Legislature(2007 - 2008)SENATE FINANCE 532
04/24/2007 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB104 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 104 | TELECONFERENCED | |
| + | TELECONFERENCED |
MINUTES
SENATE FINANCE COMMITTEE
April 24, 2007
9:05 a.m.
CALL TO ORDER
Co-Chair Bert Stedman convened the meeting at approximately
9:05:53 AM.
PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Charlie Huggins, Vice Chair
Senator Kim Elton
Senator Joe Thomas
Senator Fred Dyson
Senator Donny Olson
Also Attending: MARCIA DAVIS, Deputy Commissioner, Department
of Revenue; ANTHONY SCOTT, Commercial Analysis, Division of Oil
and Gas, Department of Natural Resources;
Attending via Teleconference: There were no teleconference
participants.
SUMMARY INFORMATION
SB 104-NATURAL GAS PIPELINE PROJECT
The Committee heard a sectional analysis of the bill through
Section 43.90.130(6) added by Section 1 from the Department of
Revenue and the Department of Natural Resources. The bill was
held in Committee.
9:09:49 AM
CS FOR SENATE BILL NO. 104(JUD)
"An Act relating to the Alaska Gasline Inducement Act;
establishing the Alaska Gasline Inducement Act matching
contribution fund; providing for an Alaska Gasline
Inducement Act coordinator; making conforming amendments;
and providing for an effective date."
This was the second hearing for this bill in the Senate Finance
Committee.
9:10:23 AM
MARCIA DAVIS, Deputy Commissioner, Department of Revenue,
testified that she would provide a sectional analysis of the
Senate Judiciary Committee substitute, which has retained its
"key structures" through the committee process.
9:11:13 AM
Ms. Davis characterized the bill, also referred to as the Alaska
Gasline Inducement Act, or AGIA, as follows.
It's essentially government taking a soft touch. It's
government stepping in an looking at a situation that has
not moved on its own under normal market forces and for
whatever reason either because of the structure of the
ownership patterns at Prudhoe [Bay oil fields], the
structure of global gas markets or simply the time has not
come. But one thing that has come is the time for the State
of Alaska to do whatever it can do to move the gas and
ensure that the time for the revenue stream flowing from
that gas happens at the soonest moment feasible given
market conditions.
9:11:54 AM
Ms. Davis shared that this bill was designed to provide several
inducements for "two pieces" of a gas line. One of which would
induce construction and the other would ensure the success of
the natural gas pipeline by inducing resource owners to commit
gas to that pipeline.
9:12:20 AM
Chapter 90. Alaska Gasline Inducement Act.
Ms. Davis began detailing each section of Chapter 90, added to
AS 43 by Section 1 of the bill.
Article 1. Inducement to Construction of a Natural Gas
Pipeline in this State.
Section 43.90.010. Purpose. (page 1, line 9)
Ms. Davis asserted that the purpose of this legislation had not
changed during the committee process. It was designed to
facilitate commercialization of North Slope gas resources,
promote exploration and development of oil and gas reserves, and
as constitutionally mandated, maximize the benefit of that gas
resource to the people of Alaska, as well as encourage oil and
gas lessees to commit gas to that pipeline.
9:13:21 AM
Article 2. Alaska Gasline Inducement Act License. (page 2,
line 6)
Ms. Davis stated that this article would specifically establish
the inducement structure.
9:13:36 AM
Section 43.90.100. Gas project. (line 7)
Ms. Davis explained this language would provide for the grant of
an Alaska Gasline Inducement Act license to a party that applies
under the provisions of this chapter and meets the requirements
set out in the chapter.
9:13:47 AM
Ms. Davis noted an important addition in the language of
subsection (b). Federal law provides that a state could not
interfere with the construction of a pipeline that traverses
across state lines. This subsection is intended to assuage the
perception by some that no pipeline could be constructed without
the license.
9:14:34 AM
Co-Chair Stedman asked whether a party that unsuccessfully
applied for a license under AGIA would be precluded from
constructing its own pipeline.
Ms. Davis answered that it would not.
9:14:55 AM
Section 43.90.110. Natural gas pipeline project
construction inducement.
Ms. Davis highlighted the key inducement of a grant of up to
$500 million provided in two phases. The first portion could not
exceed 50 percent of the total grant award and would be granted
prior to open season. "Open season" pertains to the process in
which natural gas resources would be committed to the pipeline.
The provision of this phase of the grant had initially required
a mandated 50 percent matching contribution from the licensee.
The current version of the bill stipulates that the match would
be "up to 50 percent" with the exact percentage established by
the applicant in its proposal.
9:15:35 AM
Ms. Davis continued that after the open season had concluded,
the remaining portion of the grant funds would be awarded. The
grant would be calculated as an 80 percent match to the
applicant's contribution. The amount would be established by the
applicant in its proposal.
9:15:54 AM
Ms. Davis gave a "frame of reference" for the dollar amount. The
estimated cost to progress from the grant of the license to the
open season has varied from $50 to $80 million up to $400
million. The lower estimate was cited by a party that already
held a license and proposed to amend that license. The higher
estimates were provided by a producer and by an independent
pipeline company. The amount of the State contribution in the
first three years after the grant of the license, according to
these estimates, would be $40 million to $200 million. The
provisions of this bill would allow the applicant "up to 36
months" from the date the license was issued to initiate the
open season.
