02/27/2003 03:21 PM House O&G
| Audio | Topic |
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+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
February 27, 2003
3:21 p.m.
MEMBERS PRESENT
Representative Vic Kohring, Chair
Representative Hugh Fate
Representative Lesil McGuire
Representative Norman Rokeberg
Representative Harry Crawford
MEMBERS ABSENT
Representative Mike Chenault, Vice Chair
Representative Beth Kerttula
COMMITTEE CALENDAR
HOUSE BILL NO. 113
"An Act extending the renewal period for oil discharge
prevention and contingency plans; and providing for an effective
date."
- MOVED CSHB 113(O&G) OUT OF COMMITTEE
HOUSE BILL NO. 61
"An Act establishing an exploration and development incentive
tax credit for persons engaged in the exploration for and
development of less than 150 barrels of oil or of gas for sale
and delivery without reference to volume from a lease or
property in the state; and providing for an effective date."
- HEARD AND HELD
PREVIOUS ACTION
BILL: HB 113
SHORT TITLE:DISCHARGE PREVENTION & CONTINGENCY PLANS
SPONSOR(S): RLS BY REQUEST OF THE GOVERNOR
Jrn-Date Jrn-Page Action
02/19/03 0252 (H) READ THE FIRST TIME -
REFERRALS
02/19/03 0252 (H) O&G, RES, FIN
02/19/03 0252 (H) FN1: ZERO(DEC)
02/19/03 0252 (H) GOVERNOR'S TRANSMITTAL LETTER
02/27/03 (H) O&G AT 3:15 PM CAPITOL 124
BILL: HB 61
SHORT TITLE:OIL & GAS TAX CREDIT FOR EXPLORATION/DEV
SPONSOR(S): REPRESENTATIVE(S)CHENAULT
Jrn-Date Jrn-Page Action
01/24/03 0060 (H) READ THE FIRST TIME -
REFERRALS
01/24/03 0060 (H) O&G, RES, FIN
02/04/03 (H) O&G AT 3:15 PM CAPITOL 124
02/04/03 (H) <Bill Hearing Canceled>
02/27/03 (H) O&G AT 3:15 PM CAPITOL 124
WITNESS REGISTER
MARY SIROKY, Legislative Liaison
Department of Environmental Conservation
Juneau, Alaska
POSITION STATEMENT: Briefly spoke about the intention behind
HB 113.
LARRY DIETRICK, Director
Division of Spill Prevention & Response
Department of Environmental Conservation
Juneau, Alaska
POSITION STATEMENT: Provided written testimony to explain
HB 113; offered a brief synopsis and answered questions.
DANA L. OLSON
Wasilla, Alaska
POSITION STATEMENT: Testified on HB 113, expressing concern
about the public process and that there is no rational basis for
the extension to five years.
TADD OWENS, Executive Director
Resource Development Council (RDC)
Anchorage, Alaska
POSITION STATEMENT: Testified in support of HB 113 and HB 61.
MARILYN CROCKETT, Deputy Director
Alaska Oil and Gas Association (AOGA)
Anchorage, Alaska
POSITION STATEMENT: Encouraged passage of HB 113 and expressed
support for Amendment 1.
DOUGLAS MERTZ
Prince William Sound Regional Citizens' Advisory Council
Anchorage/Valdez, Alaska
POSITION STATEMENT: Testified in opposition to HB 113 as
drafted.
BRECK TOSTEVIN, Assistant Attorney General
Environmental Section
Civil Division (Anchorage)
Department of Law
Anchorage, Alaska
POSITION STATEMENT: During hearing on HB 113, explained
Amendment 1.
LEONA OBERTS, Staff
to Representative Mike Chenault
Alaska State Legislature
Juneau, Alaska
POSITION STATEMENT: Presented HB 61 on behalf of Representative
Chenault, sponsor.
JOHN A. BARNES, P.E., Alaska Business Unit Manager
Marathon Oil Company
Anchorage, Alaska
POSITION STATEMENT: Offered presentation on the reasons HB 61
is needed; answered questions.
PAUL RICHARDS, Lobbyist
for VECO Corporation
Juneau, Alaska
POSITION STATEMENT: Testified in support of HB 61.
LARRY HOULE, General Manager
Alaska Support Industry Alliance
Anchorage, Alaska
POSITION STATEMENT: Testified in support of HB 61.
KEVIN TABLER, Manager of Land and Government Affairs
Union Oil Company of California (Unocal)
Anchorage, Alaska
POSITION STATEMENT: Encouraged passage of HB 61.
ACTION NARRATIVE
TAPE 03-11, SIDE A
Number 0001
CHAIR VIC KOHRING called the House Special Committee on Oil and
Gas meeting to order at 3:21 p.m. Representatives Kohring,
Rokeberg, Fate, and Crawford were present at the call to order.
Representative McGuire arrived as the meeting was in progress.
HB 113-DISCHARGE PREVENTION & CONTINGENCY PLANS
Number 0093
CHAIR KOHRING announced that the first order of business would
be HOUSE BILL NO. 113, "An Act extending the renewal period for
oil discharge prevention and contingency plans; and providing
for an effective date." [The bill was sponsored by the House
Rules Committee by request of the governor.]
CHAIR KOHRING, noting that [Larry Dietrick] hadn't yet arrived
to present the legislation on behalf of the administration,
offered a synopsis based on Mr. Dietrick's written testimony in
committee packets. Chair Kohring explained that HB 113 has the
goal of improving regulatory efficiency and reducing the
administrative burden [on industry] while improving spill
prevention, preparedness, and protection of the environment. It
lengthens to five years [the time for renewal of oil discharge
prevention and contingency plans], from the current three years.
He offered his understanding that the administration believes
this will create more flexibility in the system; will give
industry more time to put plans together; and will help industry
to spend more time on oil discharge prevention, and on
implementing plans already in place, before having to refile
their plans. Thus a five-year renewal period will streamline
the review process for the industry while maintaining Alaska's
strong spill prevention and response standards.
CHAIR KOHRING continued, noting that oil discharge [prevention
and] contingency plans are required of all operators of oil
terminals, refineries, crude oil transmission pipelines, oil
exploration and production facilities, oil tank vessels, [oil]
barges, nontank vessels [over 400 gross tons, and railroad tank
cars]. He said there is concern that this might compromise
environmental protection, but the administration's position is
that that won't happen and, if anything, this will complement
the current process and provide those who must submit
contingency plans more time to adhere to the regulatory
requirements and put the plans into place. He added the belief
that this extension to five years enables the emphasis to shift
from paperwork to performance.
Number 0389
MARY SIROKY, Legislative Liaison, Department of Environmental
Conservation (DEC), emphasized that this legislation is to allow
[DEC] to ensure that oil spill protection is even better than
today. Through actual drills and putting plans into place, she
said, [DEC] intends to ensure that people can put their plans
into place when a spill happens. She noted that Breck Tostevin
from the Department of Law should be on teleconference to speak
to a proposed amendment.
CHAIR KOHRING indicated amendments would be addressed after
testimony was taken. He informed Mr. Dietrick, who'd just
arrived, that he'd explained the legislation, but requested a
synopsis.
Number 0530
LARRY DIETRICK, Director, Division of Spill Prevention &
Response, Department of Environmental Conservation, read the
first sentence of his written testimony that had been summarized
by Chair Kohring, which stated, "This bill supports the
Governor's goal of improving regulatory efficiency by reducing
the administrative burden while improving spill prevention,
preparedness and protection of the environment." He offered to
answer questions.
