requirements are. We know what the
regulators want - Fish and Wildlife and EPA. We know what
they want. The rules are laid out. These engineering
firms and construction contractors know what the rules are.
They know how to follow them so you can come up with a very
good project description for not a whole lot of cost.
3:23:32 PM
The last point I want to make is just an observation of
mine. The project ... schedule as currently proposed - the
ones that I've seen are all 10 years long from start to
ready for service. I think that with a timely commitment
to firm transportation on the part of enough shippers, that
a person could shorten that schedule two or three years.
I don't have an alternate timeline to tell you but
intuitively these projects in the Lower 48, with the same
regulations, the same FERC, the same EPA, these projects
take three to four years. This would be longer because of
the short construction season and because of the fact that
you have to construct some of it in the summer, some of it
in the winter. But even given that, I'm saying seven years
maybe or eight, but not 10. Now that's assuming that
somebody steps forward, the shippers, and signs FT
agreements early on so that the pipeline company, whoever
that may be, has a commitment and then we'll just move
forward.
3:24:55 PM
CO-CHAIR GATTO said this mega project is going to follow a road
where a pipeline already exists.
3:25:01 PM
MR. SPARGER advised members to not compare this project to TAPS,
which was a true grassroots project. This project is going to
build on the knowledge learned and mistakes made on TAPS so that
those same mistakes are not made again. The road is in place,
as well as the infrastructure. Very few new roads need to be
built. He cautioned this is not a simple project and it is
large, but it is still just a pipeline. He offered to answer
questions.
3:26:07 PM
CO-CHAIR GATTO agreed the project is just a pipeline. He asked
Mr. Barger to clarify X70, X80, and X100.
3:26:41 PM
MR. SPARGER explained that X70 stands for 70,000 PSI yield
strength or the strength of the material. The higher the number
for a given diameter of pipe, for example 48 inches, the thinner
the wall. As the strength increases the thickness decreases.
As the wall thickness decreases, the tons of steel that need to
be purchased decreases. Therefore you would want to use the
highest commercially grade steel available to keep the wall
thickness down and the cost down. X80 is commercially available
today; it was not five years ago. He said if he was designing
the project, he would use X80. If he was to order it four years
from now, he would want to know if the X100 was commercially
available at that time. If it was marginal, he would bid both
ways: using X80 and X100. However, he would not use it if it
had not been used before because this is not a project for
experimentation. He believed TransCanada has used X100 on about
five miles of pipeline and has possibly used X120. TransCanada
is experimenting on a small area of pipe to see how it reacts
and bends. Maybe TransCanada will use it on 30 miles of
pipeline on its next project but, he repeated, it is not wise to
experiment with a 1700 or 1800 mile pipeline.
3:29:02 PM
CO-CHAIR GATTO asked what the wall thickness is on X80.
3:29:04 PM
MR. SPARGER said it is about one inch for a 48" diameter
pipeline.
CO-CHAIR GATTO thanked Mr. Barger for his presentation and asked
Mr. Hobbs to present to the committee.
3:29:46 PM
REPRESENTATIVE SEATON noted that after the Exxon Valdez spill,
everyone felt the aging tanker fleet needed to be replaced. The
old standard heavy thick steel tankers were taken out of
service. Now the tankers are built with high strength steel and
they are cracking because the high strength steel is less
flexible and hardens. Therefore, the new tankers need constant
repair. He pointed out that when using the latest product, over
time problems surface.
3:31:00 PM
SCOTT HOBBS, Energy Capital Advisors, related his background as
follows:
I have been a consultant for about the last six years.
During that time I was actually chairman of a midstream
natural gas company that we recently sold. It was a
natural gas gatherer and producer in Wyoming, in northern
Louisiana, East Texas. During that time I've advised
investment bankers, different potential investors on
projects as well as some private equity firms that have
been looking into investments into the energy business -
all types, pipelines, and various and sundry energy
ventures. I am here today on behalf of the Administration.
I've been asked to look at a few questions that have been
raised, points that have been made in some of the prior
testimony and I'll try to make my comments as brief as
possible but try to cover them as best I can.
3:32:19 PM
MR. HOBBS continued:
The discussion topics I'd like to cover today - it's been
suggested in some of the previous testimony that there [is]
really only one way this project can move forward and
that's for the producers to own this pipeline and to move
it forward essentially on their terms. I think they would
like to own and build on their schedule. I'm going to take
a moment and talk about the advantages and risk associated
with a producer committing to a third party to build this
pipeline because it may be that that is what the state
ultimately pursues. It may be what's in everyone's best
interest, perhaps not the producers and we'll talk about
that. When I talk about producers as some of the prior
folks have discussed, I'm talking about ExxonMobil, Conoco
Phillips and BP.
There's also been a number of ... representations made
about how firm transportation is accounted for and how
that's going to create some real burden or impairment on
the party that signs those contracts. I'll speak to that.
And then there also has been serious questions raised about
the economics that were performed by Dr. Scott and DNR in
trying to evaluate is this a commercial project. Is this
an economic project for the producers? And I'm going to
speak to that and I'll conclude with a few conclusive
remarks.
3:33:54 PM
Let's start with the advantages and the risk of contracting
for firm transportation on a pipeline as compared to owning
it and building it yourself. Probably the most significant
advantage for a producer with a substantial reserve base
like we have here on the North Slope is they avoid the
front end capital costs. You've heard, quite eloquently,
Mr. Hosie discussed about the returns that the producers,
and in particular Exxon, are earning on their typical
investment. Actually they're making greater than 30
percent return on investment. That's what they showed in
their most recent 10K. It's interesting when they say they
need to own this project because this pipeline will provide
on a comparable basis a return on investment of somewhere
around 8 to 9 percent so I find that peculiar that they
would want to own this pipeline with such a low return by
comparison with what their alternatives are.
So, I'm here to tell you that I think it would be very
advantageous for them to use that capital for those 30
percent projects and not an 8.5 percent project, but we'll
get to that and maybe perhaps understand a little better
why they want to own this project.
I think they have an ability to improve their project
economics by not owning this pipeline. I think they can
avoid a lot of risk by contracting with a third party.