9:16:53 AM
Ms. Davis stated that after the open season, the remainder of
the cost associated with the process to obtain certification by
the Federal Energy Regulatory Commission (FERC), has been
estimated at up to $1 billion. The total State contribution
would be limited to $500 million and would be subject to the
amount proposed by the applicant.
9:17:45 AM
Senator Thomas returned to Section 43.90.100(b), noting that
nothing would preclude a party other than the winning applicant
from constructing a natural gas pipeline. He asked if this
language would provide that the party would be ineligible to
receive "special treatment" from the State in its efforts.
Ms. Davis clarified that this provision would not prohibit the
State from granting tax or royalty relief or other incentives.
However, doing so for a competing pipeline project would incur a
financial consequence to the State.
9:18:39 AM
Senator Thomas indicated he would further review this provision
later.
9:18:49 AM
Senator Elton understood the licensee would submit an
application to the Executive Branch for reimbursement of up to
$500 million. The Executive Branch would request an
appropriation from the Legislature in the same amount.
9:19:20 AM
Ms. Davis replied that Senator Elton correctly explained the
first step of the process. A provision of AGIA would provide for
a special fund established by the Legislature and from which
reimbursements would be paid. Therefore, the Legislature would
appropriate the funds, although not specific to each submission.
9:19:46 AM
Senator Elton asked if the expectation would be that the
Legislature would appropriate the entire $500 million to the
special fund at once or in smaller amounts over time.
Ms. Davis responded that the appropriations would be expected to
be made "piecemeal".
9:20:05 AM
Senator Huggins cited language from Section 43.90.110(1) on page
2, line 17, which read in part as follows.
"…state matching contributions in an amount not to exceed
$500,000,000, paid in total to the licensee over a five-
year period; the payment period may be extended by the
commissioners under an amendment or modification of the
project plan…"
Senator Huggins asked for examples of scenarios that would
justify an extension and whether a limit would be imposed on the
length of time an extension could be granted.
9:20:29 AM
Ms. Davis answered that the language of the bill stipulates no
"backstop date for the filing for the FERC certification
process". The Senate Judiciary Committee had expressed concern
that "reasonable and appropriate" circumstances could occur
during the period between issuance of the license and receipt of
FERC certification that could require more than five years. The
committee intended to avoid an applicant "behaving in an
economically irrational fashion" by incurring expenses earlier
than prudent for the purpose of qualifying for the State
reimbursement. Rather costs should be incurred "in a rational
way that makes sense for the process."
Ms. Davis informed that the bill contains a provision relating
to "when can the project plan, which is captured in the license,
be modified". She would explain this provision to allow for
modification in circumstances that would improve the net present
value to the State, where required by changes by the Alaska Oil
and Gas Conservation Commission (AOGCC) "gas off take rules",
and in situations "where the conditions were unexpected and out
of the control of the applicant".
9:22:46 AM
Ms. Davis noted the aforementioned conditions were the three for
which a deadline could be extended or modified.
9:22:57 AM
Senator Huggins requested additional insight on potential
conditions that would be beyond the control of the licensee.
9:23:11 AM
Ms. Davis gave the following response.
The pipeline company is going to do everything in its power
to develop the economics, the design, all of the
appropriate bone structure around their project so that
when they go to an open season and ask the market, the
shippers, to enter into a commitment to ship gas on their
line, they've given those shippers a good solid, but still
an estimate because the pipeline still hasn't been built,
such that shippers would come forward.
There will be two situations: one, they'll ship, and two,
they won't ship. If they chose not to ship it could be for
two reasons: one is that despite the best efforts of that
pipeline company, they have not given enough assurance to
that shipper that they've nailed the economics - that
they've properly handled the cost overruns, etc. In that
situation you'd be looking at a shipper who still hasn't
been convinced that that project is economic and that
they're willing to enter into that contractual commitment.
There's another situation where a shipper might not tender
their gas. That would be because their own personal
economics or personal politics might require them to not
tender the gas because they are looking doing something
else at a different timeframe or in a different setting.
In that situation, you've got a pipe company that has
essentially done everything reasonable - everything
appropriate that they need to do and there's really not
much more they can do on the front of proving up their
economics, proving up the case for their pipeline company,
if that gas is still being withheld.
In that instance, the FERC has stated under the Alaska
Natural Gas Act, that they consider this gas critical to
the nation, critical to its energy supplies and that they
would proceed notwithstanding the lack of a commitment of
that gas to that pipeline. However, it's a slightly
different process. It's perhaps a longer process and will
involve more congressional involvement. That's a situation
where we would envision that the Administration, as well as
the pipe company should hold firm - keep their feet on the
line, and move that project forward. But it might take a
longer period of time for them to get to that FERC
certification process. So we're trying to make sure that we
have given all the support we can to a pipeline company to
proceed in good faith and with good science and good
economics and when they do so, stick with them to get them
through that process. Since we're asking them in return to
commit that they will go through an open season and if it's
unsuccessful, progress onto a FERC certificate
notwithstanding that.
9:26:00 AM
Senator Huggins expressed that Ms. Davis' comments were
disconcerting because of previous discussions on the cost to
extend the project. An extension would "up the payment level to
80 percent in the period when we're extending the project",
which would be counterintuitive in that it would increase the
expenditure and the length of the project. He did not have a
solution to this risk factor.
