Legislature(2007 - 2008)SENATE FINANCE 532
04/26/2007 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB104 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 104 | TELECONFERENCED | |
| + | TELECONFERENCED |
MINUTES
SENATE FINANCE COMMITTEE
April 26, 2007
9:10 a.m.
CALL TO ORDER
Co-Chair Bert Stedman convened the meeting at approximately
9:10:25 AM.
PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Charlie Huggins, Vice Chair
Senator Kim Elton
Senator Joe Thomas
Senator Fred Dyson
Senator Donny Olson
Also Attending: FREDERIC RICH, Head, Global Project Development
and Finance Group, Sullivan, & Cromwell, LLP; ROBERT SWENSON,
State Geologist & Acting Director, Division of Geological &
Geophysical Surveys, Department of Natural Resources; KEVIN
BANKS, Acting Director, Division of Oil& Gas, Department of
Natural Resources
Attending via Teleconference: There were no teleconference
participants
SUMMARY INFORMATION
SB 104-NATURAL GAS PIPELINE PROJECT
The Committee heard two presentations pertaining to the Natural
Gas Pipeline Project legislation: one from Sullivan & Cromwell
LLP on gas pipeline financing and one from the Department of
Natural Resources on potential gas reserves in the State. The
bill was held in Committee.
9:10:37 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 sixth hearing for this bill in the Senate Finance
Committee.
Co-Chair Stedman announced that this would be another in a
series of Committee hearings focused on gathering information
pertinent to the Alaska Gasline Inducement Act (AGIA).
Co-Chair Stedman announced he had asked Frederic Rich with
Sullivan & Cromwell, LLP, an international law firm based in New
York, to review select information from a gas pipeline financing
presentation he had recently presented to another Legislative
committee which Co-Chair Stedman had attended. Sullivan &
Cromwell, LLP is consistently ranked "in league tables and
surveys" as one of the top leading advising law firms for oil
and gas and pipeline financing. The firm has been a participant
in five of the ten largest "and completed" international oil and
gas pipeline financing projects.
Co-Chair Stedman noted that following Mr. Rich's remarks, the
Department of Natural Resources would be presenting information
regarding gas reserves in the State.
9:12:57 AM
FREDERIC RICH, Head, Global Project Development and Finance
Group, Sullivan, & Cromwell, LLP, informed the Committee that
Sullivan & Cromwell specializes in "mega projects" with capital
costs "in excess of a billion dollars".
Mr. Rich noted that while Sullivan & Cromwell LLT has typically
served as lead financial advisor to the producers group, his
remarks would be his own and should not be viewed as the opinion
or position of any producer group member.
9:14:18 AM
As noted by Co-Chair Stedman, Mr. Rich affirmed he would be
elaborating on specific information in the "Project Finance
Workshop, An Introduction to Project Finance for Oil, Gas and
Pipelines" presentation, dated April 25, 2007 [copy on file].
First, however, he wished to elaborate on a question he had been
asked the previous day regarding whether "the authority of the
Secretary of the Department of Energy (DOE) to issue the federal
loan guarantee, the authorization, had any sunset or expiration
date…"
Mr. Rich affirmed there was no expiration date associated with
the federal loan guarantee authorization; however, the Secretary
of the DOE must "issue the federal loan guarantee instrument"
within a two-year period after the Federal Energy Regulatory
Commission (FERC) issues a project a Certificate of Public
Convenience and Necessity.
Mr. Rich also noted that the certificate would be considered
"issued" when all the certificates had been issued that "are
required in connection with transportation of commercially
economical quantities of gas".
9:15:39 AM
Mr. Rich considered it worthwhile to remind the Committee that
"the scale and magnitude of this project and the extent to which
it would likely make its own market" makes it difficult to
compare its financing to other oil and gas projects. Here-to-
fro, the largest completed financing for any industry project
was $6.7 billion and "the largest previous pipeline financing
was $2.6 billion".
Mr. Rich characterized this project, in terms of financing, as a
"quantum leap into new territory". It is so large that no
structures and procedures from any previous project could be
"scaled up" to size. Thus, even "the magnitude of the risk is
qualitatively different".
9:17:03 AM
Mr. Rich, understanding that the Committee desired more
information on how "the presence" of the federal loan guarantee
might affect other aspects" of the project such as project
financing, shared that "the federal loan guarantee in effect
only has the affect of interposing the federal government either
as the lender or as an additional lender". Thus, any reference
to a condition imposed by the lender would infer it to be a
requirement of the federal government, especially where the
federal loan guarantee 100 percent.
Mr. Rich communicated that having a federal government guarantee
on the project "is hopefully providing an incentive for the
project to proceed by lowering the cost of the debt". One should
be mindful that the federal loan guarantee is not free money; it
must be repaid since the federal government "must behave" as any
prudent lender would.
Mr. Rich specified that were the federal government to guarantee
100 percent of the debt, "it will have a financial advisor which
will advise it on the terms and conditions and structures and
covenants" and other components of project financing.
Mr. Rich stated that in the case of a federal government
guarantee of less than 100 percent of the debt, there would be
other "lenders taking full project risks post completion" in
addition to the federal government.
Mr. Rich, referencing the immensity of the project, noted that
if the federal government guarantee was 80 percent, the
remaining "un-guaranteed portion itself would be one of the
largest project financings … ever undertaken" for an oil and gas
industry project.
Mr. Rich expressed that having a federal guarantee would likely
not change any of the requirements or "lessen any of the
pressures or requirements" associated with the project. Were the
federal government to pay "under the guarantee" for any default
in a loan, there would simply be "a change in lender; the
borrowing company, the pipeline company, still owes the money,
but instead of owing it to Citibank, if that was the initial
lender, it now owes it to the federal government".
9:19:56 AM
Mr. Rich next addressed the "completion support or completion
guarantee" agreements associated with a pipeline. The interplay
between the required completion support and the federal loan
guarantee is specified in federal statute, in that "the
Secretary shall not require as a condition of issuing a federal
guarantee agreement, any contractual commitment or other form of
credit support of the sponsors other than equity contribution
commitments and completion guarantees".
Mr. Rich noted that equity contribution commitments and
completion guarantees "are alternative forms of providing
completion support". Equity contribution commitments are "a
promise by the shareholders or owners of the pipeline company
that they will put in the required equity portion under the base
case budgeted capital costs and that they would put in an
additional portion in respect of overruns". Other oil and gas
projects have required an additional 30 percent of the estimated
capital costs for project overrun expenses.
Mr. Rich disclosed that a "completion guarantee is an
alternative form of completion support where the shareholders of
the pipeline entity actually guarantee the debt when the debt is
incurred during the construction period and those guarantees are
in full force and effect until completion is met". He specified
that "completion is defined as meeting a set of physical,
operational and financial tests."
Mr. Rich contended that "before completion exists, there is no
project, there is no credit, there is no facility, there's no
way for the lenders to be repaid so they are looking to the
guarantor". In order to pass a completion test, the pipeline
must be built as scoped, must be able to operate at the required
capacity; and must meet the entirety of other requirements in
the credit agreement. These other requirement might include such
things as firm shipping commitments. "Once all those things are
certified … the completion guarantees fall away".