Number 0607
REPRESENTATIVE CRAWFORD noted that he'd had a discussion with
Ms. Siroky indicating this would allow more drills and testing
of the actual spill response. He said he didn't see that
direction in the bill, however. He asked whether [DEC] would be
averse to some intent language that says the savings from this
"break" would be used towards more drills and actual [hands-on
training]. Recalling his time in Valdez from 1974-1977, he said
a tugboat was supposed to escort all oil tankers out past Bligh
Reef, an oil response crew was supposed to be on call 24 hours a
day, and there was supposed to be sufficient boom [for an
emergency]. All those went by the wayside, however, and there
was no preparedness for the oil spill in 1989. He said he
didn't want that ever to happen again, and didn't see how
extending this to five years would [prevent it]. He emphasized
his desire to see more testing, drills, and hands-on practice
for an oil spill response. He again asked whether [DEC] would
be averse to such intent language.
Number 0770
MR. DIETRICK replied:
I believe we'd be more than willing to review it. ...
That is the concept, and that is what we're trying to
do, is cut down on the bureaucratic and the
administrative burden of the plan reviews, and that is
a substantial burden. And by doing that, we're trying
to be smarter and more efficient, to achieve the
governor's goals. And I think this is a smart piece
of legislation in that regard, and it frees up the
operators to focus also on spill prevention and the
operation of their plants, which is where spill
prevention happens. And so that's very good. And
then the shift to verification exercises and training,
yeah, we think we can get a ... better "bang for the
[buck]" - better operation of the facilities.
Number 0833
REPRESENTATIVE ROKEBERG asked how long it takes once a plan is
drafted and submitted for review.
MR. DIETRICK answered that the timeframe depends on the
complexity of the facility. Prince William Sound crude-oil
tanker plans - which involve multiple owners of tankers, the
Trans-Alaska Pipeline System (TAPS), and the Valdez Marine
Terminal - are bigger and much more complex plans, and take
longer than smaller plans for smaller oil terminal facilities
around the state. There is a lot of upfront negotiation
beforehand, he indicated, but once a completed application is
received, there is roughly a 65-day period for public notice and
review.
REPRESENTATIVE ROKEBERG asked, because of the planning and
review time, whether a plan now is only good for two years and
some months, or whether the three years dates from [the time of]
approval.
MR. DIETRICK answered that depending on the complexity and which
facility the plans apply to, the process may begin up to six
months prior to the expiration date of a plan that is to be
renewed.
REPRESENTATIVE ROKEBERG said he understood DEC's testimony to be
that the preference is to have everyone perfecting the ability
to respond, rather than "sitting around writing plans."
MR. DIETRICK concurred, suggesting that setting it back to five
years would result in a significant gain [in time] and a
reduction in the paperwork burden.
Number 1051
MR. DIETRICK, in response to questions from Representative
Rokeberg, explained that the extent of changes [to the plan] at
the time of renewal really depends on the facility, the extent
to which the nature of the operation has changed, and any
corresponding change in response capability. If the situation
is status quo, then the changes are relatively minor compared
with those when somebody has added storage tanks or similar
modifications. There is a requirement to update, however, which
applies to new technology as well as "typical things" done at
renewal time. Therefore, the update to evaluate new
technologies would be an item that all operators would perform.
Number 1191
REPRESENTATIVE ROKEBERG posed a hypothetical example of a port
facility that has expanded its capacity, and asked whether it is
required under the current plans that there be modifications for
that during the course of an approved plan.
MR. DIETRICK answered that there is another provision in the
requirements for an amendment of a plan. If a change or
modification to a plan is significant and may affect the
response capability during the time when the plan is in effect,
then that would be triggered and the operator would request to
amend the plan within the three-year cycle.
REPRESENTATIVE ROKEBERG asked whether provisions in the current
process for plans approved by DEC already have flexibility to
account for a substantial change in the capacity or other
circumstances of a facility, or for new technological advances.
MR. DIETRICK said that is correct. In response to a further
question, he said one benefit of extending the renewal is that
the amendment requirement now in place requires continuous
changes to that plan for anything that happens which may be
significant during that plan cycle.
Number 1317
REPRESENTATIVE ROKEBERG asked whether it is correct, then, that
if DEC is doing its job and the amendment process works
properly, there should be no additional risk whatsoever "to
what's contemplated under a contingency plan."
MR. DIETRICK answered in the affirmative, noting that there also
is a mechanism whereby the operator is required to immediately
notify [DEC] of nonreadiness if, for any reason, that operator's
equipment or response capability isn't up to par and in a state
of readiness. He indicated the department would immediately
pursue corrective action after being notified by such an
operator.
REPRESENTATIVE ROKEBERG asked whether DEC audits these
capabilities or somehow checks on these plans periodically.
MR. DIETRICK replied:
Yes, but ... we think there's a better "bang for the
buck" if we can increase working directly with the
operators to actually verify - through exercises,
training, equipment audits, and [so forth] - their
capability. ... It's just a much easier communication.
You can work more hands-on with the operators. You
can find out where problems are that you can't through
the theoretical plan-review exercise. So, yes, we
would increase -- that is the intent. And, actually,
I believe our goal would be to get improved
performance and response capability as a result of
doing [this].
Number 1429
MR. DIETRICK, in response to further questions from
Representative Rokeberg, explained that for noncrude or refined
products, storage in excess of 10,000 barrels is the threshold
for requiring a contingency plan; for crude oil, the storage
threshold is 5,000 barrels. A plan is required for an oil well
as long as it involves liquid hydrocarbons, regardless of
whether it is an exploratory well or a production well.
REPRESENTATIVE ROKEBERG suggested a fuel oil company with more
than 10,000 barrels would have to have a plan.
MR. DIETRICK affirmed that.
CHAIR KOHRING thanked Mr. Dietrick and opened the public
testimony.
Number 1521
DANA L. OLSON referred to written testimony she'd sent the
committee and told members that contingency plans address the
permittee, not the public. Noting that AS 46.03.040 is a
requirement by the legislature for an environmental plan, she
explained:
It's not been done, and that's the public process.
So, in other words, you are assuming that the criteria
has been set for these [contingency] plans, and I
really am just going to have to raise an objection.
... You have to have a factual basis first, to ...
base a contingency plan on, and that's not been done.
Where the technological data is not provided to the
public at the lease sale ... stage or the coastal
consistency, at some point it triggers a need for the
public to know what the secondary effects are from
this ... permitted activity.
The community right-to-know laws are meaningless if
you go in and you write a contingency plan and you
make ... presumptions without any public process. I
would have to raise an objection. I feel that there
isn't an adequate public process because you're not
addressing the public; you're addressing what the
agency will do and what the permittee or the activity
will do, and ... not what the effect on the public is.
I wanted to say that the state's disaster plan is
supposed to be a community-based effort, and not an
agency-directed or an legislative-enacted activity.
And certainly contingency plans are basically a mini-
disaster plan.
And I'm really going to have to object to this five
years. It has no rational basis. If there is a need
because there is a hazard or the public welfare is in
need, it's an arbitrary decision-making thing.
Disaster is public welfare, and economics don't ...
fathom under national security either. So I don't
know how you're going to address ... a state disaster
plan when you are not addressing the public.
Number 1701
TADD OWENS, Executive Director, Resource Development Council
(RDC), testified that RDC is a private, nonprofit business
association representing individuals and companies from Alaska's
oil and gas, mining, timber, tourism, and fisheries industries;
it mission is to help grow Alaska's economy through the
responsible development of natural resources. Mr. Owens
specified that RDC supports HB 113, which changes the renewal
period for DEC-required discharge and contingency plans ("C-
plans") from three to five years. Although C-plans are
essential to spill response preparedness, he said the effort
associated with the plan renewals is significant for both
industry and the state. He told the committee:
Based on our members' experiences, a three-year
renewal cycle often does not result in meaningful
improvements in environmental protection or regulatory
compliance. Increasing the time between renewals from
three to five years will bring the program's benefits
in line with its costs.
