Legislature(2007 - 2008)
04/18/2007 04:03 PM House RES
| Audio | Topic |
|---|---|
| Start | |
| HB177 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
April 18, 2007
4:03 p.m.
MEMBERS PRESENT
Representative Carl Gatto, Co-Chair
Representative Craig Johnson, Co-Chair
Representative Vic Kohring
Representative Bob Roses
Representative Paul Seaton
Representative Peggy Wilson
Representative Bryce Edgmon
Representative Scott Kawasaki
MEMBERS ABSENT
Representative David Guttenberg
OTHER LEGISLATORS PRESENT
Representative Anna Fairclough
COMMITTEE CALENDAR
HOUSE BILL NO. 177
"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."
- HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: HB 177
SHORT TITLE: NATURAL GAS PIPELINE PROJECT
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
03/05/07 (H) READ THE FIRST TIME - REFERRALS
03/05/07 (H) O&G, RES, FIN
03/06/07 (H) O&G AT 3:00 PM BARNES 124
03/06/07 (H) -- MEETING CANCELED --
03/08/07 (H) O&G AT 3:00 PM BARNES 124
03/08/07 (H) -- MEETING CANCELED --
03/13/07 (H) O&G AT 3:30 PM HOUSE FINANCE 519
03/13/07 (H) Heard & Held
03/13/07 (H) MINUTE(O&G)
03/15/07 (H) O&G AT 3:00 PM BARNES 124
03/15/07 (H) Heard & Held
03/15/07 (H) MINUTE(O&G)
03/19/07 (H) O&G AT 8:30 AM CAPITOL 106
03/19/07 (H) Heard & Held
03/19/07 (H) MINUTE(O&G)
03/20/07 (H) O&G AT 3:00 PM BARNES 124
03/20/07 (H) Heard & Held
03/20/07 (H) MINUTE(O&G)
03/21/07 (H) O&G AT 5:30 PM SENATE FINANCE 532
03/21/07 (H) Heard & Held
03/21/07 (H) MINUTE(O&G)
03/22/07 (H) O&G AT 3:00 PM BARNES 124
03/22/07 (H) Heard & Held
03/22/07 (H) MINUTE(O&G)
03/23/07 (H) O&G AT 8:30 AM CAPITOL 106
03/23/07 (H) Heard & Held
03/23/07 (H) MINUTE(O&G)
03/24/07 (H) O&G AT 1:00 PM SENATE FINANCE 532
03/24/07 (H) -- Public Testimony --
03/26/07 (H) O&G AT 8:30 AM CAPITOL 106
03/26/07 (H) Heard & Held
03/26/07 (H) MINUTE(O&G)
03/27/07 (H) O&G AT 3:00 PM BARNES 124
03/28/07 (H) O&G AT 7:30 AM CAPITOL 106
03/28/07 (H) Heard & Held
03/28/07 (H) MINUTE(O&G)
03/28/07 (H) O&G AT 8:30 AM CAPITOL 106
03/28/07 (H) Heard & Held
03/28/07 (H) MINUTE(O&G)
03/29/07 (H) O&G AT 3:00 PM BARNES 124
03/29/07 (H) Heard & Held
03/29/07 (H) MINUTE(O&G)
03/30/07 (H) O&G AT 8:30 AM CAPITOL 106
03/30/07 (H) Heard & Held
03/30/07 (H) MINUTE(O&G)
03/31/07 (H) O&G AT 1:00 PM BARNES 124
03/31/07 (H) -- MEETING CANCELED --
04/02/07 (H) O&G AT 8:30 AM CAPITOL 106
04/02/07 (H) Heard & Held
04/02/07 (H) MINUTE(O&G)
04/03/07 (H) O&G AT 3:00 PM BARNES 124
04/03/07 (H) Moved CSHB 177(O&G) Out of Committee
04/03/07 (H) MINUTE(O&G)
04/04/07 (H) O&G RPT CS(O&G) NT 3DP 2NR 2AM
04/04/07 (H) DP: RAMRAS, DOOGAN, OLSON
04/04/07 (H) NR: SAMUELS, KAWASAKI
04/04/07 (H) AM: DAHLSTROM, KOHRING
04/04/07 (H) O&G AT 8:30 AM CAPITOL 106
04/04/07 (H) -- MEETING CANCELED --
04/05/07 (H) O&G AT 3:00 PM BARNES 124
04/05/07 (H) -- MEETING CANCELED --
04/10/07 (H) RES AT 1:00 PM BARNES 124
04/10/07 (H) Heard & Held
04/10/07 (H) MINUTE(RES)
04/11/07 (H) RES AT 1:00 PM BARNES 124
04/11/07 (H) Heard & Held
04/11/07 (H) MINUTE(RES)
04/12/07 (H) RES AT 1:00 PM BARNES 124
04/12/07 (H) Heard & Held
04/12/07 (H) MINUTE(RES)
04/13/07 (H) RES AT 1:00 PM BARNES 124
04/13/07 (H) Heard & Held
04/13/07 (H) MINUTE(RES)
04/14/07 (H) RES AT 1:00 PM BARNES 124
04/14/07 (H) Heard & Held
04/14/07 (H) MINUTE(RES)
04/16/07 (H) RES AT 1:00 PM BARNES 124
04/16/07 (H) Heard & Held
04/16/07 (H) MINUTE(RES)
04/17/07 (H) RES AT 1:00 PM BARNES 124
04/17/07 (H) Heard & Held
04/17/07 (H) MINUTE(RES)
04/18/07 (H) RES AT 1:00 PM BARNES 124
WITNESS REGISTER
ANTONY SCOTT, Commercial Analyst
Division of Oil & Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Presented information regarding pipeline
project economics and answered questions.
