Legislature(2009 - 2010)BUTROVICH 205
03/10/2010 03:30 PM Senate RESOURCES
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| Overview: Agia Regulations | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
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ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
March 10, 2010
3:33 p.m.
MEMBERS PRESENT
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
MEMBERS ABSENT
All members present
COMMITTEE CALENDAR
OVERVIEW: AGIA REGULATIONS
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
MARCIA DAVIS, Deputy Commissioner
Department of Revenue (DOR)
Juneau, AK
POSITION STATEMENT: Commented on AGIA regulations.
FRED HAGEMEYER
Black and Veatch
Consultant to the Department of Revenue (DOR)
Juneau, AK
POSITION STATEMENT: Commented on AGIA regulations.
COMMISSIONER PATRICK GALVIN
Department of Revenue (DOR)
Juneau, AK
POSITION STATEMENT: Commented on AGIA regulations.
ACTION NARRATIVE
3:33:50 PM
CO-CHAIR BILL WIELECHOWSKI called the Senate Resources Standing
Committee meeting to order at 3:33 p.m. Present at the call to
order were Senators Wagoner, French and Wielechowski.
^Overview: AGIA Regulations
Overview: AGIA Regulations
CO-CHAIR WIELECHOWSKI said the committee would take up an
overview of the long-awaited AGIA regulations.
COMMISSIONER Patrick Galvin, Alaska Department of Revenue (DOR),
and Marcia Davis, Deputy Commissioner, Alaska Department of
Revenue, introduced themselves.
COMMISSIONER GALVIN said today they would deal with two
different regulation packages that were put out by the DOR over
the last month for public comment. They deal with the
interrelationship between the ACES (Alaska's Clear and Equitable
Share) production tax law and the AGIA (Alaska Gasline
Inducement Act) open season.
With the open season coming, he said they recognized that the
AGIA tax inducement provides an opportunity to a company that
would commit to acquire capacity at that open season to obtain a
tax exemption. A tax exemption is for the difference between
what the taxes are at the time they are actually producing and
the taxes that are in effect at the commencement of the open
season. So, the first part of their discussion would be about
what they are referring to as the ACES regulations dealing with
how gas is priced for tax purposes - how the destination value
of the gas will be determined for production tax purposes and
how transportations costs are deducted to get to a point of
production value.
3:35:25 PM
SENATOR BERT STEDMAN joined the committee.
3:36:52 PM
COMMISSIONER GALVIN said those are needed to be in effect at the
commencement of the open season in order to insure that the gas
tax system was as comprehensive as possible before going into
it. Another package of regulations deals with the tax inducement
itself. One section deals with how to qualify and how the
inducements would be used.
3:37:29 PM
COMMISSIONER GALVIN started with the regulations for valuation
and transportation deductions, which for gas are incredibly
complex because of the nature of the natural gas markets.
3:38:22 PM
SENATOR GARY STEVENS joined the committee.
COMMISSIONER GALVIN said the Alaska Department of Natural
Resources (DNR) has a similar task to determine a valuation
methodology for its royalty purposes. Under the AGIA inducement
associated with royalty they are actually offering a valuation
methodology as part of the upstream inducement that is intended
to provide more certainty and predictability for the producer in
being able to anticipate what their gas valuation will be. He
explained that the DOR tried to mirror as much as possible the
DNR methodology so that it provides a more unified system from
both taxpayer and department perspectives. It would make
implementation easier for both departments because they could
use each other's information and work off each other's thoughts
in working through complexities.
Today Commissioner Galvin said he would provide a broad overview
on taxes from a structural standpoint and how some of their
issues were resolved.
SENATOR STEDMAN asked if the committee had a quorum to start.
CO-CHAIR WIELECHOWSKI answered no; but they were not going to
conduct any business.
MARCIA DAVIS, Deputy Commissioner, Alaska Department of Revenue
(DOR), started with a discussion of the over-arching principles
that guided them in preparing the ACES regulations. She said
that Fred Hagemeyer, Black and Veatch, and John Larson, Audit
Master, DOR, were on line; they were both key in developing the
regulations. The first principle was the department's duty to
insure that full value is received by the state through its
production tax laws from the natural gas production. In
addition, she said, a lot of lessons were learned with having
oil marketed valued for tax and royalty purposes, and they don't
want to make the same mistakes with gas - things like the proper
way to value oil using prevailing value and reasonable value -
marketing was something at arm's' length, et cetera. They want
to provide as much clarity as possible to industry.
MS. DAVIS said they met with their DNR brethren to see what they
had to do to value gas for royalty purposes and what the DOR did
for tax purposes and tried to come up with a common approach so
that industry could understand clearly if one value for gas was
used for tax purposes, why another might be used for royalty
purposes. While each department has its own statutory authority,
she said they tried to be consistent where it was legally
permissible.
3:43:27 PM
MS. DAVIS said they benefited from having a common consultant
who could understand and grasp their concepts and who could help
the departments, hopefully, pick the best solutions for a
particular problem. She explained that the DOR has a 25-30 year
body of case law and a body of regulations on how to value
things and principles on valuing things. So, what they did had
to be consistent with past practices.