A five-year renewal cycle will allow the state to
focus its resources on site inspections, rather than
the office work associated with plan reviews.
Currently, [DEC] is responsible for more than 125 C-
Plans in Alaska. And we believe that allowing agency
staff additional time in the field will provide them
with a more thorough understanding of industry
operations. A five-year renewal period will give
agency staff a better opportunity to determine the
effectiveness of existing plans and to observe plan
implementation prior to any incident. By utilizing
this information and experience, subsequent plan
renewals will have better oversight, incorporate more
high-value improvements, and be less vulnerable to
legal challenges.
Meanwhile, industry will be able to shift its
resources away from the largely administrative
exercise of three-year renewals to additional
prevention-specific activities. Improved networking
and communication between industry and [DEC] will
further emphasize and enhance the quality of plan
renewals. Also, a five-year renewal cycle would
mirror the federal requirement, allowing industry to
consolidate its review process.
RDC's members believe that increasing the C-Plan
renewal cycle from three to five years will result in
a more thorough public process, the creation of more
realistic and sophisticated plans, and establish a
more efficient and predictable regulatory regime.
HB 113 deserves the committee's support.
Number 1886
MARILYN CROCKETT, Deputy Director, Alaska Oil and Gas
Association (AOGA), testified that AOGA is a trade association
whose 17 member companies account for the majority of the oil
and gas activity in the state. All of AOGA's members that have
activity in the state are required to have a C-Plan approved and
in place. She told the committee, "Clearly, we have a
significant interest in this legislation, and we encourage the
committee to pass it."
MS. CROCKETT reported that AOGA spent considerable time over the
past 12 months looking at permitting programs and identifying
those in need of updating and streamlining, and early on had
adopted a guiding principle: "accomplish updates and
streamlining without compromising environmental protection of
safety standards." She said HB 113 fits perfectly within this
principle.
MS. CROCKETT indicated the five-year cycle proposed in the bill
is the cycle used by the federal government, the West Coast
states, and "other oil-producing states that we've studied."
She reported that the cost of renewal alone can average $60,000
to $100,000, depending on the type of facility; that doesn't
include legal challenges, which can increase figures up to half
a million dollars. In addition, the renewal process is time-
intensive. She reported that experience has shown that for some
plans, even with submittals 180 days in advance of the
expiration date, approvals can still average 360 days,
"essentially meaning that once a renewal is complete, work must
begin on the next renewal."
Number 1982
MS. CROCKETT emphasized what purpose a C-Plan serves: it is a
blueprint describing how an operator will respond to an event.
The proof of its effectiveness isn't how often it is renewed,
but whether the response identified in the plan can be delivered
as promised. Demonstration of this effectiveness is
accomplished through drills, she said, suggesting this area is
where the biggest benefit of extending the renewal cycle will be
seen, by shifting the focus from administrative processing to
field performance. The extension also will provide additional
time for agency staff to increase their familiarity and
understanding of a particular operation for which they are
responsible.
MS. CROCKETT, calling these C-Plans "evergreen" documents, said
they are continually reviewed by the operators to ensure that
the information is kept up to date, and that the plan continues
to reflect the current operation and state of readiness. She
noted that DEC regulations require that updates and amendments
be submitted to the department.
Number 2033
MS. CROCKETT referred to the amendment mentioned by Ms. Siroky
[to be discussed by Breck Tostevin of the Department of Law].
That amendment [later adopted as Amendment 1], read as follows
[original punctuation provided]:
Page 1, following line 10:
Insert a new bill section to read:
**Sec. 2 The uncodified law of the State of
Alaska is amended by adding a new section to read:
TRANSITION. Notwithstanding any contrary
provision of AS 46.04, including the review procedures
in AS 46.04.030, and the regulations adopted under AS
46.04, the expiration date of an oil discharge
prevention and contingency plan approved by the
Department of Environmental Conservation before the
effective date of this Act shall be extended for two
years, or for a shorter period if a shorter period is
requested by the holder of the approved plan, if
(1) the plan is still in effect on the day
before the effective date of this Act; and
(2) the Department of Environmental
Conservation has not given a notice of violation of AS
46.04.030 to the holder of the plan that has not been
corrected to the satisfaction of the Department of
Environmental Conservation.
Renumber remaining sections accordingly.
MS. CROCKETT specified that AOGA supports the amendment. She
noted that with her were people she considered experts in this
field who could answer technical questions.
Number 2129
DOUGLAS MERTZ, Prince William Sound Regional Citizens' Advisory
Council (RCAC), testified in opposition to HB 113 as drafted.
Noting that his organization is a coalition of mostly municipal
and borough governments and other entities formed after the
Exxon Valdez [oil spill], he said it is actively involved in
tracking the entire process of oil transportation from Valdez,
through Prince William Sound and throughout that area.
Intimately involved in the C-Plan creation and approval process
on an ongoing basis, the RCAC has concluded that it must oppose
this bill as currently drafted because it will, in fact, weaken
Alaska's oil spill prevention and response capabilities,
Mr. Mertz reported.
MR. MERTZ discussed the three ways his organization believes
this will happen. First, extending the timeframe inhibits the
timeliness of the agency's ability to incorporate into C-Plans
those lessons learned from on-the-ground, in-the-field drills
and other exercises, which are an incredibly important part of
learning and preparation for oil spills. Second, it reduces the
frequency of updating the "best available technology" (BAT)
analyses, a highly important part of the entire oil spill
process. Under the C-Plan requirements, plan holders are
required to employ BAT in their oil spill preparedness,
prevention, and response capacities. Extending the time period
for these renewals will basically defer - and almost double -
the time period during which the BAT analyses must be undertaken
and implemented. And third, it reduces the agency's and plan
holder's familiarization with the plan, which could result in
complacency. From the Exxon Valdez and other major spills, he
cautioned, [it has been learned that] what very often precedes
such a spill is a period of complacency.
Number 2270
MR. MERTZ countered testimony that an extension to five years
would align Alaska's requirements with federal requirements. He
pointed out that because Alaska's requirements now are stricter
than the federal ones, the federal requirements "tend to be a
much less extensive plan update to the Alaska requirements."
Furthermore, the federal regulations have an additional
requirement for an annual review and update. There is no such
requirement in Alaskan law, and this bill wouldn't add one. He
suggested:
If you really want to align what happens on the state
level with what happens on the federal level, then
that same annual review and update should be
incorporated; in fact, you could lift the language
from the federal regulations and incorporate them into
state law directly, to truly make it in alignment.
MR. MERTZ noted that the RCAC's testimony was provided by fax to
each member the previously day, and said he wouldn't read it
this day. He again pointed out that his organization, which
follows these issues carefully, is increasingly uncomfortable
with the idea of extending this plan without this kind of
additional safeguard and additional requirements that ensure an
ongoing, mandatory duty to update plans annually or on some more
frequent basis than five years.
Number 2359
REPRESENTATIVE ROKEBERG offered his understanding from
Mr. Dietrick's testimony that already in existence are the
amendment process and provisions for notification of
nonreadiness with regard to C-Plans in Alaska. He asked whether
those processes aren't working correctly, and whether they
aren't equivalent to annual review.
MR. MERTZ responded:
They're not the equivalent. Those are ... tools which
can be used in the extraordinary circumstances of true
inability to respond to fulfill the plan, or some
extraordinary event [that] makes actuality diverge
from what's in the plan. But that's different from
what the federal regulations require, ... an actual,
ongoing update incorporating best available technology
... as a regular matter - in other words, ... a
constantly evolving process that ... continually
causes ... an improvement in the ability of the plan
holder to perform.
