Legislature(2007 - 2008)SENATE FINANCE 532
05/03/2007 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB104 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 104 | TELECONFERENCED | |
MINUTES
SENATE FINANCE COMMITTEE
May 3, 2007
9:05 a.m.
CALL TO ORDER
Co-Chair Bert Stedman convened the meeting at approximately
9:05:36 AM.
PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Charlie Huggins, Vice Chair
Senator Kim Elton
Senator Fred Dyson
Senator Donny Olson
Senator Joe Thomas
Also Attending: DAVID KEANE, Vice President, Policy and
Corporate Affairs, BG North America; DAN DICKINSON, Certified
Public Accountant, Certified Management Accountant, and
Legislative Consultant, Legislative Budget and Audit;
Attending via Teleconference: There were no teleconference
participants.
SUMMARY INFORMATION
SB 104-NATURAL GAS PIPELINE PROJECT
The Committee heard from a representative from industry and a
legislative consultant. The bill was held in Committee.
9:05:47 AM
CS FOR SENATE BILL NO. 104(JUD)
"An Act relating to the Alaska Gasline Inducement Act;
establishing the Alaska Gasline Inducement Act matching
contribution fund; providing for an Alaska Gasline
Inducement Act coordinator; making conforming amendments;
and providing for an effective date."
This was the sixteenth hearing for this bill in the Senate
Finance Committee.
9:05:49 AM
DAVID KEANE, Vice President, Policy and Corporate Affairs, BG
North America introduced himself and informed that his
presentation would be accompanied by a handout titled "BG North
America, Legislative Hearings, David Keane, Juneau, 3-4 May
2007" [copy on file].
9:07:33 AM
Page 3
BG Group snapshot
· A world leader in natural gas
· A FTSE 20 company, listed on London and New York Stock
Exchanges
· Market capitalisation over $49 billion
· Production circa 70% gas; 30% oil
· Employs approx 4,766 staff; 64% outside UK, at year
end 06
The integrated gas major
Mr. Keane overviewed this page, noting that BG was primarily
focused on exploring for and developing natural gas reserves
rather than oil.
9:08:59 AM
Page 4
Business model
[Pictorial illustrating BG's involvement in exploration and
production of liquefied natural gas, transmission,
distribution, and power.]
Resources - Enabling - Markets
A global natural gas business
Mr. Keane revealed that BG was the largest importer of liquefied
natural gas (LNG) into the United States, transporting 49.8
percent of the imported LNG. The company also had a "strong
presence" in South America as a natural gas distributor.
9:09:53 AM
Senator Huggins asked if BG was solely the transporter, or the
owner-transporter, of the LNG imported to the U.S.
Mr. Keane responded that BG was involved in exploration and
production of gas, and controlled 20 ships through ownership or
long-term charters. BG did not own regasification facilities in
the US, but leased 100 percent of entry capacity at the Lake
Charles, Louisiana facility, as well as the majority of capacity
at the Elba Island facility.
9:10:47 AM
Senator Huggins clarified that his question was if BG owned the
gas that it imported to the US.
Mr. Keane affirmed that BG owned all the gas it transported.
9:11:03 AM
Page 5
Countries of current operation
[World map depicting the locations of BG operations in
Canada, United States, Trinidad & Tobago, Bolivia, Brazil,
Argentina, Uruguay, Italy, the UK, Norway, Tunisia,
Algeria, Nigeria, Libya, Egypt, Madagascar, Israel/PA,
Oman, Kazakhstan, India, Malaysia, Singapore, Thailand,
China and the Philippines.]
Active in over 25 countries
Mr. Keane summarized this page.
9:11:18 AM
Page 6
Gas market focus
[World map with overlay indicating Developed Market,
Developing Market, and Supplies.]
Connecting gas to markets
Mr. Keane reviewed this page, noting that BG's primary market
was Europe and added that the company was expanding its business
in North America.
9:11:33 AM
Page 7
Global gas trade - the recent past
[World map with overlay indicating Markets, LNG, and Pipe]
Industry evolution: from three main trade regions…
Mr. Keane recounted that until recently, natural gas generally
remained in the region where it was discovered and produced.
9:12:16 AM
Page 8
Global gas trade - gradually evolving
[World map with overlay indicating Markets, LNG, and Pipe.]
…to a globalizing gas industry
Mr. Keane spoke to this page, and shared that current trends
tended to favor global marketing to meet demands.
9:13:16 AM
Page 9
BG LNG supply projects
Atlantic LNG, Company of Trinidad and Tobago
· Train 1: 3.1 mtpa - 1999 (BG 26.0%)
· Train 2/3: 6.6 mtpa - 2002 (BG 32.5%)
· Train 4: 5.2 mtpa - 2005: (BG 28.9%)
· BG initiated project and was instrumental in Phillips
design
· Single train start-up
Liquefied Natural Gas, Egyptian LNG
· Train 1: 3.6 mtpa - 2005 (BG 35.5%)
· Train 2: 3.6 mtpa - 2005 (BG 38.0%)
· Egypt's largest project financing to date
· Unique project commercial structure
· Utilized lessons learnt from ALNG
Atlantic LNG - total export capacity of 15 mtpa in just 7
years
Mr. Keane overviewed this page, noting that Atlantic LNG was one
of the largest facilities in the world. Egyptian LNG was "up and
running" within five years of the initial gas discovery in that
region.
9:13:58 AM
Senator Dyson asked for a definition of "mtpa".
Mr. Keane defined mtpa as "million tons of LNG per annum".
9:14:20 AM
Page 10
US market summary
· Lake Charles import terminal
· Phase I expansion Q4 2005
o 1.2 bcf/d sustainable send out
o 1.5 bcf/d peak send out
o 9.1 bcf total storage
· Phase II expansion Q2 2006
o 1.8 bcf/d sustainable send out
o 2.1 bcf/d peak send out
· Elba Island import terminal
o 0.45 bcf/d sustainable send out
o 0.67 bcf/d peak send out
o 4.0 bcf storage
o 1.17 bcf/d firm send out & 8.2 bcf storage after
second expansion
Capacity in two of the four existing US onshore terminals
Mr. Keane reminded that BG held leases for 100 percent of the
Lake Charles facility, and had assisted in significantly
expanding that facility. A recently completed pipeline from Elba
Island to northern Florida provided that state with access to
natural gas from a source other than the Gulf of Mexico for the
first time.
9:15:34 AM
Page 11
LNG imports - 2003 to present
Share of US LNG imports
[Bar graph depicting the percentage of US LNG imported by
BG, Distrigas, BP, Shell, Statoil, and Other for the years
2003, 2004, 2005, and 2006, and listing the total mt for
each year.]
BG - the largest US LNG importer in 2003, 2004, 2005 and
2006
Mr. Keane overviewed this page.
