Legislature(2009 - 2010)BUTROVICH 205
03/17/2010 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Overview: Sb 143-railbelt Energy & Transmission Corp. | |
| SB301 | |
| Update: Agia Regulations by the Dnr | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| + | TELECONFERENCED | ||
| + | TELECONFERENCED | ||
| + | TELECONFERENCED | ||
| = | SB 301 | ||
ALASKA STATE LEGISLATURE
JOINT MEETING
SENATE RESOURCES STANDING COMMITTEE
SENATE SPECIAL COMMITTEE ON ENERGY
March 17, 2010
3:39 p.m.
MEMBERS PRESENT
SENATE RESOURCES
Senator Lesil McGuire, Co-Chair
Senator Bill Wielechowski, Co-Chair
Senator Charlie Huggins, Vice Chair
Senator Hollis French
Senator Bert Stedman
Senator Gary Stevens
Senator Thomas Wagoner
SENATE SPECIAL COMMITTEE ON ENERGY
Senator Lesil McGuire, Chair
Senator Bert Stedman
Senator Bill Wielechowski
MEMBERS ABSENT
SENATE RESOURCES
All members present
SENATE SPECIAL COMMITTEE ON ENERGY
Senator Lyman Hoffman
Senator Albert Kookesh
COMMITTEE CALENDAR
OVERVIEW: SB 143 - RAILBELT ENERGY & TRANSMISSION CORP
- HEARD
SENATE BILL NO. 301
"An Act relating to the power project fund; authorizing the
Alaska Energy Authority to charge and collect fees relating to
the power project fund; authorizing the Alaska Energy Authority
to sell and authorizing the Alaska Industrial Development and
Export Authority to purchase loans of the power project fund;
providing legislative approval for the sale and purchase of
loans of the power project fund under the memorandum of
understanding dated February 17, 2010; and providing for an
effective date."
- MOVED SB 301 OUT OF COMMITTEE
AGIA Regulations presented by the Department of Natural
Resources
- HEARD
PREVIOUS COMMITTEE ACTION
BILL: SB 301
SHORT TITLE: POWER PROJECT FUND
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
02/26/10 (S) READ THE FIRST TIME - REFERRALS
02/26/10 (S) RES, FIN
03/15/10 (S) RES AT 3:30 PM BUTROVICH 205
03/15/10 (S) Heard & Held
03/15/10 (S) MINUTE(RES)
03/17/10 (S) RES AT 3:30 PM BUTROVICH 205
WITNESS REGISTER
JAMES STRANDBERG, P.E., Project Manager
Alaska Energy Authority (AEA)
Anchorage, AK
POSITION STATEMENT: Supported SB 143.
ANTHONY SCOTT, Commercial Analyst
Division of Oil and Gas
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Presented AGIA regulations for the DNR.
MARTY RUTHERFORD, Deputy Commissioner
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Presented AGIA regulations for the DNR.
FRED HAGEMEYER
Black & Veatch, Corporation consultant
POSITION STATEMENT: Presented AGIA regulations for the DNR.
DEEPA PODUVAL
Black & Veatch consultant
POSITION STATEMENT: Presented AGIA regulations for the DNR.
ACTION NARRATIVE
3:39:38 PM
CO-CHAIR WIELECHOWSKI called the joint meeting of the Senate
Special Committee on Energy and the Senate Resources Standing
Committee to order at 3:39 p.m. Present at the call to order
were Senators Huggins, Stedman, Wagoner, Stevens, French,
McGuire, and Wielechowski.
^Overview: SB 143-RAILBELT ENERGY & TRANSMISSION CORP.
CO-CHAIR WIELECHOWSKI announced the first order of business
would be an overview of SB 143, also known as the GRETC bill
(Greater Railbelt Energy Transmission Corporation).
3:40:33 PM
JAMES STRANDBERG, P.E., Project Manager, Alaska Energy Authority
(AEA), said he had 11 power point slides that he hoped to use to
summarize the work the administration in cooperation with the
Railbelt utilities has done to date with the Railbelt G&T
(generation & transmission) restructuring effort and what the
new corporation is all about including its initial tasks -
should this bill pass.
He said last year he appeared before them with a very different
GRETC bill. At the end of that session the bill was held in this
committee at the request of the Railbelt utilities that wanted
to take a year and involve all the boards of directors for the
utilities in a task force to make the plan more responsive to
their needs. They came up with a committee substitute (CS) to SB
143 that has major support within this utility group. His
agency, the AEA, working with the Governor's office participated
in the majority of these task force meetings and acted as both
advisor and observer as the work on the bill progressed through
the summer. The Attorney General's Office provided a
representative as well to assist in drafting changes to the
legislation. They are awaiting the CS from the drafters.
He said the fiscal note will be reduced generally because they
have taken a hard look at the requirements for forming the
business and with the new framework there is a lesser fiscal
requirement. That is also forthcoming.
MR. STRANDBERG said that AEA accomplished the REGA Study to
understand the economics of regional G&T organizations, and that
study found that forming a GRETC-like company could save
ratepayers significant money through reduced rates over the long
term. AEA also completed a regional plan for future generation
transmission projects (RIRP) in the late fall, which indicated
several things that add to the urgency of forming a regional
entity such as GRETC. First this study defined critical near
term projects that a unified G&T company should take on from
critical fuel supply projects to near term transmission projects
to needed generation additions. It also identified a critical
capital shortfall where the cumulative capital needs for the
region are much larger than the abilities of the Railbelt
utilities to raise capital for projects defined in the RIRP.
This plan concluded that a GRETC or GRETC-like unifying
organization with state financial backing is the best approach
to achieve a future of reliable and affordable electric service.