You've already heard Mr. Sparger talk about negotiated
rates. They can actually allocate through negotiations
with a third party pipeline provider. They can allocate
risk to that party, most notably cost overrun risk and
we'll talk about that. So, there are - and they can force
certain schedule requirements if they do desire for this
pipeline to be built by a certain timeframe.
So, those are commonplace in agreements between pipelines
and producers or shippers. I failed to mention I was an
executive at a pipeline for - well I was actually the chief
operating officer for the last eight years. I worked for
two natural gas pipeline companies in the Lower 48, two
major pipelines, for about 24 years so I do have a bit of
experience to draw on in terms of talking about how
producers, how shippers negotiate with pipeline companies
and how those risks are shared or allocated between the
parties.
3:36:48 PM
I will tell you that when you look at ExxonMobil, BP,
Conoco, they all have major projects all over the world.
Look at their annual report. They have LNG projects. They
have major - more conventional gas projects. They have
tremendous projects that are going on everywhere. By
contracting with a third party for this pipeline, they can
actually avoid what would be a significant drain on their
human resources. You read in a lot of industry text now
about - that is one of the major issues that the industry
is facing. Its workforce is getting older. The young
people have not been coming into the business. They need
capable people to manage projects and to perform the
functions they have to be successful.
By contracting with a third party, such as those that have
come forth and made proposals, or at least provided
testimony to the Legislature, that being TransCanada,
Enbridge, MidAmerican - as we've said there may be other
parties that become interested in this project. These
people have very strong regulatory and construction
expertise in building pipelines in North America. Mr.
Sparger has talked about that. I think there's an ability
to tap that capability, contract and protect yourself with
the appropriate terms in that contract and lay off some of
that work, that effort, that risk on a third party. That
is not an unreasonable strategy for a producer to pursue.
Okay, well why wouldn't they do that? Well let's look at
the risk. What you've heard is that if they don't manage
this project, they are going to end up paying for all the
cost overruns.
3:38:30 PM
Hopefully we've debunked that theory. The last ten years
do not support that. Their own experience and contracts
that they've executed support the fact that they can put
off that risk or lay off that risk on a third party
pipeline. That's very prevalent in the Lower 48. In this
case, I will tell you that I don't think that the producers
would be able to lay off 100 percent of the cost overrun
risk here. It will be some sort of negotiated sharing
arrangement.
That's a logical outcome for a project of this size and
complexity but, I will tell you, they can very easily force
a pipeline company to take enough risk where they will
[have a high incentive] to build this pipeline on budget,
otherwise they will be facing substantial reductions in
their return and potentially even a loss situation.
3:39:22 PM
MR. HOBBS continued:
The ability to finance the project - well, you've heard
stated that really you have to be an ExxonMobil or a BP to
get this project financed. I will tell you in my
experience that is probably another overstatement. Think
about it. You have a federal loan guarantee here. You
have very capable pipeline operators that are operating
very sizeable companies and you have world class reserves
that have already been proven that are being recycled into
the ground. Those are the components for a very solid
project. This project will be financed. You do need
ultimately, firm transportation contracts, which I think
will ultimately be signed, but this project, although it's
very large, will be financed and can be financed by parties
other than the big producers.
So why is it that this project is in the position that it
is and has been for years? I believe if the producers
contract with a third party or put forth a proposal under
AGIA, they lose control of the process. It's that simple.
They can no longer dictate the design, the schedule, the
tariff provisions or the rate designs that might promote
competition or development by third parties. Once they
fall into either a third party or an AGIA sponsored
project, these types of, let's say - these types of items
that are available to them - what they'd be able to
accomplish if they were owner and the shipper, are no
longer available to them and that is exactly what AGIA has
been designed to do. Quite frankly I think that is one of
the reasons that they have so much trouble with AGIA and
why they also don't want a third party. They are going to
give up a lot of power, so to speak, negotiating power,
market power, call it what you will. They are good
businessmen. They are trying to maximize the value of
their investment and, in so doing, they'd like to keep the
position they currently enjoy.
3:41:40 PM
MR. HOBBS continued:
Moving on, there's been a lot said about the accounting for
firm transportation agreements. It's been stated that FT
agreements are debt or they are at least debt-like. Well,
having reviewed the producers' 10Ks, Mr. Hosie explained to
you that there's a lot of information in their annual 10Ks
that they file every year. FT agreements, at least as
these producers - and quite frankly as the industry
generally handles them in their accounting, they are not
debt, they are not debt-like in that they are not
capitalized or recorded on the balance sheet. That is not
the way firm transportation agreements are handled.
3:42:45 PM
If you look at their 10ks, and I brought ConocoPhillips' as
an example ... this is a copy of an excerpt from Note 18 in
ConocoPhillips' financial statements. Every major company
will have a note that speaks to contingencies and
commitments. What I've done is taken an excerpt, and I'll
just scroll down. If you look at the highlighted portion,
interestingly enough, you'll see a reference to the
Venezuelan government and the fact that they may
nationalize - they're considering it. Obviously that's
happened - so much for fiscal certainty.
Here it is in highlight. This is the disclosure that
ConocoPhillips makes for certain FT agreements. It's not
on the balance sheet. It's in a note to the balance sheet
and essentially to make this disclosure - it has to be
directly tied to a financing of a project that's providing,
in this case, the service that they've signed a long term
throughput commitment on. They're called unconditional
purchase obligations. I realize this is a little bit
arcane from an accounting standpoint, but the point I'm
trying to make is it has to fall into a very specific
category. Look at the amounts - $77 million was what
they're estimating they would pay under throughput
agreements or take or pay agreements that are in support of
financing arrangements. That's a key term. If the terms
of this are not directly tied to the financing of this
facility, it's not required to be disclosed.
You look at the amounts there. This is what is disclosed
in a note to the financial. It is not debt. It is not on
the balance sheet. This is what's required.