What [Mr. Dietrick] ... was talking about really can
be invoked only in extraordinary circumstances. And
right now the agency doesn't have the ability to say
to a plan holder that "you must do these incremental,
almost continuous improvements in your ability to
perform."
Number 2434
CHAIR KOHRING asked whether anyone else wished to testify. He
then closed public testimony.
Number 2453
REPRESENTATIVE ROKEBERG asked Mr. Dietrick to respond to the
testimony of Ms. Olson about the public process and the idea
that C-Plans are supposed to be a community-based effort.
MR. DIETRICK answered:
The public review process is provided for, for
contingency plans. It's a 30-day public review
process with a request for additional information.
And we ... do those. So ... that's a fairly standard
public notice review period that the department uses
for most of its major permits and authorizations. So
that's the one that's in place for contingency plans,
and that's what we use to provide for the public
notice.
Number 2504
REPRESENTATIVE ROKEBERG asked Mr. Dietrick to respond to
Mr. Mertz's three main points [also set out in the RCAC's letter
dated February 26]. He offered his own assessment that having a
plan longer leads to more familiarity, rather than complacency.
MR. DIETRICK replied:
First of all, ... I think the good news about the bill
is, I think everybody has the same goal. The Prince
William Sound Regional Citizens' Advisory Council has
been given an oversight role under the Oil Pollution
Act of 1990 to make sure we all do a good job. And we
work with them all the time. They've got good
expertise and experience, and we ... seriously
consider their input on all oil spill prevention and
response matters, ... as we do their comments today
... on this bill. So we treat those very seriously,
and ... they are a very key player here in ensuring
the integrity of the system.
We sometimes disagree on the approach and ... how to
get to those goals. ... We believe that actual field
testing is a better way to move forward and test the
capability of these systems than these ... three-year
renewals. And that's why we believe the extension to
five-year [renewals] is a substantial improvement.
With regard to the lessons learned and the delaying
the lessons learned, we do not wait even till three
years now to incorporate lessons learned from drills
into a plan. We do roll those into a plan now, if
they are significant, by amendment. So extending it
to five years is neither here nor there, because if it
is significant, the idea is, we use the amendment
process to include them now.
And for major plans, even in the Prince William Sound
area, we have monthly meetings - they call them the
"response planning group" - to review lessons learned,
sort through them, determine which ones are
significant; they're even tracked in a system called
"Passport" (ph). We ... would like to improve on
that, but ... there very clearly is a mechanism in
place to ... roll those lessons learned in without any
delay.
Number 2659
MR. DIETRICK addressed the RCAC's concern about review of the
best available technology as follows:
With regard ... to the second point in their letter,
the best available technology reviews, those are
performed at the time of renewal, and ... the intent
behind those is to keep these plans current with
changes in technology. Now, the technology-review
cycle for oil spill response equipment is ... long.
... There have not been many breakthroughs. A five-
year cycle for a technology review, I believe, is an
appropriate cycle. As a matter of fact, our
regulations require that we conduct a "best available
technology" conference on a five-year basis right now.
This would simply line that up.
The best available technology analyses that are
performed in these plans [are] a theoretical exercise.
And we believe it's more important - than to review
those - to actually go out and test those premises
more frequently to see if they work, to see if the
technology that was analyzed and arrived at in the
plan is actually the ... best available technology
when you implement it. So increasing our ability to
do that in the field will, I believe, drive faster
advances in technology improvements, because ... we
will have the ability ... to test those, reject the
ones that don't work, and then seek improvements ...
and get better ones ... that will work.
Number 2733
MR. DIETRICK responded to the RCAC's concern about complacency
as follows:
I think the third point, then, was the complacency.
And, indeed, that is a significant phenomenon that we
all need to be aware of. It's the one that, a decade
ago, was pointed to quite frequently. And I think no
one wants to slip back into that mode.
This change, however, again, I think is a smart change
because it gets us away from the theoretical reviews
and gets us [to] the point where we can actually test
the capabilities of the response system and actually,
then, through testing, identify which ones are real
and which ones aren't, and then seek the improvements
that way. So I think it's a much more productive way
of 1) interacting with the companies, 2) finding out
what does work, and 3) that is really, in our opinion,
an increased interaction with the operators, which to
me does just the opposite - it reduces the
complacency.
Number 2835
REPRESENTATIVE ROKEBERG asked whether both the plan applicant
and [DEC] have the ability to move to amend [a plan].
MR. DIETRICK replied that he believes the statutes are quite
strong. He paraphrased from AS 46.04.030, which read in part:
(f) Upon request of a plan holder or on the
department's own initiative, the department, after
notice and opportunity for hearing, may modify its
approval of a contingency plan if the department
determines that a change has occurred in the operation
of a facility or vessel necessitating an amended or
supplemented plan, or the operator's discharge
experience demonstrates a necessity for modification.
The department, after notice and opportunity for
hearing, may revoke its approval of a contingency plan
if the department determines that
(1) approval was obtained by fraud or
misrepresentation;
(2) the operator does not have access to the
quality or quantity of resources identified in the
plan;
(3) a term or condition of approval or
modification has been violated; or
(4) the person is not in compliance with the
contingency plan and the deficiency materially affects
the plan holder's response capability.
REPRESENTATIVE ROKEBERG requested that Mr. Dietrick provide a
copy for the committee's files and for the bill packet [to be
given to the next committee of referral].
MR. DIETRICK said he would gladly provide those parts of the
statute and the nonreadiness [provisions].
Number 2878
CHAIR KOHRING moved to adopt Amendment 1 [text provided
previously].
The committee took an at-ease at 4:07 p.m. and was called back
to order within a minute.
Number 2911
BRECK TOSTEVIN, Assistant Attorney General, Environmental
Section, Civil Division (Anchorage), Department of Law,
explained that Amendment 1 adds a transition provision that
requires DEC to administratively extend the expiration date of
an oil discharge prevention and contingency plan that was
approved before the effective date of this Act. That extension
would be for two years, or for a shorter period if a shorter
period were requested by the holder of an approved plan. He
said a shorter period would be to allow a plan holder to
synchronize with a federal plan review or if a shorter period
were needed for some other reason.
MR. TOSTEVIN said there would be two limitations on the
authority for extending the plan renewal date. First, the plan
would have to be in effect on the day before the effective date
of the Act. And second, if the department had issued a notice
of violation to the C-Plan holder concerning the C-Plan, that
would have to be corrected to the department's satisfaction
before the extension of the plan expiration date.
MR. TOSTEVIN explained that the intent behind the transition
provision is to extend the expiration date of existing plans
without requiring a new administrative review or renewal
procedures, or requiring DEC to adopt unnecessary regulations.
This transition provision would allow immediate benefits to the
industry and the department, he suggested, as discussed earlier
by Mr. Dietrick. He offered to answer any legal questions.
TAPE 03-11, SIDE B
Number 2976
CHAIR KOHRING renewed his motion to adopt Amendment 1. There
being no objection, it was so ordered.
The committee took an at-ease from 4:11 p.m. to 4:13 p.m.
Number 2950
REPRESENTATIVE CRAWFORD moved to adopt [Conceptual] Amendment 2.
CHAIR KOHRING objected for discussion purposes.
REPRESENTATIVE CRAWFORD explained that he wanted to adopt intent
language taken from Mr. Dietrick's written testimony, as
follows:
Streamlining the process would allow the applicant to
focus on the actual testing of oil spill prevention
and response preparedness through [in-the-field]
inspections, drills, and exercises, which is our most
effective means of ensuring spill prevention, response
readiness, and protection of the environment.