9:15:47 AM
Page 12
Alaska E&P
[Map of Alaska showing Alaska North Slope Gasline,
Potential Spur Lines to Southcentral, Existing Gas
Transmission Network, Potential Offtake Points, and
Existing Commercial Natural Gas Users.]
2.1 million acres in the Foothills of ANS and .2 million in
the ENS
Mr. Keane summarized this page, and informed that BG was
currently in partnership with Anadarko in exploration efforts in
the Foothills area of the North Slope, as well as on the Eastern
North Slope.
9:16:11 AM
Page 13
Alaska Gasline Inducements Act
· BG is investing in Alaska
o Exploring along North Slope and ENS
· BG supports AGIA
o The process is fair, open and inclusive
o BG supports the mandatory provisions on access
and rates
o Will encourage new explorers to invest in Alaska
· AGIA provides:
o Opportunities for input by all interested parties
o Several opportunities for legislators to provide
input:
ƒInitial legislation
ƒWhen pipeline applications are submitted
ƒLegislative review of the winning
application
AGIA will encourage development
Mr. Keane reviewed this page, and stressed the importance of the
construction of a natural gas pipeline in Alaska.
9:17:20 AM
Page 14
Alaska Gasline Inducements Act
· AGIA addresses BG's concerns by:
o Providing a level playing field for all
participants
o Providing certainty that when we discover gas, we
will have access to pipeline capacity
o Providing a mechanism to ensure just and
reasonable rates
· AGIA creates competition to build the pipeline and
possibly an LNG export facility
· AGIA spells out what is required of any applicant
· Clearly identifies the Sate's "must haves"
· BG's "must haves" are:
o Regulated pipeline
o Open access provisions in the tariff
o Just and reasonable rates
AGIA will encourage development
Mr. Keane spoke to this page, characterizing the Alaska Gasline
Inducement Act (AGIA) as an "extremely fair process", regulated
by either the Federal Energy Regulatory Commission (FERC) or by
the Regulatory Commission of Alaska (RCA).
9:18:45 AM
Page 15
Key messages
· AGIA is good for Alaska and for the natural gas
industry
· AGIA will encourage the continued development of
Alaska's untapped natural gas reserves
· AGIA's purpose:
o "…to encourage expedited construction of a
natural gas pipeline that
1) Facilitates commercialization of North Slope
gas resources of the state;
2) promotes exploration and development of oil
and gas resources on the North Slope;
3) maximizes benefits to the people of the
state from the development of oil and gas
resources in the state; and
4) encourages oil and gas lessees and other
persons in the state to commit natural gas
from the North Slope to a gas pipeline
system for transportation to markets in this
state or elsewhere."
Alaska must continue to encourage development
Mr. Keane summarized this page, and stressed that AGIA would
"serve as a vehicle" for the expedited construction of a natural
gas pipeline. He contended that the application process should
commence prior to debate regarding specific aspects of pipeline
construction and management.
9:19:55 AM
Co-Chair Stedman referred to page 14, and quoted BG's claim that
AGIA would address concerns by "providing a level playing field
for all participants." He asked for a definition of "all
participants."
Mr. Keane understood AGIA to provide equality for new explorers,
applicants who want to build Alaska's pipeline, the "big three"
producers, and the Alaska State Legislature. All parties would
have access to information and an opportunity to participate.
9:20:55 AM
Co-Chair Stedman asked regarding access to the pipeline, and
inferred that BG regarded FERC as a "non-functioning entity"
unable to ensure access to the pipeline via its regulatory
authority.
Mr. Keane disagreed with that statement, and clarified that BG
judged that regulation of the pipeline would be necessary, by
FERC or another interstate regulatory body.
Co-Chair Stedman asked if an interstate pipeline could avoid
FERC regulation.
Mr. Keane was not aware of a method to circumvent FERC
regulation.
Co-Chair Stedman indicated that FERC would regulate the pipeline
and determine the appropriate level of "openness and access".
Mr. Keane affirmed.
9:22:18 AM
Co-Chair Stedman asked if BG intended to participate in the
first binding open season.
Mr. Keane explained that BG was "eager" to participate in AGIA,
and would be drilling next winter in the foothills along the
North Slope. He continued that BG could "conceivably" have
adequate natural gas reserves within three to four years to
commit to the pipeline in the form of a firm transportation (FT)
agreement. If BG did not have sufficient reserves to commit to
capacity during the first open season, the company anticipated
doing so in the second open season.
9:23:22 AM
Co-Chair Stedman provided the following comments.
Binding commitments by showing up to the first open season,
or the first binding open season, you would receive under
AGIA is some fiscal stability. Currently in the bill it's
ten years, the tax rate is 22.5 percent, and there's a
couple little issues with progressivity we have to work on
mechanically, but. So does your firm have any issues with
not having any [fiscal] stability past the binding first
open season?
Mr. Keane asserted that BG had concerns with the fiscal
certainty provisions in the bill. He opined that companies
actively exploring should be granted a measure of fiscal
stability, whether reserves had been identified at the time of
the first open season or not.
Co-Chair Stedman asked for recommended language changes from BG,
as well as identification of provisions in the bill supported by
the company.
9:25:09 AM
Senator Dyson was impressed with BG's presentation, and asked if
the company was interested in building or partnering to build
the Alaska natural gas pipeline.
Mr. Keane responded that BG was not currently considering
building the pipeline.
Senator Dyson asked if BG was confident that FERC would provide
access to all shippers regardless of who built and operated the
pipeline.
Mr. Keane opined that the best interest of the State and
explorers would be served if an independent third party built
and operated the pipeline. If a major producer had an ownership
interest in the pipeline, adherence to strict affiliate rules in
term of access to information would be important.
9:26:47 AM
Senator Dyson asked for an explanation of "strict affiliate
rules".
Mr. Keane clarified that strict affiliate rules would guarantee
that a marketing affiliate would not have access to information
which was not available to the rest of the industry.
9:27:19 AM
Co-Chair Stedman asked Mr. Keane to provide specific references
in FERC regulations that appeared insufficient to protect
pipeline access interests.
Mr. Keane would provide that information to the Committee.
9:28:14 AM
Senator Thomas relayed concern that was expressed in previous
testimony that the shippers would bear the financial risk of the
pipeline project. He asked why BG did not appear concerned with
the risk borne by the shippers.
Mr. Keane responded that the risk would be spread to all
producers in the form of FT commitments, and that he expected
shippers to be "extremely involved" in the regulatory process
upon award of a license under AGIA.
9:29:46 AM
Senator Huggins asserted that FERC was a "federal body" that
operated independent of the producers, pipeline investors, and
the State of Alaska.