3:45:03 PM
They also have a section called The Management Discussion
and Analysis of Financial ... Condition and Results of
Operations. Again, I've tried to highlight the relevant
points. Here they're spelling out all of their contractual
obligations. This is a supplemental disclosure. This is
not on the balance sheet. This is what's filed in what
they call the MD&A of the SEC. Total debt you'll see there
is $27 billion. Interestingly enough, what we're talking
about here falls under purchase obligations and if you read
that note, Note B, they go through a litany of different
purchase obligations that actually aggregate to $93
billion. I can assure you ConocoPhillips does not want
anyone telling someone else that they have $93 billion of
debt. That's not the case. This is just a disclosure of
contractual commitments. Included in that is $3.8 billion
related to transportation. That's the sum total of all the
agreements they've made to transport gas, oil, whatever, on
pipelines where they've made throughput commitments.
Compare that to the $70 million that we were talking about
earlier.
So obviously, what's disclosed in the notes of the
financial has to meet very specific criteria. Here they've
gone forth and said here's everything we've got out there
and this is the way these agreements would be disclosed.
So, in summary, it's not debt. You can see it's separate.
There is a disclosure. That's just good management.
They're trying to show what's going on but they do this
everyday. This is done in the ordinary course of business.
What a pipeline operator would be asking them to do here is
no different than what they've done in countless situations
where they operate.
3:47:27 PM
The last item I'd like to - actually there's two more
items. It has been said that if they sign an FT agreement,
that's going to create a real burden or impairment on the
company. I will tell you that if they sign an FT
agreement, it will actually enhance their financial
position. The reason is they are unlocking this treasure
chest of reserves that have been sitting in Prudhoe Bay or
Point Thomson for a very long time. When you talk about a
ratings agency, that being Moody's or S&P, it's also been
said that they're going to look at this negatively.
Actually they're going to look at the contractual
obligation that one of these parties or all of these
parties when they sign an agreement for firm
transportation, they will in fact build that into their
analysis. But, equally, and perhaps more importantly, they
are going to look at the cash flow it creates. In this
case, it's going to generate significant incremental cash
flow because they now can sell gas that heretofore had to
be recycled or left in the ground.
CO-CHAIR GATTO said he is glad Mr. Hobbs is commenting on this
subject because Mr. Antony Scott told the committee the same
thing and was immediately challenged by the producers, who said
he failed to include that as debt.
3:48:43 PM
MR. HOBBS explained it is neither debt nor an asset. It is a
contractual right to move gas in a pipeline. However, that
right creates significant value for the holder of that capacity.
If, ten years down the road, they don't need as much capacity,
they have the right to sell it to someone else as "capacity
release." They can release it to another party and lay off the
risk of that capacity to that party. That right unlocks a
tremendous value. He opined the rating agencies will see this
as being very favorable because they will not commit to this FT
unless reserves support it.
3:49:49 PM
REPRESENTATIVE SEATON referred to an e-mail that was circulated
to members about debt consideration. It said a bankruptcy court
only considers the first year of FT as a liability in
bankruptcy. He asked Mr. Hobbs if he could verify that
information. He thought regular debt is put into a bankruptcy
court at full value. He questioned if, under FT, the bankruptcy
would only look at debt for the current year.
3:50:39 PM
MR. HOBBS said, in his experience, it depends on the specific
contracts. He explained:
Generally you have to look at who the party is that is
bankrupt. In the case of a pipeline company, if the
pipeline went bankrupt, more than likely the trustee will
step in, or the court, and say this is a revenue producer
for the pipeline. Whoever the new operator of that
pipeline is - if they bring someone else or if it's a
debtor in possession, they will order that party to
continue to provide the service so the revenues keep coming
in. The flip side I believe is what you are talking about
where the party who actually has the obligation to pay the
firm transportation charges and use it, that's where the
one year limitation comes in. Generally if it was debt, it
would be just what you said. They would have to look at
the dollar amount in its entirety because at the date there
would be a conveyance of money and a debt instrument
created. In this case there's just a contract that says I
will use your pipe for 10, 20, 30 years, whatever. It's
paid over time. It's a commitment to use, and for that the
provider has to give the service back. In that instance,
if the party that signed the FT agreement to ship the gas -
they would be probably limited to that one year amount
you're talking about so another reason that it's really not
debt.
3:52:07 PM
CO-CHAIR GATTO noted that Enron was a pipeline company that was
not only bankrupt, but was zeroed out and the gas continued to
flow.
3:52:19 PM
MR. HOBBS said he worked with a group of private equity players
and industry players to purchase the Enron assets. Enron was
bankrupt but the Transwestern pipeline, Florida Gas and their
general partnership interest in Northern Border were operating
every day because they were viable companies, as opposed to the
parent company or trading operations, which is where the
problems were. In that case the bankruptcy did not affect them.
They continued to operate daily. Ultimately the trustee stepped
in and said assets would be sold to pay creditors.
3:53:19 PM
MR. HOBBS continued:
If you look at producer economics, one of the comments
that's been made is that the Department of Natural
Resources, in particular Dr. Scott's analysis, was just
really faulty. I have spent a good deal of time with Dr.
Scott, reviewed the model. I will tell you that I think it
is very reasonable. I think what they've done is
reasonable based on the best information they have
available. I think it's very important to know that the
producers, and you know this of course, have not provided
any economic studies to support their contention that this
is not commercially viable. So, what happened is, I think
DNR has had to use the best information they have available
in trying to estimate is this an economic project for the
producers. I will tell you that based on everything I've
seen, it clearly is.
What they've done - if you step back and think about what
is it that makes a producer project economic, I tried to
list the factors there. Obviously the first and foremost
is: Is there adequate gas reserves and deliverability
getting the gas out of the ground? Is there adequate gas
to make this project viable? This particular situation is
unprecedented from my experience to have the volume of gas
proven and already being produced and recycled. This
volume is extraordinary. So that really is not a
significant issue.
Then you have - what is it going to cost to treat and
transport this gas to market? That's where the model that
DNR has developed - they brought in consultants from Block
and Beach, who are experts that work with Lukens (ph), the
subsidiary of Black and Veatch. J. Lukens is very well
known in the industry as an old rates guy from Transco.
They did a lot of work to help them develop what the rates
would be under a pipeline project because ultimately the
shipper, the producer, will pay those costs. So they've
tried to come up with a reasonable set of costs for that.
