Legislature(2005 - 2006)SENATE FINANCE 532
07/27/2006 09:00 AM Senate SPECIAL COMMITTEE ON NATURAL GAS DEV
| Audio | Topic |
|---|---|
| SB3001 || SB3002 | |
| Start | |
| Mark Hanley, Anadarko | |
| Karol Lyn Newman, Morgan, Lewis & Bockius, Counsel to Anadarko | |
| Bob Loeffler, Morrison & Foerster, Counsel to the Governor | |
| Jim Clark, Chief Negotiator, Office of the Governor | |
| Ken Griffin, Deputy Commissioner, Department of Natural Resources | |
| Wendy King, Conocophillips | |
| Bill Mcmahon, Commercial Manager, Exxonmobil | |
| David Van Tuyl, Bp | |
| Brad Keithley, Jones Day, Counsel to Bp | |
| Gross Versus Net Tax || Dr. Pedro Van Meurs, Consultant to the Governor | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB3001 | TELECONFERENCED | |
| += | SB3002 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
SENATE SPECIAL COMMITTEE ON NATURAL GAS DEVELOPMENT
July 27, 2006
9:18 a.m.
MEMBERS PRESENT
Senator Ralph Seekins, Chair
Senator Lyda Green
Senator Gary Wilken
Senator Con Bunde
Senator Fred Dyson
Senator Bert Stedman
Senator Lyman Hoffman
Senator Thomas Wagoner
Senator Ben Stevens
Senator Kim Elton
MEMBERS ABSENT
Senator Donny Olson
Senator Albert Kookesh
OTHER LEGISLATORS PRESENT
Senator Gary Stevens
Senator Charlie Huggins
Senator Hollis French
Representative Ralph Samuels
Representative Paul Seaton
COMMITTEE CALENDAR
SENATE BILL NO. 3001
"An Act relating to the production tax on oil and gas and to
conservation surcharges on oil; relating to criminal penalties
for violating conditions governing access to and use of
confidential information relating to the production tax;
amending the definition of 'gas' as that definition applies in
the Alaska Stranded Gas Development Act; making conforming
amendments; and providing for an effective date."
HEARD AND HELD
SENATE BILL NO. 3002
"An Act relating to the Alaska Stranded Gas Development Act;
relating to municipal impact money received under the terms of a
stranded gas fiscal contract; relating to determination of full
and true value of property and required contributions for
education in municipalities affected by stranded gas fiscal
contracts; and providing for an effective date."
HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: SB3001
SHORT TITLE: OIL/GAS PROD. TAX
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
07/12/06 (S) READ THE FIRST TIME - REFERRALS
07/12/06 (S) NGD
07/13/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
07/13/06 (S) Heard & Held
07/13/06 (S) MINUTE(NGD)
07/14/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
07/14/06 (S) Heard & Held
07/14/06 (S) MINUTE(NGD)
07/24/06 (S) NGD AT 1:30 PM SENATE FINANCE 532
07/24/06 (S) Scheduled But Not Heard
07/25/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
07/25/06 (S) Heard & Held
07/25/06 (S) MINUTE(NGD)
07/26/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
07/26/06 (S) Heard & Held
07/26/06 (S) MINUTE(NGD)
07/27/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
BILL: SB3002
SHORT TITLE: STRANDED GAS AMENDMENTS
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
07/12/06 (S) READ THE FIRST TIME - REFERRALS
07/12/06 (S) NGD
07/13/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
07/13/06 (S) Heard & Held
07/13/06 (S) MINUTE(NGD)
07/14/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
07/14/06 (S) Heard & Held
07/14/06 (S) MINUTE(NGD)
07/24/06 (S) NGD AT 1:30 PM SENATE FINANCE 532
07/24/06 (S) Heard & Held
07/24/06 (S) MINUTE(NGD)
07/25/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
07/25/06 (S) Heard & Held
07/25/06 (S) MINUTE(NGD)
07/26/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
07/26/06 (S) Heard & Held
07/26/06 (S) MINUTE(NGD)
07/27/06 (S) NGD AT 9:00 AM SENATE FINANCE 532
WITNESS REGISTER
MARK HANLEY, Public Affairs Manager in Alaska
Anadarko Petroleum Corporation
Anchorage, AK
POSITION STATEMENT: Commented on the proposed contract and
answered questions during the hearing on SB 3001 and SB 3002.
KAROL LYN NEWMAN
Morgan, Lewis & Bockius LLP
Counsel to Anadarko Petroleum Corporation
Washington, DC
POSITION STATEMENT: Answered questions during the hearing on
SB 3001 and SB 3002.
DONALD SHEPLER
Greenberg Traurig, LLP
Consultant to the Legislature
Alaska State Capitol
Juneau, AK 99801-1182
POSITION STATEMENT: Answered questions during the hearing on
SB 3001 and SB 3002.
BOB LOEFFLER
Morrison & Foerster LLP
Counsel to the Governor
Office of the Governor
PO Box 110001
Juneau, AK 99811-0001
POSITION STATEMENT: Answered questions during the hearing on
SB 3001 and SB 3002.
JIM CLARK, Chief Negotiator
Office of the Governor
PO Box 110001
Juneau, AK 99811-0001
POSITION STATEMENT: Answered questions during the hearing on
SB 3001 and SB 3002.
KEN GRIFFIN, Deputy Commissioner
Department of Natural Resources
400 Willoughby Avenue
Juneau, AK 99801-1724
POSITION STATEMENT: Answered questions during the hearing on
SB 3001 and SB 3002.
WENDY KING, Director of External Strategies
ANS Gas Development Team
ConocoPhillips Alaska, Inc.
PO Box 100360
Anchorage, AK 99510
POSITION STATEMENT: Testified and answered questions during the
hearing on SB 3001 and SB 3002.
S.A. (BILL) McMAHON JR., Commercial Manager
Alaska Gas Development
ExxonMobil Production Company
Houston, TX
POSITION STATEMENT: Testified during the hearing on SB 3001 and
SB 3002.
DAVID VAN TUYL, Commercial Manager
Alaska Gas Group
BP
Anchorage, AK
POSITION STATEMENT: Testified and answered questions during the
hearing on SB 3001 and SB 3002.
BRADFORD G. KEITHLEY
Jones Day
Counsel to BP
Dallas, TX
POSITION STATEMENT: Testified and answered questions during the
hearing on SB 3001 and SB 3002.
DR. PEDRO VAN MEURS
Consultant to the Governor
Office of the Governor
PO Box 110001
Juneau, AK 00911-0001
POSITION STATEMENT: Discussed gross versus net tax systems
during the hearing on SB 3001 and SB 3002.
SENATOR HOLLIS FRENCH
Alaska State Legislature
Alaska State Capitol
Juneau, AK 99801-1182
POSITION STATEMENT: Asked questions and relayed concerns during
the hearing on SB 3001 and SB 3002.
ACTION NARRATIVE
CHAIR RALPH SEEKINS called the Senate Special Committee on
Natural Gas Development meeting to order at 9:18:46 AM. Present
at the call to order were Senators Fred Dyson, Con Bunde, Kim
Elton, Bert Stedman, Lyda Green, Ben Stevens, Thomas Wagoner and
Chair Ralph Seekins; Senators Gary Wilken and Lyman Hoffman
arrived soon thereafter. Also in attendance were Senators Gary
Stevens, Charlie Huggins and Hollis French, and Representatives
Ralph Samuels and Paul Seaton.
SB 3001-OIL/GAS PROD. TAX
SB 3002-STRANDED GAS AMENDMENTS
9:18:46 AM
CHAIR SEEKINS opened the hearing on SB 3001 and SB 3002.
SENATOR WAGONER requested a presentation next week by the
legislative consultants on issues addressed previously by the
Federal Energy Regulatory Commission (FERC), including capacity
and so-called basin control.
CHAIR SEEKINS acknowledged that. He welcomed representatives
from Anadarko Petroleum Corporation.
^Mark Hanley, Anadarko
MARK HANLEY, Public Affairs Manager in Alaska, Anadarko
Petroleum Corporation, introduced Karol Lyn Newman, the
company's FERC counsel from Washington, D.C. He drew attention
to Anadarko's handout containing: 1) a cover letter dated July
24, 2006, to Governor Frank Murkowski, copied to Commissioner
Bill Corbus of the Department of Revenue (DOR) and Commissioner
Mike Menge of the Department of Natural Resources (DNR), and 2)
Anadarko's comments on the proposed fiscal contract for the gas
pipeline. Noting Anadarko has had pipeline-access issues for a
number of years and that then-U.S. Senator Frank Murkowski was
helpful in passing legislation relating to FERC's open seasons
and providing some protections for pipeline access, Mr. Hanley
said there are a number of things the governor has done.
MR. HANLEY emphasized Anadarko's desire to see this gas pipeline
built as quickly as possible. While things might not be perfect
from its perspective, Anadarko wants this gas line as much as
anybody. Its gas-prone acreage in Alaska isn't worth anything
if the gas cannot get to market. He suggested looking at
comments during the public-comment period in the context of
changes that could benefit everyone.
He turned to page 8 of the handout, "B. The Contract Should
Reflect The Design of The Project Described In The Application
And The Preliminary Findings And Determination." Mr. Hanley
said most explorers probably won't be ready to nominate gas from
the Foothills, for instance, if an initial open season is held
in the next two years. Thus the pipe design is critical for
explorers to feel comfortable that they can get their gas into a
pipeline. He read from page 10, a quotation from the fiscal
interest findings (FIF) of the contract that stated:
Building a 52-inch line is riskier and more expensive
than building a smaller line, and for this reason the
pipeline companies that state officials talked to said
that they would build a smaller-diameter line. Not so
the sponsor group. They were willing to take this 52-
inch risk in order to take maximum advantage of the
economies of scale associated with gas pipelines.
This large-diameter pipeline not only allows a large
volume of gas to be transmitted through the line while
limiting fuel loss, it also allows for a relatively
inexpensive and attractive large increment of
expansion. In fact, the average capital cost per unit
decreases for an almost 50 percent expansion of the
line. This decreasing cost function means that
expansions not only will be in the pipeline entity's
best interest (through more tariff revenue), but will
also benefit existing shippers as well as expansion
shippers through lower per-unit tariffs. Apart from
the FERC access regulations, or the SGDA contract
provisions, the 52-inch decision is a concrete way of
telling explorers that if the gas is there, the pipe
capacity will be there to take it to market.
MR. HANLEY said while Anadarko agrees and finds such design work
comforting, nothing in the contract says it will happen. In
fact, comments indicate the pipe size hasn't been decided yet.
Although FERC regulations say the pipe design can be changed if
there isn't enough initial capacity or ability to expand, the
producers have challenged FERC's rules in court. If the
challenge is successful, FERC might not have authority to
require a design change if the pipe is too small for the
capacity necessary for explorers.
He therefore highlighted a key recommendation from Anadarko:
Somewhere in the contract, require that the pipeline be designed
to allow a significant amount of in-field compression expansion,
which is inexpensive compared with looping. Mr. Hanley noted
this essentially mimics what is in the FIF as well as the
producers' applications.
9:28:53 AM
^Karol Lyn Newman, Morgan, Lewis & Bockius, Counsel to Anadarko
KAROL LYN NEWMAN, Morgan, Lewis & Bockius LLP, Counsel to
Anadarko Petroleum Corporation, in response to Senator Ben
Stevens, observed that Mr. Hanley's remarks were directed to the
design concept, rather than exactly when that determination
needs to be made. Such a determination must be made before the
open season because FERC regulations require that the open
season itself specify the design and the expansion capability
for the pipeline.
SENATOR BEN STEVENS distributed proposed revisions to the
commission's regulations as submitted by Anadarko and received
by FERC 12/17/04. He noted Appendix C says that no open season
for initial capacity on the pipeline shall be held prior to six
months before the date the pipeline must close on its financing
arrangements. Inquiring how financing arrangements can be put
together on a proposed pipeline at specified capacity with six
months remaining, he also asked: If you can't go to open season
until you know the capacity, how can you get to closing on
financing until you have an open season that FERC has approved?
MS. NEWMAN replied that these were early comments by Anadarko,
in 2004. Since then, there have been many comments to FERC and
lots of activity at the agency. In addition, FERC issued final
rules that say it won't dictate when the open season should take
place, and indicated it will look at the pipeline design and
require that the project sponsors include, in their open-season
package, detailed information on the pipeline that the shippers
will bid on. That isn't unusual for a pipeline open season.
She specified that in its comments on the contract, Anadarko
hadn't taken the position that there must be an open season at a
particular time. Highlighting the importance of the pipe's
size, Ms. Newman noted Mr. Hanley had spoken to that issue. She
requested clarification, since there are two different points,
one related to open-season timing.
SENATOR BEN STEVENS agreed they go to two different points, but
said the topics in Appendix C, received by FERC in 2004, are
similar to comments received by the commissioner in July 2006.
While the main one is a request that there be no premature open
season, there is talk about capacity also. He asked: How can
capacity be defined on a project until there is an open season?
MS. NEWMAN suggested that speaking to the open-season point
would clarify some of the confusion. She deferred to
Mr. Hanley.
9:34:15 AM
MR. HANLEY explained that Anadarko doesn't want the open season
held any sooner than necessary to build the pipeline; it hasn't
placed any timelines. There are three recommendations. First,
the contract should require that the open season not be held any
sooner than the Alaska Oil & Gas Conservation Commission (AOGCC)
rules for determining how much gas can be taken off from Prudhoe
Bay and Point Thomson. While it seems AOGCC would set the
maximum amount, it also seems appropriate to wait at least until
then. Second, FERC-required engineering work for the open-
season process needs to be done. Third, veto authority on
timing should be given to the state so the open season isn't
held too early. The state is the most likely party to advocate
for explorers and to look out for their interests, Mr. Hanley
opined, and Anadarko doesn't want a specific time set because it
doesn't have the necessary information.
He turned to the design for capacity, noting this will be done
by the pipeline applicants. He interpreted the quotation to say
the state partially predicated this contract upon the idea that
the producers would take additional risk to make that extra
billion cubic feet (Bcf) of capacity available for explorers and
cheap expansion increments. Mr. Hanley emphasized that if it is
being sold as expandable, it should be in writing.
9:38:20 AM
MS. NEWMAN added that this pipeline is a bit different from one
in the Lower 48 or where the producers don't own it. Most gas
to be initially committed will come from Prudhoe Bay and Point
Thomson. The producers - the project sponsors - indicated in
their initial comments to FERC that in order to develop the gas
fields for this pipeline, all owners of a field must align on
the field-development plan. After field offtake is agreed to,
AOGCC has to approve it. Thus the sponsors will have agreed to
the field offtake to propose to AOGCC for Prudhoe Bay and Point
Thomson. By the time the pipeline entity is created and holds
an open season, they'll know what they're requesting for offtake
- 3 Bcf a day, for instance - and thus what can be committed for
the pipeline. Otherwise, it would be risky to commit to
pipeline capacity or reserves they couldn't take off the field.
MS. NEWMAN explained that a "normal" pipeline - not affiliated
with the producer group that's in competition with explorers -
has every incentive to build the pipeline to be accommodating
and to hold its open season when it can get the most shippers,
within the necessary constraints under its project plan. Given
that timeline, someone would go to the market and try to find
anybody willing to ship on the pipeline.
She cautioned that such an incentive might not exist in a
producer-owned pipeline. Ms. Newman highlighted concern that
this can drive the timing of the open season in a way that
wouldn't occur for an independent pipeline. She noted for this
pipeline, however, the reason for the open season isn't
necessarily to locate all shippers.
She said the producers' comments raise some concern because they
talk about the open season as the means for allocating capacity,
which suggests there is a finite number on the design. Pointing
out that Anadarko doesn't know that number, Ms. Newman reminded
members that the proposal said 4.0 to 4.5 Bcf a day, with 52-
inch pipe, expandable to 6.0.
She further explained that if there is a finite number, capacity
will need to be allocated and there'll be incentive by the
initial shippers or the Prudhoe Bay and Point Thomson producers
to hold an open season when there is no need to allocate
capacity. For those reasons, Anadarko would like the State of
Alaska to play a role in determining when that open season is
held - which Ms. Newman said they hadn't seen in the contract.