ACTION NARRATIVE
CO-CHAIR CARL GATTO called the House Resources Standing
Committee meeting to order at 4:03:17 PM. Representatives
Gatto, Johnson, Wilson, Seaton, Roses, and Edgmon were present
at the call to order. Representatives Kohring and Kawasaki
arrived as the meeting was in progress. Representative
Fairclough was also in attendance.
HB 177-NATURAL GAS PIPELINE PROJECT
4:03:27 PM
CO-CHAIR GATTO announced that the only order of business would
be HOUSE BILL NO. 177, "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." [Before the committee was
CSHB 177(O&G).]
4:04:31 PM
ANTONY SCOTT, Commercial Analyst, Division of Oil & Gas,
Department of Natural Resources (DNR), provided the committee
with a PowerPoint presentation titled "Analysis of Producer
Returns, Investment Attractiveness, and Fiscal Certainty" dated
April 18, 2007. He described net present value ("NPV") as the
"current value of a stream of future cash flows." He explained
that future cash flows are discounted to account for inflation,
impatience, and risk. He said that a cash flow 20 years in the
future is less certain than a present day cash flow. He
explained that companies discount future cash flows by what is
called the "discount rate." He suggested that investors without
any capital constraints will be likely to invest in "all
projects that have a net present value greater than zero"
because those are the type of projects that add value to the
company. He opined that the discount rate is clearly an
important factor in making an investment decision and that his
presentation and analysis will assume a discount rate of 10
percent.
4:08:36 PM
DR. SCOTT explained that another measure of investment
attractiveness is the internal rate of return, which is
"basically solving for the discount rate that makes the net
present value of a project's cash flow equal to zero." He
offered that, "bigger numbers, in general, are better." He went
on to say that an additional factor is the "profitability
index," which is basically a measure of the present value of
cash inflows." He reiterated that present value means the
discount rate divided by the present value of cash outflow. For
example, a profitability index of two means if you invest a
single dollar in a project you get two dollars of profit back."
4:09:28 PM
DR. SCOTT explained that the NPV per barrel of oil equivalent
means taking the NPV and dividing by the undiscounted total
barrel of oil equivalent off the project. He provided the
committee with materials prepared by the state's consultant Econ
One, which he said explains the meaning and use of numerous
financial terms. He referred to slide 3 which sets forth the
potential economics of a $20 billion gas pipeline with a 4.3
billion cubic feet (Bcf) per day capacity to Alberta, Canada.
Under the scenario, a $4.00 "real gas price" provides a NPV to
the producers, collectively discounted at 10 percent, of $6.1
billion. If one assumes a $5.50 gas price, the NPV of the
project to the producers collectively is around $12 billion,
with corresponding internal rates of return of nearly 40 percent
and perhaps over 60 percent. He said the profitability ratios
of the scenarios are estimated at 4.3 and 7.5.
4:11:49 PM
REPRESENTATIVE SEATON asked for clarification of "NPV 10" - does
that mean one discounts future profits by 10 percent annually
back to the present day to determine present value?
DR. SCOTT agreed that the aforementioned description "is exactly
right." He explained that in a business analysis, one examines
the profits as well as the investments. Since the investments
occur before the profits, they get discounted less. The
discount rates compound to result in an annual discount rate, he
explained.
4:12:47 PM
DR. SCOTT explained that if the proposed pipeline project has a
cost overrun of 50 percent, the predicted NPV of the project
falls. If the price of gas is $5.50, a cost overrun of 50
percent would reduce the NPV from $12.1 billion to $9.2 billion.
He characterized the project cost overrun risk as "real." He
noted in the event of a cost overrun, the internal rates of
return are still "quite high" and remain significantly above the
company's "hurdle rates." He reminded the committee that the
numbers presented are based on the producers' upstream returns.
The predictions made assume that the producers invest in a gas
treatment plant (GTP) and that the GTP is not subject to
production profits tax (PPT) deduction credits. Furthermore,
the scenario assumes that the producers make all the necessary
upstream investment for Point Thomson and associated pipelines,
but "not in the pipeline itself" he said.
4:14:11 PM
CO-CHAIR JOHNSON asked for clarification as to whether field
infrastructure is included in the predicted future scenarios
regarding pipeline development.
DR. SCOTT responded that "it does include field infrastructure"
and assumes that the producers invest in and own a GTP. However
the model also assumes the GTP is not a deductible expense for
PPT purposes.