The commodity prices - well, obviously if you talk to
anyone in the gas business they will tell you they have a
guess cost estimate so they've created I don't know how
many different price paths and possibilities and that's
what that distribution of possibilities was to try to come
up with the best analysis of what is the most reasonable
gas price. And then they showed different levels, which is
really what you have to do. What if gas costs this much?
What if it generates this much revenue? What if it
generates this much? So they've looked at alternative
commodity prices to a great extent.
Then you have to try to determine additional development
costs. What's it going to take to bring Point Thomson in?
Obviously Prudhoe is not going to cost much to bring that
gas on. Most of the infrastructure is there. And then
they've looked at operating costs, taxes and royalties, who
better than the lessee, in this case particularly under the
[petroleum production profits tax] PPT regime, to know kind
of what these costs are.
So, I think the model is reasonable. I think it speaks to
all of these, which I consider the primary drivers for
producer economics.
3:56:36 PM
The conclusion I've reached is it is very difficult to
construct a worst case scenario where the producers did not
continue to make or have solid economics. It's really hard
to find a scenario that's reasonable where they're not
going to have rock solid economics. And I need to point
out, that's with significant upside. We can try to create
a perfect storm on the downside but what if the true
perfect storm, i.e. Hurricane Katrina, hits and takes out
almost the entire Gulf of Mexico production. Gas prices
went to the low teens - actually about $15 for a short
period of time.
Under that scenario, gas prices - that's how you reach the
astronomical returns that were cited. I don't believe they
got anywhere close to that in the analysis they did. I
think they stopped at $9. So, the point is, under any
reasonable gas price scenario, I think this is a solid
project. If you give that gas price a 50 percent
reduction, if you increase current estimated capital costs
by 50 percent that is my reasonable worst case scenario.
The producers would still earn in excess of a 20 percent
rate of return.
So, when they say it's not economic - this is where they
need to come forth and show us how, because I can't get
there. So what have they done? They've said well Dr.
Scott has not done his economics properly because he didn't
capitalize the cost of FT or he didn't recognize that there
are huge capital costs associated with this project. Well,
if you contract with a third party, those are not your
capital costs and you do not have to capitalize that FT
agreement. In fact, as we've already shown, capitalizing
that is entirely inconsistent with the way they account for
it in their financial statements. So, once again there is
an inconsistency between what they are stating needs to be
done and the way they are accounting for it.
So, in this case, I think it is entirely reasonable to look
at the FT costs exactly as the model and DNR have done.
That is as an expense. They take it off the delivered cost
of gas, the delivered price. They reduce that for the
tariff costs, the transportation costs both in Canada, in
Alaska and for the gas treatment plant to come up with a
net-back price.
Let me put this maybe in perspective. If we could turn a
switch tomorrow and this pipeline was built based on the
best cost estimates we have right now and the ... rates
that had been calculated under the tariff model that Lukens
and DNR have created, I'll walk you through what I think
the current day economics would be.
3:59:23 PM
Look at the current 12 month gas price. This is traded in
the futures market. You take the current gas price. It's
roughly $8.60. That's the average price at Henry Hub.
That's the benchmark price for natural gas right now over
the next 12 months. This is from a couple of days ago.
Back off what is a price differential called the Alberta
price differential or basis swap. You can lock in by
buying futures or - on a forward price curve you can lock
in the price for what the differential between Henry Hub
and Alberta is, you can actually go out and buy that on the
exchange. That's roughly $1.17, just to use rough numbers.
That gets you to about $7.50 is the price in Alberta. This
is over the next 12 months. I'm assuming that we've turned
the gas on and it's flowing down the pipe. Then you would
subtract from that $7.50 the $2.00 pipeline and [gas
treatment plant] GTP cost. That's what is currently
estimated at the $20 billion project level. That gets you
to $5.50 is what the producers would enjoy for gas
delivered into the pipe - actually into the gas treatment
plant. That results in a $5.50 net-back price for the
producers. They would actually - what's been proposed - it
would be about 4.5 bcf a day. That provides about 1.64 tcf
a year. You take that $5.50 price times 1.64 tcf and you
have $9 billion in the first year. So that is what the
producers would enjoy in the current - obviously this is
going to take 10 years to build but if they could turn the
pipe on tomorrow using current pricing, using current
capital cost estimates, the producers would enjoy $9
billion in year one.
Now, they need to pay operating costs, they need to pay the
state's royalty share, they need to pay any sort of Capex
that's required. But they've got a substantial - so when I
say it's difficult to construct a reasonable worst case
scenario where this isn't economic, that puts it in
perspective for you. $9 billion is a big number.
4:02:19 PM
CO-CHAIR GATTO noted that is [calculated] with current gas
prices so in 10 years the prices will double.
4:02:33 PM
MR. HOBBS said the Department of Energy's (DOE's) forecast puts
the price close to $8.60. Over the next 15 to 20 years, the
forecast has gas prices ranging from $8.50 to $9.00, not that
the government forecast is better than others.
4:03:00 PM
MR. HOBBS continued his presentation:
So this number is not out of line but the pipe needs to be
built. There are a lot of challenges that need to be
overcome.
So, in conclusion, I guess from my perspective there are
very real advantages for the producers contracting for FT
with a third party versus owning the pipeline but that's
their decision. They can go forward under AGIA or they can
go forward outside of AGIA and build this pipeline
themselves. I think there are very real incentives for
them to move forward. Contracting for FT on an
independently owned pipe will not adversely affect the
producer. In fact, it's actually going to enhance their
financial position.
Finally, under any reasonable scenario, they should enjoy
very favorable returns whether they decide to own this
project or they contract with a third party.
4:03:55 PM
CO-CHAIR GATTO thanked Mr. Hobbs and asked Mr. Harper to address
the committee.
4:04:28 PM
RICK HARPER, Consultant, Econ One Research, Inc., informed the
committee that he is appearing as an advisor to the Legislative
Budget and Audit Committee (LBA). He related that he has been
involved in the energy business for over 34 years.
4:04:50 PM
CO-CHAIR GATTO noted the previous testifiers were paid by the
Administration so one could almost say they represented the
Administration. He felt their testimony was sound but said Mr.