Number 2896
REPRESENTATIVE ROKEBERG also objected for discussion purposes,
pointing out the need to have this be a conceptual amendment.
REPRESENTATIVE ROKEBERG withdrew his objection.
CHAIR KOHRING renewed his objection for discussion purposes and
asked Mr. Dietrick to provide his thoughts on the amendment.
Number 2850
MR. DIETRICK offered his belief that DEC would concur with the
language.
CHAIR KOHRING withdrew his objection. He then announced that
Conceptual Amendment 2 was adopted.
Number 2830
REPRESENTATIVE ROKEBERG moved to report HB 113, as amended, out
of committee with individual recommendations and the
accompanying zero fiscal note. There being no objection,
CSHB 113(O&G) was reported from the House Special Committee on
Oil and Gas.
HB 61-OIL & GAS TAX CREDIT FOR EXPLORATION/DEV
Number 2816
CHAIR KOHRING announced that the final order of business would
be HOUSE BILL NO. 61, "An Act establishing an exploration and
development incentive tax credit for persons engaged in the
exploration for and development of less than 150 barrels of oil
or of gas for sale and delivery without reference to volume from
a lease or property in the state; and providing for an effective
date."
Number 2795
LEONA OBERTS, Staff to Representative Mike Chenault, Alaska
State Legislature, presented the sponsor statement for HB 61 on
behalf of Representative Chenault, as follows:
HB 61 creates a new income tax credit to encourage
increased exploration and development of natural ...
gas reserves south of the Brooks Range. While focused
primarily on natural gas reserve development, the bill
also provides an incentive for the development of
marginal oil reserves, should they be discovered. For
the purpose of this bill, marginal oil production is
defined as that which initially produces 150 barrels
of oil per day or less. To qualify for the credit,
operators must successfully drill and develop
hydrocarbon reserves that produce natural gas for sale
and delivery. The credit may offset no more than 50
percent of an operator's annual income tax liability,
and remains in effect for a period of 10 years.
The tax credit would amount to 10 percent of qualified
investments - and 100 percent of services associated
with said investment - for each year. For example, an
operator who spends $20 million in a given year
successfully developing natural gas reserves would
receive an income tax credit of $2 million -
applicable to up to one-half of its income tax
liability for that year. Credits in excess of 50
percent of the operator's income tax liability can be
carried over to future years. This is a "successful
efforts" bill, which means that no credits will be
given for dry holes.
The Cook Inlet continues to have great potential for
additional natural gas development. Other Alaska
basins outside of the North Slope have similar
potential. However, the combination of exploration
risk, high development costs, and historic low natural
gas prices has ... created a disincentive to drill for
new reserves as compared to other areas of the world.
By providing a credit for successful efforts, more
exploration will occur in southern Alaska, leading to
much-needed new natural gas reserves. This will
benefit all residents and businesses, at no direct
cost to the state. In addition to the benefit of
developing new gas reserves, increased Cook Inlet
drilling will also aid the general economic status on
the Kenai Peninsula and in Anchorage, as well as other
areas of Alaska. Moreover, increased tax revenue from
additional hydrocarbon production will more than
offset any fiscal impact from the proposed credit.
MS. OBERTS informed members that there were experts available to
answer questions.
CHAIR KOHRING opened the public hearing.
Number 2626
JOHN A. BARNES, P.E., Alaska Business Unit Manager, Marathon Oil
Company ("Marathon"), came forward to provide a presentation on
why Marathon believes HB is needed [handout in packets].
The committee took an at-ease from 4:20 p.m. to 4:22 p.m. to
address technical difficulties.
[The recording didn't begin immediately; however, the handout
contained all material discussed, with page 1 being a cover
sheet.] Page 2 of the handout read as follows, with some
punctuation and formatting changes, and with abbreviations
spelled out in brackets:
HB 61 - What Does it Do?
Creates income tax credit to encourage exploration and
development of gas reserves south of Brooks Range.
Primary focus in on Cook Inlet, but applies to other
basins.
Primary focus is on natural gas, but applies to
smaller oil as well (less than 150 bopd [barrels of
oil per day]).
Levels the playing field somewhat with other
exploration opportunities around the world.
Draws more E&P [exploration and production] capital to
Cook Inlet.
Page 3 read in part as follows, with some punctuation and
formatting changes:
HB 61 - How Does it Work?
Applies to 10% of Qualified Capital Investment.
Applies to 100% of Qualified Expense.
[Recording began again at this point.]
Number 2580
MR. BARNES, noting that this bill allows an offset of no more
than 50 percent of corporate income tax in any one year,
explained that any amount left over could be carried forward for
up to five additional years. He emphasized that this
[incentive] only applies to successful efforts. Another key
point is that it could be factored into economic analyses as a
company analyzes various opportunities. Currently, he noted,
the State of Alaska has some other incentive programs that are
attractive, but often those only kick in at the discretion of
the commissioner of the Department of Natural Resources (DNR).
Thus there is uncertainty, until after the investment is made,
as to whether those would be applicable in any one case.
MR. BARNES discussed page 4 of the handout, which addressed why
HB 61 is needed. He said this is probably the most salient
point: natural gas reserves have been declining and continue to
do so in Cook Inlet. The current estimate of proven natural gas
reserves is about 2 trillion cubic feet (Tcf) or 2,000 billion
cubic feet (Bcf), based on the most recent DNR report. Despite
recent increases in [exploration] activity there, reserves
aren't being replaced on an annual basis. He explained, "You
will only have a sustainable business if you replace what you
produced in any one year; otherwise, you are in a declining
business."
Number 2486
MR. BARNES referred to page 5, a graph labeled "Cook Inlet
Proven Gas Reserves" that looks at the years 1990-2002 [with DNR
cited as the source]. He pointed out that in 1990 reserves were
in decline and totaled about 3,500 Bcf. From 1995 to 1997,
there was an increase of just over 1 Tcf, a result of
recalculations rather than drilling new wells; he said if that
incremental number were put on the front of the curve, it would
show a decline. He pointed out that [as of 2002] about 2,000
Bcf or 2 Tcf of gas was left in Cook Inlet.
MR. BARNES referred to page 6 of the handout, further addressing
why HB 61 is needed. He said Cook Inlet deliverability - "the
rate at which you could produce natural gas" - has been
declining over the last several years.
MR. BARNES turned to page 7, a graph titled "Cook Inlet Peak
Supply/Demand." He explained that the part labeled "Total
Requirement" would be what is required if "every contract peak
requirement" occurred at the same moment on the same day: if
ENSTAR [Natural Gas Company ("ENSTAR")] needed the maximum gas
for heating homes, if Chugach [Electric Association, Inc.]
needed the maximum for generating electricity, and if "the
industrials" that use gas [needed the maximum as well]. He
pointed out that the amount shown is more than 800 million cubic
feet a day of natural gas. In 1997, he reported, Cook Inlet
could produce about 900 million cubic feet a day; current
estimates are about 667 million cubic feet a day. He emphasized
that there is a shortfall - that Cook Inlet isn't producing what
would be required to fulfill the needs of every consumer.
Number 2383
MR. BARNES addressed page 8 of the handout, noting that "supply
and demand rationalization" will occur because the free market
works. He said the first occurrence is that not enough gas is
produced to "feed the low-price consumer"; he suggested members
had heard testimony previously about that. Another result of
scarcity is that the price of gas rises. He suggested ENSTAR is
probably a good measure of the cost of gas in Cook Inlet because
it is the local heating utility; its weighted average cost of
gas (WACOG), the price it pays to acquire gas from "a family of
contracts," now is about $2.55 per Mcf [thousand cubic feet].