Mr. Rich concluded that either a completion guarantee or an
equity contribution commitment would be required by a federal
guarantee. They could be in place "on day one so that the
lenders would have the comfort of the federal guarantee and the
parties providing the completion support would give the support
to the federal government". One example of this is "a straight
debt guarantee" which "would be a counter guarantee of the
federal government by the shareholders". In this case, if a pre-
completion default occurred, "the federal government would pay
the bank, and then it would turn and make a claim against the
shareholder under its guarantee".
Mr. Rich advised that a straight debt guarantee "would lower the
cost of the debt because the bank lending the pre-completion
will price it at a U.S. government risk margin".
Mr. Rich stated that if the federal government decided against
taking completion risks, it could wait to issue its' guarantee
until after the pipeline was completed. In this case "the
shareholders would directly guarantee to lenders until the
completion was met". "The cost of the guarantee would reflect
the credit rating of the shareholders of the pipeline company…"
Mr. Rich concluded his comments regarding the "interplay between
these completion issues and the federal guarantee".
9:24:29 AM
In response to a question from Mr. Rich, Co-Chair Stedman
requested that Members hold their questions until Mr. Rich
completed his presentation.
9:25:02 AM
Sullivan & Cromwell LLP
Project Finance Workshop
An Introduction to Project Finance
for Oil, Gas and Pipelines
April 25, 2007
Section 5
Project Finance for Oil, Gas and Pipelines
Page 48
Why do lenders like oil, gas & pipeline projects?
· Past experience has been good
· Resource based lending for upstream projects; contractual
based lending for pipeline projects
· Technologies are usually well-proven
· Particularly suited to cash-based credit analysis - cash
flows clear
· Either commodity products without market risk (oil), or
highly credit-worthy off-take/transportation commitments
· One of the main post-completion risks is usually price
risk - which, traditionally, banks understand and can
price
· Sponsors can be
× highly creditworthy
× experienced with large projects, conservation culture
× judged by lenders unlikely to abandon strategically
significant projects
Mr. Rich directed attention to page 48 of Section 5 in the
presentation [copy on file]. He noted that since lenders
typically provide 70 to 80 percent of a project's funding, their
primary focus is on being repaid in a timely fashion. This is a
very different perspective than those of "the developers who
stand to earn an equity return or upstream producers who stand
to be able to market their gas and earn an upstream return".
Mr. Rich communicated that lenders tend to view projects in a
"what could go wrong" manner. Nonetheless, "there is a good deal
of enthusiasm" amongst lenders, specifically commercial banks,
"about the oil and gas pipeline sector". The probability is high
that this project could be financed.
9:26:50 AM
Mr. Rich cautioned the Committee to be aware that banks and
other lending institutions "tend to be in marketing mode" during
the initial stages of a project. They might label the project
"fantastic" and state their willingness to help finance it. It
is not until later in the process that intricate issues, such as
the firm commitment contract agreements, are addressed.
Mr. Rich also noted that one of the primary questions
shareholders of any project must address is whether to seek an
independent financial advisor "who would not be competing to do
the business of making the loans or underwriting the bonds or do
they seek a bank that actually will both give them advice and
then change to the other side of the table and be the
counterpart negotiating the terms of the credit".
Mr. Rich considered there to be valid arguments for each
approach; however, most of the "more sophisticated companies" as
well as the United States government, prefer to have an
independent financial adviser. This issue is being highlighted
because it is likely that the information presented on page 48
would be experienced. Banks "love doing oil, gas and pipeline
business, especially" projects in the United States. Currently
only 15 percent of this lending market is for projects in the
United States. Most of these capital requests to banks are for
projects in places such as Russia and Venezuela, "and places
where there's a whole different element of risk".
9:29:24 AM
Mr. Rich expressed that an oil and gas project in North America
is attractive to lending institutions for the reasons specified
on page 48.
9:30:05 AM
Page 49
Upstream vs. midstream (pipelines)
Upstream
· Oil projects involve commodity products with little or
no market risk; transportation may not be an issue
· Gas projects depend on available transportation and
market, and strength of off-take commitments
Mr. Rich reminded the Committee that the upstream and midstream
marketplaces are "very different". In addition, gas is a more
complicated commodity than oil to address.
Page 50
Upstream vs. midstream
Midstream
Pipeline credits vary widely - depending on
· Degree of project integration with
upstream/downstream
ƒUpstream and midstream as integrated project
ƒSeparate but with upstream producers as
owners of midstream
ƒSeparate with upstream producers' role
limited to customer
· Contractual and credit links into upstream
ƒProducer transportation commitment vs. buyer
as shipper
ƒNature of transportation commitment
· Tariff structure
ƒUnregulated - negotiated tariff
ƒCommon carrier
ƒFERC/NEB
· Emerging market vs. developed
9:30:16 AM
Mr. Rich reminded that issues pertaining to "a separately
constituted midstream project" were discussed at length during
the previous day's presentation. While there has been
"successful financing of separately constituted midstream
projects" in the United States, the current trend outside of the
United States is that both producers and lenders are tending "to
prefer the integration of the upstream and midstream" efforts.
This project should be weighed to determine which precedents
might apply to it.
9:31:22 AM
Page 51
Main Pipeline Financing Approaches
Degree of Integration with Upstream/Downstream
· Especially for large strategic projects which rely
on single transportation system, producers want (i)
timely development of transportation, (ii) control
over construction and operating costs, and (iii)
reliability - usually leads to integration with
upstream or producer participation if midstream is
separate
· Even if pipeline is organized as a separate project,
development of upstream resources, transportation
commitments and downstream markets are foundations
of the pipeline credit
Mr. Rich declared that "as long as this project is separately
constituted, which it will be, the key issues would be: what is
the nature of the link or the contractual claim that the lenders
to the midstream pipeline project have on the availability of
the upstream reserves … That of course is a function of the firm
transportation contracts."
9:31:29 AM
Page 52
Main Pipeline Financing Approaches
· "Dual Project Risk"
o Dual completion risk if separate upstream project is
also greenfield
o Crux of issue: midstream lenders exposed to upstream
risks without normal covenants with and remedies
against upstream project
o Creates tremendous pressure (i) for common ownership
or (ii) on terms and conditions of transportation
agreements as only "link" into upstream
o Financing complexity, time and costs also can increase
Page 53
Transportation Agreements
· Transportation Agreement defines cash flows for pipeline
borrower
o Producer or buyer as shipper
o Nature of shipping commitment
ƒShip-or-pay (most common)
ƒShip-and-pay
· For ANGP, as FERC/NEB regulated project, open season bids
would be on the basis of firm transportation commitments
9:31:40 AM
Page 54
Transportation Agreements
Firm Transportation Commitment (ship or pay)
· Key midstream financing issues are tenor, volume,
tariff, shipper credit and force majeure
o If Federal guarantees are available and used,
these are issues for Federal government as
guarantor, and for lenders as to any uncovered
portion of debt … but force majeure exceptions to
"ship or pay" obligations are key
· Starting point for midstream post-completion credit
is blended credit behind shipping commitments
· Shipper credit analyzed based on (i) financial
strength, (ii) upstream development and operating
costs and break-even net-back, (iii) end-user
markets, and (iv) sufficient volumes to fulfill firm
commitment
· In FERC regulated transaction, tariff adjusts -
generally protects lenders because costs passed on
to shippers
· Producers may be reluctant to enter into firm "ship-
or-pay" commitments if they do not own the pipeline
Mr. Rich identified key elements a lender would consider when
judging the adequateness of firm transportation agreements
(FTs). These would include: "their duration in relation to the
duration of the debt" as "the general rule is that the tenor of
the off-take contract or the FT agreement" should be as long or
longer than the length of the debt obligation; "the volume of
the commitments must be sufficient to repay the debt"; and "the
credit" behind the FTs.