Harper is paid by the Legislature.
4:05:14 PM
MR. HARPER said he was with ARCO for 15 years and then served as
an advisor for 10 years after that. He noted that he ran
Atlantic Richfield's North American natural gas business
activities. He also noted that he served as president of ARCO
Gas and was also an executive member of ARCO's royalty policy
committee, which dealt with the issues Mr. Hosie discussed.
Those issues were alive then and are alive now. He was also the
CEO and President of a Canadian oil and gas exploration
production company operating throughout the Western sedimentary
basin in Canada. Most recently, Mr. Harper related that he was
senior vice president of Northwest Natural Gas Company,
operating in the Pacific Northwest. For the past six years he
has run an international oil and gas consulting firm
headquartered in Houston, Texas. He has worked with the
Legislature in collaboration with Econ One. He noted Mr.
Leitzinger and Mr. Pulliam of Econ One could not attend today so
he will make a few comments on their behalf.
4:07:26 PM
MR. HARPER began his presentation, as follows:
My presentation is a little different than it might have
been, if not for the events earlier today. I will tell you
that, as I've told a number of you who are here and
listening, this is really just the beginning. I think it
was said by some of you on the floor and then at the
Governor's press conference that really, in some ways, the
more important decisions for you may be yet to come so
everything you are hearing today and have heard today is
still very pertinent, not dated in the least, and I've
tried to tailor my comments in light of what's happened
today to help begin to equip you for what will be to come.
There's been a lot of hyperbole over the last months and
years and, as Spencer and Scott and Ken and Bill have
advised you, you would expect hyperbole and you would
expect the parties to represent their interests because
this has been to date in the context of a negotiation. So
it's been our job as your legislative consultants to try to
create a no spin zone for you and I feel that has been my
job. I have no stake in this. I have no family member who
is involved or employed. I own no stock interest in any of
this so that has been my goal.
4:09:01 PM
So I guess my comments today are going to revolve around
and actually will fit very nicely with many of the things
that have been very accurately said here today by the
Administration's team to talk a little bit about the risk
parameters, the kind of decisions that go on in producing
companies, how they make decisions, and in pipeline
companies because you're going to be reflecting on that as
projects and consortiums come forward, I believe, to you in
the not too distant future. To talk a little bit about how
economics are viewed and to talk also about how FT is
viewed. We still think that's a live issue. We don't
think - Mr. Hobbs and I don't think that this is the end of
that subject coming before you.
4:09:28 PM
MR. HARPER continued:
At any rate, so my comments are generally qualitative in
light of the events that have happened today. But I will
tell you this. I support fully the thesis that this is not
- not a high risk venture. It is an extremely large
venture but there is a very big difference.
What we have in North America, certainly throughout the
United States and Canada, is an extremely mature business
infrastructure in natural gas. We have well developed
legal and regulatory precepts. We have well developed
markets. This project is not contingent upon market
development in any sense of the word. It is not contingent
upon downstream infrastructure development in any sense of
the word and it is not, for the most part, contingent upon
upstream reserve development. So when you look at both
ends of this thing, you've got the greatest degree of
certainty that I've seen in pipeline construction, in FT
subscription in my business.
4:10:39 PM
I will also state, as I said before and created some
excitement and support in some of those in the geological
and geophysical roles in DNR, some of which I've known
through the years, I really think what's at issue for you
good folks here today, the key decision makers here in
Alaska, this is not about 35 trillion cubic feet of gas.
This is about a whole lot more because, just like Texas and
Louisiana in the '50s and '60s and, to a large extent in
the '70s, nobody's been up here purposely looking for gas
for obvious reasons. That is going to change, I believe,
beginning today and, in fact, I think it's changed before
today. I think you've seen other companies coming in here
recently who haven't been here taking very, very large land
positions in gas-prone basins. So, as you think about
this, I ask you to think about it well beyond the 35. I
think it's the tip of the iceberg and, personally, and this
is very subjective, I think the potential estimates that
you've seen are understated.
4:11:24 PM
CO-CHAIR GATTO felt the big concern is whether the pockets are
big pockets or many small pockets.
4:11:32 PM
MR. HARPER said it is one of the few areas in North America
where there, he believes, is "legitimate elephant potential
remaining," which is what the majors refer to for large
development opportunities. He noted he was heavily involved in
the Western sedimentary basin in Canada in the 1990s, which is a
mature basin. The elephant days were over there in the '90s
even though huge discoveries were found - enough to support the
Alliance pipeline construction.
4:12:21 PM
He continued his presentation:
I think that a reasonable expectation of profit, just
[indisc.] back briefly to Spencer Hosie's presentation, the
producers under the lease obligations are not entitled to
profits. They are entitled to a reasonable expectation of
profit before going forward with development. Their
obligation is not only to develop, given the express and
implied covenants. Their obligation is to develop, to
market, and to account to you accurately. Those are the
three key obligations that they have. I believe that there
exists, right now today, a reasonable expectation of profit
for going forward in all regards for those producers.
4:12:59 PM
Looking at it from an economic perspective, you've heard a
lot of talk about - and you've had IRR - Internal Rate of
Return thrown at you throughout the Centennial Hall days
and here recently and a lot of confusion over how decisions
are made. I can tell you having sat at the decision table
in collaboration with other executives many times, at the
producers' as well as pipeline end, there are several
indicators that you look at. IRR is always looked at and
also cash flow is looked at. Return on capital employed is
looked at, EBITDA - Earnings Before Interest Taxed
Depreciation Amortization is looked at.
But key and number one in the final analysis is net present
worth, net present value as it's sometimes referred to.
That is king and Dr. Tony Finizza of Econ One has told you
that. I've told you that. think Antony Scott and others
in the Administration have certainly told you that and I'd
hang on to that because this issue is going to come around,
I believe, for you as these projects roll forward.
4:14:00 PM
CO-CHAIR GATTO recalled at Centennial Hall last year that Pedro
Van Meurs focused on IRR for days. He questioned whether that
is quite the same value as net present value (NPV).