She said they learned that the natural gas industry has a lot of
unique differences in the way gas gets sold and marketed, how it
moves across the nation and the system that is in place for
handling gas and the types of processing that happens with it.
Once oil leaves Alaska and hits the West Coast the state is not
involved; it doesn't pay much attention to the downstream - like
manufacturing into plastics and asphalt and things like that
(slide 4). But gas tends to be marketed more in its constituent
parts as well; so that they have to deal with the pieces of gas.
Things get marketed and people pull stuff out and send it down.
They have had a little bit of experience with that in oil, but
not as much as is going to happen with gas. They needed to go to
school on that and they got a lot of education.
3:45:13 PM
MS. DAVIS said one thing they do know is that whatever
regulations they set up for marketing for handling what the
price of gas is and how it's going to be transported, they want
them to be flexible. That is one thing they have learned from
the oil regime. What you think is always going to be a price
marker that will be there forever may not be. So, they built in
flexibility to keep people from having to come in to see new
regulations or changes in how things are done as often. They
want some certainty about how "we will step out way through our
decision tree when and if this particular bench mark is no
longer available." In this way they hope to minimize litigation
on transportation and administrative costs.
3:46:17 PM
One thing they have realized with oil transportation is the
availability of financial information. Within Alaska it is TAPS
(Trans Alaska Pipeline System). Most people think information on
that would be easily available, but she has learned otherwise as
they struggled developing the oil transportation regulations.
They wanted to ask the oil companies what their costs for
transportation are, but Elkin's Law states that the pipeline
can't share information with the shipper if they have their own
subsidiary shipping as well. So, there is "an appalling lack of
information flow" between a pipeline company and the people who
ship on that line.
She said the department had been struggling with how to obtain
publicly available information that relates to the cost of
shipping that a taxpayer can access and use readily in
calculating their tax bill. So, they have "devolved" to using
what gets reported on FERC reports or other reports that have to
be filed from the prior year. Then that information is applied
to this year. She remarked that this is just in Alaska where
theoretically the DOR has subpoena power and could acquire the
records, but those records couldn't be shared with the taxpayer.
She mused that perhaps they could be posted as an aggregate.
3:48:33 PM
MS. DAVIS said when they look at gas transportation costs they
are looking at transportation that occurs mostly in Canada and
the Lower 48 that is beyond the subpoena power of the DOR and
certainly beyond the ability of the taxpayer to get information,
because some of the transportation systems are unregulated.
Gas's regulatory oversight is a little different than taxes with
FERC. TAPS almost always has an adjudicated just and reasonable
rate. With FERC and gas lines there is less scrutiny and you
tend to just get approved. One of their concerns in drafting
what costs can be deductible in the transportation regulations
was to come up with a system that would insure the taxpayers
could find the information necessary to make the deductions.
Finally, she said gas is unique because of the system set up
under AGIA the gas that gets transmitted via the commitment at
the open season (versus subsequent open seasons) has benefits or
non-benefits. Also, a lot of gas is co-mingled from different
places, but they wanted to ensure that neither the state nor the
shippers could game the system. She would not want the state to
be able to pick the highest price gas with the lowest
transportation cost and say it was from Alaska; and likewise
they would not a taxpayer to do the reverse - pick the lowest
price gas with the highest cost of transportation and tell
Alaska that was their gas that got marketed.
3:50:46 PM
CO-CHAIR LESIL MCGUIRE joined the committee.
3:50:53 PM
So, Ms. Davis said they developed a pro-ration system that
equitably allocates the pluses and the minuses of market pricing
and transportation costs evenly across the board. The last over-
arching principle is where the Legislature gave direction to
look at rates set by FERC and to honor those as prima fascia
evidence of a reasonable cost to deduct; they tried to carry
that principle into the gas transportation regulations
structures as well.
3:51:48 PM
SENATOR HUGGINS joined the committee.
3:51:58 PM
(Slide 6) MS. DAVIS explained that a taxpayer producer
calculates its tax by first deriving the value of its gas at the
point of production (POP) - the entry point to the pipeline
after gas processing. This means the value at that place (think
of a place on the North Slope) before it gets put into the gas
treatment plant (GTP) and into the pipeline.
SENATOR FRENCH asked exactly where the point of production for
gas is.
MS. DAVIS answered the POP for gas is downstream of gas
processing and upstream of the gas treatment plant. She
explained that the North Slope has gas processing essentially
because the CGF and NGL is getting pulled out to reinject.
Everything else would be left in that gas stream that they would
want to market somewhere else. The purpose of the GTP is to make
sure the gas is in a condition that it is safe to transport,
which means that it doesn't have water in it to rust the pipe or
CO that will hurt the valves.
2
CO-CHAIR WIELECHOWSKI inserted that they now have a full
committee and that he had have been trying to set this hearing
up for several weeks and then regs just came out. He asked Ms.