Mr. Rich disclosed that lenders analyze FTs on two levels. The
technical analysis would consider the entity giving the
commitment and their credit ranking. "There is no credit"
accompanying a company whose sole business "was the production
of upstream reserves in Alaska" as that company would not have
"the cash to pay the commitment unless it is in fact monetizing
the gas". This scenario might be acceptable to lenders if the
company was a component "of a larger corporate group" and there
was the "expectation that the larger corporate group will cause
that affiliate to meet its obligations".
Mr. Rich expressed that that expectation would not typically
hold true if the entity behind the FT "does not have a public
investment grade credit rating". In that case, the lenders would
require additional credit supports or guarantees.
9:34:39 AM
Mr. Rich stated that the second analysis would be a commercial
and economic analysis of "how likely is it … that company would
perform its obligations". In the case of a gas pipeline, this
analysis "leads right into an integrated economics of the whole
enterprise". Questions would include such things as whether the
netbacks would be positive, and, over a 20 or 30 year period,
would "it make commercial sense to lift the gas and transport"
it. The "entire value chain" of the project must be modeled and
projected.
9:35:12 AM
Mr. Rich stated that the modeling would be comprehensive and
would consider such things as operating costs, reservoir data,
fiscal, and gas market forecasts. The ultimate question would be
whether the company could pay back the $20 billion debt over the
next 20 years under a negative netback scenario as compared to
the scenario "where the upstream business is going fine and the
netbacks are positive and they're continuing to produce".
9:37:17 AM
Page 55
Transportation Agreements
Force Majeure
· In "ship-or-pay", force majeure provisions define
circumstances where shippers do not have to pay
· Of key importance to lenders, since force majeure events
result in interruption in cast flow available to service
debt
· Main force majeure provisions cover
operational/availability risk in midstream - if midstream
cannot accept gas, shippers not obligated to pay
· Result is keen lender interest in (i) quality of original
design and construction, (ii) operational expertise and
track record of midstream operator, and (iii) technical
and financial capacity of midstream project company and
its owners to address operational issues
· Project size and complexity, together with long tenor and
large size of midstream financing, likely to increase
these concerns in ANGP
Mr. Rich identified force majeure (FM) provisions as another key
consideration in the lending process as contracts do not require
shippers "to pay the tariff in 100 percent of the
circumstances". Even though shippers "do take most of the risk"
of paying, "they are excused from paying … if pipeline is not
available to accept and transport tenured gas … As a result,
it's a risk the midstream lenders take". If the pipeline is not
available due to such things as an environmental problem,
"there's no cash flow".
Mr. Rich informed that consideration of the pipeline operators'
"operational track record and expertise" as well as technology
and operating support is "an essential part" of the lender's
credit decision and "their pricing of the credit". "Force
majeure provisions are heavily negotiated" and are not
standardized. In addition, they are affected by the Federal
Energy Regulatory Commission (FERC) process.
Mr. Rich, who professed not to be an expert in the FERC process,
did know that "FTs are able to be negotiated prior to the open
season so that these force majeure provisions [indiscernible]
basically arise as a matter of negotiation".
Mr. Rich emphasized that FTs do affect the financing of a
project. "If the owners of the pipeline are completely dependent
on financing", an attempt would be made early in the process "to
understand and anticipate" what financing would be required.
Therefore, it is likely that at the time the FTs are being
negotiated, a company would be anticipating finance
requirements. "But there is always risk". He could not comment
further as he was uncertain of this project's development
timetable. Nonetheless he espoused that integrating the FERC
timetable with the financing timetable "is a complex matter".
9:40:55 AM
Mr. Rich acknowledged, however, that finance commitments are
"conditional ultimately on the issuance of the certificate" and
other assumptions. "But at the end of the day, the FTs have to
be acceptable to the lenders one way or another."
9:41:23 AM
Page 56
Structural issues for cross-border pipelines
ƒSeparate entities in each country most common
ƒCan be separately tranched loans to each entity, but
o Cross-completion risk
o Sometimes structured to create unified credit
ƒTwo loans can equal more complexity and cost and longer
time to develop
Mr. Rich stated that the issue with cross-border pipelines "is
that even if the pipelines were separately constituted in Alaska
and Canada or had separate ownership groups" they would be
considered a single "integrated" pipeline from a credit
perspective.
Mr. Rich voiced that cross-border transactions are complex,
costly, and require additional time to process and develop.
9:42:13 AM
Page 57 and 58
10 Largest Oil and Gas Pipeline Project Financings
(greenfield and expansion only - excludes acquisition
financing and refinancings)*
[Listing of five projects by name and location, total
capital cost (senior debt portion), sponsors, and financial
advisors to the consortium.
For example, the Alliance Pipeline Project (Gas) in Canada
and the United States cost $3,730,000,000 with
$2,590,000,000 of that being debt. It was sponsored by
Coastal, IPL, Williams, Fort Chicago Energy, and Westcoast
Energy. Goldman Sachs, Scotia, Paribas served as the
projects financial advisors.]
*Also excludes primarily upstream projects with an
integrated pipeline component. Based on Dealogic database
Mr. Rich informed the Committee that the largest United States
pipeline project cost slightly less than one billion dollars.
The smallest of the top 20 largest pipeline project financing
projects was in the vicinity of $10 to $20 billion.
Mr. Rich stressed that one of the toughest judgment calls
associated with this project is whether the largest domestic
FERC-regulated project to date could be scaled up to this
project's size "and expect it to achieve the same result". The
effort must be to determine what components of the large
projects would apply or not apply to AGIA. This would include
consideration of upstream conditions, multiple producers, access
to a variety of fields, the nature of the off-stream off-take.
Particular attention and worry would revolve around the scale of
the project.
Mr. Rich concluded his remarks.
9:43:46 AM
Co-Chair Stedman asked for further information about how
"lenders deal with the debt to equity split", including whether
a specific split ratio was favored. He also questioned the
leverage a lender might have in "requiring a change in the debt
to equity".
9:44:17 AM
Mr. Rich stressed that from a financing perspective, both "the
percentage and the actual quantum of the equity in the project
is one of the key foundations of the credit". What lenders like
"to see is that somebody else has a lot of skin in the game."
This is because the equity placed in a project is the element
that would suffer the losses first. Thus, "lenders take a
tremendous amount of comfort from the size and percentage of the
equity interest".