9:26:47 AM
Ms. Davis noted a mitigating factor would be that the funds
reimbursed after the initial five-year time period would be
"later in time" and would incur a minor "time, value and money"
benefit. This benefit would not counterbalance Senator Huggins's
concerns.
9:27:17 AM
Co-Chair Hoffman asked if discussions about the funding source
of the $500 million grant had been held and whether the source
would be general funds, the Constitutional Budget Reserve (CBR)
fund, the Permanent Fund Earnings Reserve Account, or other
sources.
9:27:40 AM
Ms. Davis reported that no such discussions had yet been held on
this matter.
9:27:56 AM
Ms. Davis resumed her analysis of the sections of the bill,
noting that language of Section 43.90.110(1)(C) on page 2, line
31 through page 3, line 8, describes and defines the types of
expenses that would be eligible for reimbursement. The expenses
had been "carefully delineated" to identify "those that are
directly and reasonably related to obtaining a certificate or
amended certificate of public convenience and necessity".
Specifically excluded would be overhead costs, litigation costs,
assets, and work product that predated the issuance of the
license and civil or criminal penalties and fines.
9:28:45 AM
Co-Chair Stedman directed attention to Sec. 43.90.100(1)(B) on
line 26 through 30 that reads as follows.
(B) after the close of the first binding
open season, the state shall match the licensee's
qualified expenditures at a level specified in the
license; however, the state's matching contribution
may not be greater than 80 percent of the qualified
expenditures incurred after the close of the first
binding open season
Co-Chair Stedman questioned the use of "shall" versus "may",
posing that the State could "have a different opinion at that
time."
9:29:12 AM
Ms. Davis characterized this as the "promise" the State would
make to potential applicants that "this is the terms for which
we are holding out and asking you to make an offer to us to
build our pipeline." The intent is to induce an offer from a
party to commit its time and funds to build a pipeline. In
return, the State would match funds up to 50 percent based on
the proposal by the successful applicant. Originally the
language of this provision stipulated the match would be 50
percent.
9:30:21 AM
Ms. Davis explained that once the applicant has submitted an
offer, the Administration has reviewed it and the Legislature
has accepted it, the matching funds would be committed. This is
akin to a contractual agreement.
9:30:59 AM
Senator Thomas, referencing the qualified expenditures listed in
Section 43.90.110(1)(C), asked if certain litigation expenses
relating to disputes over the open season should be allowed.
9:31:30 AM
Ms. Davis responded that a determination was made that the State
funds would be better invested in matching contributions made
directly to the project, thus avoiding any debate over
qualifying expenditures. While some litigation costs could be
reasonably incurred by the licensee, delineating those from
other litigation costs could be difficult.
9:32:28 AM
Senator Dyson appreciated the notation of the changes made by
the committees that previously heard the bill. He requested the
testimony include comment as to whether the Palin Administration
supported the changes.
9:33:09 AM
Co-Chair Stedman announced he would direct the Administration to
prepare a comparison of the amendments to the bill made by the
Senate Resources Committee and the Senate Judiciary Committee.
9:33:51 AM
Senator Dyson repeated his request for the Administration's
position on the changes; especially those changes which the
Administration deemed "not helpful" to the intent of AGIA.
9:34:08 AM
Co-Chair Stedman remarked that the comparison could include a
column indicating the Administration's support or opposition to
the amendments.
9:34:15 AM
Senator Dyson surmised that the Co-Chair would not permit the
witnesses to provide this information in the present setting.
9:34:27 AM
Co-Chair Stedman stated that such comment would be allowed.
9:35:04 AM
Ms. Davis continued, pointing out that the second inducement the
State would provide to the licensee is listed in Section
43.90.110(2) on page 3, lines 9 and 10, and reads as follows.
(2) the benefit of an Alaska Gasline
Inducement Act coordinator who has the authority
prescribed in AS 43.90.250.
Ms. Davis explained the position that would be created to assist
the licensee. Concern had been expressed by industry
representatives that this benefit would act as a de facto
deterrent for other potential pipeline projects. If a competing
project did not have representation of this coordinator, the
concern was that the State could deny permits to the competitor.
9:37:06 AM
Senator Huggins voiced confidence that the Administration would
make every effort to accommodate any competing projects. He had
been told that the State pipeline coordinator position would be
"tailored" after the similar federal position.
Ms. Davis affirmed.
Senator Huggins pointed out however, that the federal pipeline
coordinator position was charged to assist with any pipeline
project, while the State position proposed in AGIA would be
directed to assist with only the project undertaken by the
successful applicant.
9:37:47 AM
Co-Chair Stedman requested the language pertinent to the federal
position for comparison purposes.
9:38:10 AM
Section 43.90.120. Request for applications for the
licensee. (page 3, lines 11 through 18)
Ms. Davis resumed analysis of the bill. This section would
direct commissioners to develop a request for applications (RFA)
as soon as possible after the effective date of the Act. The RFA
would be similar to the request for proposals (RFP) process
utilized for the awarding of other State contracts. She
disclosed, "In reality because of the concerns about mitigating
and eliminating delay, we're beginning that process know just to
ensure that we have an rfa ready to go as soon as possible."