Davis for a quick overview of timelines.
MS. DAVIS responded that the regulations on transportation cost
deductions and how the gas is valued for purposes of calculating
tax were released about mid-February ago; they have a 30-day
comment period. DNR regs are due approximately a week later with
public comments due around March 22.
3:55:09 PM
MS. DAVIS said for a taxpayer to calculate their taxes they take
what they got for their gas or what the state tells them is a
prevailing value and subtract the actual cost or, if the rules
indicate, their reasonable cost of transportation, and end up
with the gross value at the point of production. This is on the
pivot point of deciding two things; the first is does a taxpayer
get to use his actual sales price or does he have to use a
prevailing sales price. The statutory direction to the
department is to require the use of a prevailing sales price
(that other people generally get) when that transaction is not
arm's length or when it is suspiciously below market price.
CO-CHAIR WIELECHOWSKI said that seems to give a huge amount of
leeway, but was it to the producers or to the department.
MS. DAVIS replied that the regulations define what an arm's
length transaction is by essentially looking at who the seller
and the buyer are and if there is a relationship between those
two such that they would define them as being affiliates of the
same entity. The definition of affiliate is if you have a 10
percent or more voting interest in who you sold to.
3:57:01 PM
COMMISSIONER GALVIN mentioned if the price is between the
prevailing value and the arm's length value the state would use
the higher of those two to calculate the production tax.
CO-CHAIR WIELECHOWSKI asked if prevailing price is Henry Hub
price.
MS. DAVIS answered that they have several choices for selecting
a prevailing value. Transportation depends on if you ship on a
transportation facility (which includes a GTP, the pipeline and
anything downstream) and vessels; if it's not arm's length or
with an affiliate the DOR would figure a reasonable cost of
transportation calculation.
3:58:35 PM
MS. DAVIS went back to explaining Gas Valuation (slide 8): When
gas is delivered off the North Slope the value is based on the
"higher of" the weighted average sales price of arm's length
transactions (unassailable sale prices in the market) or the
prevailing value at destination markets which is set by statute.
She recalled that gas product that has to have a value assigned
can be sold as it comes out of the ground without being touched.
CO-CHAIR WIELECHOWSKI asked what happens if 1 bcf is sold at
$6/mcf and then 3 bcf is sold at $7/mcf.
MS. DAVIS answered that in those cases an average price per mcf
is calculated and that is defined in regulations. You may sell
your gas as stripped out so that all that's left is residue
(residue gas is the methane you have left if you strip
everything else out of Prudhoe gas). Utilities burn methane, so
they value that. Gas plant products - ethane, propane, butane
and NGLs - get stripped out and sold separately. Some people go
through the extra process of freezing gas and selling it as LNG.
So there are four different kinds of products and gas plant
products have another whole range of products to keep track of.
4:00:18 PM
(Slide 9) She assumed the actual sale price can't be used, so
the department created a "first destination market" concept and
used the first place where this gas went that had a very liquid
market, one that has a lot of third-party transactions. She
reminded them of the over-arching principles for dealing with
Lower 48 pipelines and destination markets where five pipelines
might be involved. Generally a liquid market will have posted
prices and it's a place of certainty where everybody can figure
out what the price of gas is at that liquid market.
CO-CHAIR WIELECHOWSKI said Alberta has the ACCO market, but
asked if the gas goes to Valdez what would the market be there.
MS. DAVIS replied if it goes to Valdez she presumed they were
talking about LNG and they would look at the daily volume of
regasified LNG that is sold in arm's length transactions. A body
of law already exists for establishing LNG value for taxing the
plant in Nikiski; so they are pretty comfortable with developing
a value for the gas for purposes of tax.
Finally, if there are gas plant products, they would generally
look at a place where both the residue gas and the gas plant
products are being pulled out. They don't want to end up in some
obscure place where all they do is pull out butanes for some
unique process, because it's just not going to have a lot of
third-party action. Their goal is to look for some place with
lots of activity where they can have some confidence that the
marketplace is functioning really well and that the market price
that is being placed on these products is a "good solid one"
that hasn't been manipulated either because of lack of supply,
lack of demand, or parties knowing each other.
4:03:56 PM
(Slide 10) The prevailing value (PV) for gas delivered to a
market in Canada, the Lower 48 or foreign market is based on the
total value of the component residue gas, Ms. Davis said. They
will add up all the pieces that got stripped out and sold if
that is what happens.
SENATOR FRENCH asked it is the higher of all the choices.
MS. DAVIS answered it would depend upon what the circumstances
are. If the constituents aren't broken out, you use the weighted
value. Slide 10 showed the hierarchy to establish the
comparison.
COMMISSIONER GALVIN said the "higher of" is the higher of
between an individual tax payer's arm's length transactions and
the prevailing value. In order to compare those two for an
individual taxpayer, they have to determine what the prevailing
value is at a particular location. If you can't find published
prices, then they get a weighted average of all the sales they
can collect to establish a prevailing value. If that's not
available, they will look for government prices.