It would save the ratepayers a lot of money over the long run
and forming that entity will give them the ability to meet the
capital needs of the future. Without that they will have a very
hard time raising money.
3:46:13 PM
He said he would next explain how the CS is different from the
original bill. He developed four topics in his summary: the
governance of the new company, the powers of the corporation,
external controls for the corporate activities and a discussion
of the initial tasks for GRETC.
The key points of the Board of Directors make up are:
· The corporation is a private not-for-profit entity (not a
state corporation).
· Each of the six Railbelt utilities regardless of size,
generating capacity or transmission line ownership, will
have two board members and two votes.
· GRETC has 6 public utility members and 12 board members; it
has one public member that is appointed by the Governor
from a list of three candidates supplied by the public
utility members. Public utility members do not have terms
of service, but the public member has a four-year term. The
board will be required to designate a chief executive
officer.
3:47:40 PM
Types of business GRETC can undertake:
· Providing wholesale power to its Railbelt customers (one of
the distribution utilities that would buy wholesale power.)
No retail customer relationship.
· Providing wholesale power is at the center of the
corporation's purpose and GRETC can undertake a
considerable number of tasks to generate and sell its
wholesale power that are allowed under the new language in
the bill.
3:48:27 PM
MR. STRANDBERG said GRETC is now a voluntary organization
similar to the JAA effort that was made several years ago, but
there are significant differences in approach now (slide 8).
CO-CHAIR WIELECHOWSKI asked why it is in the best interest of
consumers to have an all volunteer corporation.
MR. STRANDBERG answered to get to the goal of becoming a unified
operation their studies have indicated companies need
significant flexibility to make mid-term agreements so that two
utilities can have agreements but still participate in GRETC.
They believe through state funding they will have the ability to
channel the organization more towards the unified organization.
Extensive conversations with the utilities on these matters have
revealed an understanding that they need the flexibility now to
really take up the issues in the Railbelt, as well as a need to
focus over the long run into a tighter integration.
3:52:19 PM
MR. STRANDBERG said that GRETC is now much more flexible so
utilities can act to meet the future wholesale power needs of
their regions. One point is that utilities under this statute
really can undertake their own projects, approach GRETC for
power supply or do any number of arrangements for providing
wholesale power. A critical difference is that the earlier
bill's intent was that the company would evolve towards being an
all-requirements provider for wholesale power in the Railbelt.
That language has been left out of the CS that rather provides
the flexibility to make different arrangements.
Another difference is that GRETC now has the Railbelt Integrated
Resource Plan (RIRP), last year it didn't. Another critical
difference is that four utilities now must agree to join GRETC
before it can actually form.
SENATOR WAGONER asked if Homer Electric were to join this
organization, would its administration would have to go to the
annual meeting.
MR. STRANDBERG answered yes; the commitment would have to be
approved by their board.
SENATOR WAGONER said "Good luck," because he knows the politics
of the situation in his area.
MR. STRANDBERG said participating with boards' members has been
a very interesting and positive process over the past year. This
flexible platform is what all the groups as a whole saw would
allow them to get through their board processes and really begin
unifying over the long haul.
CO-CHAIR WIELECHOWSKI said he understood that all the utilities
support the CS.
MR. STRANDBERG said that is correct.
3:55:05 PM
He went to the External Controls in slide 9 saying a lot of
people have talked about rate regulation and the RCA issues. AEA
sees a definite need for oversight for consumer protection as
well as financial oversight to make sure the company is managing
money correctly, particularly if the state is going to back it
in some way. The third thing is to make sure the corporation is
actually doing its job.
The significant protections in the CS include: RCA economic rate
regulations which would sunset at the end of five years unless
the legislature took further action. Also included is a
requirement for a management audit done in accordance with the
National Association of Regulatory Utility Commissioners (NARUC)
standards.
3:56:59 PM
The near term tasks for GRETC (slide 10) are: forming the
company, getting the legal documentation together, and hitting
the ground running and actually starting the work. AEA has
accomplished the RIRP which is being provided to the utility for
GRETC for its consideration as it starts up its operations. The
plan has a priority list of projects, business functions and
contractual agreements that need to be accomplished. The AEA has
spent a lot of time over the last three years working with the
utilities with this plan, and clearly utilities take issue with
things like committed units. So, their expectation and hope is
that utilities will take the plan to heart.
Finally, the CS has the requirements to develop a capital
improvements plan and a financial management plan. Last, there
is a critical need to begin generation of transmission projects
in the Railbelt.
3:59:02 PM
SENATOR HUGGINS said he implied phases, but he didn't see that
broken down anywhere and asked if he had that somewhere. He
thought Mr. Strandberg was expecting this to change over time;
and that is implied in the sense that the RCA goes away at the
end of year five.
MR. STRANDBERG said the first five years will be very critical.
They need to induce the utilities to provide their board members
to come to the table and actually meet and create bylaws. They
will have to hire a CEO, and certainly, if there are major
projects and the utilities actually come to the table and begin
to do major projects with this company and the state begins to
pour money into that, they are going to need to get the external
controls going right away. A major amount of oversight is
necessary in these formation phases of the company and likely
there will be a need for agency involvement "to make sure public
benefit flows."
SENATOR HUGGINS said he had discussed four big debate points so
far and asked if any are remaining.
MR. STRANDBERG said the RCA was a major sticking point.
Utilities wanted to be able to continue making near term
arrangements for power. There was concern that if utility
operations were consolidated, one group of ratepayers could end
up paying more when another group was paying less. There was
concern that the evolution to an all requirements provider was
too constraining and it didn't really reflect some of the
arrangements that would be need to be made in the near term.