9:30:23 AM
Mr. Keane agreed. He stated that FERC would be involved if the
pipeline served interstate commerce. Additionally, several of
the parties that would likely be involved with the pipeline were
currently embattled in legal matters challenging FERC decisions
related to access. This was a concern to BG.
9:31:17 AM
Co-Chair Stedman asked if BG had argued a case before FERC.
Mr. Keane affirmed.
Co-Chair Stedman requested a list of cases BG had argued before
FERC within the past ten years.
9:31:31 AM
Senator Huggins asked for evidence to support the claim on page
15 that AGIA would "encourage expedited construction" of the
gasline.
Mr. Keane answered that AGIA would advance the project. The
proposed contract offered by former Governor Murkowski to the
Legislature the previous year was not inclusive and had other
faults. AGIA set forth specific timelines and real measures of
progress for the construction of a natural gas pipeline.
9:33:29 AM
Senator Huggins retorted that some elements of AGIA "do the
opposite" of expediting a pipeline, such as the allowance of
five years to acquire financing for the project.
9:34:13 AM
Senator Elton understood Mr. Keane's testimony to indicate that
BG's preference would be that a pipeline company would build the
gasline. Producers had expressed a desire to be involved in the
construction process to exercise cost control and prevent an
overly burdensome tariff as the result of construction cost
overruns. He asked if BG shared similar concerns.
Mr. Keane informed that BG, as a company that would participate
in the open seasons, would monitor and intervene during the
construction process to contain tariffs and costs.
9:35:33 AM
Co-Chair Stedman relayed that TransCanada and Enbridge had
testified they had the capability to build the gasline, but
preferred that it be constructed by a consortium. He asked if BG
would be financially able and interested in participating in a
pipeline consortium if adequate reserves were identified.
Mr. Keane replied that BG would not be interested in building
the pipeline, and expected that a consortium of pipeline
companies would ultimately construct the project.
9:36:50 AM
Co-Chair Hoffman asked why Alaska was not included in the "Gas
market focus" map on page 6 of the presentation, and also asked
what role China had as a developed market.
Mr. Keane responded that Alaska was considered part of North
America, and therefore included in the North America category.
Currently volumes of gas were moved from Alaska to Japan.
Co-Chair Hoffman clarified that his question referred to
supplies and developing markets. The map did not show Alaska as
a major market supply.
Mr. Keane directed attention to page 8 which depicted the
evolving global gas trade. Alaska was shown as a supplier of LNG
to the continental U.S.
Co-Chair Hoffman understood the "evolution" of the gas market,
and reiterated that Alaska was not shown as a developing market
or a supply of gas on the chart on page 6.
9:39:04 AM
Mr. Keane explained that the map on page 6 illustrated the
company's market focus, not the global distribution of gas.
9:39:26 AM
Senator Thomas asked regarding the anticipated "consortium" that
would build the pipeline, and whether Mr. Keane was familiar
with the experience of the Alliance pipeline project. In that
instance, producers were initially involved but had entirely
sold out their interests by completion of the project. He asked
if it would be reasonable to expect a similar outcome from the
anticipated Alaska gas pipeline consortium.
Mr. Keane answered that BG would not be concerned if a producer
held an interest in the pipeline company, as the gasline would
be a major undertaking which would likely require the "pooling"
of resources.
9:40:57 AM
Senator Thomas asked regarding BG's presence in Canada.
Mr. Keane informed that BG had exploration business in the
Western Canadian Sedimentary Basin and in the Northwest
Territories.
Senator Thomas asked if BG was producing in those areas.
Mr. Keane replied that BG had sold most of the small producing
areas, and was focused on developing larger resources.
9:41:35 AM
Senator Huggins informed that TransCanada and Mid-America had
indicated interest in participating in the construction of the
gasline, and asked for a prediction of what entity would build
the Alaska gas pipeline.
9:42:14 AM
Mr. Keane could not speculate on who would build the gasline.
Senator Huggins asked if Mr. Keane was aware of any other
parties qualified to take part in the AGIA process.
Mr. Keane was unable to provide that information.
9:42:32 AM
Senator Huggins understood that the FT commitments made during
the first binding open season would provide a "key piece" to
ensure financing for the construction of the natural gas
pipeline.
Mr. Keane affirmed.
Senator Huggins furthered that the FT commitments carried
obligation and debt burden.
Mr. Keane agreed.
9:43:13 AM
Co-Chair Stedman described the two most important issues to BG
as guaranteed access to the pipeline and a fair tariff rate.
Mr. Keane affirmed. BG's primary concerns were securing access
to a pipeline to transport gas to market, and fair tariff rates
in the form of rolled-in rates. The guarantee that the initial
shippers' rate would not exceed 15 percent of the preliminary
rate was sufficient protection.
Co-Chair Stedman asked BG's experience with tariff rate
structures world-wide, and whether negotiated, incremental or
rolled-in rates were most common.
9:44:56 AM
Mr. Keane replied that the rate structure depended on the
condition of the market. The U.S. exhibited competing pipelines
while other countries had no competition for gas transportation,
thus the tariffs in these areas differed greatly.
9:45:21 AM
Co-Chair Hoffman referred to the bar graph on page 11, and asked
how the gas was imported to the United States and if the
imported gas depicted on that page was utilized primarily to
supply the East Coast market. He furthered, asking how BG would
address the gas needs of the United States in the absence of an
Alaska natural gas pipeline.
Mr. Keane answered that the LNG imported into the U.S. arrived
via tanker ships and was delivered into the terminals at Elba
Island and Lake Charles where BG had leased space. Those
facilities were connected by pipeline to deliver gas to U.S.
markets in the Midwest and East Coast.
9:47:03 AM
Co-Chair Hoffman asked if BG would increase its tanker fleet to
import more LNG to meet U.S. demands if the Alaska natural gas
pipeline did not reach fruition.
Mr. Keane responded that BG currently owned seven ships and
would receive two more within the year. Two additional ships
would be delivered by 2010, and BG also had long-term charters
of nine other vessels, for a total of approximately 20 tanker
ships world-wide. He continued to express the desirability of a
natural gas pipeline to transport North Slope gas to American
markets.
9:48:14 AM
Co-Chair Hoffman asked if BG would prefer a pipeline that
transported gas to Alberta to tie into existing pipeline
infrastructure, or a pipeline that transported gas to Valdez to
be shipped by ocean going tanker.
Mr. Keane informed that a pipeline to Alberta would produce
greater "net backs" than carrying the gas by tanker from Valdez
to the West Coast of the U.S.
9:48:46 AM
Co-Chair Stedman asked Mr. Keane to repeat his remark.
Mr. Keane reiterated that a pipeline into the Continental U.S.
would produce greater revenues than would transporting the gas
by tanker.
Co-Chair Stedman concluded that the reference to "net back"
indicated the returns to the company and the State.