SENATOR FRENCH said ultimately this would come down to a value
judgment by somebody as to which of these applies and he wanted
to know where that authority rests.
MS. DAVIS explained that the department has charged itself with
looking for published prices with established criteria. If they
are unable to find published prices, by default they will have
to drop down to the weighted average sale price. Again, it will
be their obligation to report that number to the taxpayers so
that they know what the weighted average sale of third-party
transactions is. It has to come from a place with a lot of
published third-part sales - like ACCO has, for instance.
COMMISSIONER GALVIN said it is in the hands of the commissioner
implementing the statutory requirements, but the selection is
guided by the regulations with established fairly specific
criteria upon which to base a determination.
4:07:56 PM
(Slide 11) Ms. Davis said they obligate themselves to tell their
taxpayers what they have determined qualifies as first
destination markets - that means they will have determined it
had sufficient volume, sufficient arm's length transactions, and
had a publication that could be put out for public consumption.
They would also list the name of the publication or what the
source of the published price was so that they would be able to
track it as well and be able to keep their records. Also, once
you've picked the destination market, if there is clearly a
location of quality differential - because something is being
sold elsewhere and you need to shift the location - they would
acknowledge what those are as well as quality differentials.
Finally, reasonable gas treatment processing or regasification
costs are allowed if applicable. When someone is marketing their
gas plant products which means they have gone through all that
cost to treat the gas - and if it's LNG, the cost to regasify -
there are cost allowances for that. Those would be published
because they are essentially set on a third party arm's length
kind of weighted average figures.
MS. DAVIS said people get confused because they are used to
thinking about oil - to the point that when gas gets produced on
the North Slope and gets processed through the central gas
facility (CGF) and liquids are stripped out that are called
natural gas liquids (NGL) statutorily they have said those are
oil and they will be taxed as oil. However, those NGLs owe their
source to both oil and gas down in the reservoir. She said the
CGF has two parts. The primary part is the gas processing plant,
the one that strips out the propane and the natural gas liquids.
That is upstream of the point of production and gets deducted as
a lease expenditure cost and qualifies for capital credits et
cetera.
What is left in that gas either gets diverted and sent back down
hole or is available to be sent over to a pipeline. So when you
think about it, the gas processing plant makes NGLs and its
deductible, but in the gas world there are terms of art that
conflict with that (slide 12). One of the things they had to
bump up against when they started talking to experts is that
they used the term "NGLs." The department thought they knew what
that was, but they didn't because in the gas world, NGL is
everything you can strip out of the gas (the propane, the
butane, the NGLs, et cetera) leaving just the residue gas
(methane). Also, because that can be done downstream, there are
technically gas processing plants that can be located
downstream. So, if somebody is selling their Prudhoe gas which
might be rich in propanes and butanes, it can conceivably go to
a plant down in Alberta for that processing. In Alberta or
Kenai, for instance, these components of the gas can be stripped
out in a plant that would also be considered a gas processing
plant. But it's not a gas treatment plant by their definition,
because it's not being done simply to make it transportable. The
gas industry generally calls these NGLs.
MS. DAVIS said they, therefore, had to define a thing called a
"downstream gas processing plant," because it wasn't dealt with
in prior statutes. It is essentially a gas processing plant that
is downstream of the point of production. It, too, can extract
NGLs.
CO-CHAIR WIELECHOWSKI asked if you can have a gas processing
plant anywhere else than on the North Slope under the defined
term.
MS. DAVIS responded that the term "gas processing plant" is the
term that is defined in AS 43.55.900 and it is juxtaposed with
gas treatment plant. The reason it was important to define those
terms was for purposes of administering the production tax, they
had to decide which part of the gas handling costs on the North
Slope were going to be considered upstream of the point of
production (gas processing plant) and what part of the costs
were going to be determined to be downstream (gas treatment
plant).
4:14:49 PM
She explained there can be the processing of gas that occurs off
of the North Slope and they had to come up with a word for that,
because in the gas world a gas treatment plant is a meaningful
term. The FERC regulates tariffs associated with gas treatment
plants, but gas processing is not necessarily regulated. It's
more of a manufacturing process that happens when gas flows
through and has valuable components in it. So they couldn't call
it a gas processing plant because that's defined as a specific
type of plant that is located upstream of the point of the
prodcution for tax purposes. So, they are now calling the thing
that happens that involves gas processing when it's not on the
North Slope (downstream) a "downstream gas plant." Developing
terminology that helps keep their concepts clear and straight is
one of the challenges they have encountered working through the
regulation, she commented.
MS. DAVIS said they hated hearing people call all the stuff they
strip out of gas in the Lower 48 NGLs, because "we are so bred
to think of NGLs as that product stream that we call oil that
comes off the North Slope." So they came up with the term "gas
plant products" and it includes all the stuff that can get
stripped out of gas including NGLs while distinguish those
things from what remains which is essentially a methane stream
(residue gas).