4:14:52 PM
CO-CHAIR JOHNSON asked how a value was placed on the
infrastructure used in the economic models.
DR. SCOTT explained that information provided by the producers
and knowledge of Prudhoe Bay fields indicates that the
incremental in-field investments required at Prudhoe Bay will be
relatively modest. He noted there is a significant amount of
infrastructure at Prudhoe Bay producing both oil and gas "except
of course, the gas treatment plant." He said that the 2001 cost
study estimated the cost for the GTP to be around $2.3 billion
in 2001 dollars. He said the cost of the GTP has been "scaled
up" to reflect the general estimate that the cost of the
pipeline has gone from $20 billion to $30 billion [assuming a
project to Chicago, Illinois.]
4:16:41 PM
REPRESENTATIVE SEATON noted that the future scenarios presented
consider differing gas prices, but do not appear to incorporate
predicted tariffs.
DR. SCOTT replied that the tariff for the economic predictions
is assumed based on the parameters listed in an appendix to the
Econ One report. The parameters used assume a 70 to 30 debt to
equity ratio, a 14 percent return on equity, and a debt cost of
6.5 percent. When rolled together, these factors result in an
estimated tariff from $1.96 to $2.00. He noted that if another
debt to equity ratio was used or if the rate of return was
different, the estimates would change.
4:17:43 PM
CO-CHAIR GATTO asked what the tariff would be were the gas to be
converted to liquefied natural gas (LNG) for shipment on a
tanker.
DR. SCOTT responded that he could not answer that question
today.
4:17:59 PM
DR. SCOTT referred to slide 5 which predicts the producers'
returns if they were both shippers and pipeline owners. He said
that this scenario requires a much greater investment by the
producers. He directed the committee's attention to slide 3 and
explained that if the producers were both shippers and pipeline
owners, one sees very substantial declines in internal rates of
return, the profitability index, and net present value. The
reason for the decline in NPV is because the tariff "off of the
pipeline throws off a return of about eight and one-half percent
on a weighted average cost of capital basis whereas the discount
rate is greater than that", he explained. As a result,
investment in the pipeline at a 10 percent discount rate "costs
you money." If the discount rate is lower than 10 percent, then
the "pipeline doesn't cost you money," he said. He explained
that pipeline companies have different discount rates and that
10 percent is not a particularly low discount rate.
4:19:49 PM
REPRESENTATIVE WILSON suggested that if the aforementioned
predictions regarding pipeline economics are factual, then the
shippers would not want to own the pipeline.
DR. SCOTT responded by characterizing the above comment as "an
extremely interesting and provocative question" which he would
address shortly.
DR. SCOTT explained that slide 6 titled "Producer NPV: Relative
likelihood," shows the distribution of NPV from an integrated
upstream investment and the relative likelihood of different
outcomes. He indicated that DNR believes that from an upstream
only investment perspective, half of the time [represented by a
blue bar] the NPV, discounted at 10 percent, is at least $13
billion. That means there is a 50 percent likelihood that the
NPV will be at least $13 billion and a 50 percent likelihood it
will be below $13 billion. He said that the further one strays
from the $13 billion figure, the "less likely the outcome is."
He said there is a small chance the returns off the project will
exceed $30 billion.
4:22:19 PM
REPRESENTATIVE ROSES sought further explanation about the
likelihood that the percentage of return would be $13 billion.
DR. SCOTT referred to slide 6 and noted that if returns were $6
billion, then the likelihood that project returns would exceed
$6 billion is considerably greater than 50 percent, indeed it is
around 75 percent.
4:23:30 PM
DR. SCOTT explained that slide 7 shows the relative frequency
distribution of the internal rate of return (IRR). He explained
that for the upstream there is a median IRR of 57 percent, which
means that there is a 50 percent likelihood that the IRR on the
upstream investment only will be 57 percent. However, for an
integrated project the "spread is much narrower" and the
probability of the IRR reaching 60 percent is "essentially
zero," he said. The reason is that an integrated project
requires the producers to make an "enormous upfront investment
in the pipeline and it drags the [IRR] down," he explained.
4:24:27 PM
DR. SCOTT explained that slide 8 sets forth the results of a
frequency distribution analysis of the producers' profitability
ratio for both an integrated project and an upstream-only
project. He summarized the presentation to this point as having
provided a general overview of potential producer returns from
this project. He indicated that a response to Representative
Wilson's question regarding why the producers would want to own
the pipeline first requires acknowledgement that there are other
investment opportunities worldwide as shown on slide 9 titled
"Comparative Project Opportunities." He opined that the data
used by Econ One to compile the graph on slide 9 is accurate and
recent. He said the NPV predictions vary depending on the price
of oil, noting that a higher oil price supports a higher NPV
determination.