9:49:18 AM
Mr. Keane agreed that the net back would be greater on gas
shipped via pipeline, provided that the gas was destined for the
U.S. If the gas was to be shipped to the "Far East," the two
modes of transportation would be comparable.
9:49:38 AM
Senator Thomas asked regarding the map on page 8, which appeared
to illustrate the flow of gas from Australia and Southeast Asia
to the West Coast of the United States. He asked if BG
anticipated the construction of receiving facilities on the West
Coast in the near future.
Mr. Keane replied that shipping gas to the West Coast was a long
range goal.
Senator Thomas asked if BG expected the need for energy to have
an impact on development in that area.
9:51:03 AM
Mr. Keane did not expect energy pressures to have an immediate
impact on the construction of new natural gas receiving
facilities on the West Coast.
9:51:23 AM
Senator Olson referred to page 11 of the presentation and asked
for an estimate of the anticipated LNG imports for 2007, taking
into consideration North Slope production.
Mr. Keane was unsure regarding North Slope production, but
anticipated an increase in LNG imports to the U.S. due to lower
prices in Eastern Asia, Europe and Japan. A mild U.S. winter and
colder winters in Europe and Asia caused LNG that was originally
bound for the U.S. to be diverted to other markets with higher
demand.
Senator Olson asked regarding fiscal certainty. He referenced
the Baku-Tbilisi-Ceyhan (BTC) pipeline project's 60 year tax
agreement, but pointed to political instability that could
negate that fiscal certainty. He asked how these circumstances,
as well as the recent nationalization of Trinidad and Tobago
petroleum, could affect investments internationally.
9:54:01 AM
Mr. Keane corrected that Trinidad and Tobago were politically
very safe and reliable. He assumed that Senator Olson was
referring to Venezuela, which had witnessed seizure of petroleum
assets.
Senator Olson surmised that BG did not anticipate any problems
with foreign investment.
Mr. Keane stated that the production in Trinidad and Tobago as
well as Egypt was stable.
Senator Olson commented that in the area he represented,
Venezuelan President Hugo Chavez had "been a major factor in
heating the homes", referring to the provision of subsidized
heating oil offered by Chavez.
Co-Chair Stedman directed, "We're not going to go down that road
here."
9:55:00 AM
Senator Elton asked if BG placed greater value on tax stability
or political stability.
Mr. Keane responded that both political and fiscal stability
were extremely important.
9:55:53 AM
Senator Thomas observed the prolific use of nuclear power in
Europe, and asked if BG viewed that as a realistic future energy
source.
Mr. Keane opined that nuclear power was important, providing
approximately 93 percent of generation capacity in France, and
contributing to power sources in the UK. The issue was national
and would have to be decided in the future.
AT EASE 9:57:41 AM/10:05:26 AM
DAN DICKINSON, Certified Public Accountant, Certified Management
Accountant, and Legislative Consultant, Legislative Budget and
Audit, communicated that he would provide a presentation to
address four key questions posed by legislators. His
presentation would be accompanied by a handout titled
"Presentation to the Alaska Legislature, Senate Finance
Committee, May 3, 2007, Dan E. Dickinson, CPA, CMA" [copy on
file].
10:06:45 AM
Page 2
Question 1:
· How is gas generally taxed under the PPT? What are the
PPT credit implications of gasline work?
· Same as oil (almost) - on net value
· Investment downstream of point of production not
eligible for credits
Mr. Dickinson reminded that the State collected revenues from
petroleum operations in Alaska in four ways: royalties,
production taxes, special income taxes and special property
taxes. He would focus on production taxes and credits. Credits
were available only for costs incurred upstream of the point of
production. The costs associated with the construction of the
natural gas pipeline would be considered downstream costs and
would not be eligible for credits under the Petroleum Profits
Tax (PPT) enacted by the prior Legislature.
10:08:26 AM
Page 3
How is gas taxed under the PPT
· 43.55.011
· (e) 22.5% of net value
· (f) North Slope floor triggered by oil price
· (g)&(h) Progressivity triggered by single taxpayer net
value
· Private royalty 1.67% for gas - 1/3 of oil
· (j) Cook Inlet Ceiling
Mr. Dickinson summarized the five manners in which gas was taxed
under PPT, and would address each tax individually.
10:09:12 AM
Page 4
AS 43.55.011(e) 22.% of net value
· Total upstream costs are deducted from the revenue
streams from oil and gas sales.
· Gas Revenue Exclusion (GRE) mechanism discussed in
2006 is an administratively simple way of adjusting
the effective rate without changing the nominal rate
or making lots of allocations.
Mr. Dickinson corrected that the page should reflect "22.5% of
net value". It was not possible to separate the volumes of oil
from the volumes of gas at the wellhead, and he therefore
recommended a Gas Revenue Exclusion (GRE) provision, which would
make differentiation between gas and oils costs less complex.
This method would tax a percentage of the value generated from
the sale of gas, and was the recommended mechanism for providing
a lower tax to distance gas.
10:11:12 AM
Page 5
43.55.011(f) North Slope floor triggered by oil price
· Alternative floor just applicable to North Slope Oil
and Gas is triggered by oil price.
o Consider future if Prudhoe Bay is producing
250,000 bbls oil and 3 bcf of gas.
o If the heating value is 1,000,000 btu per mcf,
that translates to the equivalent of 500,000 bbls
a day - so 1/3 of the field's production will be
used to set the trigger.
Mr. Dickinson reminded that tax reforms under PPT changed the
tax base from a gross to a net value, and established a "floor"
on gross oil prices. He summarized the examples on the page as
illustrative of the fact that if gas production was higher than
oil, oil prices would still determine the floor. In a situation
of high oil prices and low gas prices, the floor would not be
"triggered", regardless of the quantities produced of each
product. He suggested that the Committee may reconsider that
aspect of the PPT.
10:13:31 AM
Page 6
Also insert Question 3 here:
· Question 3. How does PPT Progressivity work on gas and
what is it's link to oil?
Mr. Dickinson read this page.
10:13:42 AM
Page 7
AS 43.55.011(g)&(h) Progressivity triggered by single
taxpayer net value
· Progressivity is determined for each taxpayer on its
mix of oil and gas and all upstream costs
· Calculated on a monthly basis - monthly upstream costs
are 1/12 of the total annual costs
· Example - Next slide
o Prices April 27 2007,
o 1,000 btu per mcf,
o Equal mix of boe gas and oil
Mr. Dickinson corrected that the example on the following page
should read "1,000 btu per cubic foot", which would equal one
million btu per thousand cubic feet.