SENATOR HUGGINS said it appears the business of being able to
develop projects outside of GRETC by one of the members is a
fracture waiting to happen.
MR. STRANDBERG said that is always a possibility. If all the
utilities can't see an economic incentive to unified operations
under this arrangement it is likely that bilateral contracts
will continue. This corporation will be a success if the
utilities can see economically that it's to their benefit to
unify.
CO-CHAIR WIELECHOWSKI said it's an interesting balance they are
trying to achieve. Finding no further questions he ended the
Senate Energy portion of the hearing and announced an at ease
from 4:04-4:05 p.m.
SB 301-POWER PROJECT FUND
4:05:13 PM
CO-CHAIR WIELECHOWSKI called the Senate Resources portion of the
meeting to order at 4:05 p.m. He announced SB 301 to be up for
consideration saying it's a good bill and he had held it over to
give members the opportunity to review it over the weekend.
CO-CHAIR MCGUIRE moved to report SB 301 from committee with
individual recommendations and attached zero fiscal note(s).
There were no objections and it was so ordered.
4:07:40 PM
at ease (projector difficulties)
4:08:49 PM
^Update: AGIA Regulations by the DNR
CO-CHAIR WIELECHOWSKI called the meeting back to order at 4:08
p.m. and said the next order of business would be an update on
AGIA regulations by the DNR.
ANTHONY SCOTT, Division of Oil and Gas, Department of Natural
Resources (DNR), said the first part of the presentation is the
valuation principles of natural gas. He would then step through
an example of how they would actually value royalty gas under
the regulations - a little more complicated process than what
they saw last week with the Department of Revenue (DOR). He
would also talk a little bit about the RIV/RIK switching problem
for the state's producers under the lease and the solution they
are proposing in the regs. Finally, Deepa Poduval, Black &
Veatch consultant, will give them a sense of the range of values
that are provided to the qualifying lessees (producers) who
choose to amend their leases under the regs.
MR. SCOTT said that the public comment period would close on
March 22, so he has to be sensitive to honoring that process in
treating everyone fairly.
4:09:37 PM
He said that gas is complicated because how it will be valued
has to be clarified and then existing lease terms will have to
be modified to eliminate initial shipper exposure associated
with the cost of transportation on the mainline. An important
difference in these regulations compared to the DOR regulations
is that if a lessee qualifies, he may chose to amend his leases
and have his gas valued under these regulations. If he doesn't
like this framework, he doesn't have to have his gas valued in
this way. This is not something they can impose on lessees.
Similarly, they cannot impose the royalty switching provisions
on lessees; that is something they have to elect. They can elect
the valuation provision, the switching provision or both.
CO-CHAIR WIELECHOWSKI asked him to describe a lessee who
qualifies for royalty inducement.
MR. SCOTT replied a lessee must commit to acquire firm
transportation (FT) in the initial open season of the AGIA
licensed project to have his gas valued under these regulations.
The qualification language is exactly the same to get in the
door between both DOR and DNR.
4:14:03 PM
He said Valuation regulations (slide 4) must: minimize
retroactive adjustments in royalty value, establish fair market
value (FMV) based on reliable trade publications, allow actual
and reasonable deductions for transportation and processing,
allow reasonable share of unused capacity. So if an initial
shipper acquires capacity and he doesn't have enough production
to fully fill it the state would pick up a reasonable share of
that empty capacity and allow deductions under the 1980 royalty
settlement agreement.
MR. SCOTT said crafting regulations to meet all these
requirements is not as easy as they first thought. There are
complications like trying to protect the state and the lessee
while minimizing retroactive adjustments while first gas is 10
years in the future. So they came up with basing royalty value
on reliable trade publications as opposed to looking to actual
sales. Trade publications are public; you can look them up and
know what your royalty value will be. However where the sales
are occurring can't be traced; so there is uncertainty about
exactly where gas was marketed and how it should be valued given
they can't be sure what they might have received for it and what
they might have received for it may come apart, importantly,
from what the trade publications are.
4:16:03 PM
He said that allowing reasonable and actual deductions for
transportation and processing is quite a complication. One of
the reasons is because it means they can't simply deem one price
as the basis for determining all value by assuming all the gas
will go to the Alberta (ACCO) market, for instance. The problem
is that Alaska gas may never enter into the ACCO market, but may
interconnect with, for example, the Alliance pipeline and move
on into Chicago. Because the statute says that you get your
actual and reasonable cost of transportation, the lessee gets to
deduct their actual and reasonable cost of transportation to
Chicago. So, you wouldn't want to value gas in Albert but allow
a transportation deduction all the way to Chicago.
Allowing a reasonable share of unused capacity? Define standards
for what is reasonable, he said. They have done that in what
they think is a fair manner, but there were a lot of things to
sort through to get there.
4:16:50 PM
MR. SCOTT said gas markets are inherently more complicated in
terms of valuing ANS hydrocarbons than oil, which is relatively
straight forward. It gets produced on the North Slope, it goes
down TAPS, it's loaded on to tankers that are dedicated to the
ANS trade, and they go to refineries on the West Coast. You know
where the oil is going to a considerably high degree of
certainty. And you know where your markets are.
In the case of gas that's not true. First of all they don't know
exactly what the infrastructure will end up being. They don't
know what will get built. So, clearly they don't know exactly
where it will go - not to mention that first gas is 10 years
out. Even then, gas may directly flow from this project into
Alberta, into Sumas, Washington, and go down the West Coast
pipeline and bypass the ACCO market. ANS gas may bypass the
Alberta market and go into Chicago. Further they have to
recognize that individual molecules of ANS gas may be consumed
in Oregon or New York City, because North America has an
interconnected pipeline grid where molecules are comingled. So,
you have to come up with standards and rules about how you're
going to cut that process off for valuation while also allowing
actual and reasonable costs.