4:27:18 PM
DR. SCOTT explained that slide 10 predicts the economics of an
Alaska gas pipeline project which ends at either Alberta or
Chicago. When based on oil prices of $25 or $35 per barrel the
project is the "most attractive project," to the producers on an
NPV basis. He said there is a "significant spread" in the NPV
between Alberta and Chicago, with termination in Alberta
providing a greater rate of return due to the need for
significantly less infrastructure investment. He explained that
he updated the information used in slide 10 for slide 11 to show
the current gas pipeline economics using PPT instead of the
prior economic limit factor [ELF]. The current gas line
economic model, from an upstream perspective, indicates that the
Alaska project is "still either the first or second most
attractive project" in the producers' portfolio. If one
considers it from the integrated perspective, the project's
attractiveness drops to "maybe the third most attractive project
in the portfolio." In response to a question, he clarified that
the upstream analysis assumes "zero percent pipeline ownership."
4:31:41 PM
DR. SCOTT opined that when one considers profitability ratios
from an upstream perspective, the Alaska project has "by far the
most attractive profitability index ratio investment in the
[producers'] portfolio." Its profitability does not even "fit
on the chart," he explained, referring to slide 12. However, if
this scenario is considered from the prospective of producer
ownership of the pipeline, the profitability ratio decreases to
around the 25th percentile, meaning that roughly three-quarters
of the investment opportunities in the portfolio are more
attractive than the Alaska pipeline project. He explained that
the most important factors that decrease profitability are the
increased construction costs and the change from ELF to PPT. He
opined the change "really shows up" in Prudhoe Bay as the prior
effective tax rate there was around seven to seven and one-half
percent while the current effective tax rate on gas at Prudhoe
Bay under PPT is around 20 percent, he explained. He went on to
discuss the internal rates of return under PPT and noted that
"if you don't own the pipeline ... in terms of internal rates of
return, this is a very attractive project in the portfolio."
4:34:11 PM
DR. SCOTT directed attention to slide 14 and addressed
Representative Wilson's prior question as to why the producers
would want to own the pipeline. He suggested that some may
believe that the producers "have to" own the project as they are
the only companies that can obtain the financing necessary to
build the pipeline. He opined that this "isn't so," and noted
that there are pipeline companies that are ready and willing to
invest in the project and that "they can handle it, they can do
this." He said that these companies require firm transportation
(FT) commitments so as to obtain financing. He stressed that it
is "extremely important" to recognize that this project will not
be financed by "Exxon's balance sheet." He explained that the
project will be financed on a "project finance basis" which
means that the expected project revenues will provide the basis
for lenders to provide project financing. He opined that "it's
the gas in the ground that matters," as these proved reserves
provide assurance that there will be enough gas to "keep the
project full, with no decline, for at least 15 years." He
characterized the existence of this large amount of proved
reserves as an "exceptionally unusual circumstance" for a basin-
opening project. He said that during debate on the extension of
federal loan guarantees, it was determined that the Alaska gas
project may be sufficiently attractive from a credit perspective
that the federal government "will back this." He indicated that
a federal report on this project stated that without FT
commitments the project "will be rated - on a project finance
basis, double B [BB] instead of triple B [BBB], investment
grade." He stressed that it is the "gas in the ground that is
providing the financing."
4:38:31 PM
REPRESENTATIVE WILSON asked whether even without FT commitments
"they could still get the loan."
DR. SCOTT replied "that is exactly what we're saying." He
cautioned that an independent pipeline developer needs an FT
commitment from the producers in order to go forward with the
project. If the builders contribute 20 percent equity, or
approximately $4 billion, to the project and build without FT
commitments they run the risk that the holders of the gas will
leverage the shipper to reduce its tariffs prior to committing
their gas to the project. He emphasized that the pipeline
developer "absolutely has to have shipping commitments - it's
because of what we call 'hold-up' risk."
4:40:53 PM
CO-CHAIR GATTO asked whether it is conversely true that a
producer-owner could claim "the tariff is too low."
DR. SCOTT replied "not necessarily, no." He expanded his point
by opining that for an integrated project, such as the Trans-
Alaska Pipeline System (TAPS), the incentive is for the "lowest
cost project" with the "highest tariff." He explained that
commercial incentive exists because the taxes and royalties are
paid after subtraction of tariff costs. A pipeline owner who
also owns the gas is "indifferent to what the tariff is ... it
only matters where you take your profits - do you take them on
the pipeline or do you take them on the gas?" The tax and
royalty burden decreases if the pipeline tariffs are higher, he
indicated.
4:42:01 PM
DR. SCOTT suggested that another reason the producers would want
to own the pipeline is to control costs, a motivation he
characterized as "fair enough." He offered that it is
understandable that parties want some cost control abilities if
they are going to enter shipping commitments since the shipping
tariffs are based in part on pipeline costs. However, he
cautioned that there is an incorrect perception that the
shippers pay for the cost of the project "no matter what" since
the pipeline business is a "cost plus" business in which the
shippers charge "whatever it costs, plus a return." He opined
that this characterization is not accurate when applied to
today's pipeline business. He said that most newly built
pipelines are built on the basis of rates negotiated between the
shippers and pipeline entities prior to pipeline construction.