4:16:45 PM
MS. DAVIS said their statutes technically define "gas
treatment," but don't define a "gas treatment plant." She said,
"the nerds of us felt that lack and so we have put in that
definitional term, also."
SENATOR FRENCH asked where she expects to get push back from
industry regarding the regulations.
MS. DAVIS said she had to be careful, because they are in the
30-day comment period and would be providing written responses
back. But they had a workshop on this portion of the regulations
and questions were along the lines of trying to understand what
the regulations were saying and what prevailing value was, and
what it would mean to them in their world when they calculate
their tax. They were trying to understand the concept of "first
destination market," but they were also unclear why she was
referring to the prior year's cost data. She was able to explain
that it was done for their benefit to give them a reasonable
chance of having access to the data. The Alaska Oil and Gas
Association (AOGA) would submit comments soon that would give
her a clearer picture of what their concerns are with the
regulations.
4:19:10 PM
MS. DAVIS said there is an allowance for a processing cost
associated with a downstream gas plant, now that they all know
what it is (slide 14). Clearly, if the department is going to
ask somebody to pay their tax based on the value of a product
that comes out of a plant, they need to have the right to deduct
what the cost was to process it and get it to that point where
it was marketable as that product.
She said complexities of pro-rating are associated with somebody
having multiple gas processing contracts. The same holds true
for the allocation of cost for processing co-mingled streams,
because in Alaska someday gas will come through the
transportation system that is not taxed. It will be coming from
federal offshore leases. There shouldn't be any cherry picking
by the state or industry. Costs will be allocated fairly and
evenly across all the streams.
4:20:57 PM
She said industry has had a longer time to react to many of the
provisions for the transportation deductions, because they have
had four workshops on transportation deductions as they apply to
oil costs. As a result of those workshops, they went through a
lot of changes in their structure (slide 15). So that by the
time they realized they had to get gas pipeline transportation
costs fleshed out as well, they were able to fold that in with
all the body of work they had up to that point in time for the
oil transportation costs.
The statutory direction to the department is for the gross value
to use actual cost of transportation or the reasonable cost,
whichever is lower. In addition, when the modifications made by
ACES took place, the Legislature directed the department to make
prima fascia (reasonable) any of the costs that were certified
as just and reasonable by the FERC or the RCA.
So, fortunately or unfortunately depending on perspective,
actual costs are not necessarily reasonable costs. Accordingly,
the department looks at reasonable costs as being different than
actual costs when they have affiliated transactions (10 percent
threshold for voting interest), are non-arm's length
transactions, or are a transportation methodology that is not
reasonable in view of existing market alternatives. These three
criteria are set out in statute.
CO-CHAIR WIELECHOWSKI asked if these regulations apply to just
the gas pipeline.
MS. DAVIS answered no, they apply to both oil and gas
transportation, gas treatment plants, LNG plants, LNG
regasification, vessels; all modes of transportation costs have
a provision on arriving what the reasonable value will be if you
can't rely upon the actual cost. There are some exceptions for
the unique aspects of gas.
CO-CHAIR WIELECHOWSKI asked if they would apply to both an AGIA
gas line versus a non-AGIA gasline.
MS. DAVIS answered that is correct.
COMMISSIONER GALVIN added that most of what the regulations
cover almost exclusively deal with gas. The one component that
deals with oil and gas has to do with regard to the
transportation deduction portion.
CO-CHAIR WIELECHOWSKI asked if these regulations would apply to
a bullet line from the North Slope or a spur line.
MS. DAVIS answered yes; they have some instate provisions.
CO-CHAIR WIELECHOWSKI asked Commissioner Galvin if he agreed
with that.
COMMISSIONER GALVIN replied that it gets complicated, because
some of the valuations are different in Alaskan markets, but
they didn't get into prevailing value and published prices and
that sort of thing for the Alaskan market. He didn't want to
mislead on the scope of application to an instate line, but the
transportation deduction is relevant to an instate line, as
well.
4:25:35 PM
MS. DAVIS said they actually already have some transportation
regs on the books, but those will be limited to when gas is
marketed outside the state. She continued that when they ask
themselves what reasonable costs are, the first choice are rates
that are adjudicated as "just and reasonable" by the RCA or
other regulatory body (as directed by the Legislature in ACES).
A second that is added, because they learned that gas tariffs
don't get the degree of "scrubbing down" that the TAPS tariffs
seem to get (FERC does a lot of them and has an abbreviated
methodology). FERC does not adjudicate gas tariffs as "just and
reasonable;" instead they do an approval process. The FERC has
determined they will honor in the spirit of the directions the
Legislature gave them for the prima fascia "just and reasonable"
the initial gas tariff rates that are approved by the FERC.
These are the first ones that come out of the hat and the ones
that get filed when someone is seeking issuance of their
certificate of public convenience and necessity from FERC. It
has a high degree of review, but not technically "just and
reasonable adjudication."
A third choice, she said is pipeline and gas treatment plant
tariffs under settlement agreements to which the state is a
party. She said this came up during their oil transportation
deduction thought process; it didn't make much sense to the DOR
that if the state entered into a settlement and said okay this
is a good tariff and they want to accept it that they shouldn't
at least give it that prima fascia nod that this should be
considered reasonable.