MR. SCOTT said that meanwhile the gas business is dynamic.
Twenty-five years ago natural gas prices were regulated at the
wellhead. The transportation infrastructure was regulated quite
differently. The markets were dominated by large transmission
pipelines that purchased the gas at the wellhead and sold it to
consumers. Today it's very different, but the point is that was
only 25 years ago and they are trying to develop a framework
that will be robust for a very long time.
4:19:07 PM
An additional complication is that the North Slope gas will vary
by quality from one property to the next (slides 5 & 6). The
composition of the gas at Prudhoe Bay is different than the
composition of the gas at Pt. Thomson. But not only are those
streams being comingled, streams from other systems, quite
possibly from the British Columbia and Alberta - all of which
has different compositions - will be comingled, and the
composition of the gas has value. The gas that comes out of the
ground will have a different value for the lessee based on its
composition. So, if the lessee receives differential value, the
statute directs the state to try to obtain that value as well.
Finally, allocating processing costs is complicated. The statute
says you get processing costs, but in this particular slide (6)
you may well have multiple processing plants in a given
location, and how do you allocate the costs of those different
processing plants to Alaska gas which is also comingled with gas
from many other sources? These are the kinds of complications
they faced in putting these regulations together in a way that
treats all parties fairly.
MR. SCOTT said the legislature was wise when it passed AGIA that
directed them to promulgate these regulations; the state does
not have valuation regulations for gas outside of AGIA. He said
that real money is at stake based on the particular molecular
composition of the gas that comes out of the ground (slide 7).
No party wants to be deprived of the opportunity to get what
their due is either as a royalty lessor or as a lessee. He then
turned the discussion over to Marty Rutherford.
4:22:52 PM
MARTY RUTHERFORD, Deputy Commissioner, Department of Natural
Resources (DNR), said she would speak to the overarching policy
principles some of which are embedded in these draft royalty
regulations: (slide 8)
Overarching Principles:
1. Reduce lessee uncertainty
2. Maintain state's full royalty value (in statute)
3. Incorporate natural gas industry practices to the extent that
doing so is consistent with (1) and (2)
4:24:21 PM
She explained that the first two goals especially have a degree
of tension. They want to provide as much administrative ease and
clarity as they can while also ensuring that the state doesn't
make any assumptions that turn out to be very wrong and cost the
state substantially down the road; it has happened. (One example
will be discussed later on how the 1980 field cost settlement at
Prudhoe Bay will actually affect the cost of the gas to the
state.) She noted that not completely locking a royalty value
scheme can also benefit the lessees. The requirement of the
statute is to maintain fair market value and they think the regs
have done that.
The effort to incorporate gas industry standards themselves
stems from a desire to map the valuation scheme to the extent
they can on how it will be necessary for the lessees to account
and manage their gas flows. The department's goal is for them to
be able to use their existing gas marketing and accounting
systems to the extent possible while also complying with the
AGIA royalty valuation provisions - and frankly they are hopeful
that having normal industry practices embedded in the
regulations will also reduce room for future disputes.
4:24:59 PM
SENATOR FRENCH asked how the department measures and keeps track
of all the gas streams coming into some inlet header to the new
gas treatment plant (GTP). Is that taking place upstream of that
facility?
MS. RUTHERFORD answered yes; it is done from the unit as it
enters into the GTP.
4:26:23 PM
She said the overarching principle addressed in slide 9 is to
reduce uncertainty by:
1. Eliminating "higher-of" lease valuation terms
2. Establishing value based on published prices
3. Minimizing or eliminate retroactive adjustments
4. Allocating volumes pro rata to increase clarity of gas
value and costs of transportation and processing
This does not mean that the lessees will know what they will pay
in royalty 30 years from now. Trying to do that would be
ridiculous because of the differences in regulation, markets and
knowing that regulations change over time. But what it does mean
is that in any given month the lessee and the state will know
what the royalty value will be for that month and what needs to
be paid. Some of the details for how that is done will follow,
but achieving this principle is not trivial whatsoever. It is a
substantial change from where they are today, she said, and it
promises also to reduce litigation that has been a constant so
far on gas issues.
9
CHAIR WIELECHOWSKI asked her to explain what "eliminate higher-
of lease valuation terms" means.
She explained that the current leases require lessees to pay on
the highest value of three different measures. In practice that
means that a lessee doesn't know what it should pay in a given
month because that is a function of what other lessees receive
in value as well. In other words, of three different lessees
getting value for the same oil, whichever lessee gets the most
money, that is the basis for the lessees paying their royalty
value. It's a retroactive calculation.
CO-CHAIR WIELECHOWSKI asked for an example.
MS. RUTHERFORD explained for instance the three major producers
are producing oil from the same unit; they go to the market. BP
has an exceptionally good marketing strategy; they receive a
higher value for their oil or for their gas. And in the current
lease structure the state bases its royalty returns on that
higher value, which means that everybody will make an estimate
or maybe use their own returns as the basis for paying their
royalty in a given month, and once they go back and do an
accounting of it and audit the other firms, they will owe some
additional monies to basically bring the into alignment with the
highest amount of value received.
CO-CHAIR WIELECHOWSKI asked if the proposed regs eliminate that.
MS. RUTHERFORD answered yes, in fact they go beyond the minimum
requirements of the statute by eliminating the "higher-of" value
and they replace it with a system that allows the lessee to know
by very transparent and objective measures what its royalty
obligations for the current month are. Under the current lease
contracts, it could be several years before all the lessees know
through audit what their royalty obligation was previously and
they would have retroactive payments to make.