SENATOR BEN STEVENS voiced appreciation, but said AOGCC
commissioned a study in December 2005 and thus is already
analyzing offtake from Prudhoe Bay and Point Thomson, to be
completed by year-end. He recalled it will be at least 18
months before an open season begins; there is a 180-day process.
He said he was trying to understand why the state needs to be
involved when he believes the issues are being mitigated.
9:44:49 AM
MR. HANLEY replied that the suggestion is to just ensure the
open season isn't done before AOGCC issues its recommendation.
If it is at the end of this year, fine. He reiterated that the
state should have some say about when the open season occurs.
The state can look at other factors and decide whether it is an
appropriate time. The state is an owner that Anadarko views as
looking out for explorers as well as existing producers; it
should have the ability to determine when the open season occurs
because there is some risk, in Anadarko's view, that it could
diminish explorers' ability to have access to the pipeline.
MS. NEWMAN clarified that although there is an opportunity for a
latecomer to the open-season process - after the open season has
closed, but before the pipeline is at its final design state -
FERC has indicated it wants the pipeline to entertain bids from
interested shippers who've now developed reserves that they
could commit to the pipe. That's because FERC anticipates and
has heard there will be a gap of four to five years between the
close of the open season and the final design or when the
pipeline is ready to be built. It isn't a sure thing. It's
something the pipeline must consider, and the commission has
standards it would look at if the pipeline refused. But it
isn't something the pipeline is required to do.
SENATOR BEN STEVENS expressed appreciation for that
clarification.
9:48:13 AM
CHAIR SEEKINS asked how that would be written into the contract.
MR. HANLEY surmised some of the state's decisions would be in
the limited liability company (LLC) that has control over a lot
of this. He reiterated the need for the state, even as a
minority-interest owner, to have veto authority over the timing
of the initial open season for the pipeline.
MS. NEWMAN added that certain issues are critical to each
partner individually, in many LLC partnerships. Anadarko is
concerned that the only disinterested party at the table is the
state. Although couched in terms of giving the state the veto
power, this could be accommodated in a number of ways that work
for the LLC entity. For example, the contract could require
that the LLC say the following: Any owner has the right to
determine that the open season is premature.
9:50:08 AM
SENATOR BEN STEVENS questioned why the state would argue for
veto authority to delay the project when it wouldn't receive a
benefit until the point of first revenue.
MS. NEWMAN responded with an example where the proposal in the
open season is only enough capacity, at full pressurization, to
handle offtake from Prudhoe Bay and Point Thomson. In that
case, the state might ask why it should be done then.
SENATOR BEN STEVENS, after referring to recent testimony from
Mr. Cupina of FERC, asked why the sponsor group would put
together a package that potentially inhibits competition, when
FERC has said if the project doesn't meet the requirements of
the federal Act, that application will be changed by FERC. He
recalled presentations that it will be built at 4.3 to 4.5 Bcf,
expandable to 5.9 or 6.0.
MS. NEWMAN clarified that FERC rules don't dictate a particular
size or design; its rule says it will look at that as one factor
in determining whether any proposal for the pipeline in any
application - or any proposal for an expansion - complies with
what FERC believes the Act requires as sufficient design
capacity to accommodate expansion and all shippers. This is the
very issue the project sponsors have taken to the U.S. Court of
Appeals for the District of Columbia Circuit; they've suggested
FERC doesn't have the authority to second-guess design
determinations, and that case's outcome is yet to be seen. But
designing it a particular way isn't a violation of rules. So
there'd be no enforcement action as the result of a pipeline
design that purports to be what others might consider too small.
SENATOR BEN STEVENS opined that the demonstration to move the
project forward as outlined in the Project Summary - under
criteria set out by FERC and Congress - is pretty well laid out.
Because of the size and scrutiny, he questioned why any project
sponsor would knowingly take anticompetitive action that would
end up in litigation and thus cause delay. He referred to
presentations about building it to 4.3 Bcf, expandable to 5.9.
MR. HANLEY responded, "If they build it that way, we're happy.
And if they say they're going to build it that way, then commit
to it." He noted FERC regulation 157.37 says this: In
reviewing any application for an Alaska natural gas pipeline
project, the commission will consider the extent to which it has
been designed to accommodate the needs of shippers who've made
conforming bids during open season, as well as the extent to
which the project can accommodate low-cost expansion, and may
require changes in project design necessary to promote
competition and offer a reasonable opportunity for access.
He surmised this ability to look at low-cost expansions is the
provision referred to by Senator Ben Stevens. "It gives us
comfort that we can go to FERC and have somebody look at that,"
he explained. Referring to the court case by the producers,
Mr. Hanley indicated the producers' brief could ask that the
court find 157.36 and 157.37 invalid, since that is exactly what
they're trying to eliminate.
MR. HANLEY told members this is why there are red flags for
Anadarko about whether they're actually going to build the
project they assert they'll build - taking away the ability to
go to FERC and say this hasn't met the criteria. He emphasized
that the producers should put their intentions in writing and
not challenge FERC's authority to ensure it happens that way.
9:58:18 AM
SENATOR WAGONER asked if smaller explorer-producers such as
Anadarko, Chevron or Pioneer were offered ownership in the
pipeline or tried to buy any part. He surmised these items
wouldn't be under discussion if they'd had a seat at the table.
MR. HANLEY recalled public statements five or six years ago that
there might be an open season within six months. Anadarko had
scrambled, researching past issues and producing a white paper
after identifying access concerns. Anadarko had approached the
three producers to discuss participation in the $125 million
study talked about in their findings. At the time, Anadarko
wasn't into pipeline ownership - which isn't what independent
companies typically do - but thought it important to get a seat
at the table by paying a share. Although Anadarko even offered
to buy a part of the pipeline, the producers weren't interested.
He reported that Anadarko then went to Washington, D.C.; talked
to then-Senator Frank Murkowski, who helped with some of these
new FERC language requirements; and was successful in bidding on
the state's royalty-in-kind (RIK) gas to protect its interests
by being able to nominate at the initial open season and have
capacity. Mr. Hanley indicated that contract was never
finalized. Highlighting that his company has worked for a long
time to address access to this pipeline, Mr. Hanley said he
didn't know whether other companies had been offered ownership
interests or had approached the producers on this matter. In
response to Chair Seekins, he offered to obtain the exact dates.
10:02:39 AM
CHAIR SEEKINS observed that Anadarko has grown a lot since 2001.
MR. HANLEY agreed it has been substantial, from perhaps a
$4 billion or $5 billion market cap in 1998 to about $23 billion
today.
CHAIR SEEKINS asked about a purchase or merger involving Kerr-
McGee.
MR. HANLEY answered that it hadn't been finalized yet; he also
mentioned Western Gas. In further response about North Slope
holdings, he said Anadarko has about 2 million net exploration
acres and is a 22 percent partner with ConocoPhillips in the
Alpine field production.
SENATOR BEN STEVENS offered to distribute information about the
acreage holders for the North Slope.
CHAIR SEEKINS noted he hears different characterizations of
Anadarko with respect to size and acreage. He read from
Anadarko's handout, beginning at the bottom of page 2, which
stated in part:
Therefore, the pipeline can be built to accommodate
only the project developers' reserves, at
deliverability levels that are determined by the
pipeline developers. Therefore, even if there are
expectations that reserves available to the pipeline
by the in-service date would justify a 4 or 5 Bcf/d
pipeline, the project sponsors might decide to build a
3 BCF/d pipeline. The pipeline would not be
undersubscribed, but it would be undersized.
He asked whether the concern is this: The producers might
decide to build only the size necessary to get their currently
known reserves to market, rather than what is anticipated to be
available on the North Slope, not only from their own
production, but also from production of another major
leaseholder such as Anadarko, thereby exercising basin control.
MR. HANLEY affirmed that in general.
CHAIR SEEKINS asked: Would it be to their benefit to do that?
MR. HANLEY answered it could be. He indicated if someone else
controls access to a pipeline, assets won't be available for
commercialization.
CHAIR SEEKINS asked whether the only way to preclude that is to
have the fiscal-terms contract or LLC say the pipeline must be
capable of carrying 4.2 Bcf with expandability up to 40 percent,
as heard previously.
MR. HANLEY replied that it isn't the only way; it is the
suggested way. "We'd just match what the statements have been
of what they are going to build," he specified, noting it was a
suggestion taken from both the application and the governor's
statements in the FIF.
CHAIR SEEKINS asked Ms. Newman why there isn't an incentive for
a producer-owned pipeline to build in the capability that a
privately owned pipeline would have.
MS. NEWMAN replied there could be any number of reasons. This
has been a concern for 30 years, starting with the U.S
Department of Justice analysis of what anticompetitive issues
might arise for a producer-owned pipeline from the North Slope.
An independent pipeline exists to transport gas and make money
from its transportation volume. To the extent it can expand its
pipeline economically and capture whatever is in the
marketplace, the pipeline and its shareholders make more money.
CHAIR SEEKINS noted this is the same incentive the State of
Alaska has in this ballgame.
MS. NEWMAN acknowledged that, saying the idea is to capitalize
on the asset and make the most money possible within regulatory
restrictions. Because it is a monopoly, it will be regulated
and a maximum amount can be earned on the FERC tariff. A
producer-owned pipeline has business aspects that may create
different prioritization. She gave examples, calling it a
business decision. She noted people have been concerned for
years that business motivations on the production side might far
outweigh those on the pipeline side. Because there might not be
the same incentives to do what an independent pipeline might do,
there have been greater regulatory controls over this pipeline
as it becomes clear that it might well be producer-owned.
10:10:41 AM
SENATOR BEN STEVENS referred to Anadarko's handout, page 7,
"A.3. A Premature Open Season Will Restrict Access To The
Pipeline." He paraphrased a sentence, "Anadarko is currently
planning to drill its first natural gas exploration wells in the
Foothills Region of Alaska's North Slope this winter." He
recalled an excellent presentation from Mr. Hanley this year
saying one great challenge that participants on the North Slope
face is the lead-time from exploration to production.
He also referred to Anadarko's 10-K report and comments by
Ms. Newman about priorities. Noting he was making his own
assumptions, Senator Ben Stevens said of 655 wells drilled in
2005, 7 were in Alaska; of $2 billion in investment budgeted for
2006, Alaska has the largest undeveloped lease-holding acreage
in the company's portfolio; and capital expenditures for 2006 in
Alaska totaled $70 million, whereas $800 million was spent in
the Gulf of Mexico, $450 million in Canada and so forth.
SENATOR BEN STEVENS acknowledged Anadarko's right to make
business decisions, but said while there is concern about access
to a pipeline from a company that has the largest lease holdings
of any independent company on the North Slope, there is no focus
on proving those reserves. At the same time, he asserted, the
company is requesting delay of the open season on a project that
everyone is depending on. He said FERC has made all kinds of
concessions and criteria to allow future explorers and expansion
of a line when that gas is available, but it may be six or seven
years before it is actually known how much the company can put
in the pipeline. He said he didn't understand the rationale.
MR. HANLEY replied that Anadarko won't take the full development
step until comfortable that there is access to the pipe - a real
potential restriction. While becoming more comfortable through
the process involving FERC and the contract, Anadarko is raising
issues here that would provide a greater comfort level. He
reminded members that a few years ago even the producers didn't
believe gas prices were high enough to build a pipeline, so
there wasn't the interest.
He reported that Anadarko has done significant seismic work in
the Foothills and has drill-ready prospects; it has taken a
certain amount of risk already and invested some money in the
hope that a gas line will come to fruition. Anadarko is ready
and planning with its partners to potentially drill a well this
winter. However, it likely will get into the expansion phase of
any pipeline because it is hard to invest money until it is
known that a pipeline is going forward. After a pipeline is
going forward, if the company drills its first well there still
won't be the knowledge to commit until after the open season.
Mr. Hanley acknowledged this is a bit of a Catch-22.
MR. HANLEY characterized this as a "long-term play" in
Anadarko's portfolio. Reminding Senator Ben Stevens of a
computer presentation in the Senator's office about Anadarko's
process in Alaska, he said Anadarko is looking for anchor-field
opportunities, larger-type fields for gas or oil that tend to be
farther from infrastructure, more frontier and riskier; they
also take longer to develop. Noting the commercial side is
often greater than the noncommercial side - the geologic risks -
he noted the ability to get gas to market is a crucial issue.
He emphasized the desire to see the gas line go as quickly as
possible. Mr. Hanley specified that Anadarko's suggestion on
the open season isn't to delay the project. Rather, it is to
make sure that the open season is not held prematurely, before
it's necessary for progress of the project. Nor is the company
trying to suggest a time when the open season should be held or
delayed. Because the state probably has more aligned interests
with the explorers, Anadarko believes that giving the state some
say over timing would provide more comfort for explorers.
10:18:36 AM
SENATOR WAGONER provided his understanding that currently the
three major producers are the only companies with proven
reserves on the North Slope. Noting Anadarko and Chevron are
partial owners in that, he asked whether any independents have
proven gas reserves on the North Slope in any quantity.
MR. HANLEY answered that he believes Chevron is a significant
owner at Point Thomson, for example, and there are smaller
owners in some fields, though he wasn't familiar with those.
10:20:03 AM
SENATOR BEN STEVENS asked which would better raise the
attractiveness of Alaska for Anadarko's portfolio: 1) opening
the basin for a gas line, but not revising the oil tax; 2) the
oil tax proposal before the committee, but with no pipeline; or
3) a combination of revising the oil tax and opening the basin.
MR. HANLEY noted Anadarko has testified the latter would be the
most advantageous; has testified in support of the governor's
20/20 [20 percent tax on oil, with a 20 percent credit] proposal
and suggested it would increase investment; and has said
Anadarko wants the gas pipeline built.
CHAIR SEEKINS asked about the 10-K report, observing it says the
results of the seven wells drilled in Alaska are held as
confidential for competitive reasons.
MR. HANLEY opined that in Alaska information about certain wells
can be kept confidential for two years, and statutes say who can
get the information; for example, the department can receive it
on a confidential basis, and rules relate to its release. To
his belief, certain information can be kept confidential beyond
that period; the state has developed a policy for when that
information is released. While suggesting most companies would
prefer it never be released, for competitive reasons, Mr. Hanley
offered to obtain more precise information. As for the seven
wells, they're on the North Slope, largely in the National
Petroleum Reserve-Alaska (NPR-A), where Anadarko partners with
ConocoPhillips, which he believes is the operator for most of
those. The location of the wells is public information.
CHAIR SEEKINS observed the high success rate in Louisiana, Texas
and Western states, for example, in contrast to Alaska. He
expressed curiosity about wells shown in footnote 2.
MR. HANLEY responded that they're frontier exploration wells.
In the Lower 48, some are in or around existing fields; a lot of
gas wells are drilled and come online quickly in fairly
identified areas. Referring to the federal Securities and
Exchange Commission (SEC) rules, Mr. Hanley noted that what a
company is allowed to say in such reports is fairly tightly
controlled; Anadarko follows the statutes and SEC rules. In
Alaska, the success rate is substantially lower; Anadarko goes
into more frontier-related areas with higher risk, looking for
larger-type prospects than it might elsewhere.
10:25:06 AM
SENATOR STEDMAN highlighted the idea that the state would be a
20 percent owner of a project like this and then not try to
maximize the benefit for its people, particularly for issues
like sizing the pipe for volume, basin access and trying to
extend the basin life for 30-50 years or longer. He asked
whether Anadarko thinks the State of Alaska doesn't have a
vision of maximizing the life of Prudhoe Bay.
MR. HANLEY opined that Anadarko is aligned with the state's
interests, and that the state is most aligned with respect to
Anadarko's interests. Agreeing the state will maximize its
interests, he remarked, "I don't disagree with anything you've
said." He noted the question becomes whether the state has the
ability, through the contract - and particularly through the LLC
agreements - to actually influence some of those decision.
While the state, as a 20 percent owner, would typically have a
say, it may get outvoted - which is the concern.