MS. DAVIS said they have acknowledged that each of these
"sanctionings" of a tariff rate as being reasonable is limited
in time. It can get stale. For instance, a tax rate that is
adjudicated as "just and reasonable," is generally a very
cumbersome process; and for someone to make the case they will
gather their test data about what their costs and the rates of
return were it usually takes about two years before that test
data gets "sanctified" by FERC as being just and reasonable. So,
they give whatever data they put in front of the FERC five years
to be valid. At that point, they start to look at something
else. The same with the initial gas tariff rates; they have said
they will be good for at least three years.
CO-CHAIR WIELECHOWSKI asked if settlement agreements were prima
fascia evidence.
MS. DAVIS replied that they are putting those in the same
category as "adjudicated just and reasonable," but with
conditions. It has to be a settlement agreement that the state
is a party to, the settlement is cost-based (one that on its
face is very similar to what FERC would administer allowing them
to be depreciated, allowing a rate of return on capital - a
normal settlement), and in addition in order for it to be
"evergreen" or to let it ride, the state needs to have a
reopener at least every two years to get out of it if it has
become stale or anachronistic at that point.
CO-CHAIR WIELECHOWSKI said he thought that was an excellent
provision, because he remembered the state getting stuck with a
really bad settlement agreement years ago that cost us billions.
MS. DAVIS said yes; they have had an opportunity to learn from
their experiences in the oil world. She said they are trying to
be fair and balanced and want to have a policy that encouraged
settlement. Litigation generally eats up everybody's dollars.
Finally, if none of those three categories is available because
the facts don't involve them, there is the "default method" or
the methodology they have developed in the regulations that will
establish the reasonable cost of service if it is not an arm's-
length or third-party transaction.
4:31:29 PM
She said it is a cost of service methodology (slide 19) in
proposed regulation 15 AAC 55.197. It is modeled after the FERC
and RCA methodologies where operating and maintenance expenses
are allowed, economic life of the pipe is established, you
depreciate all the capital only once (so if somebody sells it,
it can't be depreciated all over again), you allow income tax
deductions and allow a return on undepreciated capital. They
have essentially tried to look at how the experts (FERC) have
done it and used a similar rate of return which involves getting
a proxy group. To the extent that FERC isn't involved
(unregulated gas treatment plant or something else), they have
selected Moody's All Industrial Users Baa rating (slide 20).
4:33:08 PM
MS. DAVIS said that they have two examples; the first is a
simple one of North Slope gas being delivered to Alberta and the
other one, a more typical example where gas may be delivered to
two places, Alberta and Chicago. They thought that walking
through this example with Fred Hagemeyer, Black & Veatch,
consultant for the Department of Revenue, would eliminate the
pieces they had just gone through in terms of the global
structure.
FRED HAGEMEYER, Black & Veatch, said he would be happy to walk
through example 1 on slide 21. This is intended to encapsulate
many of the things Ms. Davis had been walking through but in a
very simple way. Generally speaking, it starts with production
of 91 mcf, which converts to 100 mmbtu, and will be used most
for the valuations after it leaves the point of production. It
will go down through the gas treatment plant, move down through
transportation facilities (which can be more than one); in this
case the destination is a processing facility in Alberta. There
you would determine a value whether it be through the processes
that were described by Ms. Davis in terms of an actual value or
prevailing value based upon indicators. It turns out that
Alberta has a fairly liquid market, particularly for ACCO, for
residual gas and gas product at Edmonton.
The way the example is set up, they would start at the bottom at
destination value and use 90 mmbtu of residue gas. He mentioned
that the example did not show the gas that would normally be
used as fuel at various stages of the transportation or
treatment. The gas plant products - components of ethane,
propane, butane, and any tanes - would be extracted and
collectively have a 200-gallon volume. The residue gas would be
sold at $6/mmbtu which is the prevailing price in the ACCO
market in this case. This translates over to an absolute dollar
value of $.50/gallon. At that point the destination value is
$640 total. Moving up to a number of allowances in terms of
deductions, one of them would be the processing costs in the
Alberta market. In this case, they have an inlet volume of 100
mmbtu and as that got extracted out it ended up as 90 mmbtu of
residue gas, and gas plant products which are measured in
gallons at that point. Then usually in the case of a gas
processing facility there can be a number of ways to contract
but it can be converted to dollars per mmbtu for a cost factor -
in this case it's $.20. That's a deduction and as you move back
up you also have an allowance for transportation, which is
usually a fairly significant portion. In this example they had
100 mmbtu for volume coming down the Alaska Pipeline for both
the Alaska and the Canadian segments and they used $3/mmbtu
cost. In the Alberta system the cost rate is $.10 to get to the
processing plant or the ACCO market. Then as you move back up,
you have the gas treatment plant expenses (using the total
volume of 100 mmbtu in this case) and a $1 for the throughput
rate. As you subtract those elements, you end up with a total
value at the point of production of $210.