4:14:13 PM
MR. HARPER said IRR is a different creature. Dr. Finizza gave a
thth
presentation to the Legislature on either June 14 or June 15
of last year and provided a full expose on IRR. IRR is an
important indicator but it is not the decision maker. It never
has been and is not likely to ever be.
4:14:48 PM
MR. HARPER continued his presentation:
One thing I want to point out is that - and there has been
confusion and I keep saying this - there is no gas supply
commitment required to construct, expand, have anything to
do today with a natural gas pipeline in North America. In
the old days the supply commitment, when the pipelines were
actually buying all the gas, was important. There is no
supply commitment anymore. All that's needed is
commitments to ship and that's what FT represents. Those
commitments are typically made by electric utilities, gas
utilities, marketers, producers and industrials. Those are
the companies that typically make those. Now either they
have some strong position from a market perspective or they
have some strong position from a supply perspective.
Why they would take FT varies and I think you are going to
be surprised once you get a project going, and there are
actually subscriptions, as to who might show up. And you
will see people taking FT on a speculative basis as well as
a tangible, concrete basis associated either with reserves
or with market. But just remember, there is no supply
commitment required. They don't have to step forward with
a supply commitment. That pipeline is subscribed, as Mr.
Hobbs was just telling you about - that's going to move
forward as Mr. Sparger said. Once that happens, you might
be surprised how quickly this pipeline can move forward. I
could not agree with Mr. Sparger's comments more on that.
4:16:15 PM
REPRESENTATIVE SEATON said when legislators were dealing with
IRR and Net Present Value, the proposal presented contained
evaluation terms for the state to use on a proposal on the NPV
of future cash flow. He asked Mr. Harper if he feels that is an
appropriate measure for legislators to look at and whether there
are any others.
4:17:07 PM
MR. HARPER said he believes that is the right thing to look at.
He suggested that members be up to speed on IRR, EBITDA and cash
flow, the relative financial health indicators.
4:17:45 PM
MR. HARPER continued his presentation:
In my experience in the roles that I have played in
corporate life, the question of whether to capitalize FT
has always come up. Firm transportation is a relative part
of a local gas distribution company's business - is a much
bigger part of their business than it is of a producer's
business because it is their life blood. It's a much
bigger part transactionally, commercially and it's also a
much bigger expense item relative to the total business
operation. It also came up at ARCO, it came up in Canada -
my operations in Canada. Not once did we decide that FT
should be capitalized or constitute debt.
It is a substantial obligation - that is not to minimize
it. But I will also tell you this. When it came time to
sign an FT deal, it was sort of like you folks here today
when the bill was done. It's a time of celebration. Gosh,
I've heard this thing discussed as though oh, my gosh,
we're going to have this FT thing, it's risky, oh God, it's
going to show up as a footnote. Well, whether you're a
producer or whether you're a local distribution company or
marketer, if you've got the courage to step up for FT, it's
because you've got a really good business reason, which
means there's going to be a lot of revenue, you believe,
when it's done. Mr. Hobbs, I think, did a terrific job of
creating a very simple example "snapshotting" today and I
will assure you when they step up and sign FT they will be
toasting that evening. So, don't be misled by this dark
cloud that seems to represent FT. It represents real
opportunity.
As we said, here we have a situation, mature downstream
infrastructure, well developed and continuing to grow
markets - growing markets, and we've got a supply. We've
got enough reserves in place to initially support the
construction of this pipeline and tremendous potential to
support it and expansions to it long term.
4:19:45 PM
I guess there [are] other things I could talk about but in
light of where we are with the legislation, Mr. Chairman,
at this time I'll stop and answer any questions that you
might have.
4:19:56 PM
CO-CHAIR GATTO asked if he would comment on McKenzie.
4:20:04 PM
MR. HARPER said he could provide a limited perspective.
McKenzie is in a slightly similar position to Alaska. Some of
the same tension between some of the same producers exists in
regard to building a pipeline. In terms of the hydraulics, from
a market standpoint, within the last three weeks he has been
talking to Canadians about supply and market trends in Canada.
He is an advisor to the Northwest Industrial Gas Users and the
Northwest Power Planning Council, which is a five-state
commission appointed by the governors to handle hydro-policy.
The western sedimentary basin decline rates have been steeper
than anticipated, even with substantial improvements in current
gas prices and long term gas prices. They are peddling hard to
stay even.
MR. HARPER pointed out that two other dynamics are thrown on top
of that with oil prices being relatively higher than natural gas
prices: a movement to aggressively develop the oil sands, which
requires tremendous amounts of natural gas to be used as an
energy catalyst to extract from the sands, coupled with a shift
in the infrastructure in the U.S. He suggested Mr. Sparger
address the committee on that topic because he was involved in
the Rocky Mountain Express project. He believes the Rocky
Mountain Express will cause a complete shift in the way physical
gas moves across America.
MR. HARPER further pointed out in the current situation, the
Pacific Northwest and Canada have growing concerns about the
physical availability of supply, specifically widening basis
differentials where they will have to pay substantial premiums
to attract supply. In addition, they have concerns that the
Western Sedimentary basin gas may be used in oil sands carrying
a risk that the very large lines coming out of the basin may
have isolated or stranded capacity. The bottom line is Alaskan
gas and McKenzie gas are much more attractive now than they were
a year ago on a relative basis. He believes the McKenzie
project will not compete, but will be complimentary to an
Alaskan project. He offered to research the question more if
desired.
4:23:20 PM
CO-CHAIR GATTO said a lot of pipes from Alberta to the states
are not full and Alaska gas will help put more pressure in those
lines.
4:23:41 PM
MR. HARPER assured members that regarding the notion of price
effects of Alaska gas and McKenzie gas, the price expectations
are already factored in.
4:24:30 PM
REPRESENTATIVE BUCH asked Mr. Harper or one of the other team
members to address the prospects of LNG, an interstate gas line,
and the possibility of a Y line.
4:25:30 PM
MR. HARPER responded:
Thank you - very insightful and complex questions. I would
say with regard to LNG, LNG from a world perspective is
going to become increasingly important because there are
certainly more future hydrocarbons and methane than there
is apparently in oil, based on what we know and there's a
growing trade and it's a different kind of a market because
those cargos move around depending upon price signals that
are occurring real time - a little different than a
pipeline.