SENATOR STEDMAN recalled FERC testimony about its own
independence in deciding the size of the pipe. He also recalled
questions by Senator Wagoner about having two pipes versus one,
with FERC's response being that FERC would make that decision at
the proper time. Senator Stedman said they didn't mention that
litigation in the courts might block them from making that
decision, but had said they'd make the size of the pipe
applicable to the goal of opening that basin and harvesting the
natural resources for the benefit of Alaskans and Americans.
MS. NEWMAN surmised Robert Cupina of FERC, the head of projects,
is well aware of the court appeal. She recalled his testimony
that FERC would look at the size and ensure the pipeline was
properly sized to allow for expansion, and that it would
accommodate what FERC felt was important in terms of sizing and
design. Ms. Newman said that authority of FERC has been
challenged by the project sponsors. They are asking the U.S.
Court of Appeals for the D.C. Circuit - in a review petition
filed from the FERC rule making with respect to what rules it
would follow in acting on an application for expansion or for an
initial certificate - to decide FERC doesn't have that authority
and power, and to vacate those aspects of its regulations.
Until the court decides that case, the issue is unresolved.
SENATOR STEDMAN voiced hope that Congress would step in to
protect Americans' interests if something like that occurred.
10:29:30 AM
SENATOR STEDMAN noted concern that there could be substantial
manipulation by the industry to diminish the state's revenue
share, affecting the federal government as well, since it gets
roughly half the government take. He asked: If a publicly
traded company aggressively manipulated expenditures to increase
its income and hence falsified its 10-K report and so on, what
ramifications would be faced with respect to the SEC?
MR. HANLEY replied that Anadarko isn't going to break the law or
try to manipulate things in that way, which would have severe
ramifications. He noted companies go out of business because of
manipulation and illegal activities, and people get fired. He
reiterated support for the governor's original 20/20 proposal.
SENATOR STEDMAN clarified that he was using the opportunity to
speak to it because of having in his hands a 10-K, a report
filed with SEC on corporate activity including income and
expenditures.
10:34:50 AM
SENATOR BEN STEVENS pointed out that the comments on
Article 8.7, state-initiated expansion, on pages 16-20 of
Anadarko's handout, conclude it would be best to eliminate
Article 8.7 entirely. Opining that Anadarko makes a compelling
case from its perspective, he requested a roundtable discussion
to learn what advantages the administration sees in Article 8.7.
10:37:07 AM
MR. HANLEY addressed Article 8.7. He acknowledged the state's
intent to provide another avenue for expansion. However, the
criteria make it more onerous than even the federal mandatory-
expansion program under FERC for this pipeline; the federal
program has 8 criteria, to his belief, that the state adopted in
essence, adding 10 or 12 more that diminish the value.
Mr. Hanley said Anadarko couldn't foresee a scenario in which it
would use the state process. If it couldn't meet the federal
process, it wouldn't be able to meet the state process with its
additional onerous provisions.
He discussed limitations. First, the state-initiated expansion
proposal cannot be used until commencement of the pipeline, a
limitation Anadarko doesn't believe makes sense; if a company
finds enough gas and wants to propose an expansion before the
pipeline actually starts operations, Mr. Hanley said normally
that can be done. Another limitation is restricting the state
process to every five years. A further limitation suggests that
even if someone goes through the process and meets all the
conditions, the certificate shall be rejected if FERC issues a
certificate that has different conditions than applied for.
He indicated BG Group, one of Anadarko's partners, had prepared
comments including an analysis of concerns about Article 8.7;
Mr. Hanley noted these comments are public, though he didn't
know if they'd been submitted. He opined that it would be
harder to restructure what exists with Article 8.7 and come up
with something that might work than to eliminate it and then add
other criteria specified in Anadarko's proposal. Although he
offered to work with the state in this regard, Mr. Hanley said
it was difficult to see how to salvage it; there are too many
restrictions on the expansion capability, and it would be
ineffective. Thus the suggestion is to remove it.
SENATOR BEN STEVENS asked whether the state-initiated expansion
is categorized by FERC as a voluntary expansion.
MS. NEWMAN noted it's an interesting question. She gave her
understanding that FERC hasn't opined what this would or
wouldn't be. There are two ways to look at it: 1) Yes, it
would be a voluntary expansion because it would be a proposal
filed by the pipeline with FERC, as opposed to an expansion
initiated by an unhappy shipper who'd tried unsuccessfully to
get capacity, or 2) FERC regulations define "voluntary
expansion" as an expansion made voluntarily by the pipeline
entity, and it isn't known how that would be portrayed by the
pipeline entity when it found itself making that filing. Thus
it possibly could be either answer.
CHAIR SEEKINS acknowledged that attendees seemed to wish to
comment on that point.
MR. HANLEY indicated Anadarko hadn't gone through each section
today to explain each concern, but could do so. He referred
members to the concerns described in Anadarko's comments as well
as BG Group's comments, which add clarity to the concerns raised
in this particular section.
10:43:33 AM
SENATOR STEDMAN asked: If Anadarko, as the largest independent
company, doesn't participate in the initial open season, will
other independents likely participate?
MR. HANLEY replied Anadarko may or may not. It depends on
whether it has reserves. There will be a large monetary
commitment to transport gas for a significant amount of time.
He didn't know whether other independents had found a gas field
from which to nominate.
SENATOR BEN STEVENS asked whether it is accurate that Anadarko's
recommended term for commitment has consistently been 20 years.
MS. NEWMAN noted Anadarko took the position that there should be
a cap of 20 years, but FERC didn't accept that proposal.
SENATOR BEN STEVENS asked: When FERC does the revision and
approves the tariff rate, does it set the term?
MS. NEWMAN replied FERC doesn't set the term for contracts.
That is done by private agreement. There will be an open
season, and FERC has indicated it won't dictate the maximum term
for purposes of doing a net-present-value calculation in an open
season, if the possibility of capacity allocation is faced. She
recalled FERC also indicated it will look at it; if FERC
believes it is unduly anticompetitive, it could raise an issue
and suggest that if somebody bid for 50 years, for example, that
would be inappropriate. But FERC hasn't indicated there is any
time limit it would set for purposes of a contract term.
10:46:28 AM
^Donald Shepler, Greenberg Traurig, Consultant to the
Legislature
DONALD SHEPLER, Greenberg Traurig, LLP, Consultant to the
Legislature, concurred. He noted the following suggestion was
made on behalf of the legislature: For purposes of bid
evaluation on the open season, FERC should cap the bid period at
20 years, since FERC typically approves a net-present-valuation
methodology to determine the value of the bids. As Ms. Newman
had said, concern was expressed that someone might bid an
excessively long period to increase the value of a bid
unnecessarily in order to win capacity. While FERC rejected
that proposal by the legislature as well, Mr. Shepler reported
that FERC said it will observe and withhold judgment, depending
on the length of contract term bids in the open season.
^Bob Loeffler, Morrison & Foerster, Counsel to the Governor
BOB LOEFFLER, Morrison & Foerster LLP, Counsel to the Governor,
agreed with Mr. Shepler. "We urged that position," he said,
indicating it places some limit on the length of the firm
transportation (FT) commitment. "We struggled with describing
what the expected length of the FT would be in the fiscal
interest finding," Mr. Loeffler explained, indicating it could
be 10 to 20 years or longer.
He noted the other party in this arena is the financial
community, which looks at those commitments as part of the
overall financing scheme, and which will have a large voice
because it is security for the whole financing of the pipeline.
Characterizing it as a tug-of-war, Mr. Loeffler said if a
company bids for too long, it pays for capacity it doesn't have
gas to fill; it's an extra financial liability. Thus he
suggested the financial community might want as heavy an
FT commitment as possible, or might want it shorter. This plays
out in constructing the financing plan and in the open season.
SENATOR BEN STEVENS summarized that it is to be determined, as
for many questions raised here. He asked: For the open season,
will the terms be a requirement? Or will each individual bidder
bid for the length and term and capacity? How can the financial
world put together its term sheets until the project has a FT
commitment that, to his belief, would have a consistent term
among all shippers, even though the volume would vary?
MS. NEWMAN gave her understanding of the normal process in an
open season for capacity. The pipeline frequently sets a
minimum bid term. It can place its own cap, and some set it at
10 years. It also can place a minimum length of time.
Evaluation of the bids is done by the pipeline entity, the
project sponsor. If somebody believes bids have been evaluated
improperly, a complaint can be made to FERC.
SENATOR BEN STEVENS surmised the whole project would be reviewed
by FERC before the issuance of the certificate.
MS. NEWMAN explained that for this particular pipeline the
commission will review the terms that go into the open-season
packet. As to what information will be provided, she didn't
know yet whether it would match identically what FERC has said
the open-season package must contain or would be less specific.
It will be seen at the time. After FERC reviews that, there
will be an open season. Anybody can file a complaint following
an open season if it is believed something was done improperly.
She reported that FERC has agreed this will be fast-tracked if
there is a complaint so the process isn't unduly delayed. If
there are no complaints, a certificate application will be filed
using the precedent agreements executed as a result of the open
season itself. That becomes part of the package filed with
FERC, and it is pretty much the last opportunity for people to
object to what is going on in the certificate application.
Ms. Newman said FERC will look again at that point. She noted
as a result of the Alaska Natural Gas Pipeline Act (ANGPA), FERC
promulgated rules on open seasons that differ from those for
Lower 48 pipelines. She elaborated about the latter.
SENATOR BEN STEVENS asked whether the following is correct: The
criteria for the open season will be reviewed by FERC. If a
potential bidder has a grievance, that can be filed during the
open season and it will be fast-tracked and thus addressed
during that period of time.
MS. NEWMAN replied that the exact timing of the complaint isn't
specified. Theoretically, someone could file a complaint at any
point if something improper were perceived in the open season.
10:54:46 AM
MR. HANLEY turned to comments on Articles 8.1, 8.2 and 8.3 of
the proposed gas contract, beginning on page 20 of the handout.
He indicated he'd discussed this previously in relation to the
Regulatory Commission of Alaska (RCA) and the regulatory gap.
He recalled that all parties want to go to FERC and seek FERC
jurisdiction over these facilities, but there is a question of
whether FERC will grant it. Even if FERC grants it, as heard
the other day, there is a question of whether it has the
authority, and there are related court cases.
He explained that Anadarko is concerned that the contract limits
the state's ability to request or support RCA jurisdiction to
the extent it may exist. Mr. Hanley recommended that the
requirement that everybody request FERC jurisdiction remain, but
the other portions of these provisions be removed. Recalling
that Shell's comments suggest RCA should regulate if FERC
doesn't, he noted there'd been discussion since then. Anadarko
therefore recommends the following: Remove sections that limit
the state's authority, and then everyone go jointly to Congress
to ensure FERC has authority to regulate these things. Then the
question will be moot, since they'll be regulated by FERC.
Mr. Hanley deferred to Ms. Newman to address Anadarko's concerns
with capacity-management issues in Article 10 of the contract.
The committee took an at-ease until 11:06:05 AM.
MS. NEWMAN referred to pages 11-14 of the handout. Calling
Article 10 lengthy and complex, she explained Anadarko's concern
that it is extremely restrictive as to the state's particular
rights, and may interfere with the normal process of capacity
release and the availability of capacity in a secondary market
for this pipeline. This may become important down the road for
people without capacity who are looking for released capacity,
from time to time, from those who have capacity in the line.
She said it isn't at all clear that FERC rules would permit one
shipper to bid for another shipper such that Shipper A shares
information about its bid with Shipper B. Normally, the open-
season process contemplates individual bids by individual
shippers; it doesn't contemplate the shippers getting together
to decide how to formulate a bid, even though they may have some
common relationships. Ms. Newman opined it would require
special FERC approval, if FERC were to give it at all.
She raised a second issue: Article 10 seems to contemplate
there will be terms and conditions of service that may be
negotiated in a precedent agreement following an open season
that could differ from shipper to shipper. Ms. Newman said FERC
rules don't allow differences in terms and conditions of
service, but only allow differences in price, other than some
inconsequential terms and conditions.
She made a third point: It appears the state's right to
forecasts of monthly production information - which, to her
belief, is in Article 10.4 - appears somehow contingent upon the
state's agreeing to all of Article 10. While this may not be
intended, Ms. Newman said it appears to read such that if the
state didn't agree to all capacity-trading provisions of Article
10, perhaps it wouldn't receive the necessary information
required with respect to its RIK gas.
MS. NEWMAN said Article 10 also seems to contemplate prearranged
releases of capacity at rates perhaps other than the pipeline's
maximum tariff rate. This isn't permitted under FERC's
capacity-release rules, which only allow a replacement contract
to be executed in a prearranged capacity-release deal if the
rate is at the maximum tariff rate - not the rate the initial
shipper is paying. If the rate is lower, Ms. Newman said, it
must be put out for bid. If higher, it must require specific
FERC approval.
She also said the commission tries to ensure initial capacity of
a pipeline is available to all shippers, and it tries to ensure
that those who obtain initial capacity don't use their control
over it to extract monopoly rents from nonshippers who seek
capacity in the capacity-release market. The object of that
rule - the restriction on the maximum tariff rate - is to keep
that in check. Thus Ms. Newman said it isn't clear that a
predetermined capacity-release arrangement will pass muster
under existing rules. Furthermore, as this is structured -
looked at across the board among all the producers who'd be
shippers, as well as the state's interest with respect to each
producer's leasehold - it appears if these articles apply to
every one of them and to potentially every shipper on the
pipeline, there will be a real restriction in the capacity-
release market.
11:11:50 AM
MS. NEWMAN raised concern that Article 10 seems to contemplate
shipper-to-shipper transactions without participation of the
pipeline. But the capacity-release programs at FERC work
through the pipeline, which is therefore in the middle of these
transactions. There can be a replacement shipper, but that
person then must execute a contract with the pipeline. While
perhaps this is contemplated to be done after the fact, when the
tariff is written, it appears to deviate from current FERC
requirements and thus requires special FERC approval.
She also expressed concern that it appears to restrict trading
and capacity. If Anadarko were looking for additional capacity,
the state couldn't decide on its own to sell its excess capacity
to Anadarko, but would have to first give its capacity to BP,
ConocoPhillips or ExxonMobil, which could then decide whether to
release it to Anadarko. Conversely, if the state wanted extra
capacity and Anadarko had some, the state couldn't go to
Anadarko and buy it - even if Anadarko were willing to provide
it at half price. Instead, the state would have to go through
BP, ConocoPhillips or ExxonMobil and obtain the capacity through
them at whatever price they negotiated.
MS. NEWMAN concluded that Article 10 seems unduly restrictive
and perhaps unnecessary. She acknowledged perhaps the state
believes it needs some protection from a leaseholder having a
better price or getting a better deal in an open season than the
state could get. However, she opined that the state should be
able to cure that with something akin to a "most favored
nations" clause with respect to the transportation price on the
pipeline - because it is the state, has royalty interests to
protect and needs to get the same price for its production as
the producers do. She surmised that would pass muster at FERC.
11:14:36 AM
SENATOR BEN STEVENS said he finds this interesting, since
Anadarko says it is aligned with the state's interests and yet,
to his recollection, the capacity-management in Article 10 is
Mr. Clark's pride and joy. He recalled testimony that this was
designed to provide offtake in Alaska without a penalty for not
meeting the capacity requirements with the group as an owner.
He asked to hear from Mr. Clark, recalling he'd heard in
presentations since May that Article 10 is favorable for the
state and that there were many concessions from the other
sponsor applicants.
He turned to Mr. Cupina's testimony earlier in the week, noting
Ms. Newman had been present then. Senator Ben Stevens read from
page 13 of Anadarko's handout, which said in part: "In short,
Article 10 attempts to remove the trading of interstate pipeline
capacity on the Alaska pipeline from FERC's jurisdiction and
have it governed, instead, by private contract." Offering his
recollection that Mr. Cupina had said the contract cannot usurp
FERC jurisdiction, Senator Ben Stevens asked: Do you have any
question about FERC's ability to interpret the capacity-
management program, with the statement that Mr. Cupina made?
11:17:13 AM
MS. NEWMAN expressed confidence that FERC will have to look at
Article 10 and the entire capacity-management program and
determine whether it can allow it. Nor did she disagree that
the contract cannot override FERC regulations in terms of
capacity trading on this pipeline. She gave her reading as
follows: It purports to try to do that by setting up a private
contractual arrangement through which the parties can go to
arbitration to resolve disputes, and they're precluded from
raising issues with regulatory agencies. Ms. Newman clarified
that it appears the contract tries to do something she believes
it cannot do.