4:39:30 PM
MR. HAGEMEYER moved to example 2 on slide 22 that is very much
the same except that in this example they come down the Alaska
main line and at a point just north of the Alberta market half
of the gas volume goes down the Alliance Pipeline System to
Chicago. This example presumes that there is an interconnection
of Alliance into the Alaska main line at some point before it
enters the Alberta system. The 91 mcf converted to 100 mmbtu
goes through the gas treatment plant; it goes down the Alaska
main line through both the Alaskan and Canadian segments, splits
off into the Alberta and Chicago markets. Those become two
destination markets and would be identified as being liquid
destination markets and both would have residue gas prices as
well as gas products prices.
At the bottom of the example at the Chicago market the residue
gas volume of 45/mmbtu and 100 gallons of gas plant products has
a value of $.60 on average and equaling $60 - 45/mmbtu X $6.75
mmbtu has a value of $303. So, you have a total value of $363 at
that destination. The same process just above it in yellow
happens in Alberta where it has a $6 ACCO price against a
45/mmbtu and 100 gallons of gas plant products that have been
extracted into constituent parts with an average of $.50 per
gallon. Those add up to $320. The deduction for processing in
Chicago is $.20, and $.25 in Alberta. Moving up the example they
also see the TAPS still at $3 for the total volume of 100/mmbtu
(fuel line loss is not shown). The Alberta system has a $.10 for
half the volume at that point. The Alliance Pipeline shows a
$1/mmbtu cost; you also have the 100 mmbtu X the $1 GTP cost.
Eventually you end up with $2.06, and in this case having to
split the volumes you come back with $2.06 for that month as the
value at point of production.
4:42:53 PM
CO-CHAIR WIELECHOWSKI asked if the Alliance Pipeline runs from
Alberta to Chicago.
MR. HAGEMEYER answered yes. It originates in Alberta and
actually truncates in Chicago to an area west of Chicago into a
very large gas plant facility.
4:43:15 PM
COMMISSIONER GALVIN said he wanted to make sure they were clear
that it looks like going to Chicago results in a $43.75 "uplift"
in terms of actual destination value, but when you deduct the
differential cost to get to Chicago from Alberta, it appears to
be about $47.50. He asked given what they described earlier
about prevailing first destination value that in this particular
instance the destination value in Chicago turned out to be less
than the destination value in Alberta, would there be a use of
the Alberta price or would they be able to get the lower point
of production value by going to Chicago.
MR. HAGEMEYER answered in this example if Chicago is determined
to be a destination value then it's felt to be a liquid market
for all the considerations they talked about. The fact that
Chicago has a slightly lower cost for transportation to get
there coming from the end of the Alaska main line just happens
to be the situation that month. It would not change the process
whereby you would look at Chicago because it's been determined
to be the destination value at that point assuming that the
residue gas price is utilized in the destination value
determination.
4:45:42 PM
COMMISSIONER GALVIN said if there is a situation where other gas
than Alaska gas goes to Chicago and Alberta, would that gas have
to be prorated.
MR. HAGEMEYER answered yes. This example does not go into the
fact that very possibly the particular shipper will have other
gas associated with this gas. So the contract that they may be
selling to in Chicago, for example, could have a number of other
streams.
4:46:43 PM
COMMISSIONER GALVIN moved on to the section dealing specifically
with the AGIA inducement regulations (slide 23). The package is
referred to as the ACES regulations dealing with valuation of
transportation and they went out for notice on February 9. There
was a public hearing on March 3, and the comment period closes
on March 15. The section they are moving into now with the AGIA
regulations were noticed on February 19 and the public hearing
was yesterday, March 9; comments are due on those by March 22.
4:48:03 PM
In order to understand the qualification for the AGIA
inducements for both royalty and tax inducements, the
requirements are basically shared between the commissioners of
DOR and DNR; so the application is done jointly. In order to
handle this in the regulatory process because the state has two
different inducements, one in the royalty section of regulations
and one in the tax section, they have two identical descriptions
of how one qualifies in the two different sections of the regs.
Commissioner Galvin said he would be describing the sections
within the tax inducement portion.
He said the sequence of events is that the inducement is
available to shippers who commit to acquire firm capacity in the
initial open season of the AGIA pipeline. A distinction will be
made between shippers who are producers and shippers who acquire
capacity who aren't a producer. In which case those shippers
would acquire a voucher for this inducement and pass it on to
the shipper for their tax and royalty benefit and presumably get
some compensation for that when they make their purchase of the
gas.
In order to identify what shippers qualify for this inducement
they had to look at the transaction that took place between the
pipeline company and the shipper in order to determine who would
ultimately qualify for it. So, they had to define a couple
terms. The first one is a precedent agreement (PA), which is the
agreement that will emerge from the initial open season
transaction between the shipper and the pipeline company. It
will establish the general terms of transportation service that
the shipper will be obligated to acquire if they ultimately
reach the actual agreement to transport the gas which is
referred to as a transportation services agreement (TSA). That
agreement isn't going to be reached until they get down to
sanctioning decisions on the pipeline - you have to get your
FERC certificate, your financing and other things.