10:14:33 AM
Page 8
AS 43.55.011(g)&(h) Progressivity triggered by single
taxpayer net value
Dest Price
Oil: 63.76
Gas: 7.32
Downstream Adj
Oil: (5.00)
Gas: (3.00)
Gross Value
Oil: 58.76
Gas: 4.32
6.00
Gas BOE: 25.92
Upstream Adj
Oil: (7.00)
Gas BOE: (7.00)
Net Value:
Oil: 57.76
Gas BOE: 18.92
Taxpyr Ave: 35.34
.011(h) limit
Oil: (40.00)
Gas BOE: (40.00)
Taxpyr Ave: (40.00)
Price Index
Oil: 11.76
Gas BOE: N/a
Taxpyr Ave: N/a
.011(g) factor
Oil: 0.0025
Gas BOE: 0.0025
Taxpyr Ave: 0.0025
Progressivity %
Oil: 2.940%
Gas BOE: N/a
Taxpyr Ave: N/a
Mr. Dickinson testified as follows.
The destination price, I pulled it out of the newspaper,
was $63.76. Let's assume for a minute that TAPS and the
tankering costs are $5.00. I'm using all sort of round
numbers here. And that would leave you a gross value of
$58.76. Let's assume that upstream costs …I'm assuming a
number $7.00 worth of per barrel costs, and that brings us
out to a net value of $51.76. The law says that we compare
that to $40.00, and so what the law calls the price index,
we're $11.76 over that. What you stipulated was that for
every dollar over the base price, over the price index, you
would add a quarter of a percentage point of progressivity,
and so the net result is there's about 2.94 percent, and
just so I can sort of do this in my head, if we call that
three percent, you take three percent of 51, and so what
you would see at today's prices folks are paying about 1.50
in every barrel on a progressivity charge. So they pay a
22.5 percent charge, and on top of that they pay another
$1.50.
10:15:54 AM
Mr. Dickinson continued his testimony as follows.
Let's go over to the next column. I again went to the
newspaper, $7.32 for a thousand cubic feet of gas. Who
knows what the tariff is going to be, I used $3.00 and that
leaves ya $4.32. At my assumption of how many btus there
are per mcf, we end up saying a gas barrel of equi, a
barrel of equivalent of gas will now be worth $25.92. It's
significantly lower. We said, my assumption that oil and
gas are split fifty-fifty, so I'm gonna use that same $7
charge, and we come out to $18.92 in net value. That's way
below the $40 in limit. So the gas, if the gas were
standing alone, would not pay any progressivity and if you
average the two numbers together they don't pay any
progressivity. So what's really happening is, because the
charge, the tariff, the cost of getting the gas to market
is such a significant percentage of its destination value,
when you look at the well head a barrel equivalent, a gas
barrel equivalent will contribute a whole lot less than an
actual barrel of oil. Again, as you can see, $5 is, you
know, seven or eight percent of the destination price of
63, but a three dollar tariff is between a third and half
of the gas price. So, the point I want to make here is on
the kind of prices we see today, and let's assume that's
not typical or average but it's what we might expect in
that range, generally a producer who has a lot of gas, that
will lower their progressivity payments. And in fact in the
example I gave here, I think most of us, maybe it's just
those of us who've been around a while consider $63.76 an
extraordinarily high oil price, and yet if we were in a
situation where we were producing half gas and half oil, it
would not be sufficient to generate a progressivity charge.
10:18:04 AM
Mr. Dickinson noted that other versions of AGIA had contained
progressivity provisions that would speak to gas prices without
considering the upstream calculations. The tariff for gas would
represent a much larger percentage of the "final realization"
price, thus reducing progressivity rates.
10:18:44 AM
Page 9
Dollar/bbl Progressivity Charge at various Destination
values and net deductions
Per barrel Progressivity Charge
Per Barrel Costs: 5
Monthly Average Destination Value per bbl in Dollars
50: 0.56
55: 1.25
60: 2.06
65: 3.00
70: 4.06
75: 5.25
80: 6.56
Per Barrel Costs: 6
Monthly Average Destination Value per bbl in Dollars
50: 0.44
55: 1.10
60: 1.89
65: 2.80
70: 3.84
75: 5.00
80: 6.29
Per Barrel Costs: 7
Monthly Average Destination Value per bbl in Dollars
50: 0.32
55: 0.96
60: 1.72
65: 2.61
70: 3.62
75: 4.76
80: 6.02
Per Barrel Costs: 8
Monthly Average Destination Value per bbl in Dollars
50: 0.21
55: 0.82
60: 1.56
65: 2.42
70: 3.41
75: 4.52
80: 5.76
Per Barrel Costs: 9
Monthly Average Destination Value per bbl in Dollars
50: 0.10
55: 0.69
60: 1.40
65: 2.24
70: 3.20
75: 4.29
80: 5.50
Per Barrel Costs: 10
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: 0.56
60: 1.25
65: 2.06
70: 3.00
75: 4.06
80: 5.25
Per Barrel Costs: 11
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: 0.44
60: 1.10
65: 1.89
70: 2.80
75: 3.84
80: 5.00
Per Barrel Costs: 12
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: 0.32
60: 0.96
65: 1.72
70: 2.61
75: 3.62
80: 4.76
Per Barrel Costs: 13
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: 0.21
60: 0.82
65: 1.56
70: 2.42
75: 3.41
80: 4.52
Per Barrel Costs: 14
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: 0.10
60: 0.69
65: 1.40
70: 2.24
75: 3.20
80: 4.29
Per Barrel Costs: 15
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: n/a
60: 0.56
65: 1.25
70: 2.06
75: 3.00
80: 4.06
Per Barrel Costs: 16
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: n/a
60: 0.44
65: 1.10
70: 1.89
75: 2.80
80: 3.84
Per Barrel Costs: 17
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: n/a
60: 0.32
65: 0.96
70: 1.72
75: 2.61
80: 3.62
Per Barrel Costs: 18
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: n/a
60: 0.21
65: 0.82
70: 1.56
75: 2.42
80: 3.41
Per Barrel Costs: 19
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: n/a
60: 0.10
65: 0.69
70: 1.40
75: 2.24
80: 3.20
Per Barrel Costs: 20
Monthly Average Destination Value per bbl in Dollars
50: n/a
55: n/a
60: n/a
65: 0.56
70: 1.25
75: 2.06
80: 3.00
Mr. Dickinson summarized this table, and pointed out that at
current oil prices of approximately $65 per barrel, the
producers would pay approximately $1.50 to $2.00 per barrel in
progressivity charges.
10:19:23 AM
Co-Chair Stedman acknowledged that the PPT legislation was
drafted with the assumption that the State would take its gas
payments "in kind". He understood that the current
Administration had proposed modifications that effectively
caused progressivity to "act as a dilution" to State revenues.