He opined that the risk of cost overruns is addressed in the
negotiated rate discussions. He offered that a great number of
pipelines are built in the Lower 48 on the basis of "fixed price
negotiated rates." In some instances, the shipper is then
assured of a "set it and forget it," rate while the pipeline
company bears all of the cost overrun risk.
4:44:37 PM
DR. SCOTT opined that the Alaska pipeline project will likely
not have negotiated rates because the project lead times are so
long that there are numerous cost factors "not in anybody's
control." This factor of uncertain costs does not place the
Alaska project "in a cost plus environment," rather "what we
absolutely expect is that risk sharing is to be negotiated
between the pipeline entity and the shippers," he opined. He
gave as an example the Rockies Express Pipeline in the Lower 48,
which has three different negotiated rates, each reflecting a
different risk scenario and the parties' "differing appetites
for risk." He explained that one variable that could be
included in negotiated rates for the Alaska project would be
"steel price escalators," since steel prices are a significant,
but uncontrollable factor that will affect pipeline costs.
4:46:07 PM
REPRESENTATIVE WILSON asked about the role of the Federal Energy
Regulatory Commission (FERC) if negotiated rates are determined
prior to open season.
DR. SCOTT explained that these rates will be negotiated prior to
open season, but "consummated at the open season," He agreed
that the parties will negotiate prior to any FERC determination
of a "cost-based tariff." He said that FERC does not rule on
whether a negotiated rate is in the public interest. He
explained that FERC will exercise its regulatory jurisdiction
only over the "maximum or recourse rate," which is the rate
available to any shipper without negotiation. He said it is
possible that there could be no shippers ever on the "FERC
established rate," and explained that there are pipelines where
all shippers pay at negotiated rates.
4:48:02 PM
REPRESENTATIVE WILSON expressed concern as to why issues have
been raised about the tariff provisions of the bill if it is
"irrelevant most of the time."
DR. SCOTT replied that the recourse rate will be important to
the state's interest because it will provide a benchmark for the
state to consider when determining the tax and royalty rates,
particularly if the pipeline owners are also the shippers. In
that instance, the owner/shipper may negotiate a rate that is
much higher than the "FERC cost of service rate." In that
instance, the state must decide whether to establish taxes and
royalties based on the negotiated rate, or on the FERC cost of
service rate.
[Co-Chair Gatto turned the gavel over to Co-Chair Johnson.]
4:49:54 PM
DR. SCOTT summarized that there are valid commercial reasons why
a producer would like to own the pipeline, such as cost control.
He suggested that there is a perception that the pipeline
company has no incentive to control costs in an integrated
project, but opined that this conclusion is not accurate and is
"not to be expected on this project."
4:50:28 PM
REPRESENTATIVE ROSES asked whether it is in the best interests
of the producers for the state to create a mechanism that gives
them the maximum amount of flexibility possible to allow them to
"really play with the cards and the economics."
DR. SCOTT responded that the aforementioned statement could be
considered a "commercially reasonable statement."
4:51:04 PM
DR. SCOTT went on to say that there will likely be further
discussion as to whether a FT commitment is the same as a debt
obligation. He offered his understanding that the producers'
stated view is that an FT commitment is exactly like issuing a
debt obligation. He indicated that DNR has studied and
considered this issue "for a number of years." He said his
opinion on this issue has been formed by market factors as
"that's ... reality." He opined that the first thing to note is
that an FT commitment shows up as a footnote on financial
statements, but "does not go against" the company's balance
sheet. He suggested that a contention that an FT commitment is
a debt equivalent is akin to stating an FT commitment is the
same as a lease. He offered that characterization of the nature
of the obligation "does not really play out" in terms of "how
the IRS {Internal Revenue Service] views it." He suggested that
if the IRS viewed FT commitments as equivalent to leases, then
depreciation benefits under tax provisions would flow to leases
[lessees] as opposed to owners. He explained that the tax
treatment of depreciation "does not flow from a pipeline company
to a shipper." He reiterated that the IRS does not "view a FT
commitment as a debt or lease equivalent."
4:54:57 PM
DR. SCOTT explained that analysts in the credit rating agencies
have been asked by [state economists] if an FT commitment is a
debt equivalent which would reduce the company's future ability
to issue debt. He said that the credit rating agencies replied
"absolutely not, that's not how we look at things." He put
forth that credit rating agencies may potentially consider FT
commitments in assessing the overall risk profile of the
company. However, in general FT commitments are "not considered
at all," a point he indicated is supported by a Moody's Investor
Service report of 2003 which states "in general we [Moody's] do
not look at FT commitments when assessing E/P [earnings and
profits] credit strength." He opined that this makes sense
because FT commitments may actually increase a company's credit
increase by establishing positive future cash flows.
4:57:47 PM
REPRESENTATIVE ROSES indicated he understands the aforementioned
analysis, but asked what happens should the pipeline volume be
insufficient to meet the FT commitment requirements.