Ms. Davis informed that the original language of this section
would have directed the commissioners to undertake this process
within 90 days of the effective date. However, legislative legal
counsel advised that unforeseen circumstances could arise making
the mandated deadline unattainable. To address this, the 90 day
timeframe was transferred to a different section of the bill
pertaining to "goal[s] or aspirational" benchmarks. The
intention that the process would be completed within 90 days
would be retained.
9:39:23 AM
Senator Elton asked if this change would be acceptable to the
Administration.
9:39:31 AM
Ms. Davis answered it would, and reemphasized the Administration
goal to complete the RFA process sooner than 90 days. The
Administration appreciated the "wisdom" and advice regarding
deadlines and unintended consequences.
9:39:51 AM
Section 43.90.130. Application requirements. (page 3, line
19)
Ms. Davis characterized this section as embedded with "the
State's must haves". She detailed the criteria.
9:40:48 AM
Ms. Davis stated that the language of subsection (1) would
provide for a deadline for submission of the RFA s.
9:40:58 AM
Ms. Davis noted subsection (2) would require the RFA to include
a detailed description of the project including the route,
receipt and delivery points, size and design capacity at those
points, the economic analysis, and a technical viability of the
project.
Ms. Davis directed attention to an amendment to the original
language of this section on page 4, lines 6 through 8.
Co-Chair Stedman interrupted to direct the witness to detail the
criteria individually.
Ms. Davis repeated that Section 43.90.130(1) would provide for
the deadline and Section 43.90.130(2) would provide for a
detailed description of the project and categorizes the
components into subparagraphs.
Ms. Davis stated that Section 43.90.130(2)(A) stipulated that
the detailed description must contain a proposed route for the
natural gas pipeline. Subparagraph (B) pertained to the receipt
and delivery points. Subparagraph (C) would require the RFA to
include an analysis demonstrating the project's economic and
technical viability.
Ms. Davis explained that Section 43.90.130(2)(D) listed the
economic and technically viability of the work plan, the
timeline and associated budget, including a description of how
the applicant would perform field work, environmental studies,
design and engineering, and how the applicant would implement
practices for controlling carbon emissions from natural gas
systems as established by the federal Environmental Protection
Agency.
9:41:56 AM
Ms. Davis pointed out that the provision relating to carbon
emissions was inserted into the bill by a Senate committee to
address concerns about future global warming. The project could
have carbon emission impacts and the State must be mindful of
the applicants' ability to minimize those impacts.
Ms. Davis continued outlining the provisions of subparagraph (D)
noting the rfa must include a description of how the applicant
would comply with State, federal and international laws.
Ms. Davis noted the further delineation of Section
43.90.130(2)(D) into two types of projects that would require
"special attention; special focus". The first, listed as (i) on
page 4, lines 11 through 16, addressed potential "Canadian
throughway issues, which would entail having the applicant
describe if the project does require transiting through Canada,
giving us specific details about the right-of-way situations or
capabilities and the regulatory issues involving Canada." The
second project type was listed as (ii) beginning on line 17,
"focuses on the specific details that relate to a liquefied
natural gas (LNG) project."
Ms. Davis stressed the following.
Keep in mind the AGIA process does not prejudge what type
of project can be submitted. It can be an all in-state line
for gas; it can be an in-state with an export for LNG
[liquefied natural gas]; it can be a combination of those -
one or both of those, with a gas line that would transit
through Canada into the Lower 48, or into just Canada. So
there's a wide range of projects that this bill has to back
up and make sure that its got language that covers and
enables commissioners to make a proper analysis.
9:43:46 AM
Ms. Davis next described Section 43.90.130(3) on page 5,
beginning on line 3, as the criteria that would require the
applicant to provide "date certains". Subparagraph (A) contains
"the one hard deadline that the AGIA bill imposes upon an
applicant" to conduct an open season no later than 36 months
after the date the license was issued.
9:44:19 AM
Co-Chair Stedman requested Ms. Davis elaborate on the 36 month
deadline and explain the difference between a binding open
season and "potentially an unsuccessful open season".
Ms. Davis answered as follows.
The process by which an applicant has an open season is
guided in good part by FERC. They set out specific
procedures for the manner in which an open season is to be
held.
An open season is simply a period of time that that the
pipeline company says, "I've put out this information,
here's the data; I would like to invite the market to come
forward and offer to ship on my pipeline." It's not a date;
it's not a single date, it's a process that has to last, I
believe, at least six months. And so you open a period of
time of six months in which you wait for the market and you
have dialog with the market. You encourage the market to
come forward. In that time period you will be offering up
what you believe are the likely tariffs; the likely
structures.
This is a period of time of negotiation for the pipeline
with its shippers. In this time period, it will either get
commitments from shippers that say "sure, sign me up for
the base rate, the rack rate", or they'll say "you know,
we're going to be doing a lot of business with you; we'd
like to ship for this period of time for this volume of
gas. We'd like to negotiate our own rate." That's a time
period when they can actually negotiate a rate as opposed
to take the FERC approved rack rate kind of structure.
9:45:59 AM
Ms. Davis continued.
This time period is the testing of the market. This is when
the pipeline company finds out if they've done their
homework and they've structured a project that will meet
the needs of that market. It's a process that lasts for up
to six months. Once the pipeline company has tested the
market and seen the response, either they figure out that
they didn't size the pipeline big enough, or they find out
that they got it just right, or they find out that they've
got more pipe then they've got gas being offered. That's
when they step back and they ask themselves "Do I believe
that my design is correct and that there's still more
market demand out there that I just haven't been able to
attract and I need to do more work to attract it. Or did I
size my pipe wrong and I need to downsize my pipe to match
what is in fact the real market demand."