He said the most recent ENSTAR gas contract was signed at a
price that has a floor of $2.75 but can range upward to a
"rolling average of Henry Hub." He pointed out that the recent
Henry Hub price of $15 or more per Mcf is an aberration in the
marketplace; in reality, the Henry Hub price has been averaging
$4 to $5 per Mcf. Mr. Barnes told members that the marketplace
works, that natural gas prices are rising, and that "there's an
impact of higher prices."
Number 2307
MR. BARNES addressed page 9 of the handout, "Cook Inlet Reserves
& Resources." He reiterated that current proven reserves are
estimated at 2,000 Bcf. At an annual consumption rate of 200
Bcf per year, which he said is what is burned in Cook Inlet, the
reserve life there is about 10 years. Beyond reserves - gas
known to be in the ground - he explained that there is a
category called "resources" - gas that technologists,
geophysicists, and geoscientists estimate could be found.
Speaking of unspecified committees, he said:
The most recent that I'm aware of is the estimate by a
potential gas committee of two resources: a probable
reserves, which is about a 50 percent chance that
you'll find it, of about 1,050 Bcf of gas; and
possible reserves, which is less than a 50 percent
probability, of about 2.1 Tcf [or] 2,100 billion cubic
feet.
Number 2245
MR. BARNES addressed page 10 of the handout, impacts to the
State of Alaska from HB 61. He said that first and foremost,
Marathon believes [the bill] would stimulate activity in Cook
Inlet and potentially other basins, and would aid in maintaining
Cook Inlet's current production of 200-plus Bcf a year. He said
200 Bcf a year is a significant number. If converted on an
"energy basis" to equivalent barrels of oil a day, it would be
roughly 33 million barrels, about one month's worth of North
Slope production; he therefore suggested viewing Cook Inlet
[production] as a thirteenth month's worth of North Slope
production for the state. He pointed out that it provides gas
for the Cook Inlet utilities; provides feedstock for
"industrials"; and would result in jobs, royalties, and taxes.
Number 2195
MR. BARNES turned to page 11 of the handout. He reported that
Marathon believes the incentive clearly would be positive for
the State of Alaska. He listed factors when thinking about
impacts: how many developments might be incentivized; how much
gas will be discovered; what the price of the gas will be when
it is sold, which affects royalty and severance tax value; and
how much money will be spent in efforts to explore for and
ultimately develop reserves. He called it "successful efforts-
driven," since no incentives for dry holes are included in
HB 61.
MR. BARNES addressed page 12 of the handout, which includes a
conceptual estimate of fiscal impacts to the State of Alaska
under HB 61. He clarified that the assumptions he'd used
included the following: the field size of the discovery was
varied from 0 Bcf to 500 Bcf; and he'd used a development-cost
estimate of $.50 per Mcf, a royalty of 12.5 percent, severance
tax at 7.5 percent, ad valorem at 2.7 percent, and a gas sales
price of $2.50 per Mcf. He noted that other parties might vary
these assumptions for their own analyses.
Number 2132
MR. BARNES turned attention to page 13, a table labeled "Fiscal
Impact to State of Alaska." Choosing a discovery with a field
size of 50 Bcf as an example, he explained that the development
cost for that field - what the operator would spend to drill
wells and probably put in facilities - would be around $25
million. The tax credit proposed in the bill, at 10 percent of
[the taxpayer's qualified capital investment], would be about
$2.5 million. The gross revenue generated by the field would be
about $125 million. The royalty received [at 12.5 percent]
would be about $15.6 million. The severance tax [at 7.5
percent] would be $9.3 million. And the ad valorem would be
estimated at about $1 million. Therefore, the total tax
generated through this discovery would be about $26 million,
about 10 times the value of the tax credit.
MR. BARNES turned to page 14, a graph illustrating [the
information on page 13]. He pointed out that the tax credit is
rather low on the curve, but that the lines showing the total
development cost and total tax take are about the same. He said
it means, on average, that the money an operator spends finding
and developing a field is [about the same] as what the state
might ultimately receive in royalty and other tax payments.
Number 2025
MR. BARNES discussed conclusions on page 15 of the handout. He
noted that there might be a question of how many of these fields
truly need incentives. Based on this conceptual tax model, he
said, if only one field were incentivized, that tax credit would
generate enough other taxes to pay for the "incentivization"
that the state might lose, so to speak, from ten other fields of
roughly the same size.
MR. BARNES told members Marathon believes the credit is needed
now, and that he believes there isn't enough exploration and
development activity in Cook Inlet now to meet demand.
Providing an example, he reported that recently [Marathon]
advertised to hire four production operators, and received more
than 90 applications from people looking for work in the gas
fields there. He also pointed out that new discoveries take
about three years to bring to "first gas" because of permitting
and other issues. He said Marathon is very appreciative and
supportive of efforts underway to look at the permitting
process; he suggested that would be good for the state as well.
Number 1958
MR. BARNES addressed the final page of the handout, page 16,
suggesting someone would look for the following to determine the
success of this legislation: increased lease activity by those
looking to acquire leases; increased drilling rig activity;
increased construction activity; increased production; increased
deliverability; and that credits are being applied for, which is
"the measure that new gas is being found." He pointed out that
under the economic scenario he'd proposed, approximately $10
would be spent successfully to develop new reserves, and about
$10 would come to the state as new tax revenue.
CHAIR KOHRING commended Mr. Barnes for presenting such a
compelling argument.
Number 1901
REPRESENTATIVE CRAWFORD referred to page 3 of the handout, which
said this would apply to 100 percent of qualified expenses. He
asked, when Mr. Barnes had explained the figures on page 13,
whether those included the qualified expenses.
MR. BARNES answered that it is intended to be included. He
suggested perhaps it is a problem of wording or misunderstanding
between how an oil and gas company might present the economics
and how the state might draft the bill. He said the 100-
percent-of-service charge would be intended to represent "the
intangibles for labor costs that might be associated with
putting the tangible - the iron - in the ground, so to speak, or
to build a facility." He suggested this committee or a
subsequent one might want to discuss a language change in this
regard, but said it is intended that it be represented in that
10 percent of the cost.
Number 1834
REPRESENTATIVE ROKEBERG said he was glad to hear Mr. Barnes talk
about the fact that Cook Inlet [is estimated to have] 10 years
for proven reserves and perhaps 15 for probable reserves. He
expressed concern about ensuring that the resource is available
for economic development and growth there. Referring to
testimony by Mr. Barnes about gas prices, he asked whether
supply and demand wouldn't go a long way towards solving the
problem if, in fact, the reserves were there.
MR. BARNES responded:
My view would be that if you could depend solely on
market conditions, ... probably ... you'd see prices
increase until there was sufficient stimulation for
activity. And then you'd have activity, and then ...
you might find enough gas for supply-demand to drive
it down again. ... That would be ... one model; you're
correct. Alternatively, if sufficient drive was
created soon enough, you might actually see sufficient
activity to find gas that might moderate that supply-
demand marketplace action you were talking about.
Number 1711
REPRESENTATIVE ROKEBERG asked whether it is whatever [Marathon]
expends in exploration and production for new production that
would qualify [under the bill].
MR. BARNES answered:
It's intended to represent -- into the pot of funds
that would qualify would be those funds expended
towards the exploration and development of new - and
that's ... the critical term, "new" - gas reserves or
oil, if you found oil and it was a small enough field.
So it's not your ongoing, day-by-day expenses
associated with your current activities. It's
expenses associated with finding and then bringing to
production ... that new field.