4:58:07 PM
DR. SCOTT replied that it is exactly right that an entity that
makes a FT commitment does not do so on a risk free basis, and
he did not mean to so imply. One risk related to FT commitments
is that of price, the second is reserve risk, he said. He
explained that an entity that makes an FT commitment does not
pay if the pipeline is not completed or is not in operation. He
said that the biggest risk facing the Alaska project is the risk
of low production. The pipeline developer bears the risk that
there may be insufficient production despite significant
investments made in the development of the pipeline. One way to
manage risk is to "bring in new parties and get them to bear
some," he suggested. He said that shippers do not normally have
to pay if for some reason the pipeline is not operating. In
that instance, it is the pipeline company that "is on the hook,"
he said.
5:01:30 PM
DR. SCOTT explained that another reason for integrated pipeline
ownership is control or influence over the pipeline terms, such
as tariffs, recourse rates, and expansion. He opined that AGIA
seeks to assure that the pipeline owner, whoever that may be,
will act like a pipeline company, as those companies favor
rolled-in rates and expansion. He said that although an
integrated approach may appear to lessen the project's economic
benefits to the producers, an integrated approach may improve
"bargaining position with the state."
5:03:05 PM
DR. SCOTT referred to slide 15 which represents the financial
commitment necessary to enter FT contracts for either a $20
billion or $25 billion pipeline project. He said that the total
FT commitment costs for the producers could be around $3.4
billion a year; higher should the project costs increase. He
indicated that even using conservative gas price estimates, and
assuming no additional discoveries, the likely revenues would
exceed the FT payments [as shown in slide 16].
5:04:42 PM
REPRESENTATIVE WILSON asked whether the peak revenues from the
gas pipeline as depicted in slide 16 would plateau if there were
additional discoveries of gas.
DR. SCOTT predicted that if additional gas reserves were to fill
the pipeline to capacity, the revenue projections shown on slide
16 would not plateau, but would continue to rise. He explained
that the prices used for the example are in today's dollars,
which is why the prices continue to rise. He described the
tariff as "not a real tariff" but a $2.00 "nominal dollar
tariff." Over the course of 15 years, the cost of the nominal
tariff is much less than in the beginning, he said.
[Co-Chair Johnson returned the gavel to Co-Chair Gatto.]
DR. SCOTT explained that economic forecasts predict
"considerable positive cash flow" should the gas prices exceed
the "AECO [Alberta Hub] price level," which they are predicted
to do over 85 percent of the time.
5:06:54 PM
CO-CHAIR GATTO asked about recovery of exploration costs if no
new gas is discovered despite exploration efforts.
DR. SCOTT replied that "they are out of pocket" for the costs
expended.
REPRESENTATIVE SEATON clarified that the explorers would be "out
of pocket" for basically 60 percent of the exploration costs due
to PPT provisions which set a tax rate of 22 percent and a
capital credit rate of 20 percent.
DR. SCOTT agreed that the aforementioned description is exactly
right under the current PPT.
5:07:56 PM
DR. SCOTT explained that slide 17 sets forth the effect on
revenue of raising taxes by 15, 30, or 50 percent on "day one"
of the project. A tax increase of 15 percent would reduce the
project's NPV by 5.1 percent, a tax increase of 30 percent would
decrease NPV by 10.2 percent, and a tax increase of 50 percent
would decrease NPV by 17.1 percent, results he deemed
"material." However, he offered his belief that it is important
to put the effect any tax increases in context. He indicated
that a $0.50 change in the price of gas may have more of an
effect on the NPV than a tax increase of 30 percent. He opined
that the "big risk" on this project is price risk. He responded
to an inquiry by noting that gas prices tend to change
significantly and daily.
CO-CHAIR GATTO noted that the scenario discussed so far assumes
a tax increase as of "day one."
5:13:11 PM
DR. SCOTT presented a prediction based on the assumption that
production taxes would be increased in the eleventh year of the
project. Under this scenario, a 15 percent tax increase would
decrease NPV by 2 percent, which indicates that set production
tax rates for a 10 year period "makes a material difference in
terms of exposure to fiscal uncertainty," he said. Tax
increases have less of an effect on NPV after 15 years, since a
15 percent tax increase in the sixteenth year may decrease NPV
by only 1 percent, he said, referring to slide 20. He opined
that the "value of fiscal certainty starts decaying rapidly,"
after a project's initial few years of operation.
5:15:19 PM
CO-CHAIR GATTO observed that the first ten years of a project
appear to be the most important in terms of fiscal certainty.
DR. SCOTT agreed that the early years of the project are the
most important period for which to have fiscal certainty. He
noted "we are dealing with compounding" and explained that one
needs to remember that companies make investments on the basis
of discounted value.
5:16:28 PM
DR. SCOTT went on to explain that internal rates of return (IRR)
do not "move very much with tax increases," and that 10 years of
fiscal certainty is adequate from an IRR basis. He went on to
say that profitability indexes also show that the project is
economically attractive. In response to an observation, he
explained that a 30-year project life forecast is all that is
needed to get a good understanding of the pipeline project
economics.