Mr. Dickinson agreed. The general understanding of the 24th
Alaska State Legislature was that the PPT should stand alone
with or without a gasline contract. He shared that Cook Inlet
currently produced approximately 100,000 barrels of gas per day,
and the companies that had both Cook Inlet and North Slope
production were enjoying the "degradation" of the PPT
progressivity taxes.
10:20:55 AM
Page 10
AS 55.43.011(i) Private Royalty 1.67% of gross for gas
· This is one third the rate for oil which is 5% of
gross.
Mr. Dickinson reviewed this page.
10:21:52 AM
Page 11
AS 43.55.011(j) Cook Inlet Ceiling
· No direct effect on North Slope gas
· Expires in 2022
· If gas line is built from North Slope to Cook Inlet
may want to consider effect of differential rates of
taxation
· Ceiling potentially different for each producer:
o Average (15 AAC 55.440) 4.947% of $3.585 per mcf.
Mr. Dickinson commented that the tax structure for Cook Inlet
gas would be very different than the taxes levied on North Slope
gas.
10:22:42 AM
Page 12
Question 2:
· Are PPT gas credits applicable to the GTP in the AGIA
bill?
· Under PPT - the GTP is not eligible for credits.
Mr. Dickinson informed that under current law gas treatment
plants were not eligible for the PPT tax credits. The
definitions in AGIA would "confuse" that issue, and he would
offer a very specific recommendation to clarify the matter.
Co-Chair Stedman asked the "rough magnitude" of the credit
dollars involved.
Mr. Dickinson responded that a gas treatment plant could
constitute an expense of approximately two to three billion
dollars, thus a 20 percent credit could amount to $600 million.
Co-Chair Stedman explained that a tax credit would have the
effect of reducing the revenues received by the State.
10:24:06 AM
Mr. Dickinson specified that the PPT tax credit was designed to
encourage upstream activity and exploration and was not related
to the construction of a gas pipeline.
Co-Chair Stedman surmised that the legislature must be precise
in drafting language in AGIA relating to the PPT tax credits to
avoid conflicting legal interpretations.
10:24:50 AM
Mr. Dickinson affirmed that no ambiguity should exist, and that
the gas treatment plant (GTP) was defined under the PPT
legislation as a downstream facility that would not qualify for
the tax credit.
10:25:20 AM
Page 13
Only Upstream Costs Qualify as Credits
· AS 43.55.023(a) "…may take a tax credit for a
qualified capital expenditure…in the amount of 20
percent of the expenditure;"
· AS 43.55.023(k) "…'qualified capital
expenditure'…means…an expenditure that is a lease
expenditure under AS 43.55.165 and is…treated as a
capitalized expenditure under 26 U.S.C. (Internal
Revenue Code)
Mr. Dickinson summarized this page.
10:26:04 AM
Page 14
Only Upstream Costs Qualify as Credits
· AS 43.55.165(a) "…a producer's lease expenditures for
a calendar year are the ordinary and necessary costs
upstream of the point of production of oil and gas…and
that are the direct costs of exploring for developing,
or producing oil or gas…
Mr. Dickinson noted that this statute clearly specified that the
tax credit applied only to costs upstream of the point of
production.
10:26:31 AM
Senator Dyson asked for the definition of "point of production".
Mr. Dickinson answered that the next pages would address that
question.
10:26:41 AM
Page 15
Where is the point of Production?
· In AS 43.55.900
· (21) gas processing
· (23) gas treatment
· (27) point of production
· Are defined so that gas processing is upstream of the
point of production and gas treatment is downstream of
the point of production.
Mr. Dickinson revealed that gas processing is defined in statute
as upstream of the point of production, and gas treatment is
downstream from the point of production.
10:27:11 AM
Page 16
PPT Definitions: Point of Production
· AS 43.55.011(27) "point of production" means
· (A) for oil…
· (B) for gas, other than gas described in (c) of this
paragraph that is
· (i) not subjected to or recovered by mechanical
separation or run through a gas processing plant, the
first point where the gas is accurately metered;
· (ii) subjected to or recovered by mechanical
separation but not run through a gas processing plant,
the first point where the gas is accurately metered
after completion of mechanical separation;
Page 17
PPT Definitions: Point of Production
· AS 43.55.011(27) "point of production" means
· (B) for gas…
· (iii)run through a gas processing plant, the first
point where the gas is accurately metered downstream
of the plant
· (C)for gas run through an integrated gas processing
plant and gas treatment facility that does not
accurately meter the gas after the gas processing and
before the gas treatment, the first point where the
gas processing is completed of where gas treatment
begins, whichever is further upstream.
Mr. Dickinson stressed that subparagraph (B)(iii) of AS
43.55.011(27) identified the point of production of gas
processed through a gas processing plant as "the first point
where the gas is accurately metered downstream of the plant".
Subparagraph (C) established the point of production for gas
that had been run through an integrated gas processing plant.
Mr. Dickinson relayed that he had been asked how the point of
production would be affected if the gas treatment plant was
placed upstream from the gas processing facility. In that
instance, although the gas would be treated prior to its entry
into a processing facility, the definition still stipulated that
the point of production was located at the first point that gas
treatment began. Therefore, the point of production would "move"
upstream, and the treatment and processing costs would remain
ineligible for the PPT tax credits.
10:29:02 AM
Page 18
PPT Definitions: Gas Processing
· AS 43.55.011(21) "gas processing"
· (A) means processing a gaseous mixture of hydrocarbons
· (i) by means of absorption, adsorption, externally
applied refrigeration, artificial compression followed
by adiabatic expansion using the Joule-Thomson effect,
or another physical process that is not mechanical
separation; and
· (ii) for the purpose of extracting and recovering
liquid hydrocarbons [producing ngls/oil];
· (B) does not include gas treatment
Mr. Dickinson overviewed this page.
10:29:50 AM
Page 19
PPT Definitions: Gas Treatment
· AS 43.55.011(23) "gas treatment"
· (A) means conditioning gas and removing from gas
nonhydrocarbon substances for the purpose of rendering
the gas acceptable for tender and acceptance into a
gas pipeline system.
· (B) includes incidentally removing liquid hydrocarbons
from the gas
Mr. Dickinson spoke to this page.
10:30:23 AM
Page 20
PPT Definitions: Gas Treatment
· AS 43.55.011(23) "gas treatment" (cont.)
· (C) does not include
o (i) dehydration required to facilitate the
movement of gas from the well to the point where
gas processing takes place;
o (ii) the scrubbing of liquids from gas to
facilitate gas processing.
Mr. Dickinson reviewed this page.
10:30:33 AM
Page 21
Under Current law:
· Gas Processing
· Starts with gaseous mixture of hydrocarbons, and
produces natural gas liquids and gas by removing the
hydrocarbon liquids.