Number 1585
REPRESENTATIVE ROKEBERG surmised that it wouldn't be for an
existing oil well, then. He asked, "Does it occur geologically
in Cook Inlet that you can ... drill a well maybe for gas and
then have some incidental production of oil?"
MR. BARNES replied, "Not very often. But, again, if you did
find a marginal oil well by happenstance, I don't know what the
probability would be, but the intent would be to try to
recognize that those economics are difficult as well."
REPRESENTATIVE ROKEBERG suggested that if a $20-million well
only produced 150 barrels a day, the company would get a tax
credit anyway. He asked whether that was what Mr. Barnes was
saying.
MR. BARNES said a company could produce a 150-barrel-a-day well,
but if it cost $20 million to get there, it would be a very
risky proposition and a company might not choose to operate it.
He indicated that the intent is, should somebody find it, that
[this incentive] would provide an opportunity [for production].
REPRESENTATIVE ROKEBERG asked, if there were an areawide lease
for which the company had a bonus bid, whether that dollar
amount also would be part of the qualified capital investment
because of its being real property.
MR. BARNES replied, "Probably so. I would think so."
Number 1512
REPRESENTATIVE ROKEBERG suggested "everything but the kitchen
sink" is included, and mentioned cost accounting. He expressed
concern about the 150 barrels a day [as a limit] and how that
would work out. Furthermore, he said, the legislature has
passed bills previously under which certain fields have been
designated for special royalty treatment; he also mentioned the
"180(j) sections" for royalty, which have never been used, as
well as a bill he and Chair Kohring are working on as an
incentive for marginal fields. He asked how these different
programs fit together.
MR. BARNES agreed that there is a "family" of royalty-reduction
programs and policies from legislation that has passed. He said
one is specific to certain fields, which to his belief must
begin production by the end of this year. There also is a
royalty reduction available for a marginal field, but that
doesn't stimulate new activity; it only maintains production in
an older field. Furthermore, a "discovery royalty" [incentive]
is at the discretion - ultimately, to his belief - of the
commissioner of DNR; to his understanding, he said, no field has
actually qualified under that. Mr. Barnes offered Marathon's
view that those are more difficult to predict with regard to
economics, whereas this could be "run through your calculator"
and is not discretionary; it is easier to analyze economically
and easier to propose to management. He added, "Discretionary
ones are more difficult, obviously."
Number 1303
REPRESENTATIVE ROKEBERG offered his understanding that the
Division of Oil & Gas has indicated a producer or operator on
the North Slope could "come to the Cook Inlet and buy existing
production or invest in an existing well," which would provide
some offset against North Slope tax obligations to the state.
He asked whether Marathon has looked at that.
MR. BARNES noted that the bill clearly says it is for the
exploration and development of new reserves. He said he didn't
understand how it would apply to buying existing production.
REPRESENTATIVE ROKEBERG again asked whether a tax credit
developed in Cook Inlet could be used to offset [tax obligations
relating to the North Slope].
MR. BARNES indicated that if a company positioned itself to
offset $10 million of North Slope-derived corporate income tax,
the company would have spent $100 million in Cook Inlet
successfully finding and developing natural gas. He said he
would think that was great, because that 10-to-1 multiplier
would indicate that the $100 million spent by the company ought
to generate new taxes. He added, "I would believe that an
offset of tax from another ... basin would not be as important
as the fact that you did find ... new gas reserves."
REPRESENTATIVE ROKEBERG clarified his point: it isn't specific
to a particular project. He suggested the company would have to
prove that expenditures which met the qualification under the
statute occurred only [south of the Brooks Range].
MR. BARNES said it would be "project-derived" and that perhaps
there would be a way to qualify what the 100 percent of expenses
means. He suggested it is meant to represent costs directly
applicable to that activity, rather than overhead for corporate
offices and so forth. That wouldn't be the intent, he said.
Number 1035
CHAIR KOHRING informed members that Mark Myers [director of the
Division of Oil & Gas, DNR] and Chuck Logsdon [of the Department
of Revenue] were available via teleconference to answer
questions or offer technical expertise.
Number 1012
PAUL RICHARDS, Lobbyist for VECO Corporation, testified in
support of HB 61. He said:
VECO believes efforts which incentivize exploration
and development in Alaska are crucial to the long-term
fiscal viability of this great state and the overall
welfare of its citizens. VECO is a multi-national
corporation that provides services - project
management, engineering, procurement, construction,
operations, and maintenance - to the energy, resource,
and process ... industries [and] to the public sector.
VECO's mission is to make our clients successful while
creating stakeholder value and providing [a] safe and
rewarding place to work.
VECO is an Alaskan company founded in 1968 with their
first project in Cook Inlet, and has built on existing
Alaskan expertise to provide added value to its
clients. The results are many long-term working
partnerships, well-trained teams, and a network of
regional offices around the world, which use
integrated, state-of-the-art project management and
communication systems to provide local solutions for
the smallest to the large mega-projects.
Values are important to VECO. They have built the
corporation on several premises, which are the keys to
our continuing success. VECO employees work every day
to ensure that every job reflects those building
stones. VECO strives to ensure that more Alaskans are
given an opportunity for employment in Alaska. And
with your help today in passing HB 61, this can
continue to be a reality.
Number 0880
MR. RICHARDS continued:
This being said, VECO has reviewed the proposed
legislation and [finds] HB 61 creates an incentive for
operating companies to explore for and develop new
sources of natural gas in Alaska, and particularly the
Cook Inlet. What does this mean for VECO? Most
importantly, it means new construction, maintenance,
and operating jobs for our employees. It also means
continued economic stimulus for local communities
where employees live, work, and shop.
As most of you recognize, Alaska's economy has a cycle
of boom and bust. Unfortunately, all too often this
cycle is driven by outside forces. VECO is strongly
supportive of efforts by this legislature and the
administration to create an environment where Alaska
controls its own fate. Encouraging and incentivizing
development through your support of HB 61 accomplishes
this.
It is particularly important to remember, this
incentive applies ... only to successful efforts. For
this incentive to be applicable, an operating company
must have or acquire leases. It must then run seismic
to identify exploration targets. Then it must drill
one or more wells. If a discovery is made, production
facilities must be installed, and potentially
pipelines must be laid. This represents a lot of work
- a lot of jobs for Alaskans. After the field is on
production, it provides more jobs, royalty, and
severance taxes. Finally, the incentive is only
applied to state income tax, meaning the company is
already making money in Alaska and supporting the
state and its economy. This is all good news.
The Cook Inlet natural gas business is an important
part of Alaska's economy. It is important for local
citizens who heat and light their homes through
natural gas. It is important to those industries
which use natural gas. VECO believes HB 61 can be
important as well, and supports it.
Number 0681
CHAIR KOHRING commended VECO Corporation for its Alaskan
investment and optimism about the future. He said he supports
this legislation as well, characterizing it as "win-win"
legislation that will be good for the industry, the state, and
the general public.
The committee took an at-ease from 4:55 p.m. to 4:58 p.m.
CHAIR KOHRING informed listeners that during the at-ease members
had indicated the desire to hear more testimony from Mr. Myers
or Mr. Logsdon, particularly with regard to royalties lost or
gained. He announced that the committee would continue to take
testimony and then hold the bill over.