It's a very fluid time period this open season. It's a give
and take process between the pipeline company and the
market and the dialog.
9:46:56 AM
Ms. Davis continued her explanation.
As a result of when the cutoff happens and when the
pipeline company says, "OK, I think I've got all the
response I'm going to get." The pipeline company takes that
information and then decides how they're going to proceed
from that point.
When we talk about an open season being successful or
unsuccessful, that's a little bit of a - it's not a useful
label because it really is sort of in the eye of the
beholder; in this case the eye of the pipeline company how
it wants to respond to the responses it got in its open
season.
9:47:39 AM
Ms. Davis concluded:
But obviously a pipeline company that's set up to have a
4.5 bcf [billion cubic feet] a day pipe and they've only
gotten shippers interested in about one billion cubic feet
of that space, they've got an issue. After they have that
open season, they'll need to figure out what the market
reasons were for why their design didn't match the market.
They'll have several ways to proceed from that point
depending upon what their analysis tells them about the
mismatch.
9:48:04 AM
Co-Chair Stedman asked the reason for the allowance of 36 months
from the date of issuance of the license to hold an open season
and why a time limit of 24 or 18 months had not been chosen. The
proposal to construct a natural gas pipeline from northern
Alaska had been "worked on extensively" for the past several
years and would not require "starting with a fresh idea into a
new basin".
9:48:42 AM
Ms. Davis deferred to the Department of Natural Resources.
9:48:54 AM
ANTHONY SCOTT, Commercial Analysis, Division of Oil and Gas,
Department of Natural Resources, testified to the question as
follows.
This is the only mandated date in the bill in terms of when
an entity must do something by a particular date. It was
important for us not to prejudge how an open season should
be conducted, or the level of data that would be assembled.
What we recognized was that 36 months gave essentially any
applicant, no matter who they were, two full field seasons
to assess, route, soils, whatever it is that they needed to
assess to be able to put together a credible project.
There are some potential applicants who may be able to move
to an open season more quickly, as Mr. Chairman you
recognized … because they have already done a tremendous
amount of work. Presumably that would work in their favor
in the application process because that goes to the issue,
hopefully, of timing and when we could expect first gas.
But again we didn't want to prejudge what an appropriate
approach would be to conducting an open season. This gives
enough time, two full field seasons; but we didn't want to
sort of prescribe and impose artificial limitations about
what could or should be done.
9:50:52 AM
Co-Chair Stedman deduced from the presentation made at the
previous hearing on this bill that a one year delay "at 5.5 as
far as the price of gas 1.8 billion - this could be a fairly
expensive extension all else being equal from 24 to 36 months."
9:51:16 AM
Mr. Scott agreed about the advantage of entities that had
already conducted "a fair amount of work" on the pipeline
project and that could move to an open season after only one
field season. The timing of the open season "sets up a process
that leads you to first gas in a reasonably defined period of
time" and "the earlier you start that process, the earlier you
get to first gas and indeed, improved net present value for the
State."
9:52:00 AM
Co-Chair Stedman again asked how the 36 month time limit was
determined and whether it was requested by any particular entity
or was the resulting recommendation of an economic analysis or
other comparisons.
9:52:23 AM
Mr. Scott responded that neither was the case. Rather, "the
desire was to permit enough time, given the timing of when this
bill would move forward, and then we would get applicants and a
license awarded, to ensure that we provided at least two field
seasons." "Having spent years in negotiation," the Department
was "quite sensitive to not wanting to tell people how they must
conduct their business and what an appropriate open season and
the preparatory work for that would be." The intention of
allowing for a competitive process and because delay on the
project would be detrimental to the State, evaluating
comparative bids on the basis of net present value would create
a competitive impetus to "move this forward more quickly."
9:53:24 AM
Senator Elton asked the reason to establish a 36 month "hard
deadline" rather than a requirement that either an open season
must conclude within 36 months or that it begin within 30
months.
Mr. Scott reiterated the intent to provide any applicant at
least two field seasons to undertake the efforts necessary to
conduct an open season. The open season process had been
mandated in federal legislation and is "fairly lengthy" and
would require approximately six months. It would include
presentation of an open season plan to the FERC, after which
FERC would have 30 days to approve the plan.
9:54:54 AM
Senator Elton asked if open seasons were ever extended by FERC.
9:55:12 AM
Mr. Scott replied that generally FERC did not have regulations
that address open seasons because the open seasons were usually
commercial practices held between two private parties. The
federal natural gas act was the only project to include FERC
regulation. The regulations require certain minimum periods of
time but do not specify maximum periods of time. If the State
did not mandate that the process by concluded by a certain date,
it would be possible that the process could start and then
continue for many years. This would not be preferable. The
intent is that a termination date be established.
9:56:15 AM
Senator Huggins requested an explanation of the rationale as to
why the deadline would not be 30 months or less. Although 36
months could be the best option, the reasons why alternative
time periods were not acceptable should be understood by the
Committee.
9:56:49 AM
Co-Chair Hoffman referred to the presentation given to the
Committee at the previous hearing on this bill, noting that one
of the "must have" criteria was to complete the pipeline sooner.