Mr. Rich declared that "lenders do not desire to be over-
exposed" and, therefore, as funding is spent, "the matching
equity" contribution component" is constantly re-certified in
order for the project to receive additional money.
9:46:00 AM
Mr. Rich advised that additional "financial drivers" included
"the concept of a project's debt capacity". He detailed the
added complexities of the debt capacity when FERC regulations
are involved, including the role shippers play in the equation.
Mr. Rich also noted "that de-leveraging gives lenders a great
deal of comfort". In contrast, a developer's financial objective
is for "maximum leveraging". In today's financial arena, "the
whole world of private equity is one where returns are increased
through the maximum use of leveraging. When debt is inexpensive,
as it is today, you get those higher returns".
Mr. Rich noted, however, that from a lender's perspective, this
serves to increase risk. Lenders would prefer "lower leverage,
higher amounts of equity". This interplays with other issues.
"None of them independently make it bankable or not bankable,
but it's the cumulative affect of all of these that raise the
cost, and make it ultimately less or more likely that the
financing will get done".
9:49:50 AM
Mr. Rich communicated therefore that "one of the strategies
used, if the developer has the financial capacity to do it", is
to de-leverage the project. If the terms of the FTs cannot be
improved in a way acceptable to the lender, then a lender could
be enticed to participate by de-leveraging the project or
changing another "risk factor that the lenders are unhappy
about". De-leveraging is a commonly used strategy.
9:50:05 AM
Senator Elton struggled with his desire to seek specifics while
understanding that Mr. Rich, whose role was not that of a
consultant, desired to speak in terms of "generalities".
Nonetheless, he directed attention to an AGIA provision which
specifies a "must have" debt-equity ratio of a minimum 70 to 30
(70:30) percent. He understood that an 80:20 ratio would be
acceptable, but a 65:35 would not, as that would result in a
lower tariff. He concluded therefore that "if a hard line" was
set, it could limit the pool of lenders.
9:51:12 AM
Mr. Rich stated that while he could not address the specifics of
that provision in AGIA, he would stress "that flexibility is
key". He reiterated a statement he had made during his full
presentation as to "how important" it was "that the DOE not be
prescriptive in the loan guarantee provisions". This is
extremely important in "a project of this size and complexity".
"… At the end of the day, de-leveraging the project somewhat
could be what was required to get it to go ahead".
9:52:24 AM
Mr. Rich communicated that at the onset of a project this size,
it would be impossible to have "utter confidence going into it
…of what would be required". "It's only once the commercial
arrangements have been set and contracts have been negotiated
and the project has been designed, you know, the cost estimates
been refined, that you can really get a sense of what the
finance plan is going to look like. And what degree of equity is
required and what leverage is permitted is one of those things
you discover through that process".
9:53:01 AM
Senator Huggins spoke to an [unspecified] Library of Congress
document that addressed the two year time period after the
issuance of the FERC certificate. The concern was to what
considerations might be made by the DOE Secretary in regards to
a project when the time required to meet the conditions mandated
by DOE exceeded the allotted time period.
9:54:28 AM
Mr. Rich admitted being worried about the two-year provision. He
could foresee a multitude "of circumstances where, despite the
best efforts in the world, we would not be in a position to
close the financing and have the loan guarantee agreement issued
within that two year window". The historical experience for
financing mega projects has been approximately five years. Time
must be permitted to address such things as litigation or
permitting issues.
Mr. Rich was unsure how the DOE Secretary would address this.
Usually this person forms a team of lawyers and advisors,
develops financial models, conducts studies, and analyses the
credits and the contract, and develops documentation.
9:57:00 AM
Mr. Rich advised of another worry. That being that "the
promoters of the project will not only want a financing, but
they'll want to optimize the financing because the cost of the
financing is the major determinate of the economic viability of
the whole project". Another consideration is whether the health
of the overall financial marketplace is favorable.
9:57:42 AM
Senator Huggins declared that the operational concept of this
project might be one that "could see the lapsing of the loan
guarantee and we're continuing to move toward something that is
scary."
9:58:12 AM
Co-Chair Stedman asked for further information about "the
potential of the non-recoursability of the loan guarantee";
specifically whether "that loan guarantee could be issued using
government bonds". This would allow the bond market "to generate
the capital to build the line and then" having the entity
desiring to build the line "have a non-recoursability against
the note so we can't in any way have the corporate balance sheet
exposed to back the loan guarantee". In other words, the
question is whether a firm could "use the loan guarantee on a
non-recourse basis so they don't have their balance sheet
exposed".
Mr. Rich replied "yes, post completion ….The loan guarantee is
available for a limited recourse project financing structure, so
that after the completion tests have been met, the federal
government in its role as lender … and its quite right as you
say, there's bond holders out there…they don't care, if the
guarantee covers 100 percent of their bonds, they hold a U.S.
government piece of paper. So, they're indifferent as to whether
the project is able to pay its debt, because, if there's any
problem, the government pays them. And then the question is,
'what is the nature of the government's recourse?' And, post-
completion, the government's recourse is limited recourse, i.e.
it is to the project pipeline company and not to the balance
sheet of its shareholders. So, the government is no different
than if the guarantee was not into place. It's the same thing.
Pre-completion, it's looking to recourse to the parent company
balance sheets, if there's a guarantee, or to the parent company
balance sheets for over-run funding if it's an overrun equity
commitment. Post-completion, they're taking the risk that the
pipeline company will have the revenue sufficient to pay."
Mr. Rich concluded by stating "pre-completion, full recourse;
post-completion, limited recourse".
10:00:52 AM
Co-Chair Stedman surmised therefore that in the pre-completion
phase, "it would be reasonable to expect the lender then to want
a balance sheet or a consortium of 'em strong enough to handle
the impact" of a project if things go amiss.
Mr. Rich agreed. "It's easiest to analyze if it's a classic
completion guarantee", as referenced in federal stature, where
it specifies "equity contribution commitments and completion
guarantees. And if it is a completion guarantee, the party
giving the guarantee has to be creditworthy." He noted having
read a recent [unspecified] Notice of Intent document in this
regard written by the DOE Secretary, "which is quite typical" to
what "you see from the other federal guarantee programs: 'There
has to be a reasonable reassurance of repayment of the debt. The
terms and conditions provide adequate terms and security
appropriate to protect the financial interests of the United
States'."
Mr. Rich stated that the Secretary would "look at this just the
way a bank would". He shared two points: first, "the credit
behind the completion guarantee does have to be adequate. There
is a binary element to this. It's highly improbable that a
project of this size could be done without investment grade
credit behind that completion support. There's also a pricing
element" in that the interest levied pre-completion would
reflect that credit.
Mr. Rich exampled therefore that the interest costs would be
lower for a company with a AAA credit rating giving the
guarantee. The costs would be higher for a company with a BBB or
a BBB- credit rating, which both qualify as investment grade
ratings.
Mr. Rich stated that there is an "availability, a do-ability,
and a pricing aspect to that, absolutely".