CO-CHAIR WIELECHOWSKI asked if this is being eliminating for gas
only or both oil and gas.
MS. RUTHERFORD replied this would be for gas.
CO-CHAIR WIELECHOWSKI asked if she had any estimates of what
sort of loss this will be to the state.
MS. RUTHERFORD answered yes; Deepa Poduval would talk later
about the values they believe are being conveyed through these
regulations to lessees who choose to accept this valuation and
royalty switching methodology.
4:29:18 PM
CO-CHAIR WIELECHOWSKI asked if this is an option they are giving
to the producers.
MS. RUTHERFORD answered yes. Because the state's leases are
contracts, they cannot impose this upon them and at the end of
the day they can choose whether or not they like this
methodology - valuation of transportation costs and switching
higher-of - better than their existing contract requirements.
4:30:00 PM
She said they also established the value based on public prices.
The regulations propose relying only on published prices to
establish a destination value. These published prices are
knowable by both the lessee and the state. They have also
recognized that published prices evolve over time and expect
that will continue in the future years. The regulations contain
a provision to insure that as the publications or their
reliability change the regulations can be amended, but in no
instances will there be retroactive adjustments to the prices
once that is established by designated publication.
CO-CHAIR WIELECHOWSKI asked if these regulations apply for the
entire duration of the gas pipeline or do some of them apply
only to the 10 years under AGIA.
MS. RUTHERFORD replied that they apply to the gas that is
committed in the initial open season - for the duration of how
long that throughput occurs.
CO-CHAIR WIELECHOWSKI asked again for clarification if these
regulations apply to gas from the initial open season.
MS. RUTHERFORD said these regulations apply for the entire
duration. "As long as that gas that qualifies in the initial
open season continues to flow through the AGIA pipeline then
they will have the benefit of these alternative regulations,
should they choose them."
4:31:56 PM
SENATOR STEDMAN asked if a company answers the initial binding
open season and has a 20-year commitment, is it normal for them
to have extensions beyond 20 years or would this arrangement
last for 20 years plus any extensions.
MR. SCOTT said the regulations would apply to the initial 20-
year contract period. The open season offering right now
contains options for extension. So a shipper could sign up for a
20-year contract with a 5-year option to extend, but the
regulations would apply only to the 20 years. If they sign up
for a 25-year contract, the regulations would apply for
valuation for that 25 years. Options to extend are not included
within the scope of the valuation regulations.
CO-CHAIR WIELECHOWSKI asked if they are still trying to
encourage producers to come in at the initial open season and
bid gas for the duration of the pipeline.
MS. RUTHERFORD replied yes. These were the inducements that were
embedded into AGIA - the tax inducement on gas and the royalty
inducements. These regulations flesh out what that looks like in
application.
MR. SCOTT explained that it is fair to say that their burden
isn't that they want people to sign up for exceptionally long
contracts, but rather in exchange for making a commitment in the
initial binding open season they get some benefits. Once the
project is launched, then the need for the state to provide
inducements for extensions is different. It basically preserves
some options for the state to renegotiate whatever deal it wants
to.
MS. RUTHERFORD said the assumption is that the project will be
capitalized based upon that initial throughput, so there won't
be the same requirements for the state to provide as much value
exchange at a later open season.
4:34:38 PM
They tried to carry the principle of minimizing retroactive
adjustments through and making revisions to the key concepts
underlying royalty value. For example, if a publication changes
or if an appropriate location or quality differential changes,
they don't go back and recalculate royalty. The regulations have
a strong emphasis on identifying forward-looking values instead
of retroactive.
4:35:17 PM
She said there is no way to identify the molecules that are
moving through the pipeline in terms of allocating volumes. So,
they have established pro-rata allocations to prevent either
party, the state or the lessees, from gaming this issue and to
ensure that both are treated fairly. This means that there is a
recognition that North Slope qualifying gas will only be part of
the total gas stream that reaches the market. The value will go
in various directions, and rather than attempting to trace
molecules which is impossible or worse, have the state really do
what it is currently doing - determine that one company's
marketing strategy is better than another's, they have landed on
a policy where on a pro rata basis an individual's quantity of
gas is proportionately spread across all the markets they might
utilize. This is only for the purposes of royalty valuation.
These rules are very clear and minimize the scope of dispute -
hopefully limiting litigation going forward.
SENATOR FRENCH asked how they do that if gas goes to tidewater.
MS. RUTHERFORD said they are not speaking here about LNG
valuation and have given themselves a bye in it within the
regulations because there aren't any clear market indicators to
use at this time.
MR. SCOTT added that today some trade publications publish
prices that give some indication, but nothing reliable that are
indicative of LNG values landed in Japan. The market for LNG
isn't as mature as the North American market. But that said,
they didn't completely throw up their hands. If there were an
LNG cargo shipped today that went to Japan they have an approach
for valuation, but it doesn't honor all of the same principles.
They wouldn't rely on industry trade publications, for instance.
They will if they can, but it will depend on where the gas goes.
If the cargo goes to Baja, they could establish value on the
basis of reliable trade publications in Southern California with
an appropriate location differential. If the cargo was going to
Japan they would have to do something different. Provisions in
the regulations address that.
4:39:10 PM
SENATOR STEDMAN said the state loses flexibility after May 1,
the date of the initial open season. Assuming someone comes in
and fully subscribes to a project that takes it to tidewater
with the intent of LNG exports to China or somewhere that could
handle the capacity (Baja is not one of them), and asked what
position is the state in after May 1 to deal in the regulatory
environment with the flexibility restrictions.
MR. SCOTT answered that statute provides for changing
regulations subject to market conditions to achieving fair
market value. In fact the statute actually says that the
commissioner has an obligation to revisit the regulations every
two years to ensure that they are achieving fair market value.