11:18:00 AM
SENATOR BEN STEVENS surmised that would be based on dispute
arbitration involving the LLC members, not another shipper.
MS. NEWMAN concurred. The arbitration provisions only apply
among the contracting parties, but still require FERC approval
to even engage in the transactions in Article 10. Only FERC
could have jurisdiction over whether the provisions that FERC
allows in terms of the capacity-release arrangements were
properly addressed. She said she doesn't believe that can be
removed from the FERC arena and put into a private-dispute arena
or into a private contracting arrangement without prior FERC
approval. It is a regulated contract. That aspect of this
contract is a regulated contract arrangement.
SENATOR BEN STEVENS noted Article 10 had been presented as
protecting the state's interests in the event it takes its
royalty and tax gas in kind and becomes an FT participant.
11:20:39 AM
CHAIR SEEKINS read from page 13 of the handout, which said:
But if the State is to commit to take its gas in kind
and, therefore, to purchase firm transportation
capacity on the Alaska Pipeline in its own name, it
cannot, by private contract, grant itself preferential
terms and conditions to eliminate the business risks
faced by all other shippers in committing to long-term
firm capacity on the pipeline.
He asked whether this says FERC won't allow it.
MS. NEWMAN replied she believes FERC won't allow it, but she
can't say what FERC would do. She surmised FERC wouldn't let
any shipper receive preferential treatment for offsetting risk
for signing up for capacity. Every shipper would like internal
arrangements that allow simply moving capacity back and forth
among other shippers in order to offset lows or highs in
production at any point; however, that isn't how it works.
Ms. Newman added, "That's what the capacity-release system is
for, to have excess capacity available in the open market for
anyone to bid on who might need it and not just restrict it to a
single individual unless, again, it's been done at the maximum
tariff rate, in which case there's no point to bid."
11:22:32 AM
CHAIR SEEKINS asked whether other FERC attorneys, in looking at
this, generally agree it probably wouldn't be allowed by FERC.
MS. NEWMAN answered that she'd discussed this with Mr. Loeffler
as well as ConocoPhillips, whose consensus, to her recollection,
was a belief that these provisions are permissible because they
fall within the scope of the capacity-assignment or capacity-
release provisions allowing for prearranged deals. She noted
her response was this: That would be true if the prearranged
deals were set at the maximum tariff rate; in that case, all
that would be required is posting of the transaction on the Web,
for example. It wouldn't be true, however, if those
transactions were at less or higher than the maximum rate.
She noted she didn't recall discussing the permissibility of
Shipper A bidding for Shipper B, even if the latter is the state
royalty owner. Ms. Newman said she also didn't know that FERC
had ever addressed that question; she opined it would have to be
presented to FERC to determine permissibility. Ms. Newman
surmised other counsel present would agree.
CHAIR SEEKINS asked whether Ms. Newman believes the provisions
of Article 10 aren't in the best interests of the state.
MS. NEWMAN offered the view that the state shouldn't restrict
itself in terms of how it can release capacity. While
understanding the state's concern - not to be long or short on
capacity - she suggested in the long run there are ways to
manage it without the restrictions imposed by this article. She
acknowledged she couldn't judge that for the state.
11:25:29 AM
SENATOR BEN STEVENS suggested Article 10 is in the best
interests of the state but not Anadarko, and thus the attempt to
eliminate it.
MS. NEWMAN replied she doesn't believe Article 10 or
restrictions in the secondary market are beneficial to anyone
but the original capacity holders; if Anadarko were an initial
capacity holder, perhaps it would like this provision. However,
every shipper should be free to release capacity into the
market, which is part and parcel of FERC's open-access rules.
"Putting restrictions on yourself, even if it seems like it
might be good, might in the end not work," Ms. Newman cautioned.
"But I can't judge that for the state." Returning to an earlier
concern, Ms. Newman explained:
As I read Article 10, the state is going to have to
bid in the open season for its capacity in three
pieces. And it will have to balance and manage that
capacity in those discrete three pieces: the piece
that comes from BP, the piece that comes from
ExxonMobil and the piece that comes from
ConocoPhillips - and maybe a piece that comes from
somebody else. ...
Being able and being flexible to use your capacity to
its maximum sometimes requires that you have it all
packaged together. And while I'm not an expert on how
you manage and balance capacity, sometimes that is a
preferable arrangement. And I don't think anybody was
really clear how the state was going to use its
capacity once it derived it in these three separate
pieces. And so it struck me that it was very complex.
And perhaps there would be an easier way to accomplish
something the state wanted to accomplish without the
complexities of Article 10. It was just a suggestion.
SENATOR BEN STEVENS highlighted that Article 10 gives the state
the option of either managing it itself - whether internally or
by hiring a contract capacity manager - or having the producer
of the gas, which the state now would own, manage capacity on
behalf of the state. He opined that deleting Article 10 would
eliminate choices that protect the state and that provide a
variety of mechanisms to maximize the state's return and to
allow efficiency in management.
11:29:32 AM
CHAIR SEEKINS turned to the suggested change on page 14 of the
handout, which read in part:
Eliminate the capacity management program. Instead,
the State should bid on its own capacity, and, to the
extent that it is concerned that it will be
disadvantaged vis-à-vis the producers which own the
leases from which its royalty gas derives, it can
insist on a most favored nations clause with respect
to that particular producer's bid.
He asked what is meant by a "most favored nations" clause.
MS. NEWMAN noted it's what she'd alluded to earlier. The state
has the interests of its citizens at stake, and also has laws
requiring it to obtain certain value for its royalty gas.
Therefore, it could request a "most favored nations" clause that
would say the following: If the leaseholder obtains a
transportation rate lower than the one the state obtains, and if
the state's royalty gas in that instance is derived from that
leaseholder's property, then the state gets the same rate for
the shipment of its gas as does the producer who holds the
leasehold interest.
She suggested this is necessary to ensure that the differential
in the transportation rate doesn't adversely impact the netback
price that the state receives for its gas. Without such
assurance, it won't be the same price in the end, since the
leaseholder - as a larger shipper - may be able to obtain a
lower rate than the state could. Ms. Newman opined that the
state should be able to effectively argue for and possibly
obtain from FERC such a provision; that approval is needed. She
related her belief that it would resolve the pricing issue
without the complications of the rest of this.
MR. HANLEY indicated there were a couple of other points in the
written comments that he believed to be self-explanatory.
11:32:31 AM
SENATOR WILKEN recalled recent testimony about the FERC hotline.
Inquiring whether Anadarko has worked under a hotline system in
the U.S., he asked to what extent Anadarko believes a hotline
concept should be relied upon to protect the state's interests.
MR. HANLEY deferred to Ms. Newman, Anadarko's FERC counsel.
MS. NEWMAN recalled earlier this week Mr. Keithley explained
that the hotline is available for simpler issues. For example,
a shipper may call a pipeline and ask to interconnect, and the
pipeline may refuse to discuss it. The shipper then calls the
hotline person, who contacts the pipeline and suggests this
needs to be discussed. If it is relatively clear and no legal
issue is involved, or if the FERC attorney at the hotline sees a
clear answer, such issues sometimes get resolved. If something
needs to be addressed by the commission, however - including
contract provisions such as this - it isn't an issue the hotline
even considers.
She noted if the parties persist after hotline help, then a
complaint must be filed and it will go to settlement mediation
or even litigation. In further response, Ms. Newman opined that
the hotline has existed perhaps ten years.
11:35:35 AM
SENATOR BUNDE recalled discussion of a window of opportunity
such that if the window closes, Alaska's gas will be stranded a
long time. He requested Anadarko's perspective.
MR. HANLEY offered to get an answer. Noting there are numerous
reports, he remarked, "We've read them all." He said some of
those suggest Alaska's gas is needed regardless, while others
say liquefied natural gas (LNG) will come in. Mentioning the
timing of permitting for LNG facilities to import those, he
suggested the need to ask someone in Anadarko's commercial
department. He also said the sooner this pipeline can go, the
better. Noting Anadarko has acreage it wants to develop,
Mr. Hanley stressed the urgency. He recalled discussion of how
it would likely help Prudhoe Bay, the Trans-Alaska Pipeline
System (TAPS) and explorers in Alaska, in order to keep momentum
going. Mr. Hanley surmised it would be in the best interests of
Anadarko, probably Alaska and all the producers as well.
CHAIR SEEKINS thanked Mr. Hanley and Ms. Newman. He indicated
the need to build a pipeline as quickly as possible; to hold the
producers' feet to the fire to keep moving; and to ensure the
ability of companies like Anadarko to get into an open season in
order to get whatever gas they may have into the marketplace.
He invited participation in a roundtable forum to address topics
discussed this morning.
11:39:28 AM
^Jim Clark, Chief Negotiator, Office of the Governor
JIM CLARK, Chief Negotiator, Office of the Governor, lauded the
roundtable discussions for getting information to members. He
asked that Mr. Loeffler address some issues as a precursor.
11:40:27 AM
MR. LOEFFLER referred to Anadarko's comments, saying he wished
many had been carefully conformed to what the contract actually
does. While appreciating the emphasis on not delaying the
project, he noted page 4 of the handout says in part, "If the
Contract is executed this fall, an open season could be held
before year-end 2008, which seems to be premature." He said he
cannot reconcile those two positions.
He indicated the comments also say FERC regulations require a
lot of information relating to front-end engineering and design.
Mr. Loeffler remarked, "You can't comply with those regulations
unless that work is done. ... You'll be out of compliance if you
try to have an open season prematurely. I don't think we need
to get into that." He also said a set of regulations lays out
detailed information on what is required for open seasons,
including bid methodology. This takes time to do, including
fieldwork and engineering.
MR. LOEFFLER opined that the premature open season isn't
possible. He surmised the state will be inside the LLC, talking
about the open-season notice and construction of it, as well as
the engineering work. The state will have a voice. Discounting
the idea that the state needs veto power on this, he
acknowledged that may or may not happen, depending on how the
voting provisions turn out. He questioned whether it is a real-
world concern and reread the quotation from page 4.
He interpreted the comments to also say Anadarko isn't ready, at
the earliest, until 2009 or 2010. Mr. Loeffler acknowledged
Anadarko may have good reasons for itself, but said it sounds as
if Anadarko wants to delay the project. Noting some people are
pushing to start the project tomorrow, he remarked, "You just
sort of can't have it both ways."
11:44:32 AM
MR. LOEFFLER touched on Anadarko's opening comments, indicating
Anadarko said the Project Summary information should be part of
the contract. He noted Article 4.1 of the contract says the
project consists of pipeline and related facilities consistent
with the Qualified Project Plan, which is defined on page 49.
He asked, "Where's the beef?"
He turned to the capacity-management article, recalling
discussions with Anadarko that this is a novel clause,
anticipated to be submitted to FERC early, as stated in the FIF,
to decide whether it is permissible. Mr. Loeffler opined it
puts the state on equal footing with the producers because the
state doesn't get information that Anadarko, Chevron or BP would
get as a producer except by virtue of this contractual
provision. He offered the view that this is needed to reduce
risk to the state, to manage its capacity. Mr. Loeffler
continued:
The suggestion of a "most favored nation" clause would
seem to imply the exact sort of discriminatory
treatment that is criticized as part of the capacity-
management clause. And there is a difference here.
Anadarko's criticisms of the contract, save in the
capacity-management clause, are really criticisms of
the other three companies. In this clause, the way we
read it, Anadarko is looking at it as a potential
competitor to the state in the sale of its gas. And
they're trying to remove what they see, I believe, as
a competitive advantage. We see it as an effort to
level the playing field.
He reported it took enormous effort to negotiate this clause,
perhaps 31 days straight last year.
11:48:25 AM
MR. LOEFFLER asserted there are at least ten points in the
capacity-management clause that the comments ignore; he cited
Articles 10.2, 10.3 and 10.4, acknowledging he and Ms. Newman
disagree here. He indicated FERC has jurisdiction and will
provide an answer, and the state will have to deal with it once
there is an answer. Stating the intention of going to FERC for
clarity and confirmation, Mr. Loeffler opined that FERC has an
ample toolkit for almost every issue raised this morning.
He said while the written comments express Anadarko's
apprehension that the state capacity will be bundled by the
three producers to increase the value of their bid, that isn't
what the contract language provides. Rather, it provides that
each producer capacity holder requires capacity if the state
wants - it's an option with respect to its share of associated
state gas. Mr. Loeffler opined that the contract answers a lot
of the criticisms. Noting FERC has an entire enforcement
division, he said while the hotline clearly handles some
disputes, there are many other enforcement tools, discussed by
Mr. Pease previously.
He turned to the "most favored nation" clause as it relates to
royalty in value (RIV) and royalty in kind (RIV). Mr. Loeffler
opined if the state operated in an RIV world, the "old netback
world," and didn't need to market its own gas, the producers'
bids would be that much larger because they'd have all their gas
plus the associated state royalty gas, which would be RIV gas.
That isn't the case, however. Article 10.1, capacity
management, says that if asked, the producer will acquire
capacity for the state in the state's own name - not a bundled
name. Thus he said the criticism isn't fair with respect to the
contract language. He deferred to Mr. Clark and Mr. Griffin.
11:52:26 AM
MR. CLARK discussed the state's policies and the reasoning for
what was done. He agreed this was a hotly contested article,
because taking gas in kind raises concerns about the state's
risk, concerns that are critical to mitigate. To the maximum
extent, the desire was to mimic the RIV world, with three
principal objectives: 1) Never be short of pipe, and always
have enough capacity to get the gas to market; 2) be in
essentially the same position as now with respect to the
percentage of empty space on the line, and don't have excess
ullage; and 3) make these adjustments on a 30-day basis, which
producers don't do among themselves.
He said the state also has the benefit of information coming
from each producer that reveals where the gas is coming from and
where the capacity is being used - information the producers
don't get from one another, which will level the playing field.
Mr. Clark noted, with respect to the second item, that DNR has
developed a highly innovative system that, like most of this
article, is new and creative in how it protects the state by
mitigating the impacts of taking gas in kind.
He predicted Alaskans will view this article later as putting
the state as close as possible to the RIV world while achieving
the benefits of gas in kind; those benefits include in-state use
and reducing disputes. Mr. Clark voiced belief that those
policy objectives were met through hard-fought negotiation.
Acknowledging the need to have FERC look at it, he opined that
it fits closely enough with FERC policies - particularly
relating to Alaska - to receive approval. Lauding DNR for
fantastic job on behalf of the state, Mr. Clark commended
Mr. Griffin in particular.
11:57:27 AM
^Ken Griffin, Deputy Commissioner, Department of Natural
Resources
KEN GRIFFIN, Deputy Commissioner, Department of Natural
Resources, began by saying that under the administration's
concept a company must accept the terms of Article 10 in order
to obtain contractual fiscal certainty. If Anadarko chose not
to accept Article 10, for instance, it wouldn't be a party to
the upstream uniform fiscal contract or the fiscal-certainty
provisions, at least under the administration's current concept.
SENATOR BEN STEVENS asked: When a shipper signs a FT
commitment, is it also part of Article 10?
MR. GRIFFIN answered no. He explained that the signing of the
FT commitments and so forth is subject to FERC, which will
ultimately accept or approve the rules under which it is done.
Rather, the current discussion is at the fiscal-contract level.
The three producers that intend to deliver gas to this project
will have the opportunity to sign this contract, or other
producers will be able to sign the uniform upstream fiscal
contract, which will provide similar upstream fiscal provisions.
In signing that contract, they receive the fiscal-certainty
provisions, but also make certain commitments. One such
commitment is being bound by the provisions of Article 10.
12:00:33 PM
SENATOR BEN STEVENS posed a scenario in which an explorer comes
in later through an expansion, and the shipper has a certain
amount of volume of which he presumed the state would have the
same 20 percent approximately.
MR. GRIFFIN noted it would depend on whether it came from state
acreage.
SENATOR BEN STEVENS asked: When that new producer signs an
FT commitment, is it piggybacking on the state volume, or is
that state volume absorbed in the state's capacity agreement?