10:02:50 AM
Co-Chair Stedman "assumed that the number of corporate entities"
with either a AA or AAA credit rating that are able to back
billion dollar projects would decline sharply "as the size of a
project goes up in ten billion increments".
Mr. Rich emphasized that the size of a project is a major
consideration. "You can't assume that the precedence can be
scaled up".
Mr. Rich expressed that lenders might not view a company with an
"A" credit rating and four billion dollars of capital on its
balance sheet simply in terms of its "A" rating, particularly
when "the amount of the guarantee is huge in relation to the
debt".
Mr. Rich expanded his example. Were this company participating
with two other entities on an $18 billion project with an $18
billion federal guarantee, the company, with only four billion
dollars in capital, "would be adding a six billion dollar
contingent obligation. That's not a single A credit". Lenders
tend to view company's credits on a proforma basis in that they
would, in addition to considering a company's position today,
consider how it might look after it is "loaded with this large
contingent obligation on its balance sheet".
Mr. Rich noted that if this was a completion guarantee, "it's a
straight debt guarantee". In other words, the moment the
completion test is not met or any amount is due pre-completion,
the company "would be obligated to pay it as if it were their
own debt".
Mr. Rich communicated that a small company wishing to
participate in a large project might be required "to issue
additional capital … and grow in size in order to have the
financial capacity to cover the completion risk".
Mr. Rich stated that "if it's a good project", the post
completion guarantee approach is fine if a company had good
viable credit. The problem is dealing with the completion. "It's
classic in the resource sector", that, while developers and
small mining companies might have all the required rights to a
"sound, good, profitable" resource discovery, "they don't have
the financial capacity to meet the completion support" criteria.
This typically requires those small companies to join with a
larger company to gain that completion support, or sell, or
merge".
Mr. Rich characterized the project financing scenario as the
"gating issue: you don't get past the starting line unless you
can handle, somehow, the completion risk".
10:06:44 AM
Senator Dyson, referencing the cross border information depicted
on page 56, asked how the loan guarantees would work if a
Canadian firm was involved in the Canadian portion of the
project. He also asked that the term "tranched" be defined.
10:07:19 AM
Mr. Rich explained that "'tranched' means a slice or piece of
the loan". A loan could be divided up into different segments.
Mr. Rich stated that having different ownership interests on
each side of the border in a cross-border pipeline is a common
occurrence. This is acceptable "from a financing perspective,
provided that …. the credit behind the completion support is
strong enough on both sides of the border…" Lenders must be
assured that some entity would ultimately take the completion
risk. Sometimes one entity would assume the completion risks for
the entire project regardless of which side faltered.
Mr. Rich expressed that separate loans or tranches might be
assigned to the cross-border entities in order to recognize the
different companies' credit ratings or other circumstances
including whether the loan involved Canadian or United States
funds.
10:09:46 AM
Senator Dyson clarified his question. He was interested in how
the federal loan guarantee would apply to a cross border
project.
Mr. Rich conveyed that the federal loan guarantee statute would
allow this. "The Secretary may also enter into agreements with
one or more owners of the Canadian portion of a qualified
infrastructure project to issue federal guarantee instruments
with respect to loans and other debt obligations for a qualified
infrastructure project" utilized to "transport natural gas from
the Alaska North Slope to the continental United States".
10:10:49 AM
Senator Thomas deduced that the Trans Alaska Pipeline System
(TAPS) had not been included in the listing of the ten most
expensive pipeline projects because it had been privately
financed.
Mr. Rich affirmed.
Senator Thomas asked whether any other privately funded projects
the size of TAPS have been undertaken.
Mr. Rich assured Senator Thomas that many such projects have
been undertaken by "large integrated international oil
companies". They are financed in a multitude of ways including
borrowed funds or internal financing.
Senator Thomas asked whether having existing infrastructure in
an area such as in Prudhoe Bay, even though it was oil related,
was beneficial.
Mr. Rich stated that "anything that reduces cost is helpful".
Not being required to build "expensive new infrastructure will
either be beneficial to the midstream or the upstream netback,
which the midstream lenders care about". Any activity occurring
in the "upstream that provides lenders confidence that the
reserves and the dynamics of the reserves are well understood
and that the risk of bringing the gas into successful production
is low is helpful, no question".
Senator Thomas asked whether lenders would view a project in
Canada or the United States more favorably than a project in an
area with a less stable political environment.
10:13:16 AM
Mr. Rich responded in the affirmative. He stressed however, that
the fiscal aspects of a project "are universal: anything that
hits that netback is something in which lenders are interested"
regardless of its location. Aside from the fiscal risks of a
project, political risks are a consideration. This project would
generate a lot of interest due to its North American location.
Co-Chair Stedman thanked Mr. Rich for his remarks.
AT EASE 10:13:59 AM / 10:22:06 AM
Co-Chair Stedman stated that the Committee would now hear a
presentation from the Department of Natural Resources. Of
particular interest was how oil and gas activities in the
federal offshore regions might impact the capacity of the
proposed gasline, as the revenue the State receives from those
areas is significantly lower than the revenue generated from
resources on State land and offshore areas.
10:23:21 AM
Alaska Department of Natural Resources
Briefing for
Senate Finance
Current Gas Reserves & Resource Estimates
ANS & Offshore
Robert Swenson
State Geologist & Acting Director
Division of Geological & Geophysical Surveys
http://www.dggs.dnr.state.ak.us
http://akgeology.info
April 26, 2007
ROBERT SWENSON, State Geologist & Acting Director, Division of
Geological & Geophysical Surveys, Department of Natural
Resources stated that his Division and the Department's Division
of Oil and Gas have collaboratively worked on developing the
information included in this briefing [copy on file].
Mr. Swenson, whose professional background included 15 years as
a field and exploration geologist in the State, informed the
Committee that a significant amount of work was required to
develop the reserve estimates included in this presentation.
10:24:44 AM
Page 2
Overview
· The State of Alaska does not perform quantitative,
probabilistic resource assessments, but works closely
with the agencies that do
· All numbers presented here are from US Geological Survey
& MMS
· resource assessments published between 1999 and 2005.
· All estimates provided are based on rigorous analysis of
all available data, geology, existing accumulations, and
basin analogies
· All non-reserve estimates are presented as technically
recoverable resources (as contrasted with economically
recoverable or gross resources or gross in-place
estimates).
· Resource estimates used represent the mean of a
probabilistic Resource estimates used represent the mean
of a probabilistic
· distribution with associated P5 & P95
Mr. Swenson read the information and noted that the Department
works closely with the US Geological Survey (USGS) and the
Department of the Interior Minerals Management Service (MMS).
Further information on the "P5 & P95" elements would be
forthcoming.
10:25:51 AM
Page 3
Oil & Gas Resources Team
[Graphic of a Viking sailing ship with "Resource Assessors"
steering the ship and "Highly Trained Fearless Explorers
and…." manning it.]
Mr. Swenson likened the agencies composing the Oil & Gas
Resources Team to "highly trained fearless explorers that are
out there looking for the next big find".
10:26:06 AM
Page 4
Overview of Regional Geology
[Geological diagram of the Brooks Range, the Foothills, the
Coastal Plain, and the Beaufort Sea regions of the Central
North Slope.]