So, a lessee who intended to ship their gas to China would not
have the same degree of flanged up clarity in terms of how the
state would approach their problem, because it's not mature yet.
If it were going to China, they would probably eliminate the
"higher-of" but they would base royalty on their arms length
sales in China. So there would be one measure of value under the
lease and it would be their arms length sales, because there
aren't widely available industry trade publications. If those
evolve and they were able to get there then they would have the
opportunity no less than every two years to address that.
4:41:36 PM
SENATOR STEDMAN asked for a 30-second blast on where they are in
the regulations dealing with a large export possibility. A
couple of years ago it seemed rather unlikely, but today it
seems less unlikely.
MS. RUTHERFORD replied that the regulations provide for either
option equally. Should the project move to an LNG line into
Valdez, one alternative in the AGIA licensee project proposal,
then the regulations have adequate coverage to allow them to
value the royalties during the two years that will begin the
process of establishing a viable market to whatever locations
they take the gas. And the state has the responsibility to
determine whether their regulations are capturing fair market
value every two years. She said the Canadian market has more
data available to use for valuation, but either alternative can
be accommodated through the regulations.
MR. SCOTT added that a number of aspects of the regulations
apply equally to both - in terms of how transportation
deductions and unused capacity commitments are handled, how non-
arms length costs of various plants - and either liquifaction or
re-gas facilities if those are owned within the chain - are
handled. The destination value piece is a little harder for LNG
in terms of widely available reliable industry trade
publications, but other than that piece they are "pretty well
flanged up."
4:44:36 PM
SENATOR HUGGINS recalled they have "watered down" the term
"maximize the benefit of the resources" in AGIA by adding the
term "reasonably" and it appears to him that this is one of the
reasons. It is an interesting concept if constitutionally they
are supposed to "maximize" but now we're "reasonably
maximizing," which lowers the value.
MR. SCOTT said he didn't recall language around "maximize," but
there certainly is language around "reasonable share of
transportation deduction."
SENATOR HUGGINS commented that they debated that extensively.
MS. RUTHERFORD stated that the constitution provides to maximize
consistent with the public need, and what they have done is
within those parameters, because they still have to obtain fair
market value. Existing lease contracts provide that when one
competitor does better than another the State of Alaska benefits
from that improved marketing situation through its royalties.
She didn't think there was a constitutional issue as long as
they are still within the fair market parameters.
4:46:14 PM
She said slide 11 illustrates the full value under the lease. To
comply with AGIA these regulations move away from the actual
sales, which is the current valuation methodology, and instead
they look to published prices to establish value for distinct
components of the gas stream including the residue gas and the
natural gas liquids. The working assumption within the
regulations is that on average a published price in a healthy
well functioning market will closely approximate a lessee's
received value in that market.
She said they also have no way of knowing into which markets a
lessee will market their gas. Given that they simply assume that
on average "reasonably optimal decisions" will be made by the
companies, and that is what these companies do. She said there
are other complications beyond not being able to track the
molecules; for instance, they don't know how long the
publications will be in print or for how long they will be
reliable. Also, there gas value has to be established in some
markets that don't have published reliable prices and LNG is one
of those. Because of these various complexities they tried to
develop some mechanisms to ensure that the state doesn't lock
itself in to some decisions today that may be very wrong over
time. They believe that protects both the lessee and the state.
4:47:39 PM
MS. RUTHERFORD pointed out that a further clarification in these
regulations says there will be no negative royalty. This means
that the netbacks on gas components cannot go below zero. They
believe this is already the current status within their contract
structure, but that is getting clarified within the regulations.
It hasn't been tested on oil, but it is a point of disagreement
between the state and some lessees.
SENATOR STEDMAN asked her to amplify on that issue.
MS. RUTHERFORD responded that basically they are saying in a
calculation, should the cost of transportation should go higher
than eventually where their marketing goes, the state's royalty
can't go lower than zero.
SENATOR STEDMAN tried to clarify further and said the severance
or the production sharing arrangement would be gone, the royalty
value could go to zero, and that is as far south as it would go.
It can't be offset by some other direction into oil, because
that's the only value left.
MS. RUTHERFORD replied, importantly, it is currently arguable
that if transportation costs exceeded the valuation received at
the other end, the state would be placed in a negative royalty
position where it would actually owe the lessees money. The
department does not believe the state's oil and gas leases
provide for that, but that has been a question in some people's
minds. So within this set of regulations they are clarifying
that zero is as low as it can go. That situation exists with
oil now; but arguably under oil where it has never been
clarified it could go below zero.
CO-CHAIR WIELECHOWSKI noted that these regs don't address oil,
and asked if the state could be in a position of losing royalty
value there. Does oil need regs?
MS. RUTHERFORD replied that the state doesn't have regs in place
on oil and it hasn't been tested. If they got into a situation
where the value of oil fell significantly, it is possible that
someone might bring that argument forward and take it to the
court. But they do feel the lease contract is strong enough for
the state to make its case if that should come up.
4:52:05 PM
MS. RUTHERFORD said incorporating gas industry practices (slide
11) in determining the cost of transportation is very difficult.
For instance, the original TAPS tariff dispute raged for eight
years and the question of the transportation methodology was
never settled. The intent within the draft regs is to
incorporate generally well established industry practices. One
of these was to use the FERC methodology to determine the cost
of transportation for gas pipelines. They incorporated FERC's
approach in order to be consistent with how they will approach
thinking about transportation and transportation costs in
marketing the state's North Slope gas. As well for the main line
they substantially relied on the public offering by TransCanada
to establish a backstop for non-arms length transportation
costs. She said they are not just relying on FERC practice, but
on industry commercial practices as well - as indicated by
TransCanada and ExxonMobil's proposal to the FERC.