MR. GRIFFIN answered in two parts. First, if a new producer
comes in and doesn't sign the uniform upstream fiscal contract,
the lease provisions prevail. That producer would be
responsible for obtaining capacity for all the gas, including
the state's share. The state would take RIV, and taxes would be
paid under the tax statutes. The entire capacity commitment
would be that new producer's responsibility.
SENATOR BEN STEVENS suggested it is an option for the new
shipper to sign the upstream agreement or maintain the
status quo.
MR. GRIFFIN replied he'd assume so, yes.
SENATOR BEN STEVENS asked whether that is along with the
capacity agreement.
MR. GRIFFIN explained it is an all-or-nothing deal. To get the
benefits of fiscal stability, a company must take the
commitments in the contract or in the uniform upstream fiscal
contract that go with it. He turned to the second situation,
where a new producer comes in and signs the upstream fiscal
contract; in that case, Article 10 requires the producer and the
state to come up with their FT commitments, which are bids.
Provisions in Article 10 that don't quite mesh with FERC's way
will have to be worked out. He surmised, from FERC's
standpoint, that the producer would have to show up with a bid,
as would the state. From that point forward, Article 10 would
take over. If production changed, there'd be balancing of the
throughput and ullage between that producer and the state.
The committee took an at-ease from 12:05:15 PM to 1:13:09 PM.
MR. GRIFFIN emphasized that this capacity-management article is
novel, to rebalance risk with the producers in order to address
a novel situation in which a royalty owner is taking long-term,
serious financial transportation commitments without control
over the upstream.
He also noted capacity issues are subject to FERC approval, and
the state fully intends to bring this before FERC. The contract
contemplates that the capacity issue will be under FERC
regulation. If this cannot be approved by FERC, then the
contract says the producers and the state will attempt to
negotiate a substitute. Mr. Griffin expressed hope that there'd
be enough FERC guidance in such a case to figure out how to
craft a provision to accomplish this and then meet any
regulatory hurdles. "We have acknowledged and accepted the FERC
jurisdictional issues," he added.
1:16:04 PM
MR. GRIFFIN highlighted side rails to the scope of this article:
the capacity commitments sought by a producer plus those
commitments sought by the state for production from that
producer. If 80 percent of the commitments are the producer's
and 20 percent the state's, that 100-percent capacity commitment
is a side rail; there are separate side rails for each producer.
Neither the producer nor the state has the opportunity to expand
under Article 10; rather, they have the right and responsibility
to balance the capacity commitments within that 100 percent
between the two, based on the throughput coming from that
producer's properties.
He said there is no interaction between the producers under
Article 10. There is no transfer of capacity between the
producer and the state beyond what is dictated by the share of
production flowing to the state and to the producer. Thus
Mr. Griffin said the state has the opportunity to get all the
gas produced by that producer that is owed to the state. The
state can get all that gas off the North Slope as it is
produced. Conversely, if the pipe isn't kept full, the state
bears no more than its share of the empty pipe costs - the
ullage costs - related to that producer's production. That is
an absolute side rail written into Article 10.
1:18:17 PM
MR. GRIFFIN offered an example in which Anadarko goes to an open
season to obtain capacity for production from its share of
Alpine production, 100 million a day, of which 20 percent is the
state's gas under the contract. Anadarko seeks capacity for 80
million a day, and the state for 20 million a day. The
provisions of Article 10 would need to dovetail with the FERC
requirements; this remains to be done. The commitments are for
20 years. If Anadarko's Alpine production declines, since 90
percent of its acreage is on non-state land, it could pick up
the remaining production from non-state land. Hence the state's
share of the gas might be 7 percent. It's tax gas - the state
has no royalty there. Thus Anadarko would be motivated to keep
its 80 million a day full, for the life of that FT commitment.
If production flowed completely to the non-state acreage, the
remaining 13 million of empty pipe would be state capacity, and
the state would bear responsibility for it.
He explained that Article 10 would automatically correct for
such a situation, shifting 93 percent of the empty pipe back to
Anadarko because the company chose to move the production to
non-state acreage. The state would still bear some of the empty
pipe capacity, in the same proportion Anadarko has. But under
what was proposed in Anadarko's comments, the state would bear
the entire cost of that empty pipe. This is exactly the
scenario the state fought to prevent with Article 10,
Mr. Griffin emphasized.
He posed another situation, emphasizing that, in both cases, the
risk is entirely on the state unless Article 10 is in place.
Thus Mr. Griffin said he was appalled that Anadarko would say
its interests are aligned with the state's and that Article 10
should be removed. He stressed that this is one of the biggest
factors in the contract to ensure the state's risks aren't
disproportionate to those of the other producers and shippers.
1:22:35 PM
MR. LOEFFLER informed members he would look at Anadarko's
comments and respond as part of the FIF. Turning to state-
initiated expansion, he reported that in comments from four or
five independents, only Anadarko raised detailed comments about
Article 8.7, whereas one made some comment and two said nothing.
Mr. Loeffler suggested balancing what was heard and what wasn't
heard, but he also acknowledged there are some good technical
points in Anadarko's comments on state-initiated expansion that
might lead to changes.
He emphasized that clause's beneficial purpose was to provide a
third tool in the toolkit - although it is the second tool in
terms of timing, since voluntary expansion must be gone through
first, which will be in the LLC. Saying Article 8.7 would be
looked at, but that he wasn't ready to drop it, Mr. Loeffler
posited that there might be procedural advantages - which
Anadarko doesn't agree with thus far - that would result in a
faster resolution than from FERC, including the dispute-
resolution terms under the contract.
MR. LOEFFLER turned to RCA, noting everyone who has commented
agrees they want FERC to have jurisdiction. Pointing out,
first, that RCA is excluded from the definition of "state," he
said RCA's jurisdiction - whatever it is - continues intact.
Second, there is talk in the comments that non-owner shippers
are at the mercy of competitors. However, these concerns relate
to Shell, with a market cap of $127 billion; Chevron,
$149 billion; and Anadarko, $19 billion. These are smart,
astute corporations, Mr. Loeffler told members, and they know
how to use the legal and legislative processes, and how to
access RCA, which has its jurisdiction intact.
1:25:47 PM
MR. SHEPLER said Anadarko's comments had highlighted something
he hadn't seen in Article 10, that the capacity-management
provisions are the only means by which parties under the
contract - including those with an upstream contract - can move
capacity back and forth. He asked whether Mr. Loeffler believes
that is a correct characterization and, if so, what the basis is
for this being exclusive, as opposed to Anadarko, for example,
being able to take a capacity release from the state or sell gas
to the state for use in its capacity.
MR. LOEFFLER deferred to Mr. Griffin.
MR. GRIFFIN first provided a general answer, saying FERC rules
are established for selling or seeking capacity, with the
following sideboards: The state's share of production from an
individual producer is likely to shift over time, while at the
same time that producer and the state have FT commitments, with
the associated financial burden. Within that 100 percent of
capacity sought by the producer and by the state for the
production associated with that producer, as the share of the
state's production shifts - whether up or down - the financial
commitments for that 100 percent capacity shift proportionately.
He noted if the capacity article is in place, the state has no
right to seek capacity outside its terms. The producer does,
however, and must do so under FERC rules, in which case
Mr. Griffin surmised the producer's gas would have state gas
associated with it. The capacity article would fall back into
play, and identical capacity would have to provided to the state
in that proportion so that the state's gas could get off the
North Slope. With respect to going out and finding capacity for
a new field, however, Mr. Griffin said it would be the
producer's purview to initiate, and then Article 10 would ensure
the state was dealt with proportionately.
1:29:31 PM
MR. GRIFFIN explained that any producer that doesn't sign on to
the fiscal contract will be subject to the lease and to the tax
statutes, and thus will provide royalties. That producer will
have to make long-term FT commitments. But it won't want to if,
every 60 days, the state can switch back and forth as to whether
it takes its gas in value or in kind. The producer will need a
commitment from the state for one or the other. As long as
Article 10 is in place, the state has no right to seek capacity
outside its terms; the gas must be taken in value. Thus
Mr. Griffin said the producer must seek capacity for the full
100 percent and then take the capacity costs off, in adjusting
the RIV value, as happens today.
He gave the following reasons. The producer doesn't obtain
fiscal certainty under the uniform upstream fiscal contract. If
a producer wants certainty under that contract, it will commit
to Article 10, and the state will want to take its gas in kind.
If the state wants to market part of it, it needs to market all
of it. Mr. Griffin reported the producers were concerned that
if the state could seek capacity independently, it could tilt
the playing field in the state's favor along with all the
benefits under Article 10. Therefore, it was decided that under
Article 10 the state has no independent right to seek capacity
outside the terms of that article.
MR. GRIFFIN reiterated that the basis of Article 10 is to
maintain parity between the state and each producer with respect
to risk and the ability to get gas off the North Slope. He
emphasized that the state has the unilateral right, at any time,
to terminate Article 10. Ten or fifteen years down the road the
state might find that getting active independently in that arena
is to the state's advantage, for example, and could do so.
CHAIR SEEKINS thanked the participants and invited the producers
to testify.
1:34:29 PM
^Wendy King, ConocoPhillips
WENDY KING, Director of External Strategies, ANS Gas Development
Team, ConocoPhillips Alaska, Inc., said when it comes to terms
regarding access for explorers to the gas pipeline,
ConocoPhillips offers a unique perspective and a strong track
record on the forefront of North Slope exploration. While many
believe BP, ConocoPhillips and ExxonMobil are commercially
motivated and aligned in a similar fashion, many times during
negotiations they didn't see eye-to-eye.
She referred to Article 10 and Mr. Griffin's discussion of
varying state equity across the North Slope. Ms. King said the
producers also have varying interests in those fields, which
creates complications when trying to find a balance that works
for all parties. Similarly, Anadarko has a unique portfolio.
MS. KING emphasized she is pleased to see alignment between
Anadarko and ConocoPhillips in wanting to see the gas pipeline
project advanced, and to see Anadarko's sense of urgency
regarding this project. Ms. King noted Anadarko said, in its
opening comments, that one of its top Alaska priorities is to
have a gas line built as soon as possible, which will stimulate
new gas exploration and improve oil exploration economics.
However, she expressed concern that some of Anadarko's comments
seem to contract the opening remarks.
She informed members that ConocoPhillips, with others including
Anadarko as a minority partner, has been exploring in NPR-A and
the Alpine area successfully for gas as well as oil; she offered
to provide copies of three press releases. Ms. King noted
ConocoPhillips was mindful during negotiations that having
common fiscal terms for assets like NPR-A would facilitate its
ability to advance potential projects there. ConocoPhillips is
a supporter and believes the upstream model contract will help
create that aligned position to allow continuing to advance its
activities in those regions, Ms. King told members.
MS. KING also reported that ConocoPhillips sees the upstream
model contract as key to motivating its exploration efforts to
fill the gas pipeline, which she anticipates will require about
15 Tcf of additional gas, and more if the pipeline is expanded.
If those additional volumes are found in commercial quantities,
ConocoPhillips is confident that expansion and other
opportunities will exist on this pipeline to get that gas to
market. ConocoPhillips also believes there is a possibility -
which FERC policy requires - that any interested party can bid
in the open season, since it is an open-access line. Thus
volumes beyond Prudhoe Bay and Point Thomson may possibly show
up at the initial open season.
1:38:02 PM
MS. KING turned to ConocoPhillips' role as a potential shipper,
highlighting the commitment to continuing to prepare for the
open season in order to make appropriate decisions - with the
working-interest owners in those respective assets and with
AOGCC - to have each field ready for the approved offtake and
development. Not all parties to the assets are parties to the
proposed fiscal contract. Thus ConocoPhillips needs to work, as
a shipper, with the working-interest owners in those respective
fields to get those assets ready for the open season.
She highlighted Anadarko's concern that this would be a
producer-affiliate-owned pipeline; that a premature open season
could be proposed to shut out explorers; and that an open season
before year-end 2008 would seem premature. Ms. King indicated
the existing Project Summary, a public document, as well as the
Qualified Project Plan, also a public document with her
company's stranded-gas application, both estimate an open season
won't occur until 18 months to two years from the start of
project planning. Ms. King said this timing is consistent with
Anadarko's estimate of year-end 2008 if the fiscal contract can
possibly be executed in 2006, and she doesn't believe this is a
premature open season.
She said ConocoPhillips believes this project needs to be
diligently pursued; adding further delays to wait for
exploration success is an unnecessary burden on the project.
Ms. King noted FERC Orders 2005 and 2005-A, regarding timing for
that initial open season, are to ensure adequate notice is given
to all prospective shippers. In addition, ConocoPhillips will
update the Project Summary annually, so people will have other
ways to know how the project is progressing.
MS. KING emphasized that project planning and pre-permit
application activities are real, both from a shipper and a
pipeline company perspective; a number of pipeline company work
activities will need to be pursued in those phases. The open
season needs to be orchestrated for both U.S. and Canada, since
there are issues such as the Alberta-to-Lower 48 offtake plan.
1:40:26 PM
MS. KING explained that some of this work will be done by
shippers and some by the pipeline company. The affiliate rules
will be "stepping in," and the very rules ConocoPhillips and
FERC have talked about will ensure the companies keep their
different hats on during preparation.
She expressed surprise at some references about the pipeline
needing to take actions with respect to what AOGCC decides,
because she said those are shipper issues - getting the shipper
ready for the open season. MS. King noted the pipeline will be
thinking about what it needs to do to get ready for an open
season from a pipeline perspective.
MS. KING asserted that delaying the open season beyond 2008 only
delays the project, which isn't in the interests of
ConocoPhillips or the state. Potential shippers have had years
to get ready for an open season; since 2002, the project
sponsors have been indicating their desire to get the necessary
government frameworks in place.
She said ConocoPhillips has been actively driving these efforts
at state and federal levels. Delaying development of the known
resource in exchange for unpredictable exploration programs
seems a high risk for the state and the pipeline. Furthermore,
slowing the project is inconsistent with Article 5, the work
commitments, which require diligent advancement. An open season
is necessary to finalize the project design and to meet those
permitting requirements.
She referred to previous discussion, noting one potential
solution to a concern was advanced by the producers during the
FERC open-season-rules process: allow a pre-open-season
commitment process, which allows base shippers to commit to the
project and allows an open season at a final later date.
However, Ms. King recalled, the state and Anadarko argued
against this proposal, which she asserted would have been in
everybody's interest, with the result that FERC issued rules
that would have prorated down only the original shippers,
effectively eliminating this option.
1:42:30 PM
MS. KING countered the idea that someone must find gas in order
to show up at the initial open season. If parties' exploration
efforts haven't been successful in the last few years, they can
still consider showing up and taking out a FT commitment on some
"risk exploration" volumes. There'd be seven to eight years to
continue the exploration appraisal-and-development program
before commercial operations commenced. It is a risk-based
commercial decision each party can make.
She addressed the comment that the contract should reflect the
design of the project described in the application. Ms. King
noted Article 4.1 already says this will be a large-diameter
pipeline. She said the specifics of project rates cannot be
committed to because there hasn't been an open season, and thus
it's premature to dictate the rates for the initial open season.
She turned to the design, indicating she believes there has been
confusion about ConocoPhillips' ongoing petition with FERC,
submitted June 2006, which challenges the commission's assertion
of authority in Sections 157.36 and 157.37 to mandate - long
after the open season has ended - increased capacity for an
Alaska gas pipeline project or expansion, and to dictate the
amount of unsubscribed capacity/unused expandability that
initial project must build in. Ms. King told members, "That is
specific to the petition we're pursuing right now."
MS. KING read another quotation from that petition which says
the commission has adopted regulations that jeopardize timely
permitting and construction of an Alaska natural gas pipeline in
contravention of Congress's intent in enacting ANGPA. By the
time the commission acts upon an application for a certificate
of public convenience and necessity, a project sponsor will have
spent several years and hundreds of millions of dollars
developing the optimal project design, conducting the open
season and preparing the certificate application.
She went on to say that design changes imposed by the commission
as conditions for receipt of a certificate could either scuttle
the project entirely or require that additional time and
resources be spent revising the project. This could delay the
project that Congress, through ANGPA, sought to expedite. "We
are focused on that issue in that ongoing petition," Ms. King
concluded.