· Gas Treatment
· Starts with produced gas and removes nonhydrocarbons
(including incidental hydrocarbons) to prepare the gas
for tender to the pipeline. Nothing is produced.
Mr. Dickinson summarized this page.
10:30:57 AM
Page 22
AGIA Definitions: Gas Processing
· AS 43.55.900(7) "gas processing" means the treatment
of gas downstream of the point of production to
extract natural gas liquids. CSHB 177(RES)
· AS 43.55.900(7) "gas processing" means post-production
treatment of gas to extract natural gas liquids. CSSB
104(JUD)
Mr. Dickinson corrected that the reference to AS 43.55.900
should have been a reference to subparagraph (7) of Section
43.90.900. Definitions., in SB 104, the AGIA legislation. It
defined gas processing as "the treatment" of gas, while PPT
differentiated between gas treatment and processing.
10:32:37 AM
Page 23
AGIA Definitions: Gas Processing
· Suggested Definition
· AS 43.55.900(7) "gas processing" has the same meaning
as "gas processing" in AS 43.55.900(21)
Mr. Dickinson provided his suggested definition to achieve
continuity between the proposed AGIA bill and the PPT statute.
10:33:01 AM
Page 24
PPT Point of Production for Gas
[Flow chart summarizing the following four pages.]
Mr. Dickinson informed that the following pages would expound on
this page.
10:33:10 AM
Page 25
Gas Point of Production
[Illustration indicating that the point of production of
gas that is not run through a gas processing point or
subject to mechanical separation is the first point at
which gas is accurately metered.]
Mr. Dickinson noted that this was the simplest form of gas
production, and the least common.
10:33:37 AM
Page 26
Gas Point of Production
[Illustration indicating that the point of production after
mechanical separation for gas not run through a gas
processing plant but subject to mechanical separation is at
the first point at which gas is accurately metered after
separation is complete.]
Mr. Dickinson spoke to the page.
10:34:01 AM
Page 27
Gas Point of Production
[Illustration indicating that the point of production after
gas processing for gas not run through an integrated gas
processing plant and a gas treatment plant is at the first
point at which the gas is accurately metered downstream of
the plant.]
Mr. Dickinson explained this page.
10:34:27 AM
Page 28
Gas Point of Production
[Illustration indicating that the point of production for
gas run through an integrated gas processing plant and gas
treatment plant is the furthest upstream point in which
treatment begins or processing ends.]
Mr. Dickinson summarized this page.
10:34:46 AM
Page 29
Prudhoe Bay: Point of Production under the PPT
[Flow chart summarizing the point of production for gas and
oil on the North Slope.]
Mr. Dickinson described this page as follows.
What happens on the North Slope now? You have well fluids
coming out in the lower left had corner coming out of
wells. They go into six separation facilities that are
called usually the gathering centers or the flow stations.
What happens there is you have water and sediment. You pull
that out, you have liquid hydrocarbons which get delivered
to PS1 (pump station 1) of TAPS, which is where they become
oil. That's the point of production for oil, and you have a
gaseous mixture of hydrocarbons that get pulled off the top
of each of those facilities. Those all get routed together
and sent to something called the Central Gas Facility.
Central Gas Facility uses a much more sophisticated set of
processes, so they qualify as gas processing. It gets down
to very, very low temperatures, and it separates out some
more hydrocarbon liquids that get delivered to the TAPS
and, off the top we pull off a bunch of gas. Some of it
gets used for sale, some of it gets used for use, and of
course the one thing that we all regret is eight billion
cubic feet a day of that gets reinjected back down into the
ground. That's the situation we're trying to remedy.
10:36:04 AM
Senator Elton had understood that the point of production came
"after fuel use", and asked if this was a "new interpretation".
Mr. Dickinson replied that page 31 would address that question.
Page 31
North Slope Central Gas Facility
· On the Alaska North Slope the Central Gas Facility is
a gas processing plant,
· AS 43.55.020(e) "…gas used in the operation of a lease
or property in the state in drilling for or producing
oil or gas or for repressuring…is not
considered…as…gas produced from a lease or property."
Mr. Dickinson agreed that the gas Senator Elton identified was
not considered to be produced at the point of production.
10:36:56 AM
Page 32
Answer to the Question:
· If CGF remains a separate plant and sends gas to a Gas
Treatment Plant (GTP), gas would be produced as it is
metered out of plant. The GTP would be downstream of
the point of production for the gas and thus
associated operating and capital costs would not
qualify as lease expenditures under AS 43.55.165 (a)
nor would capital costs qualify for credit treatment
under AS 43.55023(a).
Mr. Dickinson overviewed this page.
10:37:30 AM
Page 33
Prudhoe Bay: Point of Production under the PPT with a GTP
[Flow chart depicted on Page 29 with the addition of a Gas
Treatment Plant and an Export Gasline.]
Mr. Dickinson pointed out that the addition of a gas treatment
plant would not change any of the prior established points of
production. Therefore, the definitions that existed under the
PPT would sufficiently delineate the point of production for the
purposes of the AGIA legislation, and could be imported from
existing statute.
10:38:13 AM
Page 34
Answer to the Question:
· If CGF becomes integrated into a Gas Treatment Plant
(GTP) (produced gas is not metered), then the gas
would be produced within that integrated facility, at
the furthest point upstream of the beginning of gas
treatment of the end of gas processing. If plants are
integrated, the risk is that some gas processing will
move downstream of the point of production, not that
gas treatment will move upstream of the point of
production.
Mr. Dickinson summarized this page, noting that gas treatment
could not be moved upstream to become eligible for the PPT
credits.
10:38:51 AM
Page 35
Prudhoe Bay: Point of Production under the PPT w/integrated
GTP
[Flow chart depicted on Page 33 with the Gas Treatment
Plant integrated into the Central Gas Facility.]
Mr. Dickinson declared that the point of production would always
be the furthest point upstream that gas treatment occurred. Any
process that could be identified as removing nonhydrocarbons for
the purpose of preparing the gas for transport would be defined
as gas treatment and considered the point of production.
10:40:00 AM
Senator Thomas asked the likelihood that the gas treatment plant
and the central gas facility would be attached.
Mr. Dickinson understood that the most common assumption was
that the gas treatment plant would be located approximately 50
yards downstream from the central gas facility. The possibility
also existed that facets of the central compression plant could
be incorporated into the gas treatment plant, with the central
gas facility standing independently.
10:41:31 AM
Page 36
Question 4:
· We are trying to determine how attractive an
investment this pipeline is. Antony Scott, Commercial
Analyst, DNR, Oil and Gas, in his April 11, 2007
presentation shows that using the IRR metric this
project can have very high rates of return,
particularly with a third party line. However we
believe he does not include the cost of shippers' firm
transportation commitments in his numbers when
comparing an independent pipeline with a producer
owned pipeline. How might this affect his results?