5:20:11 PM
DR. SCOTT responded to a request to clarify his prior testimony
regarding the relationship of FT commitments to possible federal
loan guarantee provisions. He said that the authorizing
language for the loan guarantees in the Alaska Natural Gas
Pipeline Act of 2004 (ANGPA) states that "the Secretary of the
Department of Energy ... may impose ... no condition on the loan
guarantee beyond what the project proponent imposes on ... the
shippers." He said that means if a project proponent does not
obtain FT guarantees from the shipper, the Secretary of the
Department of Energy cannot place "that as a requirement of
receiving a federal loan guarantee." He explained that the
potential cost to taxpayers of the federal loan guarantees for
the Alaska pipeline project was analyzed by federal economists
with the assumption that there would be no FT commitments. He
reminded the committee that TAPS was built without FT
commitments, although he noted that the economics surrounding
the construction of TAPS were different.
5:22:41 PM
REPRESENTATIVE SEATON set forth a hypothetical assumption that
there are FT commitments for the first five to seven years of
the pipeline. In that situation, he asked whether the federal
loan guarantee would still apply to the other 80 percent.
DR. SCOTT agreed that the aforementioned description is correct.
The federal loan guarantee would apply to all the project debt,
including debt service that extends beyond the terms of any FT
commitments, he explained.
REPRESENTATIVE SEATON asked whether it is possible to reduce
risk to shippers by asking "for an open season of seven years
... so then people could bid on whether they want seven or they
want to guarantee themselves more time on that pipeline."
DR. SCOTT replied that such a scenario is possible, but unlikely
because such a short FT commitment period by an independent
pipeline company is due to "hold up" risk, he said. He went on
to explain that the federal government will guarantee the
construction debt, but that the pipeline company will require a
return on equity, which is not guaranteed by the federal
government. He said that FT commitments for 15 years have been
used for pipelines in the Lower 48, but opined that FT
commitments for the Alaska project would more likely be 15 to 20
years. He said that a shipper does face some reserve risk as
production will decrease after 14 or so years. However, he
opined that shippers are best positioned to "wear that risk," so
it makes more business sense for the shippers to take a 20 year
FT commitment while the pipeline builder takes more of the cost
overrun risk as it can better manage costs. He explained that
in commercial negotiations, companies prefer to bear the risks
they have the ability to manage.
5:28:12 PM
CO-CHAIR JOHNSON asked if a change in the debt to equity ratio
would allow for a shorter FT commitment.
DR. SCOTT replied that he did not think so. He said FERC never
permits pipelines to base rates on 100 percent equity. The
situation is different from a residential mortgage, where debt
is retired. In pipeline projects, the debt retirement schedule
is not necessarily at all the same as the debt retirement
schedule that rates are based on. FERC will not allow rates
based on 100 percent equity - that is "outside the zone of
reasonableness," he said. He stated that the lowest debt ratios
are usually around 30 to 35 percent debt, and that debt is
maintained throughout the life of the project.
5:30:08 PM
CO-CHAIR JOHNSON asked for further information on the effect of
differing debt to equity ratios on the FT commitment terms and
on the approaches available to provide an acceptable level of
fiscal certainty.
DR. SCOTT answered that the debt to equity ratio will not effect
the appropriate period for FT commitments. These two issues are
"not linked," he opined.
5:31:57 PM
REPRESENTATIVE WILSON asked if negotiated rates are "solid
deals," not subject to later adjustment by FERC.
DR. SCOTT replied that is correct. The contracts for negotiated
rates are finalized at open season and are known as "precedent
agreements" as there are often conditions that must be satisfied
before the shipper must commit to the contract terms. He
offered his belief that for this project one of the "conditions
precedent" will be that the cost estimates be within the bounds
estimated at the time of the open season.
REPRESENTATIVE WILSON asked if the shippers can "back out" under
certain situations.
DR. SCOTT agreed that the shippers could "back out" if the
contract had a clause that allowed them to under certain
circumstances, such as a cost increase of a certain magnitude.
He said that for large, complex projects, it is not unusual for
parties to enter agreements which require the shipper to take
certain actions as a "condition precedent" to contract
performance.
5:36:32 PM
REPRESENTATIVE WILSON noted that previous producer testimony had
expressed opposition to use of rolled-in rates, while the
independent pipeline companies did not seem to oppose them. She
asked for some further explanation of this issue.
DR. SCOTT explained that rolled-in rates are "unequivocally
good" for a shipper interested in exploring for additional gas
supplies. For a shipper that is not an explorer, rolled-in
rates are "potentially a problem" because rates can rise, which
is harmful to shippers. A pipeline owner who is also a shipper
does "not care" what the rate is, assuming there are appropriate
distribution rules in its limited liability partnership
arrangement. The "rate is immaterial because you are paying
yourself," he said. A pipeline owner who is also a shipper
therefore does not support rolled-in rates because "they can
only hurt ..." Therefore, an independent pipeline company that
does not plan on owning the pipeline may support rolled-in rates
as they can be less costly than incremental rates. He opined
that incremental rates can be so much higher than rolled-in
rates that it may affect the ability to expand the pipeline.
For example, if expansion was done through compression, the rate
increase under incremental rates could be around $1.00, while
the rate increase under rolled-in rates could be around $0.15.