Under this provision, he asked if the applicants would be
questioned on how soon, within the 36 month deadline, the open
season would conclude. If so, he asked the priority that would
be given to applicants that demonstrate an ability to complete
this process in a shorter time period.
Ms. Davis affirmed that the "structure" of AGIA would require
the applicant to provide a date by which it would conclude the
open season. This date would be one factor considered in
determining the net present value to the State of the proposal.
Additionally, experts would be employed to judge the credibility
of the date provided by the applicant because the "likelihood of
success" would be another factor in determining the winning
applicant. A projected date could be deemed unrealistic based on
the amount of information and data collected by the applicant
and would "counter balance" the advantage of the earliness of
the date.
9:58:47 AM
Co-Chair Hoffman asked the value that would be given to an
application with an earlier completion date.
9:59:30 AM
Ms. Davis replied that the evaluation criteria are defined in a
separate section of the bill that would establish a formula
utilized to rate each application and determine the net present
value to the State. The projected date for completion of an open
season would be one factor considered. If all factors of two
applications were identical with the exception of this, the
application with the earlier completion date would be ranked
higher.
10:00:36 AM
Senator Thomas assumed consideration must have been given to the
impact of the timing of the inducement reimbursements on the
ability to complete the open season.
10:01:07 AM
Ms. Davis affirmed that the timing of State disbursements would
affect the net present value of the project to the State. The
determination of the net present value would be complex given
the multiple factors that are not only "stand alone important"
but also impact the other factors.
10:01:38 AM
Senator Thomas remarked upon the urgency of completing the
pipeline project. He would therefore consider the 36 month time
limit in relation to when and in what amounts reimbursements
were paid. Larger payments could be made sooner to "urge that
project along."
10:02:10 AM
Ms. Davis continued the sectional analysis, stating that Section
43.90.130.(3)(B) on page 5, lines 9 through 12, would require
the applicant to provide a date certain of the pre-filing for a
FERC certification. This process had been established by FERC to
"facilitate the ultimate FERC certification process" and
"focuses significantly on the environmental evaluations of the
project." This effort would assist in the streamlining of the
FERC certification process in the event an applicant partakes in
the pre-filing procedure. FERC currently does not require pre-
filing for a non-LNG project; however, this legislation would
request the applicant to participate. Participation would
"encourage quicker action".
10:03:23 AM
Ms. Davis explained that Section 43.90.130(3)(C) relates to the
actual application for the FERC certificate and would request
the AGIA applicant to propose a date certain in which an
application for FERC certification would be submitted. A
projected date of receipt of the FERC certificate is not
required because once the FERC process was underway an applicant
would not control the pace by which FERC would issue the
certificate.
10:04:05 AM
Co-Chair Stedman posed a scenario and made the following
request.
One of the potential exposures for time that the State
faces if we don't have as much success at open season we'd
like and we go to the FERC certificate and we match the 80
cents on the dollar and we go for FERC certificate without
enough FTs to construct whatever we're hoping to construct.
So can you bring back to the Committee how often that
process is done elsewhere; is this a common way large lines
are built, or large projects, or not, and what projects
have had failed open seasons, gone on to the driven on to
the FERC certificate, which ones were successful and non-
successful.
10:05:08 AM
Ms. Davis answered that she would provide the requested
information.
Ms. Davis next characterized the provisions of Section
43.90.130(4) on page 5, beginning on line 17, as the "analog" to
subparagraph (3); however "in a setting where the project is not
governed by FERC but rather Regulatory Commission of Alaska
[RCA], which means that the project would be an in-state
project." Subparagraph (A) includes "a parallel requirement of
concluding an open season within 36 months" and subparagraph (B)
includes a requirement that the AGIA license apply for the
certificate from the RCA by a date certain.
Ms. Davis explained that Section 43.90.130(5), on line 25
through 27, pertains to the commitment required of applicants to
assess market demand for additional pipeline capacity at least
once every two years through nonbinding solicitation. She
informed that once the design of the pipeline is completed and
open season has commenced, the licensee could express a
resistance to change the design despite a market offering a
large quantity of natural gas.
Ms. Davis asserted that the long term success of the Alaska
Natural Gas Pipeline would depend in part on expansion with new
gas from other fields to backfill declines in existing fields.
Therefore a "cycle of renewal of gas resources over time" would
be necessary. To accomplish this, "the explorationists need to
look ahead and be able to say 'OK in x years ahead, I will have
the opportunity to put my gas in a pipeline.'" The opportunity
to do this would depend on that pipeline company's willingness
to seek solicitations in a "fairly regular period" for interest
in expansion.
Ms. Davis relayed that criticism of this provision had been
voiced by industry representatives due to concerns that "in a
typical setting, when a pipeline company goes and solicits
interest in expansion, they do so in a fairly formal process."
10:07:52 AM
Mr. Scott further explained that the provisions of Section
43.90.130(5) and (6) "were designed to ensure that whoever owns
the pipeline will act like a pipeline company." Nonbinding open
seasons were regularly held and were "merely" solicitations of
interest. If sufficient interest existed to support economic
expansion, a pipeline company would later conduct a formal
binding open season. Subsection (5) would provide a mechanism in
which solicitations of some form would be acquired. This process
would not have to be expensive and would require no engineering
or design work.