Mr. Swenson stated that the unique regional geology of the North
Slope is a crucial element in the assessment numbers. This
region is considered the definitive "world class hydrocarbon
province". Three primary areas of importance in this analysis of
the North Slope are the Barrow Arch, the Colville Basin, and the
Brooks Range. The Colville Basin is a collection point for
sediment eroded off the Brooks Range.
10:27:30 AM
Page 5
North Alaska Stratigraphy & Petroleum Plays
- As used in USGS NPRA Assessment
- Play definitions will vary slightly among assessment
provinces
[Cross-sectional diagram depicting the strata formations
and Petroleum Plays during the Cenozoic, Cretaceous,
Jurassic, Triassic, Permian, Pennsylvanian, Mississippian,
and Devonian and Older ages based on a 2002 USGS
assessment.]
Mr. Swenson explained that one component of the assessment
includes comparing the various geological events in Alaska, such
as continental "rift" areas, to other regions in the world. Rift
analogies have been drawn to places such as the North Sea, the
Suez Rift area, and other rift basins with significant
hydrocarbon bases.
Mr. Swenson disclosed that the "thrust belt" in the foothills
regions of the Brooks Range is another geologic occurrence with
analogies around the globe, including "the Canadian Rocky
Mountain front, where there has been a significant amount of
exploration" and a significant amount of gas found.
Mr. Swenson stated that the North Slope "is unique" in that it
contains these "two major types of oil provinces".
10:28:38 AM
Page 6
[Diagram depicting the variety of information gathered to
develop the "probalistic resource potential of an area."
Mr. Swenson stated that this information is reflective of the
intensity of the work conducted to complete a resource analysis
for, in this case, the National Petroleum Reserves - Alaska
(NPR-A). The stratigraphic diagram on the right depicts rock
formations deposited over time. To the right of that is depicted
the "petroleum plays", which are based on seismic data, well
logs, and the experience of discoveries across the basin. All of
these factors are considered when developing the "probalistic
resource potential for an area".
10:29:16 AM
Page 7
NPRA Assessment Area
[USGS Seismic Grid of the National Petroleum Reserve -
Alaska, depicting exploration wells and known accumulations
of oil, gas, and Announced Oil discoveries.]
Mr. Swenson noted that this diagram depicts known accumulations
of oil, gas, and announced oil discoveries based on seismic data
in NPR-A. The geological activities depicted on page 6 were
conducted in order to project the area's "play types".
Mr. Swenson pointed out that the density of exploration wells in
NPR-A is depicted by white dots on the diagram. It would be
"fair to say that this is a very under-explored region". "This
area would be completely covered up with white dots" were it a
mature area that had experienced a significant amount of
exploration. Information from exploration wells with discoveries
is utilized in the resource assessment.
10:30:35 AM
Page 8
North Slope Oil & Gas Activities & Discoveries March 2005
{Map depicting oil and gas activities and discoveries. Oil
accumulations, gas accumulations, recent discoveries, and
exploration wells drilled in 2003, 2004, and 2005 are
identified.]
Mr. Swenson stated that discoveries, specifically in the Barrow
Arch region, are depicted on this page. A number of discoveries
have been made in both the foothills region and the State's
offshore regions even though those areas have experienced a
limited amount of exploration.
10:31:10 AM
Page 9
Proven Gas Reserves
Does not include Probable
(reserves growth through continued development)
North Slope
Badami Unit O BCF
Barrow 34 BCF
Colville River Unit 400 BCF
Duck Island Unit 843 BCF
Kuparuk River Unit 1,150 BCF
Milne Point Unit 14 BCF
North Star 450 BCF
Prudhoe Bay Unit 24,526 BCF
Other Undeveloped 8,000 BCF
TOTAL NORTH SLOPE 35,417 BCF
Cook Inlet 1,650 BCF
TOTAL STATE 37,067 BCF
Source: 2006 Annual Report, Alaska DNR-Div. of Oil and Gas
Mr. Swenson explained that the collection of geological
information assisted the Department in its analysis of the
State's proven gas reserves, including reserves that are already
discovered and delineated, proven and probable.
Mr. Swenson communicated that approximately 35 trillion cubic
feet (TCF) of proven gas reserves are available on the North
Slope. Geologists refer to these reserves as "behind pipe".
10:32:02 AM
Page 10
[Map of the State depicting Statewide Alaska Natural Gas
Resource basins based on USGS estimates of State onshore
and offshore natural gas resources, as well as MMS
estimates of federal Outer Continental Shelf (OCS) natural
gas resources]
Mr. Swenson stated that the important point regarding the USGS
resource assessment of gas in the State, conducted in the year
2001, is that "these are technically recoverable reserves and
undiscovered volumes". A range and mean of the reserves at each
location is provided. These ranges are "estimates are volumes of
gas at 95% and 5% probabilities". A 95 percent probability case
would indicate there being "95 percent confidence that what will
be found in the future in these resource assessments, it falls
within that range". A five percent range indicates there being a
95 percent probability it would not. The mean is "the maximum
occurrence within that distribution". The mean must be
determined "in order to be statistically correct".
10:33:36 AM
In response to a question from Senator Elton, Mr. Swenson
provided further information about the probability ranges. The
"0.0%" lower range assigned to many locations in Western Alaska
does not mean there are zero reserves there. It is instead
indicative of the fact "there is so little data available to do
the analysis" in those areas. A "0.0% range would indicate that,
at that particular level of exploration, there is a 95 percent
chance "that you will have found at least zero".
Mr. Swenson noted that the distribution range in areas where
there is "a significant amount of data" would be "much much
narrower". He compared ranges in highly explored areas of NPR-A
to the ranges in western Alaska. "A broad distribution with a
very very low end number on the 95 percent case, and a much
higher end on the higher case" typically indicates there is very
little data available.
10:35:56 AM
Page 11
Technically Recoverable ANS Reserve Estimates
Does not include economic thresholds
North Alaska Assessments of Undiscovered, Technically
Recoverable Gas
USGS Assessment Segment Year F95 Mean F05
State Lands oil-
associated gas, BCF 2005 2,681 4,198 6,092
State Lands non-
associated gas, BCF 2005 23,939 33,318 44,873
NPRA non-
associated gas, BCF 2002 40,372 61,351 85,317
ANWR non-
associated gas, BCF 1999 0 949 3,660
MMS Assessment Segment
Chukchi Shelf gas, BCF 2006 10,320 76,770 209,530
Beaufort Shelf gas, BCF 2006 650 27,650 72,180
Hope Basin, gas, BCF 2006 0 3,770 14,980
Total Arctic OCS 2006 16,410 108,190 183,530
Total Onshore & OCS 2006 208,006
Mr. Swenson communicated that as more seismic and geological
data becomes available, it is periodically incorporated into the
USGS and MMS analyses, as portrayed on page 11. Rather than
dramatically changing numbers, it simply "fine tunes" some of
the potential resources in the basins.