Additionally, in crafting the regulation language, Ms.
Rutherford said they used the Mineral Management Service (MMS)
royalty value regulations as a template. All the North Slope
producers are familiar with the MMS regulations for their Lower
48 gas production. Some MMS regs were modified in order to
comply with AGIA. For example, the MMS regulations are built
around a gross proceeds measure of value, whereas AGIA requires
the department to use widely available industry trade
publications. That said, they have retained a number of
approaches to try to ensure it is well understood and that it
limits opportunities for dispute.
4:54:12 PM
FRED HAGEMEYER, Black & Veatch Corporation consultant, said he
would talk about five of the key valuation concepts:
1. Destination where gas is valued
2. Publishing value at destination
3. Backstop measure of FMV for residue gas
4. Actual and reasonable transportation and processing costs
5. Appropriate deductions for unused capacity
4:56:24 PM
A lessee's gas is valued for royalty at destination, he said. In
determining destination a lessee's qualified gas is generally
considered to be at destination when it first:
1. enters a first destination market (defined in regulation)
2. has been sold in a arm's length transactions; or
3. has been processed to extract residue gas and gas plant
product (this gas will have a lot of NGLs so there will be
a lot of processing).
MR. HAGEMEYER said the key around first destination markets is
that they are looking for is something the state can rely on
that has a lot of liquidity, an area where they believe that ANS
gas is physically transported, and where it can be bought and
sold, there is processing and where they can find published
indices available. As an example the Alberta market, which is
referenced often, is clearly a first destination market.
4:58:32 PM
He said one of the things that is key throughout parts of the
regulations is being able to put on the DNR website elements and
information prior to the royalty reporting period so the lessee
can value royalty during the month in question, and locations of
the first destination markets is a key concept. They will have
all the elements to value the gas even if gas goes beyond that
including:
· The name of the source of the published price for residue
gas, gas plant products at the first destination market
· Appropriate location or quality differentials to establish
FMV with reference to first destination market
· Reasonable gas treatment, processing, or re-gasification
cost allowances.
5:00:23 PM
Alternative Destination Value for residue gas (slide 15) is
found using a basket of published indices to calculate a
backstop fair market value to published index prices at
destination markets - published ahead of time. These
publications will provide the range of fair market value in that
market. A number of market centers have interconnectivity to ANS
gas that could go off into different areas after or before being
processed. Each one would have publications that would qualify
under the criteria of publication. A weighted average of the
volume on the basket would be compared to the price at ACCO (for
instance) and a 5-percent buffer accounts for month to month
fluctuations. The basket is relied upon only when the published
price at a destination market is less than 95 percent.
Another transportation concept is around the non-arms length
transportation cost. A unique thing about these regulations is
that they have had the luxury of knowing what has been offered
in the TransCanada ExxonMobil open season offering so they
suggest that they provide a watermark for reasonable non-arms
length transportation costs. During the process of the open
season they will see if a shipper can negotiate a better rate
than can be calculated from the basic terms in it now, and the
state would take the lower rate. As a general principle they are
going with FERC-based methodologies to calculate
"reasonableness," even though other pipelines segments
particularly out of the Alaska/Canada main pipeline will have
cost deductions.
5:03:18 PM
The last point he wanted to make about something that is a
reasonable and actual cost has to do with processing costs and
in this case they have used the template of what the MMS is
allowing; typically those plants are not regulated.
5:04:38 PM
MR. HAGEMEYER said the last major bullet in this area is around
unused transportation capacity which is designed to balance the
need and mitigate the producers' risk associated with taking out
that capacity as well as help protect the state from unintended
costs associated with that. A detailed example of how it would
work was on slide 18.
5:08:05 PM
MR. HAGEMEYER went to slide 19 on the royalty in kind (RIK)
royalty in value (RIV) switching issue. He explained that under
the lease, the state has the option of taking its share of
royalty either in RIK or RIV. This can in the case of taking out
firm capacity (FT) in the open season create a risk for shippers
along the lines of if the state takes its RIK during a period of
time when the shippers may have excess capacity and that
capacity could be fairly expensive (for the shipper). But if the
state were in RIK for a period of time and wanted to switch back
to RIV and now the timing is fairly short (maybe 90 days) then
the shipper may not have capacity to take that back in, and they
would have to acquire capacity somewhere or do something else.
In addition, producer marketers will put elements in place, some
short term some long term, over the course of the volumes they
are moving (no matter which market it may be); so there needs to
be some time to adjust those volumes if the royalty portion is
not there. Given that, they have tried to work through ways of
mitigating that risk while protecting the state.
SENATOR WAGONER said he thought if the state would take RIK it
would be for a specific length of time and a specific amount by
contract.
MR. HAGEMERYER replied it can do that, but it is not required
right now according to the lease.
SENATOR WAGONER stated that it's at the state's option not the
producers' then.
5:09:02 PM
MR. HAGEMEYER said in switching from RIV to RIK, the regulation
is set up so that the state would be obligated to seek capacity
corresponding to the state's RIK share from the producers in a
prearranged deal. This means the state would take the released
capacity that they acquired at original contract rate and in
doing that, the state risks foregoing a potential better deal
that could be negotiated. The state would be taking capacity
from the shipper sort of like the capacity is going with the
gas. If the gas went to the state the capacity goes to the
state, too; if capacity is switched from RIK to RIV that
capacity goes to the producer. They felt it was reasonable for
both sides to do this, and he mentioned both sides wanted it to
happen.
SENATOR WAGONER asked what if the producer in the meantime has
filled that capacity with other gas.