Mr. Scott stated that if adequate interest for new capacity was
expressed, the provision of subsection (6) would require the
pipeline company would commit to expand the project in
"reasonable engineering increments and on commercially viable
terms."
10:09:36 AM
Co-Chair Stedman spoke of "considerable interest in this." He
stated, "Clearly this is a basin-opening project and it's in the
best interest of the State to open the basin up, have more
exploration and development in the Arctic along with the ability
to access the offshore issues, offshore gas."
Ms. Davis pointed out that subsection (5) was intended to allow
for a public non-binding solicitation or similar means. This
could be "a fairly loose process" and would not need to be
expensive.
Co-Chair Stedman identified two areas of concern; one of which
would be the impact of this clause on project design and
engineering and possibly construction of the pipeline itself
prior to the date of first gas. The second concern was the
"relative frequency of it". He could not argue that the process
should not occur, but asked how common such a two-year
assessment clause was imposed.
10:11:18 AM
Mr. Scott was unaware of any pipeline in the Lower 48 states
governed by a fixed schedule to conduct solicitation of demand
on a formal or informal basis. The Administration recognized
that the Alaska Natural Gas Pipeline project would be unique and
would probably not have competing projects. The likelihood that
the producer group could own the pipeline was significant and if
the producer group were solely concerned with generating
pipeline returns, this project would likely already be underway.
He did not challenge the producer's right to be interested in
returns in addition to those generated from a pipeline; however
the producer groups were not "geared towards the steady
relatively modest returns that pipeline companies enjoy."
Mr. Scott stated that the two year schedule would be "something
new". If the pipeline entity "engaged in a process which is
common in Canada" the outcome would be in the State's best
interest. Tariffs in Canada have a "cueing system" in which
interests expressed in shipping through a pipeline are noted and
at the point sufficient interest has been expressed to support
expansion, the interests are granted on a "first come first
served" basis.
10:14:08 AM
Mr. Scott emphasized that solicitation must be periodic to
support the robust exploration and development necessary for
success.
Co-Chair Stedman asked if the two-year requirement was
determined as a result of economic modeling or other analysis.
Mr. Scott answered it was not. Recognition was given that the
time period must be "sufficiently long" to ensure that the
process would be "meaningful", and also a "short enough period"
to provide those interested in exploration and development of
hydrocarbons with "reasonable predictability" of when those
efforts could be commercialized. If the Committee deemed that
the exact amount of time should be different, he would not
oppose an amendment to the subsection.
10:15:33 AM
Co-Chair Stedman asked whether an analysis had been conducted on
when the smaller exploration and development companies would
have capacity of gas in sufficient amounts to participate in the
pipeline.
10:15:42 AM
Mr. Scott characterized this as "a chicken and egg problem". The
date certain for the open season is important to "get this
process moving" and provide increased predictability for those
parties to begin to expend funds for exploration and "prove up"
the anticipated reserves. "Explorer companies" would unlikely be
able to prove up hydrocarbons in time to participate in the
initial open season. This is one reason for the importance to
continue the solicitation process past the open season.
10:17:11 AM
Co-Chair Stedman, qualifying his limited expertise in oil and
gas issues, commented and posed questions as follows.
When we do this line; and maybe it has initial capacity of
4.5 pcf, maybe it's expandable to six, some ballpark
numbers that seem to come up quite a bit in the analysis
and we can assume that - do that type of volume or run a
line down the continent into Canada. Clearly there's an
interest in the State in seeing the basin opened up and we
get more players up there; we have more exploration and
expansion and we have the ability, like you've just
mentioned for these newer applicants that have
substantially less volumes of gas to be able to enter into
a gasline and sell their product. But we also have, I
think, roughly 52 or something right over 50 percent of the
potential of reserve capacity laying offshore where the
State of Alaska would not get as much economic activity off
of it as we do on the North Slope.
What kind of analysis or process - or has there been
anything done on that particular issue to see what impact
that may have in squeezing out these smaller companies on
shore that we're trying to see expand so they one, don't
have the ability to access … feeder lines … there's another
term and I can't remember it right now, to feed into the
[indiscernible] and then out and down the line.
There's also the issue of just capacity in the line. Before
you can get to that point you gotta get it to it. So can
you enlighten me a little bit on that and the Committee on
the potential risk that Alaska may be facing in the
potential squeeze out that we may face in the offshore
federal - I'm assuming that the folks offshore are gonna
want to use that gasline to ship their product.
10:19:30 AM
Mr. Scott made the same assumption, and acknowledged that the
relative pace of different developments was unknown. "Which gas
will come when" could not be determined at this time and was
subject to different corporate strategies which the State was
not privy to.
Mr. Scott spoke to additional "must haves" provided for
elsewhere in the bill, and discussed at a later hearing, as
follows.
One of the reasons on balance why we strongly believe that
the rolled in rate provisions are in the State's best
interest is because it is not at all - it is entirely
possible that offshore gas could come in and fill the
relatively inexpensive expansion capacity first. In that
event without rolled in rates, gas from State lands might
have to wait 15 or more years until Prudhoe Bay starts
coming off decline before there's adequate capacity at an
economic rate to get into the pipeline. So given the
uncertainties on balance, we think it is clearly in the
State's interest to have a level playing field for all gas
across the board.