1:45:13 PM
MS. KING turned to the capacity-management provisions.
Concurring with Mr. Griffin about the challenges faced during
lengthy negotiations, she highlighted efforts to have those
provisions be consistent with FERC policy and to replicate how
capacity would have been handled if the state were in the RIV
world. "We believe we have been successful in doing that,"
Ms. King told members, noting provisions also say that if FERC
finds inconsistency with its policy, there will be good-faith
negotiations towards an alternative.
She said ConocoPhillips stands behind the provisions negotiated
with the state on capacity. Many of Anadarko's criticisms
relate to provisions negotiated to provide the state the option
"to follow the decisions that we will make regarding our
capacity management, which means the state is going to see
confidential information," Ms. King added. As to whether this
precludes parties from putting capacity on the open market, she
said Article 10.3(b) has provisions such that if ConocoPhillips
- in its relationship with the state as a shipper on the
pipeline for its volumes - finds it no longer has enough gas to
fill those, the company is obliged to notify the state that it
will go to the market to post its capacity. Ms. King explained:
When we go to the market to post that capacity, the
state has the option to pursue that as well, which
means we are giving them confidential information that
we're about to go to the market, to give the state the
option to follow in that transaction. There's a
reason why we have those confidential provisions in
there, but we ... do believe that those provisions do
allow that capacity to get to the market if it is not
being used by the gas volumes associated with the
state and ConocoPhillips and our relationship.
1:47:19 PM
MS. KING gave a technical perspective to emphasize a point made
by Mr. Loeffler. She said it wasn't anticipated that the
producer's bid would be volume-inflated by the state's bid; the
contract doesn't say that. Rather, the state will provide the
paperwork to the producer, which will submit the bid independent
of the producer's bid. This is a change from the RIV world.
With respect to the capacity provisions, she indicated there is
concern that the producer would get that capacity. If
ConocoPhillips discovered a new field in NPR-A, for example,
obligations in here ensure the state has the ability to receive
value for its gas if it needs capacity on this pipeline.
MS. KING reported that a concern of ConocoPhillips had been that
the state could take that 20 million a day ConocoPhillips had
acquired and turn around and give it to somebody else, posting
it on the market, and then come back to ConocoPhillips and
request more capacity for the field the state was about to
develop. ConocoPhillips could continually have to get capacity
that was being spun off to others. Thus some protections are
written into the capacity-management provisions.
1:48:37 PM
MS. KING noted she wouldn't raise some points, to give time to
her colleagues. She emphasized that ConocoPhillips supports the
public-comment process outlined in the Stranded Gas Act,
believing it is important for the public and the legislature to
ask such questions. However, ConocoPhillips believes it has a
responsibility to respond when those concerns are inconsistent
with the company's understanding of FERC policy; the fiscal
contract drafted May 24; and how mega-projects should work.
She related ConocoPhillips' belief that making one party
subsidize another's access to the pipeline is a problem.
Existing shippers shouldn't have to subsidize expansion or
access for others. Existing shippers could include the three
project sponsors - BP, ConocoPhillips and ExxonMobil - and the
state, but also Alaskan local distribution companies (LDCs) or
other explorers that show up at the initial open season.
ConocoPhillips also believes FERC is the appropriate adjudicator
of rate treatment in defining what a subsidy is, and that a
pipeline company should have the right to propose the rate
treatment in its FERC filing that it deems appropriate for a
particular expansion. Ms. King said provisions are in the
contract so any party can protest that as a shipper.
She highlighted ConocoPhillips' commitment to trying to develop
Alaska's gas resources. Between 2001 and 2006, ConocoPhillips
drilled 47 wells - 19 in 2001 alone, mostly on the western North
Slope. It frequently partners on those wells with independents
and other new entrants, and it partnered with Anadarko in 24 of
those 47 wells. The company is steadily moving its exploration
to the west, Ms. King noted, with two NPR-A wells in 2005.
MS. KING reported that ConocoPhillips is reviewing those
comments on the proposed fiscal contract for which it has
received copies; she and the team will review those.
ConocoPhillips is commitment to working with the producers and
the state to complete the LLC, and to finding a solution that
hopefully will work for all parties to the fiscal contract and
will facilitate legislative approval of the contract.
1:51:13 PM
SENATOR ELTON asked why there would be reluctance to add other
sponsors to the project; he suggested other testifiers could
address this also. He gave his understanding that Anadarko has
an interest in participating in the pipeline project. He
surmised spreading risk as broadly as possible makes sense; it
is one argument for the state's participation.
MS. KING answered that she wasn't aware of some meetings and
conversations referenced earlier, although some of her
colleagues have been involved longer. For any party that wants
to participate in the project, it is a commercial decision to be
brought to the project sponsors for discussion.
1:52:42 PM
^Bill McMahon, Commercial Manager, ExxonMobil
S.A. (BILL) McMAHON JR., Commercial Manager, Alaska Gas
Development, ExxonMobil Production Company, recalled the
formative stages of this project in 2001, when it was decided to
have only three participants; they were still trying to see if
there was a commercially viable project. He said there is a
practical limit to the number of parties involved. He agreed
with Ms. King that once the fiscal contract is approved and the
project moves forward, nothing prohibits commercial transactions
that could include others in the process.
1:53:30 PM
^David Van Tuyl, BP
DAVID VAN TUYL, Commercial Manager, Alaska Gas Group, BP, echoed
those comments, adding that once BP is confident there is a
project - for which approval of a fiscal contract is a first and
essential step - BP has said it would welcome participation of
others that can add value to the project and take on the
necessary risks, advancing the project and associated
obligations. The key is getting to that place.
He turned to Anadarko's comments, on page 18, that perhaps some
specifics should be mandated about the project design. Mr. Van
Tuyl expressed concern that this would preempt the open season
process, putting the cart before the horse. He emphasized
getting the design right, a fundamental tenet of the open-season
process during which customers come together and meet with the
pipeline company to get the project designed appropriately.
While BP anticipates building a large-diameter pipeline, likely
in the 48- to 52-inch range, BP doesn't want to preempt the
open-season process. Stipulating the design or diameter may
actually cause damage by limiting sources for steel, for
instance. Thus BP believes it should stay with the FERC process
and allow that open-season process to run its course.
MR. VAN TUYL drew attention to Anadarko's concerns about the
AOGCC process in setting the offtake rates at fields such as
Prudhoe Bay and Point Thomson, and that those needed to be
authorized before the open season. Indicating BP has had a
series of meetings and hearings with AOGCC about that topic, Mr.
Van Tuyl said analysis of the appropriate offtake rates at those
fields has been underway for over a year.
He reported that the three individuals before the committee
today provided testimony before AOGCC multiple times regarding
the timing of the offtake-rate decision; its potential impact on
the project; and how that dovetails with the open-season
process. As a result, a process was established jointly with
AOGCC to ensure they could complete the technical work that
needed to be done within the timeframe in order to avoid
impacting the project. Mr. Van Tuyl said he thinks it is a
valid concern, and it is work that needs to be done, but there
is already a process identified to meet those objectives and to
establish those rates.
He noted concern that the preliminary engineering wouldn't be
completed before the open season occurs. Mr. Van Tuyl surmised
the Gantt chart in BP's Project Summary might not be clear, but
suggested the associated wording is. He said the preliminary
engineering - front-end engineering and design (FEED) - will be
completed before the open season. A design must be submitted as
the basis for one's certificate application.
1:57:18 PM
MR. VAN TUYL recalled Anadarko's statement about planning to
drill its first gas-exploration well in the Foothills this
winter. He commended this because the project needs additional
exploration volumes: 35 Tcf of known resource is a great start,
but more is needed to keep the pipeline full for its expected
duration. However, he recalled hearing similar statements in
previous years from Anadarko. In 2001, as part of the
$125 million joint study, a preliminary information session was
conducted for all interested potential shippers on the pipeline;
at the time, Anadarko said there may not be carbon dioxide (CO)
2
associated with its gas that may be found in the Foothills, and
thus had requested that the CO-removal service be unbundled in
2
the gas treatment plant (GTP) and that there be a separate
compression service and CO service.
2
He indicated BP heard that concern, now reflected in Article 8.5
of the contract where it specifies the GTP will offer unbundled
service. Mr. Van Tuyl explained that BP disagrees with the
assertion that, because of Anadarko's decisions not to drill
exploration wells, an open season in two years' time is
premature. He added that BP wants to see pursuit of a gas
pipeline project for Alaska as soon as possible.
MR. VAN TUYL also disagreed with the suggestion on page 3 of
Anadarko's comments that the producers might intentionally
design a smaller system specifically to exclude explorers.
Noting BP has moved to larger diameters to make the project
economics work, he said it makes no sense to build an uneconomic
pipeline just to exclude others. Nor is that BP's intent. In
addition, FERC would ensure that didn't happen as part of the
open-season process. He highlighted the need for exploration
volumes for this project, whether at day one or later.
2:00:08 PM
MR. VAN TUYL turned to capacity management, reiterating
Mr. Griffin's point that the state has the option to operate
under Article 10. The state can obtain capacity on its own from
day one, operating under Article 10, or later can decide it no
longer wants to operate under that article, at which time it
would provide notice. The state just doesn't have the
flexibility to operate under both at the same time, for the
reasons discussed.
He agreed that BP, ConocoPhillips and ExxonMobil hold most of
the known gas resource on the North Slope; that is because those
companies have made the billions of dollars of investment
necessary to define and develop those resources. Mr. Van Tuyl
also agreed with Mr. Loeffler that it is difficult to reconcile
some of Anadarko's statements. One is that Anadarko doesn't
want to delay the project and wants a gas pipeline as soon as
possible, but doesn't want an open season until ready, whenever
that is. Mr. Van Tuyl remarked that BP can't dictate the pace
at which others choose to explore, and doesn't think Alaska
should continue to wait for a gas pipeline. He concluded by
saying BP wants to continue to support advancing the project as
soon as this body authorizes the contract. He deferred to
Mr. Keithley for FERC-related issues.
2:02:00 PM
^Brad Keithley, Jones Day, Counsel to BP
BRADFORD G. KEITHLEY, Jones Day, Counsel to BP, informed members
he would offer points from having worked on other projects, one
being BP's Baku-Tbilisi-Ceyhan (BTC) project, from which the
following was learned: Don't try to tie down a large number of
detailed provisions at the outset, but let those evolve as the
project occurs. In that project, the partners and governments
involved weren't overly detailed at the outset about design and
other requirements. They allowed the study to go forward; from
the study they designed the pipeline; and from the design they
determined various rules, regulations and rates that would
apply, in the normal course. Referring to yesterday's
testimony, he conveyed BP's pride that this highly successful
project came to fruition. Noting this Alaska project is in an
early stage, he cautioned that imposing restrictions now will
reduce needed flexibility as the project becomes more defined.
He turned to Anadarko's concern about potential mistreatment of
nonaffiliates. While agreeing such concerns are serious,
Mr. Keithley said FERC regulations already provide remedies for
all those. There really are no independent pipelines in the
Lower 48; instead, almost all have either affiliated producer
companies or affiliated marketing companies. As a result, FERC
has extensive rules for affiliate treatment. He referenced
recent testimony about Order 2004; Order 670, which prohibits
any action for the purpose of impairing, obstructing or
defeating an honest and well-functioning market; and FERC's
enforcement powers. Mr. Keithley said all those powers and
rules come into play, providing Anadarko with an effective
remedy down the road if the concerns come to fruition.
He opined that Anadarko has shown it knows how to use the
process. Recalling its participation in the congressional
process that resulted in ANGPA, Mr. Keithley predicted
participation in the FERC process. He surmised Anadarko is
trying, through the contract, to preempt the FERC process and to
impose its preferred remedies in advance. For reasons outlined
by Mr. Loeffler and Ms. King, he said those instances - if they
occur down the road - should be left to FERC enforcement, rather
than contemplating such possible problems now.
MR. KEITHLEY also opined that because of the state's ownership
interest, this project will have more enforcement than any
project ever in the Lower 48 or internationally. The state can
play an important role through its ability to complain as an
owner - both internally, if unfair or discriminatory interests
are seen, or externally with FERC.
He suggested while the hotline isn't the only FERC remedy, it
will probably play a more important and useful role in
connection with this project than in the Lower 48, again because
of the state's ownership interest. If producer-owners try to
direct the pipeline in a way that results in an unfair or
discriminatory advantage, there will be an opportunity to raise
those issues. Although the hotline doesn't always have all the
information needed to deal with allegations of discrimination,
here the state will be an internal policeman of sorts that can
provide that information immediately to FERC and the hotline if
an unfair advantage is perceived. This will reinforce the
hotline's ability to moderate the pipeline's behavior,
Mr. Keithley predicted.
2:08:52 PM
MR. KEITHLEY, in response to Senator Wagoner about Lower 48
pipelines, referred to previous testimony about the preamble to
FERC Order 2004. Mr. Keithley said he believes 16 pipelines are
affiliated with producers, and 6 of those carry more than
60 percent of the throughput. Probably all pipelines are
somehow affiliated with marketing companies, which buy gas in
the field from producers and then transport it through the
pipelines and sell it in competition with independent marketers.
Those pipelines have the same incentives as producer-owned
pipelines to bias the rules in favor of their marketing
companies. Thus FERC developed this extensive set of
regulations to deal with affiliate relationships. It is a rare
exception that a Lower 48 pipeline is affiliated with neither a
producer nor a marketing company.
SENATOR WAGONER asked whether "affiliated" means they have
contracts with the producers to ship. He recalled being told in
the Senate Resources Standing Committee months ago that there
basically are no producer-owned pipelines transporting gas.
MR. KEITHLEY specified it means ownership: the pipeline owns
the marketing company, the marketing company owns the pipeline
or a holding company owns both. There aren't many pipelines
owned by producers, but almost all are affiliated with marketing
companies. He noted FERC found that pipelines affiliated with
marketing companies are as likely to be biased in favor of those
companies as pipelines affiliated with producers are likely to
be biased in favor of the producers; thus FERC developed
regulations.
CHAIR SEEKINS surmised ownership is the common thread. The
marketing company owns the gas it ships to market, just as the
producer owns the gas it ships.
MR. KEITHLEY affirmed that. He reiterated earlier points in
response to Senator Stedman.
2:14:44 PM
SENATOR ELTON asked: Given Governor Murkowski's comments, as
well as the presumption of many that this pipeline will be a
certain size - over 4.0, expandable to somewhat less than 6.0 -
and the opportunity later to change the project plan as more
things become known, why not have a starting presumption, with a
later change in the project plan if necessary?
MR. VAN TUYL replied that the contract refers to the Project
Summary, which outlines the base design, referencing a large-
diameter pipeline and the 2001-2002 study wherein the base
design consisted of a 52-inch pipe. The reason for not
stipulating in the contract that the design includes a specific
diameter or turbine driver, for example, is there isn't enough
information today. Technology could change. High-strength
steel might be applicable, for example, enabling a design change
to save money. Offtake might not be guessed correctly.
Additional volumes may become available and thus be bid at an
open season. The desire is to avoid mandating limitations that
might result in a suboptimal system, which wouldn't be in
anyone's best interests.
SENATOR ELTON surmised a reference in the contract isn't as
strong as having it in the contract itself.
MR. VAN TUYL emphasized the Project Summary is a living document
that the contract requires to change from time to time. It
didn't seem efficient to impose the burden of requiring all
parties to execute a written amendment whenever there is a
design change. The Project Summary and the Qualified Project
Plan are therefore separate from the contract, but the contract
requires updating of those periodically and allows the project
itself to be executed efficiently.
2:20:26 PM
MR. McMAHON stated agreement with everything said so far. For
Senator Wagoner he listed seven producer-owned pipelines:
Maritimes-Northeast, Discovery, Green Canyon, Destin, Garden
Banks, Nautilus and the new Rockies Express that is moving
forward; he also mentioned the Alliance pipeline from Canada to
Chicago.
He returned to another matter, in order to put the appeal of the
FERC order in context. Mr. McMahon explained that FERC wrote
itself the unprecedented right to mandate a design change in the
pipeline. This puts undue risk on the initial shippers. If
FERC requires a higher-volume pipe built just in case additional
volumes are found, it requires overbuilding the pipeline without
additional underpinning for the extra capacity. If those
volumes don't materialize, the initial shippers bear the cost.