Mr. Dickinson articulated the question on this page.
10:42:30 AM
Page 37
Firm Transportation
· Shipper makes a Firm Transportation commitment (FT) to
pay the capital portion of the tariff whether it uses
the pipeline or not.
· It is that financial commitment that underwrites the
pipeline:
o Required by FERC before approving a project
o Required by lenders before lending money to a
project.
Mr. Dickinson reviewed this page.
10:43:08 AM
Page 38(9)
Producers' returns as both shippers + pipeline owners
$3.50
NPV: 3.0
IRR: 12.6%
P/I: 1.3
NPV per BOE: $0.37
$4.00
NPV: 5.0
IRR: 14.0%
P/I: 1.4
NPV per BOE: $0.60
$4.50
NPV: 6.9
IRR: 15.4%
P/I: 1.6
NPV per BOE: $0.83
$5.00
NPV: 8.7
IRR: 16.7%
P/I: 1.7
NPV per BOE: $1.06
$5.50
NPV: 10.6
IRR: 17.9%
P/I: 1.9
NPV per BOE: $1.28
$6.00
NPV: 12.4
IRR: 19.0%
P/I: 2.0
NPV per BOE: $1.50
$6.50
NPV: 14.2
IRR: 20.1%
P/I: 2.2
NPV per BOE: $1.72
$7.00
NPV: 16.0
IRR: 21.1%
P/I: 2.3
NPV per BOE: $1.93
$7.50
NPV: 17.7
IRR: 22.1%
P/I: 2.5
NPV per BOE: $2.14
$8.00
NPV: 19.3
IRR: 23.0%
P/I: 2.6
NPV per BOE: $2.33
$8.50
NPV: 20.8
IRR: 23.9%
P/I: 2.7
NPV per BOE: $2.51
Mr. Dickinson informed that the information depicted on pages 38
and 39 of his presentation was garnered from presentation
material provided by Antony Scott, Commercial Analyst, Division
of Oil and Gas, Department of Natural Resources on April 11,
2007. This page examined the expected internal rate of return
(IRR) for a producer-owned pipeline for which the producers were
also shippers.
10:44:04 AM
Page 39(7)
Producer Upstream Returns Base case cost = $20.5B
$3.50
NPV: 4.1
IRR: 29.8%
P/I: 3.2
NPV per BOE: $0.49
$4.00
NPV: 6.1
IRR: 39.7%
P/I: 4.3
NPV per BOE: $0.74
$4.50
NPV: 8.1
IRR: 48.7%
P/I: 5.3
NPV per BOE: $0.98
$5.00
NPV: 10.1
IRR: 56.3%
P/I: 6.4
NPV per BOE: $1.22
$5.50
NPV: 12.1
IRR: 62.9%
P/I: 7.5
NPV per BOE: $1.46
$6.00
NPV: 14.0
IRR: 68.9%
P/I: 8.5
NPV per BOE: $1.70
$6.50
NPV: 16.0
IRR: 74.2%
P/I: 9.5
NPV per BOE: $1.93
$7.00
NPV: 17.8
IRR: 79.2%
P/I: 10.5
NPV per BOE: $2.15
$7.50
NPV: 19.6
IRR: 83.9%
P/I: 11.5
NPV per BOE: $2.37
$8.00
NPV: 21.3
IRR: 90.4%
P/I: 12.4
NPV per BOE: $2.57
$8.50
NPV: 22.9
IRR: 95.6%
P/I: 13.2
NPV per BOE: $2.76
Mr. Dickinson commented that this page provided the anticipated
IRR if the producers were not pipeline owners, but merely
shippers on the line. At current gas prices, the rate of return
on the pipeline would be approximately 80 percent. He allowed
that the analysis could be incorrect, as the project had not
been undertaken and costs not studied for several years.
10:44:54 AM
Co-Chair Stedman asked for a definition of the terms "net
present value", "internal rate of return", and "profitability
index".
Mr. Dickinson defined the net present value, or NPV, as "how
much better off" a firm would be after making "this investment".
It was a "measure of net gain" for participating in a project
after expenses were paid.
Co-Chair Stedman understood NPV to compare all future income
from a project in a lump sum, effectively "moving money and time
back to today" for the purpose of comparison.
Mr. Dickinson affirmed, adding that the future cash flows would
be adjusted or discounted to take into account the time those
dollars were invested.
10:46:58 AM
Mr. Dickinson explained the profitability index (PI) as a ratio
of the "out flows" to the "in flows". It examined income as the
result of an investment in comparison to the initial investment.
A PI ratio higher than "one" was desirable, as that would
demonstrate profit.
10:47:43 AM
Page 40
Calculated IRR at various price levels
[line graph depicting the internal rates of return for a
shipper-owner and a shipper at various gas prices from
$3.50 to $8.50]
Mr. Dickinson was concerned that this graph indicated that the
IRR for a shipper-owner at gas prices of $8.50 was less then the
IRR for a shipper without an ownership interest at gas prices of
$3.50. He opined that the rates of return demanded further
analysis.
10:49:05 AM
Co-Chair Stedman referred to the $7.00 gas price listed on page
39 and asked the following question.
If we look at seven, which is the seven dollar price,
regardless of what entity you're investing in, just the
mechanics of the internal rate of return, if this is over a
25-year horizon or whatever time horizon it's calculated
under, am I interpreting this correctly to make that seven
79.2 whatever number on the bottom, you'd have to reinvest
every year's cash flow into a project that would return
that 79.2 first cash flow for 20 years, second cash flow
for 19 years, and isn't that rather challenging?
Mr. Dickinson responded that Co-Chair Stedman had identified the
"reinvestment problem", which was one reason that IRR was not
used to evaluate potential investments. It implied that other
opportunities would be just as "fruitful", without taking into
consideration reinvestment challenges.
10:50:49 AM
Senator Huggins was "alarmed" by the figures presented, and
asked if Mr. Scott had questioned the validity of the model.
Mr. Dickinson shared that Mr. Scott would acknowledge that IRR
was a limited calculation that was not applicable to all
circumstances. He opined that Mr. Scott would warn against
reaching a firm conclusion based on that analysis.
10:51:55 AM
Senator Elton reported that he had been told that Mr. Scott's
analysis and use of numbers closely reflected the information in
Conoco-Phillips' most recent "10K" filing. He asked if Mr.
Dickinson had knowledge of that, and how Conoco-Phillips'
analysis differed from Mr. Scott's.
10:52:37 AM
Mr. Dickinson would review that with the Committee. He referred
to the 2003 annual reports of BP, Conoco, and Exxon, and would
address those issues.
ADJOURNMENT
Co-Chair Bert Stedman adjourned the meeting at 10:54:23 AM
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