10:36:39 AM
Page 12
Arctic Alaska Province Resource Estimates Summary
[Map depicting undiscovered oil and gas assessments for the
Chukchi Shelf, Beaufort Shelf, Central North Slope, Hope
Basin, NPRA, and ANWR 1002 Area]
Source: Houseknecht and Bird, 2006, USGS PP 1732-A, fig. 4
Mr. Swenson informed the Committee that this is the most recent
assessment of reserve estimates in the areas depicted, including
federal offshore reserves. This information is depicted in graph
form on page 13.
10:37:45 AM
Co-Chair Stedman asked for further information about the term
"proven reserves".
10:37:55 AM
Mr. Swenson explained that "proven reserves" indicates that
exploration has occurred and a zone of hydrocarbons has been
found. The hydrocarbons in the zone are further tested and
delineated as either "P1" or "P2" proven reserves.
Mr. Swenson noted that another type of reserve is a "Probable"
reserve. This references an area within a unit which "has not
specifically been penetrated but" to which both the seismic data
and the surrounding well data would suggest that reserves are
there.
Mr. Swenson noted that the entirety of information depicted on
pages 12 and 13 are "potential reserves". Geologic information
such as seismic and well data, surface information, and
individual discoveries in an area was applied to similar but
relatively unexplored geological areas within that area to
develop a probalistic analysis of probable field sizes there.
10:41:20 AM
Mr. Swenson explained that "technically recoverable" areas are
those to which there is land access, regardless of the
economics. An economic "filter" would be applied to a field to
determine whether it was an "economically recoverable" field.
Mr. Swenson declared it would be unlikely that a field 300 miles
from the nearest infrastructure with surface access obstacles
would be included in an economic resource analysis unless either
the access issue or the economics significantly changed.
10:41:49 AM
Co-Chair Stedman asked that "bookable reserves" be addressed.
Mr. Swenson deferred to Kevin Banks.
10:42:15 AM
KEVIN BANKS, Acting Director, Division of Oil and Gas,
Department of Natural Resources explained that "bookable
reserves" are those in a field that has both access to market
and favorable economics. The process undertaken by the Division
when conducting reserve estimates for oil fields in Prudhoe Bay,
would consider the current development status of the field
including known and predictable activities that might occur in
the area within the next few years.
10:43:41 AM
Mr. Banks stated that when considering "bookable gas reserves
under AGIA, the Division considers the level of the commitment
made by a producing company and the probability that the
pipeline would be successfully completed. That would assist in
calculating proved gas reserves. Once there is a commitment for
the construction of the gas pipeline, "the owners at Prudhoe Bay
would be able to "book" the gas reserves there.
Mr. Banks noted that the term "other undeveloped" gas reserves
would apply to the Pt. Thomson field. Gas there is not
considered "bookable, proved reserves" even though the field has
been sufficiently delineated, there is "a fairly good notion of
how big the bucket is", and "the likely recovery capability" is
known. The economic challenges to developing Pt. Thomson are a
consideration.
10:46:00 AM
Co-Chair Stedman asked for an estimate of the bookable reserve
numbers for Pt. Thomson and Prudhoe Bay.
Mr. Banks referred the Committee to the reserve information on
page 9 of the Department's presentation. Of the total 35.4 TCF
North Slope proven gas reserves, Prudhoe Bay holds approximately
24.5 TCF. The 8 TCF quantity depicted for "other undeveloped"
reserves on that page primarily refers to the Pt. Thomson field.
10:46:50 AM
Co-Chair Stedman estimated therefore that were the gas pipeline
to advance, the State could expect an immediate production of
approximately 35.4 TCF less the 8 TCF in the Pt. Thomson Field.
The 8 TCF in Pt. Thomson would be available within the next few
years as development progressed.
10:47:04 AM
Mr. Banks affirmed. The timing for the 8 TCF would depend on how
the development plans for Pt. Thomson progressed.
10:47:17 AM
Senator Thomas asked whether a history of the gas reserve
estimates was available as he was curious whether the reserves
increased annually or over time. The current 35.4 TCF North
Slope estimate appears to be a stagnant number.
10:48:01 AM
Mr. Banks, agreeing that "the number has been relatively
static", reminded the Committee that the estimate does consider
the fact that gas is used as fuel in Prudhoe Bay. This has had
the affect of lowering the estimate slightly over time.
10:48:41 AM
Mr. Swenson advised that gas estimates in Prudhoe Bay are based
on oil producers' field data.
10:48:58 AM
Mr. Banks affirmed. Seismic data provided by oil producers and
explorers in Prudhoe Bay and other fields does provide a great
deal of information to the Department.
10:49:38 AM
Senator Huggins asked for examples of the economic return the
State might garner from gas reserves in the Chukchi and Beaufort
Seas.
10:50:06 AM
Mr. Banks advised of being unfamiliar with "the economically
recoverable" reserve potential for either the Chukchi or
Beaufort Sea areas.
Mr. Banks commented, however, on the fact that the State does
receive 27 percent of the royalty the federal government
receives from oil and gas development between three and six
miles off the State's coastline. The State has no taxing
authority outside of the State's three-mile from shore boundary.
10:51:05 AM
Senator Huggins asked for confirmation that the federal Outer
Continental Shelf (OCS) jurisdiction applied to reserves up to
six miles offshore.
10:51:35 AM
Page 13
Table 4. Estimated mean volumes of undiscovered,
technically recoverable petroleum in conventional
accumulations for areas in the Arctic Alaska Petroleum
Province.
[Table depicting oil and natural-gas liquids in billion bbl
and natural gas in trillion cubic feet, in onshore and
State offshore areas; federal offshore areas; and the
Arctic Alaska Petroleum Province onshore and offshore
areas.
Total undiscovered, but technically recoverable liquids
amount to 50.75 billion bbl. Total undiscovered but
technically recoverable gas is 227.34 trillion cubic feet.
There is a total of 35.42 trillion cubic feet of known gas
fields for a total of 262.74 TCF.]
Mr. Swenson stated that this information, which is based on the
2006 assessment, should address Senator Huggins' question. The
State's rights extend to three miles offshore; the federal
jurisdiction is between three and six miles offshore. 32 percent
of the total 227 TCF of undiscovered but technically recoverable
gas reserves in the State is in NPR-A. The Central North Slope
accounts for 16.5 percent, ANWR accounts for four percent, the
Chukchi Shelf accounts for 33.5 percent, the Beaufort Shelf
accounts for 12 percent, and the Hope Basin accounts for
approximately two percent.
Mr. Swenson noted that, when known gas reserves are added in,
there is a total of 262 TCF of available gas.
10:52:39 AM
Page 14
Undiscovered Mean Field Size Distributions - USGS
[Diagram depicting undiscovered oil and gas accumulations
and an assessment of recoverable quantities on State Lands;
in NPRA, and in ANWR 1002.]
Mr. Swenson informed the Committee that one of the activities
conducted in the gas analyses is the development of a
distribution of field sizes. "Any geologic basin when it's fully
explored will have a distribution of field sizes." As depicted
on this graph, there would typically be many small fields and
only a few, if any, large fields. Charting field sizes helps to
ensure there being a "realistic analysis". An analysis would be
suspect if, for example, the majority of field sizes were large.