The pipeline always recovers its costs.
MR. McMAHON further explained, "That's why we're fighting that
unprecedented right. It's not to try to find a way to
manipulate this pipeline. It is to make sure that we can design
the pipeline to match the results of the open season, which we
think is the prudent thing to do." He said while pipelines can
build additional capacity on speculation, it isn't prudent for
this risky, high-cost pipeline. The desire is to match the
open-season commitments with the project design, and to build in
the appropriate amount of expandability for the future. Thus
the initial shippers will know what they're signing up for.
CHAIR STEVENS thanked the testifiers and invited the Anadarko
representatives back to the witness table.
2:22:34 PM
SENATOR BEN STEVENS recalled speculation as to when a company
could actually book its North Slope gas reserves. He gave his
understanding that those aren't bookable until the time of
project sanctioning, authorization for expenditure and issuance
of a certificate of public convenience. He asked Anadarko: Do
you have proven gas reserves? When would your discovered
reserves be bookable? Would you have to have a FT commitment,
or would it just be a transportation system to market? He
requested an answer at some point for Anadarko and other
explorers. He also asked: At that time, are other companies
that have reserves on the North Slope allowed to book it because
there is a transportation mechanism, or does the SEC require an
FT commitment to be able to book it?
MR. HANLEY offered to get an answer, noting he doesn't work in
that area but that there are guidelines on the timing for
booking reserves.
MS. NEWMAN said she didn't know and wasn't an SEC lawyer.
MR. HANLEY interpreted as follows: If a pipeline is built, if
somebody explored and found gas, does there have to be a full-
time commitment, or is it just because there's a pipeline?
SENATOR BEN STEVENS said he didn't know, suggesting it is
blurred. They're not bookable now because there isn't
transportation capacity to market. But if that exists, can
somebody then convert undeveloped resources to bookable
reserves, benefiting everybody?
SENATOR STEDMAN suggested perhaps asking the consultants to
guesstimate the values of the producers' bookable reserves for
the aforementioned.
The committee took an at-ease until 2:26:46 PM.
MS. NEWMAN asked: If the offtake isn't known and other factors
are ambiguous, why not hold a nonbinding open season to see if
there is something else out there or if it is realistic? While
FERC requires specifying the pipe design, and perhaps 30 other
items, for a binding open season, most pipelines hold a
nonbinding open season first, to determine market interest; they
may even hold a second one. They may present a scenario and
inquire about interest and what people are willing to pay.
People respond, and it goes back to the drawing board.
She noted this pipeline has been studied for years, with a
$125 million study concluding the design isn't economic. Giving
some history, Ms. Newman recalled that pre-subscriptions were
opposed by many and yet FERC allowed them, saying it might be
suspect if the design only suited pre-subscriptions. If there
isn't enough capacity when the real open season is held,
therefore, FERC might require proration of the capacity signed
up for in advance of everyone else. As a matter of fairness,
FERC then agreed if somebody signs up under the same terms and
conditions as the pre-subscription, that is prorated too.
Ms. Newman noted pre-subscriptions could be signed up today.
MS. NEWMAN emphasized that affiliate rules don't kick in until
there is an affiliate, which doesn't happen until the project
entity is formed. Thus there is no issue until then, and there
is no enforcement policy at FERC for this. It will get sorted
out when the open season occurs, because nothing has been
violated. However, the problem arises before the rules kick in.
A nonbinding open season should be held if there is a need to
figure out what is going on.
She asked: Why should the state object to having authority to
decide it's a little early for a binding open season? Anadarko
wants a pipeline, Ms. Newman explained, but doesn't want to be
disadvantaged by having everything etched in stone before the
open season. If the playing field is level, it isn't a problem.
2:32:12 PM
MR. KEITHLEY remarked that FERC Order 2005 specifies affiliate
rules will apply from the time of planning for the open season;
as BP interprets it, this is from the date the project entity is
formed - soon after the fiscal contract is passed. In the
Lower 48, by contrast, the rules don't apply until after the
pipeline is certificated by the commission. Order 2005 has an
exception for the Alaska pipeline because of heightened concern
about affiliate relationships.
MS. NEWMAN suggested she and Mr. Keithley don't disagree, but
have different perspectives. She concurred that the rules don't
apply until the project entity is created. Until that happens,
there is no affiliate to apply a rule to, regardless of how
early the planning process is begun.
MR. KEITHLEY added that the project entity being discussed is
the LLC, which he predicted would be formed very soon.
The committee took an at-ease from 2:34:07 PM to 2:45:06 PM.
^Gross versus Net Tax
^Dr. Pedro van Meurs, Consultant to the Governor
DR. PEDRO VAN MEURS, Consultant to the Governor, discussed the
fundamentals of a gross versus net tax, giving a PowerPoint
presentation with an accompanying handout dated July 25, 2006.
He highlighted common ground and differences between HB 3004,
proposed by Representatives Berkowitz and Gara, and his own
proposal made to then-Governor Knowles on April 29, 2001. He
said this goes to the heart of gross versus net. Like HB 3004,
his 2001 proposal completely modified the outdated economic
limit factor (ELF), since the field and production formulas
needed to be adjusted. It had a strongly progressive tax based
on price, with much higher tax rates under high prices and zero
tax when low, and it had incentives for heavy oil. The big
difference from HB 3004 was significant tax credits.
He explained that he'd proposed a strongly price-sensitive tax
because of a good experience with clients two years earlier,
when oil prices were declining - the best time to propose such a
tax; one client now is highly satisfied with its oil and gas
revenues, a royalty equivalent to 40 percent. However, Governor
Knowles hadn't accepted his similar proposal, not feeling
politically that it was the right moment for such a dramatic
change; if he had, the state would be $6 billion richer today.
Dr. van Meurs noted these gross taxes have a short life.
Whenever it is discovered that the formula is outdated, it is
costly and difficult to adjust. Revenues are lost meanwhile.
2:52:23 PM
DR. VAN MEURS focused on revenues versus structure, beginning on
page 5 of his presentation. He highlighted three fiscal options
that create equal revenues, two based on tax credits and one
based on minor or no credits. The former included a system
based on statewide revenues like the proposed petroleum
production tax (PPT), as well as his 2001 proposal that is based
on gross revenue per field with no deductions for capital or
operating costs. The latter was similar to HB 3004, primarily
based on the gross structure in the fields. For two key North
Slope fields that produce 50 million and 150 million barrels,
revenues would be equal under those options, as shown on pages
8-9 of his presentation.
He said these fields are typical of what oil companies believe
will be the next generation of more difficult, more viscous,
somewhat heavier oil that will be encountered on the North
Slope. If he'd used fields with much lower costs, the PPT would
look much better because deductions would be less.
DR. VAN MEURS explained that pages 10-12 describe how he'd
modified each of the three options to result in equal revenue.
For the PPT variation, he'd used 20/20, adding a progressive
feature based on net, starting at $35 a barrel and increasing
0.2 percent for every dollar, with a maximum rate of 50 percent;
it didn't include a corporate allowance of $12 million in tax
credits or a $73 million deduction as it had originally. His
2001 proposal had a flat rate of 15 percent; investment tax
credits of 40 percent, applicable to all capital expenditures; a
price-adjustment factor starting at $50 a barrel based on ANS
divided by 50; and a maximum rate of 40 percent. He highlighted
the similarity to Senator Wagoner's recent gross-tax proposal.
2:59:21 PM
DR. VAN MEURS, in response to Senator Wilken with respect to the
flat nominal rate of 15 percent, specified it is gross after
deduction of the royalties. In addition to being in Senator
Wagoner's proposal, it was in HB 3004, as he recalled.
SENATOR WAGONER clarified he'd done his proposal before
receiving copies from Dr. van Meurs.
DR. VAN MEURS noted page 12 of his presentation shows the
HB 3004 variation for comparison. He'd taken the existing
nominal rates and ELF, using a minimum rate of 6.5 percent,
compared with 5.0 in HB 3004; a rate reduction below $35 by
6 percent so that by $20 per barrel the rate becomes very low,
whereas HB 3004 lowers it by that point to 12; a similar concept
to HB 3004 for the price-adjustment factor, but using $35 a
barrel as a basis, rather than $20, taking ANS and dividing by
35; an extra percentage, like HB 3004, but not as aggressive,
using 3 percent more between $70 and $120 a barrel; and a
maximum rate of 40 percent, similar to HB 3004. Referring to
all three scenarios, Dr. van Meurs said the whole curve of
revenues can be matched for a particular field. This filters
out the revenue aspect, which allows concentrating on what is
important: the structural differences between these proposals.
He turned to pages 13-17 of his presentation, "Impact on
Investors," related to the three options. Dr. van Meurs
explained that for the two examples with 40 percent tax credits,
the rate of return is significantly higher than for the HB 3004
variation. Page 14 discusses the $150-million-barrel case,
showing a significant drop in the rate of return even with the
same revenues to the state. Page 15 shows expected monetary
value (EMV), a main indicator of the attractiveness of
exploration, since it is the net present value at 10 percent,
adjusted for the geological risk. This shows "EMV 10" is much
lower without tax credits or within minor ones. The same is
shown on page 16. For a bigger field, the differences are less
because there is more value.
3:05:02 PM
DR. VAN MEURS explained how the government's revenues can be
equal and yet the rate of return and economics for the companies
can be so much better under one proposal than another. Page 17
shows no reduction of PPT if investors invest $1 million under
the HB 3004 variation, without tax credits. With a 40 percent
tax credit - or a 20 percent deduction and 20 percent credit
under the PPT - investors perceive that investment as a $600,000
expenditure because they'll receive $400,000 back from the state
in tax credits.
He addressed pages 18-34, "Fiscal Structure," noting page 18
shows the aforementioned is achieved by first giving investors a
tax savings when investing, and then taking more tax later on.
Dr. van Meurs pointed out that when giving tax credits,
governments first grab more revenues and then reward
reinvestment in that jurisdiction, rather than simply giving
what was intended in the first place.
3:09:16 PM
SENATOR BUNDE indicated he'd read this morning that the court of
appeals, in the Como case, found an Ohio tax scheme that
benefited a local business unconstitutional under the commerce
clause. Noting that proposals here involve tax credits, he
asked if those also could be found unconstitutional under that
clause, and whether Dr. van Meurs was familiar with that case.
DR. VAN MEURS replied he wasn't familiar with the case. He
suggested it is a constitutional legal question perhaps best
reserved for the lawyers. He added that the PPT proposal was
reviewed in depth by the attorney general's team. He surmised
the issue isn't at stake here.
3:10:33 PM
SENATOR ELTON referred to page 18 and prior pages of the
presentation that discuss internal rates of return. He asked:
Can't that be accomplished with a gross tax and then a
"clawback" provision, as discussed earlier with PPT? Doesn't
that also have the net effect of encouraging investment and
lowering the tax rate so there is a higher internal rate of
return?
DR. VAN MEURS answered yes, the "two-for-one" proposal - if that
is what Senator Elton is referring to - has the same effect
because it is a method of providing tax credits. What is
attractive to investors in Alaska that already have production
and are benefiting from the two-for-one proposal is this: They
get a tax credit on top of a tax credit under the PPT proposal,
which makes the rate of return even higher than the base PPT.
SENATOR ELTON interpreted this to mean the internal rate of
return can be increased for a company with a gross that applies
a clawback. The result would be the same kind of curves shown
in the earlier graphs.
DR. VAN MEURS agreed. He recalled that when Governor Knowles
originally requested review of the existing production tax, the
political guidance was to see what could be changed in the
current system, based on gross, to increase the rate of return.
Dr. van Meurs had proposed there could be work on gross as long
as these tax credits were included; the effect would be
identical to net in terms of investment. Referring to the
graphs on page 17 and previous to that, he said from an
investment-encouragement standpoint, a 40 percent tax credit is
what counts. Had HB 3004 included this credit on all capital
expenditures, its impact on the attractiveness for investment
and the incremental rate of return would have equaled the
PPT proposal.
CHAIR SEEKINS asked whether the difference between the PPT and
the clawback is that the latter is strictly on capital
expenditures (CAPEX) and not operating expenses.
DR. VAN MEURS replied yes. The 20 percent tax credit in the PPT
and the clawback only relate to capital expenditures. The cost
deductions that exist in order to arrive at net revenues apply
to both capital and operating expenditures. The difference
between his earlier proposal to Governor Knowles and the
proposal on the table now is this: Under the former concept,
there was no deduction for operating costs. From an investment
rate-of-return point of view, however, the numbers can be
tweaked so it comes out the same for a particular field.
3:15:14 PM
SENATOR DYSON recalled that the major thing that doesn't get
taken care of with a gross production tax is deductions for
"challenged" oil. He asked Dr. van Meurs to remind members why
using the traditional way for challenged-oil royalty relief is
suboptimal for the state.
DR. VAN MEURS opined that the Alaska royalty concept - that if a
field provides uneconomic under the agreed loyalty in the lease,
the commissioner can be petitioned for royalty relief - is
sound. It is common worldwide. Most governments realize a
royalty could make a field uneconomic. Thus there is a gray
area in which a government is interested in granting relief to
get the development. From an investor point of view, however,
it doesn't do very much.
SENATOR DYSON suggested it's unpredictable.
DR. VAN MEURS concurred. He said it is an essential component
of a royalty framework, but isn't a fundamental concept to
encourage investment.
3:18:53 PM
SENATOR DYSON referred to heavy oil on the North Slope and
asked: Do other jurisdictions allow asking for royalty relief
in advance of making the investment, in order to get the
assurance necessary?
DR. VAN MEURS noted his presentation would address this later.
Light oil clearly is on its way out. Many nations are
considering changing their fiscal structures to accommodate
heavy oil, and many jurisdictions have already done that. For
example, Alberta addressed its large reserves of heavy oil by
scrapping the royalty in favor of a profit-based system;
although called a royalty, it is equivalent to the PPT.
Governments have concluded that once they get to heavy oils,
gross systems don't work well. The costs aren't known. Thus
they go to a net system like Alberta's or else they predetermine
a lower royalty level, as Venezuela, Columbia and Saskatchewan
did. Some countries have a scale directly related to gravity.
SENATOR DYSON recalled hearing about the difficulty in defining
heavy oil and a mixture of heavy, light and medium oils in some
formations.
DR. VAN MEURS agreed, noting his presentation today would
address that. There is a big difference between Alberta and the
North Slope. Alberta's heavy oil is in a limited geographical
area, Cold Lake; thus it was easy for the government to design a
new fiscal system for that area.
CHAIR SEEKINS asked how many other countries deposit 25 percent
of the royalty into a permanent fund.
DR. VAN MEURS replied that some nations, including Norway and
Kuwait, have similar but not identical funds for future
generations.
CHAIR SEEKINS surmised a scheme reducing the royalty to
accommodate additional costs for heavy oil would have the same
effect on the permanent fund as on royalty revenue - reducing it
25 cents for every dollar. He suggested if a system could be
designed to look at operating expenses as a deduction, rather
than a royalty reduction, it would self-adjust as there are
technological improvements or higher costs for the challenged
oil, but it wouldn't shortchange the permanent fund in the end.
DR. VAN MEURS agreed. He said royalties are the perfect gross-
revenue concept. The PPT was designed to be highly flexible and
leave royalties alone. In an extreme condition, however, with
ample justification - and if there is a clear choice between no
production and some - then the DNR commissioner can step in and
lower the royalty. He noted a fund for future generations
happens particularly in nations with limited populations that
realize the need to set aside for the future when a large share
of wealth derives from oil and gas. He emphasized the need to
protect the royalty system, calling it the deep, long-term
future of the State of Alaska.
SENATOR WAGONER asked what keeps Alaska from coming up with a
separate tax structure for heavy oil.
3:27:33 PM
DR. VAN MEURS clarified that the problem with the North Slope is
that everything is mixed together in the same geographical area.
Additionally, there are shallow formations so cold that light
oil becomes as viscous as heavy oil. It isn't possible to make
separate arrangements based on groups of leases. Any lease
could produce any mixture of light and heavy crudes, even from
the same reservoirs. While a sliding scale could be
constructed, as he'd done in 2001, it doesn't have the same
guarantee for the state with respect to getting the maximum
benefit from the resource.