In addition, … the rolled in rates provision in AGIA -
there's no question that because it creates a level playing
field, it opens potentially opportunities for offshore gas
to come into the project. It's certainly in the federal
government's interest. That will be helpful as we move
forward in this process. It will also be helpful in the
State's effort to try to obtain a royalty share from the
OCS gas, which is more than six miles offshore, which is
something which is of some interest now. People are working
on that and I think it will improve our position actually
as a State to obtaining that kind of share. Now, whether we
will or not, I don't know.
10:22:15 AM
Co-Chair Stedman directed the witness to provide a brief
synopsis of the reason for concern about "offshore gas from a
revenue perspective". He remarked, "All gas is not equal to the
State treasury."
10:22:35 AM
Mr. Scott responded that generally the State's royalty share
from resources developed on State-owned land is 12.5 percent or
one-eighth of the value. On federally owned lands located in the
state, the State receives one-half of the federal government's
12.5 percent royalty. The State receives a higher revenue for
developments from the greater Prudhoe Bay are, the Foothills,
Point Thompson, etc., than from the National Petroleum Reserve-
Alaska (NPR-A). The State typically receives approximately one-
quarter of the federal royalty rate from gas produced within
three to six miles offshore. Therefore, the State would prefer
that the natural gas pipeline transport gas from NPR-A versus
gas developed three to six miles offshore. The State currently
receives no royalty share from developments located more than
six miles offshore, known as the real Outer Continental Shelf.
10:24:50 AM
Co-Chair Stedman summarized the issue that monetarily all gas is
not equal to the State. The amount of revenue generated for the
Alaska Permanent Fund would be impacted significantly depending
on the location the gas was developed. The best scenario would
be that all the gas transported through the natural gas pipeline
would be developed from State-owned lands.
Co-Chair Stedman requested a summary of the expected volumes,
acknowledging the significant subjectivity.
10:25:56 AM
Senator Dyson realized that a proposal from the producers that
had the capacity to commit gas to the pipeline would be
"attractive". However, he expressed concern about a proposal
from a producer whose actual goal would be to continue to
maximize oil production and generate profits from the Trans-
Alaska Pipeline System (TAPS), and/or control the reservoir
basin, and/or control access to the natural gas pipeline. If
such a proposal were received he asked how the different goals
would be evaluated.
10:27:29 AM
Ms. Davis responded that the applications would represent
"hugely expensive commitments by companies" and would not be
submitted with the expectation that if accepted, the company
would "walk away". She predicted that because of the amount of
funds involved in preparing the applications, the motives would
not be disingenuous.
10:28:01 AM
Ms. Davis expected that the applications would be factual, would
have credibility and would detail the proposed plan. She did not
expect the applicants to "opine the pace of the gas off take".
Rather, the application "is about building a pipeline." The
Administration must conduct independent forecasting of the gas
flow.
10:29:20 AM
Ms. Davis made the following statement.
The design of AGIA has built in from the get-go, tools that
enable or ensure that that basin is not locked up. We
recognize that once you've given a license to a group of
people to build a pipeline and they're off and running,
that's their pipeline. We as a state have certain
regulatory rights, but that is their business; that is
their pipeline.
Our ability to tell them what to do or what not to do is
limited by whatever the appropriate jurisdiction rights are
through the RCA or the powers and authorities of FERC. So
there are agencies out there designed to ensure that fair
competition happens on that pipeline, that appropriate
rates and tariffs are being charged, and that the access
rights are being managed.
10:30:17 AM
Ms. Davis qualified:
With that said, in AGIA, looking ahead and anticipating
what could go wrong, that is why we have certain must haves
in the AGIA. A commitment by whoever that pipeline
applicant is, that they will look around every two years
and look to see if there's expansion opportunities and if
there is appropriate expansion that they will do so.
Finally, … is how the cost of that expansion will be borne
by the shippers and the pipeline company.
We've also go a few other must haves we haven't gotten to,
which is the debt equity structure for rate purposes. We
have some elements that we're going to hardwire from the
beginning that will protect the State's interests without
going overboard.
But as far as being concerned whether or not a producer-
owned pipeline is going to be damped - its economics
dampened because of concern about what they're doing with
the oil - we have to remind ourselves we have a stake in
the oil as well as a state. We benefit from oil production
as well and from the continuing flow of oil through TAPS.
One must hope that we've got good alignment - the State's
economics with the producer's economics subject to a couple
elements that we've put into AGIA that ensure fair play.
10:31:37 AM
Senator Dyson then expressed concern that the State did not have
adequate reservoir information about the optimum gas off-take
rate that maintains the oil production and that the producers
did have this knowledge. He asked if the State possessed the
ability to evaluate the maximum gas off-take rate proposed in an
application.
10:32:23 AM
Ms. Davis suggested the Committee address this issue as an
independent topic, given its importance. The AOGCC agency is
vested with the responsibility of managing the gas off-take rate
and has currently undertaken this in conjunction with the
producers. The producers developed reservoir data, which the
State possessed. However, the State did not posses the computer
model that provides conclusions of impacts on the reservoir.
This has been made available to the AOGCC under confidentiality
provisions. As an interested and involved party, the Department
of Natural Resources would likely have access to the information
as well for the purpose of evaluating an AGIA application. She
questioned whether a third party would have similar access.
ADJOURNMENT
Co-Chair Bert Stedman adjourned the meeting at 10:33:42 AM
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