MR. HAGEMEYER responded that when a shipper takes capacity and
that capacity is released to another party, it goes through the
carrier to the third party. So now the state would have that
capacity. The producer doesn't have the capacity to refill, but
it doesn't mean they can't acquire other capacity for other
reasons.
5:11:45 PM
One of the tools to do this is having a contract rate, so
whatever rate they have is what is transferred over. The state
requested a waiver from FERC in November (approved by FERC in
January) that essentially allows for this transfer to occur at
that contract rate. The regulations increase the notice period
trying to allow more time to arrange other marketing situations
for that royalty gas that may be taken. If it's over 200,000
Mmbtu/day it would be 180 days notice.
5:12:38 PM
DEEPA PODUVAL, Black & Veatch consultant, said she would walk
the committee estimates of what quantitative values are being
provided to the producers through these proposed AGIA royalty
regulations (slide 21).
She said one of the aims of the regulations was to provide value
to the producers while protecting the state's interest. In going
through the process of developing the regulations one of the
exercises they did was to find how much value was being
transferred in some of the key provisions; they looked at four
main provisions:
· Valuation - moving away from the higher-of provision
· Transportation - adopting a FERC-like approach for non-arms
length transportation deductions rather than the MMS-like
approach, and allowing deductions for unused capacity
· RIK/RIV switching - FERC waiver allows capacity transfer
deal at contract rates
5:15:19 PM
MS. PODUVAL said one of the challenges in quantitatively
analyzing the value to the producers is the level of uncertainty
about certain factors that influence the project going forward:
prices, project costs, volumes that may be found, reserves and
uncertainties related to RIK/RIV switching. So rather than
attempting to create base line assumptions on how some of these
uncertainties may evolve they made aggressive assumptions to
establish an upper bound on what the value to producers could be
(slide 22). In other words they looked for the highest value the
producers could get, but the actual value they would get would
be something lower than that depending on how the uncertainties
evolved. Some of the assumptions they made were:
· Methane valuation - Assumed impact of moving away from the
higher-of provision is not offset by market basket concept.
· Transportation deduction for non-arm's length transactions
Assumed that alternative was MMS methodology.
Two key provisions were related to MMS that were
different in the proposed regulations. The first is
that MMS does not recognize taxes as a valid way of
determining cost when creating the cost of service
methodology and second that the return on equity that
MMS allows on pipeline is calculated taking 1.3 times
the Bbb bond rating. The proposed regulations allow 12
percent. Based on recent data the MMS methodology
would allow a little less than 7 percent.
· Unused capacity deductions - they assumed a worst case
scenario where the only gas that flows through the pipeline
are from the proven reserves, essentially no yet-to-find
gas is found, and so there is a significant amount of
unused capacity on the pipeline and the state does not pay
for any of it. Essentially the producers bear 100 percent
of the cost of commitments they have made related to that
capacity.
5:18:46 PM
· RIKRIV switching - Assumed that the state takes its entire
royalty volume in-kind for the entire 25-year period. They
further assumed that the producers are unable to take any
mitigating actions to offset the cost of the capacity they
are now stuck with (they don't try to acquire gas from a
third party to flow through that capacity).
· They looked at what the value to the producers is from the
1980 royalty settlement agreement (slide 23).
5:19:57 PM
She estimated the quantitative value from different provisions
that could potentially be given to the producers as a result of
the proposed regulations. The biggest contributor comes from the
FERC waiver that mitigates the capacity risk that the producers
have from the state's option of switching between RIK and RIV.
It can range anywhere from zero dollars if the state never takes
RIK to up to $17 billion if the state takes all of its gas in
RIK and the producers are unable to offset their capacity costs
in any way. The second largest component is from the 1980
royalty settlement agreement where three different components
were considered: field cost allowances, GTP cost allowances and
the central compression plant allowance. That amounts to about
$6 billion of value for the producers.
MS. PODUVAL said the unused capacity is the next biggest
contributor of value to the producers. It is a range from zero
if there isn't any unused capacity and yet-to-find gas is found
and keeps the pipeline full to the other extreme; if no yet-to-
find gas is found and there is significant amount of unused
capacity on the pipeline this could be worth as much as $3
billion to the producers.
Transportation deductions, the proposed cost of service
methodology related to non-arms length transactions provides
about $2.8 billion of value to the producers. This is relative
to a benchmark where the state could have adopted an MMS-like
methodology that is used for federal royalty purposes and been
much less generous in what cost components are included as well
as what is allowed for return on equity.
The last value component is from moving away from the higher-of
provisions and is a range of zero up to $1.4 billion. The low
end is theoretically possible if all the producers get the same
value in each market and the state wouldn't be making that
higher-of comparison.
In conclusion, Ms. Poduval said significant potential
quantitative value is provided to the producers from the various
provisions of the proposed AGIA royalty regulations and it is
good to keep in mind that they would be in addition to the
qualitative benefits of improving their certainty as well as
clarity.
5:23:21 PM
CO-CHAIR WIELECHOWSKI asked if these values were calculated over
the course of the pipeline.
MS. PODUVAL said it is dollars of the day over a 25-year period.
5:24:24 PM
CO-CHAIR WIELECHOWSKI said this is an important slide that shows
some pretty significant sweeteners being added to encourage the
producers to have an open season. He calculated $8.8 billion to
$21.4 billion of incentives. He thanked everyone for their work
on this issue and adjourned the meeting at 5:24 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| GRETC-Senate Resources slides 3-17-10 (2).pdf |
SRES 3/17/2010 3:30:00 PM |
|
| SRES DNR AGIA Final - 03-17-10.pdf |
SRES 3/17/2010 3:30:00 PM |