SENATOR WAGONER asked whether the primary cost will be capital
expenses or operating expenses when heavy-oil production begins
in earnest, and in what percentages.
DR. VAN MEURS recalled that when he'd realized Governor
Murkowski was willing to go beyond slight adjustments, he'd then
offered a far better proposal, a full-scale net-revenue basis.
That was the reason for developing the PPT. The reasoning goes
to the heart of Senator Wagoner's question. A scale based on
cash flow would be pie-in-the-sky, since nobody knows the costs
of heavy oil. It is far better to say the costs aren't known.
If costs are low under a net system, a lot is collected; if
costs are high, less is collected. That is the concept of net.
He further explained that a net system effectively deals with
future uncertainty and is far more stable than a gross system,
as other nations have discovered. Thus he'd made the
recommendation, and the governor had agreed to go forward with a
system in line with the international practice, with an eye
toward investment. Dr. van Meurs expressed pride that the PPT
proposal is now in front of the legislature.
He turned to pages 19-20, "International Framework" and
"Reinvestment or No Reinvestment." Dr. van Meurs emphasized
that taking more tax and then giving something back if a company
reinvests in the jurisdiction provides the same revenues, but
investors are happy because they perceive it as getting
40 percent of their money back. A company that doesn't reinvest
pays more tax.
He reported that all governments in the Organisation for
Economic Co-operation and Development (OECD) outside the U.S.
that have important oil and gas production have figured this
out, including Norway; Denmark; the Netherlands; the United
Kingdom; Australia; and Alberta, Newfoundland and the Northwest
Territories in Canada. Another 60 developing nations use a
concept related to profits. Dr. van Meurs cautioned that this
is the world Alaska is competing with, and in Alaska
reinvestment isn't rewarded now.
3:38:49 PM
DR. VAN MEURS explained why he'd strongly recommended a net
system to Governor Murkowski. Pages 23-30 of his presentation
show difficulties with a gross system with tax credits: 1) a
relatively short shelf life for gross formulas, 2) that gross-
based systems require definition of a field or unit to which the
system applies and 3) the heavy-oil provisions just discussed.
He addressed shelf life, noting Alaska's sound royalty-based
system provides half its revenues. If another gross-based
system is added, a very large amount would relate to gross. In
1989 there was great justification for the ELF formula. If
gross is added to gross, however, there is concern about small
marginal fields and highly profitable ones. The concern is how
to make the ELF more flexible. The ELF is based on technical
information, which Dr. van Meurs said changes quickly over time.
DR. VAN MEURS noted after ten years, by 2001, Alaska's ELF was
no longer appropriate. However, it took five more years before
there was enough political momentum to change it. A lot of
money was lost. After five or ten or fifteen years, gross
formulas must be changed because of rapid technological changes
in the oil industry. Dr. van Meurs said a net-based system is
much simpler. Other nations have found if there is a net-based
system and technology lowers the costs relative to assumptions,
deductions go down and there is more tax.
He turned to defining "field." Dr. van Meurs told members if a
gross system is to be flexible from field to field, there must
be a definition a field. While 20 years ago Alaska had well-
defined units and fields, for the North Slope today it's no
longer possible to come up with a clear definition. This is a
fundamental problem with a gross-based system.
He noted today's new investment opportunities are in shallow or
deeper reservoirs or extensions of reservoirs or satellite
fields, for example. While generating enormous amounts of new
reserves, they cannot be called "new fields." However, the
system is based on fields. This creates immense tension.
Although it can be done, Dr. van Meurs said there will be
constant struggle and lack of equilibrium among incremental
investment in something that is already a unit or field and
something that is a new field. Thus it is so much simpler to
junk all of this and base it on something that makes far more
sense - which all other nations are doing.
DR. VAN MEURS discussed heavy oil. Probably the biggest problem
of defining a gross-based system is what to do with heavy oil.
While more leniency is needed, there is no sound economic basis
for doing that. It is an immense problem because 5 billion
barrels of the new oil to be produced is heavy oil. If future
economics for heavy oil cannot be identified, how can a gross-
based system be designed for it? A net-based system
accommodates the situation: more is collected if technology
progresses and costs are low, but less is collected if
technology doesn't progress and costs are high. Thus Alberta is
using a net-based system for its Cold Lake oil deposits, for
instance, and Newfoundland and some nations are doing the same.
3:47:32 PM
DR. VAN MEURS offered conclusions, pages 30-31 of his
presentation. Alaska has progressed in its mature development
of the North Slope, after 30 years of development. Old rules no
longer apply. He urged thinking about how other nations deal
with similar situations. The North Slope no longer lends itself
to a gross-based system, even if there are significant tax
credits, as he'd originally proposed. While it can be done, it
isn't the best solution. Thus he'd recommended the PPT.
He said while governments everywhere worry about the serious
issue of cost control, he believes the issue is somewhat
overblown in Alaska, perhaps because Alaskans aren't yet really
familiar with net-based systems and feel the system will be
gamed. Dr. van Meurs acknowledged things will slip through in a
net-based system. He offered his experience in other countries,
but conveyed his firm belief that horrible conditions elsewhere
in the world don't apply in Alaska. He lauded the state for
having honest individuals who do a splendid job. There already
is auditing done, for example.
He turned to page 33, posing a situation in which the whole
industry puts in a fraudulent claims for 30 percent more costs
than actually occurred. Highlighting what that would require,
Dr. van Meurs said leases in Alaska are owned by different
companies. Auditors would quickly discover if one company were
charging double. To create 30 percent fraud, all the oil
companies would have to get together and agree to produce
thousands of fraudulent invoices, hoping the Department of
Revenue wouldn't notice, and then they'd have to claim
30 percent more in costs.
DR. VAN MEURS asked: What if they got away with it? At an
average cost of $6.00 a barrel, he pointed out, 30 percent would
be $1.80. They'd save 20 percent of that on cost deductions, or
$0.36. On half they'd also save the 20 percent tax credit,
another $0.18. Thus with massive fraud they'd save $0.54 a
barrel, whereas a barrel is now worth $30.00 to $60.00. He
questioned how serious a problem that would be; said that kind
of fraud doesn't occur; and suggested if the occasional oil
company slips something through, it will be caught by auditors.
He opined that there won't be statewide, massive fraud among all
the oil companies, which have to work together as working
partners on their leases.
3:55:21 PM
DR. VAN MEURS summarized, saying he believes the cost-control
problem is overblown. To be absolutely sure, however, when the
PPT law was designed he'd gone through the list of countries he
termed "total basket cases" for which he'd had to design
procedures, making a long list of nondeductible costs so that if
there is even a minor audit they can be picked out. All these
nondeductible costs are items where companies play games. Thus
he'd gone to his basket-case list and applied that scenario to
Alaska as if it were a basket case too - which it isn't. Dr.
van Meurs noted page 34 showed the list. It read:
Fiscal Structure
PPT and Cost Control
Nevertheless, Section 25 of the PPT bill provides for
a long list of non-deductible costs, including:
1. Depreciation, depletion, amortization
2. Financing charges and cost of raising equity
3. Acquisition costs of leases
4. Cost for arbitration, litigation
5. Partnership JV, and other organizational costs
6. Any expenditures in excess of fair market value
7. Expenditures to purchase another company or business
8. Certain abandonment costs
9. Losses and damages of oil discharges.
DR. VAN MEURS highlighted what is left: real costs for drilling
wells and putting in a facility or gathering lines, as well as
real operating costs. There is no overhead. Asserting all
loopholes are closed, Dr. van Meurs opined that this PPT bill
protects well against possible misuse of the net-revenue system.
While there would be misuse, as human nature dictates, it
wouldn't cause severe damage to Alaska. That is the experience
of countries that have done this successfully for 30 years.
He closed by saying he works in these other countries and is
absolutely convinced this will work in Alaska as well. Dr. van
Meurs expressed pleasure that the governor wanted to do more
than tinker with the existing ELF system - building Alaska for
the future and considering how the North Slope actually is
today, using the international experience to get the maximum
benefit for the state.
4:00:45 PM
SENATOR HOLLIS FRENCH, Alaska State Legislature, asked how many
oil-producing nations still collect on the gross.
DR. VAN MEURS replied this is an important point. He'd done a
survey of about 140 nations that are oil producers or potential
producers. Of those, approximately 100 have some type of
royalty like Alaska's. Since it is easy to collect, audit and
verify, a gross-based royalty concept - taking up to 20 percent
of gross in royalties - is immensely popular around the world.
The vast majority do that. However, the concept of "gross on
gross" is only in the U.S., as mentioned in earlier hearings.
If a production tax on gross using some formula is added to a
royalty, that combination doesn't exist in other nations. Thus
the concept of a severance concept is uniquely American.
SENATOR FRENCH asked whether nations with higher takes than
Alaska take it all just with royalty.
DR. VAN MEURS answered no; it is the opposite. With the
exception of Venezuela, which recently increased royalties to
30 percent, as well as Texas state lands offshore, nobody
charges a royalty higher than 20 percent of gross. The first
cut is always modest. The range worldwide is 10 to 20 percent.
Nations realize if too much is built on gross, it makes too many
fields uneconomic. Thus many nations start with a royalty, as
Alaska is doing - an excellent policy. A significant part of
the income is based on gross.
He highlighted the next step: Perhaps 120-126 of the 140
nations have corporate income tax; because Alaska is a state of
the United States, it is difficult to get a large corporate
income tax. Most nations put something in between royalties and
corporate income tax, always a profit-based system. Dr. van
Meurs explained that the economics of fields among the nations
vary too much to make a simplified formula. While the foregoing
encompasses the general rule, there are exceptions. Some
countries have done away with royalties altogether, for example,
including Norway and Great Britain, which use net completely.
SENATOR FRENCH recalled that one example cited to those who
advocate a net system is the leases at Kuparuk, which haven't
shown a profit after decades in operation, although this is the
second-largest oil field in North America. He asked why there
is such trouble with those leases.
DR. VAN MEURS suggested asking DNR, since he wasn't familiar
with the details of each lease; in fact, those are confidential.
He surmised one important factor is that oil prices only
recently increased significantly; netbacks at the North Slope
were very low until three years ago. If there is a profit
feature after a royalty, for example, on a field-by-field system
such as used for the net-profit-sharing leases, there could be a
period of three to five years during which nothing is collected.
4:06:52 PM
SENATOR FRENCH inquired about delayed maintenance on the North
Slope. He recalled BP recently had a flow line that was choked
with sand, developed a leak and will have to be replaced at a
high cost; there may be many similar situations on the North
Slope. He voiced concern about granting deductions for costs
that accumulated over many years through neglect. This could
add up to the 50 cents a barrel mentioned by Dr. van Meurs with
respect to a 30 percent overrun or inflation factor - perhaps
$400,000 a day for 800,000 barrels a day, or $100 million a
year. He asked for Dr. van Meurs' thoughts about finding a way
to not incentive such costs.
DR. VAN MEURS responded that there are already two protections
in the PPT bill proposal. First, losses and damages caused by
oil discharges, such as occurred with BP, aren't deductible
expenses. Second, an important provision is that if an asset is
replaced - an old compressor, for example - the sale of the old
one has to be credited against the cost. Thus the concept that
certain assets would be renewed or replaced is taken care of to
a degree in the bill.
He added that in every oil field which becomes mature and older
than 30 years, occasional equipment must be replaced. That's in
the interest of the nation because it means oil production will
continue safely and adequately. Dr. van Meurs said it could be
an important deduction in an oil field over the coming 20-30
years. Internationally, those are considered legitimate capital
costs, provided that if a replaced item can be sold or has a
salvage value, that is deducted.
SENATOR FRENCH questioned the value of an old flow line. He
said he expects the work to be done when it is needed, rather
than having it accumulate and suddenly generate a windfall with
respect to taxes.
DR. VAN MEURS replied that he wouldn't call it a windfall.
Internationally, what Senator French mentioned are really
maintenance capital expenditures. In making a forecast of the
economics of an oil field, typically these are about 2 percent
of the total capital expenditures spent in creating the field in
the first place. If someone invested $1 billion, after 10-20
years there could be an expectation of $20 million a year in
maintenance capital expenditures; that's true worldwide.
Governments sometimes insist on better practices, and oil fields
may have to be remodeled for environmental reasons. It could be
3 percent, or somewhat lower.
4:12:15 PM
SENATOR BEN STEVENS suggested the inclusion of a gas regime
would transform the North Slope from a mature stage into a
developing stage for both gas and oil.
DR. VAN MEURS agreed, noting what he means by "mature stage"
relates to only the traditional state leases with respect to oil
production. The Arctic National Wildlife Refuge (ANWR) would be
a whole new ballgame, as would NPR-A to a large degree. The gas
project, as explained by Roger Marks, will give North Slope oil
production an entirely new lease on life, generating a whole new
cycle of development, for these reasons: 1) operating costs can
be shared in many fields between oil and gas, so suddenly the
operating costs allocated to oil become less; 2) new gas fields
will have 50 barrels a day of associated condensates, providing
a whole new cycle of condensate production; and 3) in trying to
find new resources to fill a gas line, it is likely that new oil
fields, particularly in NPR-A, may be discovered.
SENATOR BEN STEVENS commented that while some working reservoirs
might be at a mature stage, in his mind the North Slope is still
in the development stage, if not the discovery stage. He then
asked for comments on a tax on gross for gas production
internationally, and how that might be structured. He surmised
the take would be high on the high side, but he recalled
Dr. van Meurs had said Canada has higher taxes on the high side
but no tax on the low side.
DR. VAN MEURS reiterated that gas development creates a whole
new cycle. The gas project, if the contract is approved, will
be underpinned for the first 15 years by two large gas fields:
Prudhoe Bay and Point Thomson, new fields from a gas
perspective. In this particular case, since the economics of
the fields are known, it was possible to identify the "7.25
percent of gross" in order to create a total package allowing
the state to take approximately 20 percent of the gas in kind.
He cautioned that 30 to 50 years in the future, however, if it's
in a mature stage, there must be far more care with systems
based on gross. There'll be the same situation as now for oil:
all kinds of different small gas pools, and an Alberta-style
situation wherein some pools are marginal or have low
productivity. The type of stranded-gas contract submitted today
wouldn't fit in such an environment; the system would need to be
based more on net. For the current case, however, because the
two gas fields are relatively economical, Dr. van Meurs said the
state can afford to have the royalty plus "another slice on the
gross" in order to create the total gas in kind.
4:19:48 PM
SENATOR BEN STEVENS expressed appreciation for that distinction.
He asked Dr. van Meurs whether his earlier testimony was that
other regions have a tax on gross, but it varies so there is no
tax when the price is low.
DR. VAN MEURS affirmed that. Recalling his previous discussion
before this committee, he said in principle there could be
progressivity for gas as well as oil with respect to price. But
while Canada has a progressive system on gas in the Mackenzie
Valley, for example, it views progressivity as removing the
government take if gas prices fall; that system is based on the
rate of return. At very low prices, the maximum the government
will collect is a 5 percent royalty - no severance tax, property
taxes or additional state income tax. If prices are higher, it
goes to a profit-sharing scenario. It's progressivity downward,
not upward.
He added that because there is so much stranded gas today around
the world, economic rules are different for gas and oil.
Progressivity for gas means less government take if prices are
low, rather than more government take if prices are higher.
There is too much competition around the world to get gas to
market, which puts governments that like to market large blocks
of gas in a weak bargaining position.
DR. VAN MEURS closed by giving his opinion that what is
currently in front of this legislature is the absolute optimal
package. It has the maximum on oil, which is where the
bargaining power is, since oil is running out and government
takes on oil are rising. He also mentioned a sensible package
on gas, saying the total results in maximum development. That
is exactly what is on the table today.
CHAIR SEEKINS thanked Dr. van Meurs and held SB 3001 and SB 3002
over.
The committee took an at-ease from 4:25:02 PM to 4:25:22 PM.
There being no further business to come before the committee,
Chair Seekins adjourned the Senate Special Committee on Natural
Gas Development meeting at 4:27:32 PM.
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