5:40:23 PM
REPRESENTATIVE WILSON suggested that the 15 percent cap on
rolled-in rates in AGIA is designed to protect the producers
somewhat and still provide some incentive to explorers.
DR. SCOTT characterized the aforementioned description as
exactly right.
REPRESENTATIVE WILSON asked whether the 15 percent limitation on
rate increases [AS 43.90.130(7)] is reasonable and fair to the
producers.
5:41:21 PM
DR. SCOTT responded that "fairness is in the eye of the
beholder." He explained that the 15 percent provision was
developed after considering issues described in slides 1 and 2
titled respectively, "Effects of Government Subsidies on Rates,"
and "Summary of Government Subsidies on Rates," from a
presentation on "Government contributions to rates" to the
Senate Judiciary Committee, 4/16/07. He explained that the
various federal and state subsidies granted the Alaska project
reduce the pipeline tariff by $0.25. On a tariff of $2.00, a
$0.25 reduction is about 12 and one-half percent, he explained.
He noted that the owners of the GTP will receive an additional
15 percent federal investment tax credit. He suggested that one
way to view the 15 percent cap in AGIA is to assure that
government subsidies are shared by all shippers in the system,
and are not "enjoyed only by the initial shippers." A further
consideration that supports the 15 percent cap is the state's
interest in assuring future pipeline expansions are not
"artificially capped," he explained. He opined that a 15
percent cap is likely to get the pipeline through full
compression and perhaps through a first looping on the project.
After the first looping, he suggested that rates may decline or
at least hold steady. He said there is uncertainty regarding
the effect of expansion on rates as it depends on when the
expansion occurs and the costs thereof.
5:46:14 PM
REPRESENTATIVE WILSON noted that the producers can negotiate for
certain rates prior to the project. She asked why the producers
claim that AGIA does not allow them to negotiate with FERC.
DR. SCOTT opined that the producers object to provisions that
require the pipeline company not negotiate rates that would
preclude it from rolling in expansion costs up to the 15 percent
cap. He suggested that if the producers own the pipeline,
business considerations would favor that they negotiate rates
with themselves which would prevent expansion costs from being
rolled-in to them as shippers. He offered that this matters
because if there is a subsequent expansion, it will be
"exceptionally difficult" for FERC to order rolled-in rate
treatment of expansion costs because there are "no shippers to
spread it over." As a political matter, the ability of FERC to
roll-in such expansion costs would be affected, he said. He
noted that a compression expansion of one billion cubic feet
(Bcf) would cost approximately $1 billion in compression
equipment.
5:48:32 PM
DR. SCOTT responded to a concern regarding the focus of the DNR
and the Department of Revenue (DOR) by explaining that it is not
the case that DNR is engaged solely in regulatory activities.
The Division of Oil and Gas has a crucial commercial function
since it is bound by contractual lease relationships with oil
and gas explorers. In comparison, the DOR acts in more of a
sovereign capacity. He opined that DNR and the lessees can be
considered equals under the bounds of contract law. The DNR,
through the Division of Oil and Gas, tends to have more
expertise on matters of geology, pipeline tariffs, and rate
making.
5:52:07 PM
REPRESENTATIVE ROSES said that the presentation really added
some clarity to issues of flexibility. He opined that those
"who were hollering the most" about flexibility appear to be the
parties with the greatest control over both sides of the pricing
structure. Additionally, he noted that until the ownership of
the pipeline is clear, the parties may want to wait to negotiate
the rate structure.
CO-CHAIR JOHNSON stated he was intrigued by the suggestion that
a 15 percent federal subsidy applies to the rates on the project
as it seems to lessen any conclusion that the pipeline owner
subsidizes shippers up to the 15 percent.
5:53:51 PM
DR. SCOTT said there is some confusion regarding the economics
of what a subsidy actually is. Initial shippers do not
necessarily subsidize later shippers as long as all shippers are
at least paying the "marginal cost," he explained. He noted
that in business expansions, very often costs rise and all users
pay the same increased costs. The only way expansion costs
could be a subsidy is if an initial shipper believes it has a
property right to a rate, and if there is a property right to a
rate, "what we're talking about is not subsidy, we're talking
about theft," he opined.
5:56:57 PM
REPRESENTATIVE SEATON asked for further discussion of whether
the 15 percent limitation could be characterized as a subsidy.
He suggested that all AGIA establishes is the state's preference
for rolled-in rates and that FERC will ultimately decide if
there is a subsidy.
5:58:18 PM
DR. SCOTT replied that an independent pipeline owner will want
to expand its business by expanding the pipe. He said it would
be in their interest to roll-in rates so as to decrease the cost
to new entrants. He offered that the pipeline company has no
commercial interest in assessing whether something is a subsidy
or not. Under AGIA the pipeline company is required only to
propose rates, while FERC "disposes" of rate issues. He
explained that the state's approach does not infringe on FERC's
jurisdiction; rather it helps assure that the pipeline company
"acts like a pipeline company" regardless of who owns the
pipeline.
[HB 177 was held over.]
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 6:00:13
PM.
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