SENATOR FRENCH asked if these are standard industry terms.
COMMISSIONER GALVIN answered yes. The PA will also identify the
conditions that will have to be met in order for the shipper to
be obligated to enter into a TSA. As part of the open season
process the pipeline will set out what they are offering as part
of the PA and identify the things they expect the shipper to
agree to and the conditions upon which they could place and open
it up to additional conditions that could be placed during the
open season. Those would have to be negotiated after the open
season to result in a PA that actually identifies that if these
things are met, then you will go to a TSA and that is then the
unconditional obligation to pay the firm transportation (FT)
costs.
4:54:54 PM
The sequence to qualify for the AGIA inducements you have to
apply and demonstrate that you have met the qualification
requirements, and then separately you are eligible for the
royalty inducement which has certain additional requirements in
terms of having to agree to change your leases and other things
that are unique to the royalty inducement; and you also
separately have the tax inducement available through the
regulations that he will describe shortly. So, to be considered
qualified you have to commit to acquire FT capacity in the first
binding open season.
The regs say that in order to be considered to have committed to
acquire FT capacity in the binding open season you have to do
each of the following: submit a bid for FT capacity during the
initial open season, you have to execute a PA within 180 days
after the close of the initial open season, you have to
ultimately execute a TSA within five years of the open season or
two years following FERC certification whichever is later (those
dates align with the sanctioning requirements of the AGIA
statute), and you have to file your paperwork and copies of the
documents, and demonstrate that you have actually done these
things to the commissioners.
SENATOR FRENCH posed a simple hypothetical: open season happens
on May 1, a company (Exxon) wants 1.5 bcf/day in the pipeline,
they submit a bid, they execute a PA with the Alaska Pipeline
Project (subsidiary of TransCanada), and in that they say they
would give them 1.5bcf/day but the only condition is they want
$.05/mcf tax. Is that the kind of condition he meant?
COMMISSIONER GALVIN answered there could be a whole suite of
conditions that could deal most directly with what has to be
done with the pipeline project in order for the shipper to be
obligated to enter into a TSA, but there also could be
conditions that are external to the relationship between the
two, but they would have to be conditions that basically the
pipeline company is willing to have in their PA if they want the
project to go forward.
SENATOR FRENCH asked if TransCanada could conceivably reject a
condition.
COMMISSIONER GALVIN answered yes.
SENATOR FRENCH said assuming there are 10 commercial conditions
and one sort of external one could they agree to go forward with
that external condition embedded in their PA and hope that it
will somehow get resolved in time for them to execute a TSA.
COMMISSIONER GALVIN answered yes. He noted that a big part of
what is happening in the negotiation of the PA is also who is
ultimately responsible for the development costs of getting from
that point in the process to the next big flag in moving to a
TSA; and if the project ends up not going forward at that
ultimate point, who is going to pay for those things. The
conditions are on there as much to provide clarity for that part
of the relationship as well.
SENATOR FRENCH said it's a fairly complex commercial contract
negotiation between two sophisticate parties.
COMMISSIONER GALVIN said, "That's putting it lightly."
CO-CHAIR WIELECHOWSKI asked him to turn to slide 25 where it
says a PA "establishes general terms of transportation service
under which a shipper will be obligated to acquire FT capacity."
Do you have some sort of definition of "general terms?" Would a
producer who agrees to put their 1.5 bcf in the pipeline
assuming they can get fiscal certainty from the state satisfy
the "general term" requirement of PAs?
COMMISSIONER GALVIN answered that this language is not taken
directly from the proposed regs. That sentence is intended to
capture not the conditions he just described but the actual
tariff terms or the general methodology for determining what the
tariff is going to be and how costs are going to be recovered.
An example is just the open season plan that was submitted by
the Alaska Pipeline Project generated 72 pages of comments from
BP on the tariff terms being offered. One of the issues they
raised was in the winter pipeline capacity increases because of
the temperature.
5:03:09 PM
CO-CHAIR WIELECHOWSKI asked if someone agreed to put gas in the
pipeline if they get fiscal certainty or some term like that,
would they be able to get a PA under the regulations.
COMMISSIONER GALVIN answered potentially if their condition is
specified in a way that is acceptable to the Alaska Pipeline
Project for the purposes of their relationship. If they are on a
go-forward basis with a project on the basis of that particular
condition and it is sufficient for them to feel like the
development costs and the risks of going forward are properly
allocated between the parties, based on that condition.
5:04:05 PM
CO-CHAIR WIELECHOWSKI said they are running a little late but
have a few more things to cover. They would be back tomorrow and
next week for the DNR regs. He found no final questions from
committee members; therefore, he adjourned the meeting at 5:04
p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| AGIA Regulations Overview - March 10, 2010.pdf |
SRES 3/10/2010 3:30:00 PM |