Number 0514
LARRY HOULE, General Manager, Alaska Support Industry Alliance
("Alliance"), informed members that the Alliance is a nonprofit,
statewide trade association with chapters in Anchorage,
Fairbanks, and Kenai. It comprises more than 420 member
companies that derive their livelihood from Alaska's oil and gas
industry; at any given time, its employment base exceeds 25,000
Alaskans. Specifying that the Alliance membership is fully
supportive of HB 61, he suggested that in this time of fiscal
uncertainty the state needs to promote as much exploration and
development of oil and gas as possible. He said the incentive
proposed in HB 61 seems especially suited for the mature Cook
Inlet basin, which serves important gas market on the Kenai
[Peninsula], in Anchorage, and in the Matanuska-Susitna area.
He also suggested that passing legislation like HB 61 is a
proper role for government.
MR. HOULE offered that one outstanding feature of HB 61 is that
the tax credits apply only to successful efforts. He suggested
the bill will promote the drilling of new wells, and said in the
oil industry it is a simple mathematical equation: "the more
holes we drill, the more gas and oil that will be produced."
Noting that state tax-incentive programs of this nature come in
many shapes and sizes and are common throughout the country, he
acknowledged that they vary in "quantifiable effectiveness." He
said, however, that HB 61 seems to have the right combination to
be workable in a mature basin like Cook Inlet. Referring to
comments by Representative Rokeberg, Mr. House suggested it
might be worthwhile for the legislature to explore incentive
programs that include tax relief for low-volume, economically
marginal wells or idle wells. He reiterated support for HB 61
on behalf of the 25,000 Alaskans represented by the Alliance.
Number 0299
TADD OWENS, Executive Director, Resource Development Council
(RDC), testified in support of HB 61 as follows:
RDC supports House Bill 61, and we ask the House Oil
and Gas Committee to move the legislation forward.
HB 61 provides a tax credit for exploration and
development of natural gas reserves and small oil
deposits south of the Brooks Range. The legislation
will have a major positive impact - specifically, on
natural gas exploration and development in Cook Inlet.
As the committee has already heard, this legislation
is needed to help offset the continuing decline in
Cook Inlet's proven natural gas reserves. At this
time, reserves in Cook Inlet are not being replaced on
an annual basis. In fact, rising natural gas prices
in Cook Inlet threaten to greatly increase both the
cost of living and the cost of doing business in
Southcentral Alaska.
As with all of Alaska's resource industries, Cook
Inlet oil and gas projects compete for capital
investment with other projects around the globe.
HB 61 would stimulate additional exploration and
development activity in Cook Inlet by leveling the
playing field with other worldwide business
opportunities. Attracting additional private-sector
investment capital to Alaska is exactly what the state
needs to encourage a market sustainable economy - one
that relies primarily on growing our exports and
replacing our imports, as opposed to one that depends
on state and federal transfer payments and low-paying,
low-skill jobs.
The tax credit defined by HB 61 would apply, as you've
heard, to 10 percent of a company's qualified capital
investment and 100 percent of the expenses associated
with that capital investment. However, in any given
year the credit is capped at 50 percent of a company's
corporate income tax liability. And, perhaps most
importantly - and also as you've heard before - the
credit will only apply to successful exploration and
development projects, and no reward is granted to dry
holes.
By providing incentives for successful exploration and
development, Cook Inlet natural gas reserves should
increase, meaning additional royalty, severance, and
ad valorem income to the State of Alaska. Increased
natural gas reserves in Cook Inlet will also ensure an
adequate supply for Southcentral communities,
utilities, and industrial operations, meaning stable
jobs and tax revenues for the region.
Number 0069
MR. OWENS concluded his testimony as follows:
The bottom line is this: current exploration activity
in Cook Inlet is not sufficient to meet future demand
for low-priced natural gas. House Bill 61 will help
provide an attractive business environment for
companies looking to increase leasing, drilling, and
construction activities in Cook Inlet. Our members
believe it is a timely piece of legislation, and we
hope the committee will see fit to support the
legislation.
Number 0003
KEVIN TABLER, Manager of Land and Government Affairs, Union Oil
Company of California (Unocal), began his testimony, indicating
he holds the manager position for Unocal in Alaska.
TAPE 03-12, SIDE A
Number 0001
MR. TABLER, speaking in support of HB 61, expressed appreciation
for consideration of the bill as a vehicle to stimulate gas
exploration and development south of the Brooks Range. He told
members:
Although we recognize this bill may serve to improve
the economics of marginal oil reservoirs discovered or
defined while exploring for gas, it is the
identification and development of new gas reserves in
Cook Inlet which are needed if we are ... to sustain
our local economy in Southcentral Alaska. Without ...
new gas reserves, value-added businesses and
industrial exporters will suffer cutbacks in
production, yielding to the ever-present Southcentral
utility needs. These disruptions in supply, if left
unchecked, will lead to a lower tax base, unemployment
and underemployment, and loss of the monetary cycling
effect as dollars change hands throughout a community.
I place an emphasis on Cook Inlet, as Cook Inlet is
where Unocal's infrastructure base and manpower are
best defined. Although we do have working interests
in the fields on the North Slope, our ownership
interest is such that we play a minor role in the
exploration and development operations of these
fields. While we recognize that incentives available
to North Slope explorers and producers will have a
beneficial impact on Unocal, the beneficial impact of
incentive legislation in Cook Inlet is magnified when
applied to the marginal nature of the mature fields
and the declining gas-reserve base in Cook Inlet.
For this reason, incentive legislation such as HB 61
will help achieve the desired effect of identifying
new gas reserves by providing a predictable and
quantifiable credit to help lessen the inherent risk
of costly exploration. The increased tax revenue from
additional hydrocarbon production will more than
offset the initial financial impact from the tax
credit. The objective is not to shift a larger share
of an existing pie to industry; rather, the objective
is to increase the size of the pie for everyone.
Number 0215
MR. TABLER continued:
For the last several years, Unocal has consolidated
and restructured its Alaskan operations and focused on
becoming the safest, lowest-cost producer in Cook
Inlet. We have, either through purchase and/or
exchange of properties, positioned ourselves to have
the most cost-effective operation possible. The Cook
Inlet, with its mature and declining fields, low
margin properties, high operating costs, and
regulatory uncertainty, is a very challenging
environment in which to stay profitable, let alone
risk ... capital. Cost cutting, in and of itself, is
only a temporary fix. The only sustainable solution
is to increase the reserve base.
Unocal's considerable stake in its Cook Inlet
infrastructure, manpower, and capital investments are
continually threatened by internal global competition
for investment dollars. Evidence of this
vulnerability is confirmed by the recent drilling of
three dry holes on the Kenai Peninsula in an effort to
meet the growing demand of the natural gas market.
Although we were rewarded by a discovery of the
Ninilchik Unit with our partner Marathon, the expense,
risk, and uncertainty of success has reduced our
Alaskan capital budget from $70 million last year down
to $35 million for 2003. Providing a credit for
successful efforts will definitely improve the
attractiveness of our Alaskan exploration projects.
Number 0330
MR. TABLER continued:
Not only will HB 61 create an incentive for companies
currently active in gas exploration in Cook Inlet, the
attractiveness of such a credit will act as an ...
industry incentive to those thinking of investing in
exploration south of the Brooks Range. If you think
of the credit as costing the state $1 for every $10
invested by someone else, and paid out only in a
success scenario, the risk to the State of Alaska is
negligible when compared with the ancillary benefits
of new reserve identification.
In conclusion, we believe this bill will add certain
attractive parameters to companies during the
investment decision-making process, with very little
exposure to the State of Alaska. Therefore, we
encourage passage out of your committee.
Number 0480
CHAIR KOHRING told Mr. Tabler he'd made some excellent points
with which he concurred. He also thanked Mr. Myers and
Mr. Logsdon for standing by on teleconference. He announced
that HB 61 would be held over.
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Oil and Gas meeting was adjourned at
5:10 p.m.
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