What we're seeing is a great deal of difficulty in getting
...import projects sited. It's a very slow process.
There's a great push in the Pacific Northwest and
California right now to get something done - one, maybe two
projects, just one or two projects to help with the supply
hydraulics. Do I think Alaska gas is competing with LNG?
No I do not. Certainly the more supply that you have,
relative to supply demand obviously improves the supply
configuration and intends to moderate price outlooks, the
more that you have. But on the other hand, the more
moderated the price outlook gets, then the more energetic
you get in terms of looking at future demand.
We're not looking at a static demand market and this is the
problem I had with the argument a year ago. You've got LNG
and Alaskan gas that when they hit the market from a cost
perspective they're not too far off. Now Dr. Finizza, Econ
One, will tell you even in that analysis you're not
competing with LNG, you're competing with the highest cost
source. That's the first one that gets threatened by new
supplies, which is non-conventional gas and some of those
things. That really is what you're looking at from a pure
economic standpoint. But I can tell you, the folks in the
Lower 48 states right now are hoping for more LNG and
they're hoping this Alaska gas comes on soon and the price
outlooks now are so robust. I think - if I'm not wrong Mr.
Scott, your high side case in your economics was in the
$8.50 range. We're at $8.00 gas right now. This was the
perfect storm on the upside in his economics and in the
Econ One models.
4:27:56 PM
And oh, by the way, I meant to say earlier that in addition
to Mr. Hobbs' work separately from the Administration
group, Econ One who did not have time or the information to
do a full scrub of the Administration's work, looked at the
methodology in the model, the way FT was treated, and also
endorsed fully the methodology that Mr. Scott used.
But, anyway, I hope I've begun to answer your question
anyway. I don't think they're mutually exclusive. I don't
think they're directly competitive and LNG is going to be a
bit slower than everybody down there is hoping for with
these high prices.
4:28:27 PM
CO-CHAIR GATTO asked Dr. Scott to give the committee a brief
comparison of the economics of LNG versus Alaska gas.
4:28:43 PM
REPRESENTATIVE GARDNER asked Mr. Harper if it is fair to say
that some people are "crying in their beer" given the current
possibilities for Alaska as opposed to where the state stood a
year ago with the proposed contract.
4:29:30 PM
MR. HARPER said certainly. He noted there are good and well
meaning legislators who probably still view that as a logical
alternative. He feels certain the part of the industry that was
advancing that contract is very disappointed.
REPRESENTATIVE GARDNER said she was referring to members of the
industry, not legislators.
MR. HARPER said he has no doubt the counter parties to that
Stranded Gas Development Act (SGDA) contract are very
disappointed. He pointed out they are not denied an opportunity
to step forward and compete now. If they want to drive the cost
down they should up the ante in the competitive bidding on this
pipeline.
4:30:28 PM
CO-CHAIR GATTO commented these presentations have been very
beneficial to the committee and everyone watching on Gavel to
Gavel. He thanked all members. He noted while AGIA passed
today, it is just the beginning. The Legislature will have to
choose a licensee and will be addressing other important votes
in the future. He felt this presentation was just as valuable
after the floor vote as would have been before. He asked Dr.
Scott to address the question about the economics of LNG versus
Alaska gas.
4:32:19 PM
ANTONY SCOTT, Commercial Section, Central Office, Division of
Oil & Gas, Department of Natural Resources (DNR), said he is not
an expert on LNG. He asserted that discussions about LNG coming
and the window of opportunity for Alaska gas closing have been
considerable. ConocoPhillips' CEO recently said LNG, Alaska
gas, and McKenzie gas are all needed. North American supply is
having a hard time keeping up. Most of the inexpensive gas has
been produced so what sets prices in North America will be the
marginal cost of supply, that being the most expensive gas. He
noted that LNG displaces that a little bit, but not a lot.
Although LNG will affect the price in North America, it will not
set the price. It is clear there is plenty of room for LNG and
Alaskan gas given North American demand.
4:33:57 PM
CO-CHAIR GATTO asked, if [Alaska gas] would still be a good
project if, in a worst case scenario, tons of LNG are produced
and new terminals are built.
4:34:04 PM
MR. HARPER told members:
I can tell you that we at Econ One have looked at this and
we do not see a scenario where it's still a good project.
What you can see is a re-ordering of the way product moved
around in the U.S., depending upon where these things are
sited and how they come in, which may ultimately affect the
downstream movement of Alaskan gas but from an economic
impact standpoint, and the economics of this project given
the upside case the downside case and expected case that
your consultants at Econ One have run, that the
Administration has run and others in the industry have run,
we haven't seen a scenario where it doesn't work. And Mr.
Hobbs did his work here for you today. We don't see a
scenario at this time - not that one couldn't exist, but we
haven't seen one.
4:34:50 PM
REPRESENTATIVE SEATON referred to an article he read that said
LNG would not come on at the anticipated rate because of the
high cost of projects and that several in Qatar had been put on
hold. He asked if the perception is that not only are the
loading points unavailable, but that LNG supplies are short
because of increased demand.
4:35:46 PM
MR. HARPER asserted he does not have a good understanding of LNG
on the upstream side. He reiterated that on the downstream
side, the siting of these [facilities] has become very difficult
because of local resistance. When it comes in it actually has a
quality problem because it is so incredibly dry. The AGA is
looking at quality specification issues right now. Local
distribution companies are looking at piping infrastructure and
other changes that will need to be made. Those changes will
occur over time but he believes LNG will be slower rather than
faster in arriving here than what was projected a year ago.
However, over the next 50 years, LNG will be huge so its
development should be encouraged.
4:36:53 PM
MR. HOBBS added that everything else being equal, it is in the
United States' long term strategic interest to get this pipeline
built, which is the reason for the federal loan guarantee and
other federal support. This gas will be sold to U.S. consumers.
LNG can be sourced in many places in the world and many issues
could arise that may effect that, sometimes purely economic
because, for example, Japan might want more than the U. S. does.
He concluded, "Everything else being equal, Alaska gas will beat
out LNG but obviously it's going to have to compete on an
economic front as well."