Mr. Swenson noted that while 35 percent of the State's resource
potential might be located in offshore areas, those reserves are
technically recoverable not economically recoverable numbers.
They do not reflect the field's accessibility or economics.
Mr. Swenson specified that the first area of any field being
explored and developed would be that with the highest economic
viability. They would be close to infrastructure and have easy
access and permitting issues.
Mr. Swenson also noted that the size of a field would also be a
consideration in the economic viability analysis. A large field
would drive exploration.
10:55:27 AM
Mr. Swenson exampled a large oil basin off the coast of
Greenland. While it has been viewed as "very very attractive",
ice and other environmental issues would likely delay the
recovery of that oil for many years.
10:55:58 AM
Page 15
Arctic Alaska Province Leased Acreage
[Map depicting existing leases and high bid tracts from
April 18, 2007 Beaufort Sea OCS in NPRA, ANWR 1002 area,
and the Beaufort and Chukchi Seas.]
Mr. Swenson reiterated that even though an amazing amount of
data is utilized in the resource assessment effort, some people
still might not consider the outcome of the "rigorous
mathematical analysis" believable. Thus, he avowed that one of
"the best indicators" of an area's resource potential is to
study "what type of lease activity there has been" there. The
level of activity in areas depicted on this map would indicate
strong resource potential. The companies who lease tracts "are
very very good at what they do and they have to spend a lot of
money well out in front of any possible viable market".
10:57:25 AM
Page 16
Unconventional Gas Potential
Page 17
Known Gas Hydrate Accumulations
[Modeling of known gas hydrate accumulations and hydrate-
associated free gas accumulations in the "Tarn trend" and
"Eileen trend" regions in the vicinity of the major North
Slope oil fields.]
Mr. Swenson stated that while the primary focus on the North
Slope to date has been to conventional gas reserves, this
information focuses on the potential of gas hydrates, which are
considered "unconventional gas" reserves. While research is
being conducted on hydrates, it has not been "proven that we can
produce hydrates economically into a well bore yet".
Mr. Swenson informed the Committee that he had recently attended
an international conference on gas hydrate reserves. The
economics of this resource is a "huge issue" and efforts to
identify the location and type of hydrates are being conducted.
However, these reserves are not considered technically
recoverable as the technology needed to bring them to the well
bore has not yet been developed.
Mr. Swenson noted that the "Tarn trend" has 60 TCF of gas
hydrates and the "Eileen trend" has 44 TCF of gas hydrates.
10:59:01 AM
Page 18
Eileen and Tarn Trend Gas Hydrate Accumulations
[A cross-section of the gas hydrate accumulations in these
trends]
Mr. Swenson reviewed the location of the gas hydrate
accumulations in relationship to such things as the permafrost
level. Hydrates are essentially a "methane molecule that is
encased in a ice cage". Further research must be conducted to
determine "how to disassociate that methane from that ice cage".
10:59:58 AM
Page 19
ANS Potential Hydrates Resource
All Values Trillions of Cubic Feet (TCF)
· 32,965 Tcf - Gas Hydrates in Place Resource
· 104 Tcf - Gas Hydrates in Place Prudhoe - Tarn area
· Technically Recoverable Numbers cannot be determined at
this time
Mr. Swenson deemed the potential of gas hydrates to be
significant. For instance, there is approximately 104 TCF of
natural gas hydrates in Prudhoe Bay and Tarn trend area. He
reviewed some of the technological theories being considered to
extract this resource.
11:01:05 AM
Page 20
Energy Sources in Remote Alaska
[Map depicting the location of villages and population
centers and the locations of coal basins and coal units in
the State.]
Page 21
[Map of State depicting the locations of 1)
Exploration/Prospective Phase resource basins; 2) Pre-
Development Phase resource basins; 3) Producing Mine; 4)
Major port; 5) Alaska Railroad; 6) Highways; and 7) Coal
fired power plants and coal technology projects.
Mr. Swenson stated that little discussion has focused on the
"tremendous amount" of coal reserves on the North Slope, even
though it has not been analyzed well. There are multiple demands
for this resource in the United States and internationally.
Mr. Swenson concluded his presentation.
11:02:21 AM
Senator Olson asked how much of the proven gas reserves depicted
on page 9 were beyond the six mile offshore limit and therefore
exempt from paying royalty to the State.
Mr. Banks responded that all of the undeveloped gas reserves
depicted on page 9 are located on State land or within the
State's three mile offshore area.
11:03:48 AM
Senator Thomas asked that the royalty revenues to the State at
the various offshore distances be revisited.
11:03:59 AM
Mr. Banks explained that zero to three miles of offshore
reserves fall under State jurisdiction and would therefore be
subject to the Petroleum Profits Tax (PPT) and State royalties.
While resources in the three to six mile offshore area are under
federal jurisdiction, the federal government would share 27
percent of its royalty revenue with the State. The State would
receive nothing from development occurring beyond six miles
offshore. 100 percent of those royalties would go to the federal
government.
11:04:37 AM
Senator Elton understood that the federal government could
negotiate their royalty share with the leaseholder.
Mr. Banks acknowledged that in recent sales, the federal
government has offered leases within their jurisdiction with
"royalty suspension volumes" in that, depending on the size and
location of the lease, up to 45 million barrels of oil would be
exempted from the federal royalty tax. This federal incentive
effectively precludes the State from potential royalties.
Mr. Banks noted however, that bidders on royalty suspension
leases do take the suspension into account in the bid. The State
might benefit from "the bonus" generated from that situation.
11:06:00 AM
Mr. Swenson stated that in the Gulf of Mexico and other areas of
the country where there is offshore production, "royalty sharing
agreements have been developed with the federal government" in
consideration of the offshore developments impact on on-shore
areas.
11:06:24 AM
Senator Huggins suggested there would be "merit" to the State
conducting an analysis of when and how much of the gas in
federal areas might come on line, and how that might affect the
State.
Co-Chair Stedman agreed that such analysis had merit. Measures
should be taken to ensure that the States does not "build a gas
line for the federal government".
11:07:20 AM
Co-Chair Stedman asked the Department to alert the Committee to
any area of concern pertaining to any federal offshore
activity's impact on the State.
11:07:38 AM
Mr. Banks pointed out that there was a significant amount of gas
between Deadhorse and the Chukchi Sea. The likelihood of
developing gas in the mid-area of this region was higher than
that of the Chukchi Sea area due to immense costs associated
with developing offshore areas.
Mr. Banks also noted that, as depicted in the presentation, most
current leases were on-shore.
11:08:16 AM
Co-Chair Stedman acknowledged that development of offshore areas
in places like the Chukchi Sea were years into the future.
Nonetheless, there were federal leases off the coast of Prudhoe
Bay, and those leases would have "fairly easy access into the"
online distribution system.
Mr. Banks affirmed.
Co-Chair Stedman identified this as an area of concern.
11:08:41 AM
Co-Chair Stedman reviewed the schedule for the afternoon hearing
on AGIA.
The bill was HELD in Committee.
ADJOURNMENT
Co-Chair Bert Stedman adjourned the meeting at 11:09:05 AM.
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