CO-CHAIR GATTO said he appreciates the "second opinion" the
presenters are providing.
4:38:02 PM
REPRESENTATIVE SEATON said his question has to do with one of
the provisions in the contract about the evaluation terms number
6 (page 12 of the work draft). He continued:
This is evaluating the Net Present Value and then it was
other factors found by the commissioners to be relevant to
the evaluation of the Net Present Value of the anticipated
cash flow to the state.
REPRESENTATIVE SEATON noted that provision is different than the
wording used in the House Resources version. He furthered:
I was wanting to see if we could get Mr. Shepler to give us
some evaluation of that as far as with FERC and also we
have - you know one of the reasons we put this in there was
because we had one of the proposals coming forward doing a
profit share system with us that was a Port Authority
proposal. It was talking about several things. One was a
PILT, payment in lieu of taxes, for the property tax on the
pipeline, a payment in lieu of taxes possibly for
offsetting corporate taxes because of course it's a
municipal entity so it wouldn't pay corporate taxes. The
third thing that we had considered or that we incorporated
in the language was a direct contractual profit sharing
with the State of Alaska of the profits. I'm wondering if
we could have him address those issues.
4:39:51 PM
MR. SHEPLER said despite his commitment to Representative Seaton
he was unable to corral the Commissioner of Revenue to assure
that his answer was consistent with one the commissioner gave in
testimony. Evaluation factor number 6 is one of the factors the
commissioners will consider when evaluating competing bids under
the AGIA process. He read, "Will be economic value resulting
from payments required to be made to the state under the terms
of the proposal." It goes to the Port Authority's project but
could apply to other projects in the context of a payment in
lieu of taxes or profit sharing. If one project is going to
give the state more value in some form, the state should
recognize that.
MR. SHEPLER explained that comes up in several contexts. One
was the notion that one way the state could receive economic
value might be in the form of an applicant offering to repay
part of the $500 million over time. Another was the concept of
a payment in lieu of taxes or profit sharing. Obviously, the
more elevated the value to the state, the more elevated that
project proposal would become. However, one issue does surface,
that being whether the payment to the state is coming on the
back of the shippers. If, as a result of the payment to the
state, the rates or the project for the shippers goes up, that
will have an offsetting negative value to the state because the
netback to the state will be reduced. His perception is that if
the economic value is actually coming from the applicant's
pocket that would be a positive factor in the evaluation
process. If it is coming from the shipper's pocket or the
state's pocket, that would offset the economic value.
MR. SHEPLER stated in the context of the Port Authority agreeing
to give half of its equity return, which it is allowed to
recover in the rate making process, to the state that would be
one thing. However, if the Port Authority proposes to collect
money from shippers for payment in lieu of taxes, which they
would charge the customers for, that would be problematic
because it would raise and lower the benefits to the state. He
added whether FERC would even allow the Port Authority to
collect rates that reflect costs, the PILT, that the Port
Authority is agreeing to make but not required to make is
questionable. It's almost as if the Port Authority is allowed
to recover costs it is not incurring. He opined that such a
proposal would have to be evaluated on the totality of the
economic value - whether the applicant is contributing value
from its pocket or whether it is contributing value by raising
rates.
4:44:50 PM
REPRESENTATIVE SEATON recalled the commissioner stated in the
House Finance Committee that it wouldn't be countered if it
could be charged to the shipper or increased a tariff; however
he doesn't see anything in the language that says that.
4:45:27 PM
MR. SHEPLER replied AGIA requires that the $500 million must
come from the rate base, which has a rate reducing effect at the
outset. He thought Commissioner Galvin was saying the effect of
the consideration written into the law is that if it is going to
raise the shipper's rates, consumers' rates will rise so that
will not count. If it does not raise customers' rates but gives
the state more value that would be recognized as a value for the
state.
4:46:49 PM
REPRESENTATIVE SEATON said he is trying to make sure everyone
who is thinking about submitting a proposal understands the
situation. He gave the following illustration and asked for an
analysis: an entity has a 20 mil property tax, which would be a
cost that goes into the tariff. However, if that entity is a
tax exempt municipality, that would not go into the rate. He
said in one case, the 20 mils would not come to the state as a
property tax payment but it would lower the tariff. He said the
20 mils is a positive in that it lowers the tariff but the state
does not receive any of the 20 mils.
4:48:40 PM
MR. HARPER deferred to Dr. Scott but added AGIA contemplates the
RFP process, so to the extent something was unclear, the RFP
would focus on that.
4:49:04 PM
DR. SCOTT gave the following example to illustrate the concept
brought forward by Representative Seaton. Assume the effective
tax rate on gas is roughly comparable to oil, 12.5 percent. The
royalty is typically about 12.5 percent. That puts the state's
value in terms of the flow of gas at 25 percent. If the costs
on the project are reduced by $1, the state receives a quarter
of that. If local property taxes are $100 million less on the
project, then the state receives a $25 million benefit through
the tariffs and the netback in terms of looking at royalty and
production tax revenues. He acknowledged the point
Representative Seaton raised is important in terms of the
potential of a municipally owned project, which commits to
providing payments in lieu of tax but is not required to.
Assuming the municipality is FERC regulated, whether it is
permitted to flow those costs through to rate payers is
something the state would have to take a hard look at in terms
of the likelihood of the promised cash flow.
4:51:48 PM
REPRESENTATIVE SEATON felt it is very important to think about
these things and address them before proposals are solicited so
that potential applicants know how value will be evaluated. He
said it is likely the state will receive a bid from one
municipality so the discussion may be characterized by that
municipality. However, it is similar to the $500 million. If
an entity decides to increase its benefit to the state by saying
it will pay that back, the $500 million could not be included in
its equity. He felt the language in number 6 is not as clear as
the language inserted by the House Resources Standing Committee.
4:53:45 PM
DR. SCOTT said it is incumbent upon the Administration to
explain how all of the different situations will be evaluated in
very clear terms in the Request For Applications (RFA) so that
it is completely transparent.
4:54:01 PM
CO-CHAIR GATTO thanked all participants.
4:54:05 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 4:54 p.m.
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