03/16/2004 03:15 PM House O&G
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+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
March 16, 2004
3:15 p.m.
MEMBERS PRESENT
Representative Vic Kohring, Chair
Representative Cheryll Heinze
Representative Jim Holm
Representative Norman Rokeberg
Representative Harry Crawford
Representative Beth Kerttula
MEMBERS ABSENT
Representative Lesil McGuire
COMMITTEE CALENDAR
SENATE BILL NO. 264
"An Act repealing the time limitation on the authority of the
Department of Natural Resources to enter into agreements with a
person or persons desiring to own an oil or natural gas pipeline
proposed to be located on state land for the purposes of
providing for payment of the reasonable costs incurred in
preparing for activities before receipt of an application under
the Alaska Right-of-Way Leasing Act; and providing for an
effective date."
- MOVED SB 264 OUT OF COMMITTEE
HOUSE BILL NO. 531
"An Act relating to natural gas exploration and development and
to nonconventional gas, and amending the section under which
shallow natural gas leases may be issued; and providing for an
effective date."
- HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: SB 264
SHORT TITLE: REPEAL PIPELINE PREAPPLICATION DEADLINE
SPONSOR(S): RULES BY REQUEST OF THE GOVERNOR
01/14/04 (S) READ THE FIRST TIME - REFERRALS
01/14/04 (S) RES
01/28/04 (S) RES AT 3:30 PM BUTROVICH 205
01/28/04 (S) Moved SB 264 Out of Committee
01/28/04 (S) MINUTE(RES)
01/30/04 (S) RES RPT 4DP 1NR
01/30/04 (S) DP: OGAN, STEVENS B, SEEKINS, DYSON
01/30/04 (S) NR: ELTON
02/25/04 (S) TRANSMITTED TO (H)
02/25/04 (S) VERSION: SB 264
02/26/04 (H) READ THE FIRST TIME - REFERRALS
02/26/04 (H) O&G, RES
03/16/04 (H) O&G AT 3:15 PM CAPITOL 124
BILL: HB 531
SHORT TITLE: CONVENTIONAL & NONCONVENTIONAL GAS LEASES
SPONSOR(S): RESOURCES
03/04/04 (H) READ THE FIRST TIME - REFERRALS
03/04/04 (H) O&G, RES, FIN
03/16/04 (H) O&G AT 3:15 PM CAPITOL 124
WITNESS REGISTER
MARTY RUTHERFORD, Deputy Commissioner
Office of the Commissioner
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Presented SB 264 and answered questions.
REPRESENTATIVE BEVERLY MASEK
Alaska State Legislature
Juneau, Alaska
POSITION STATEMENT: Presented HB 531 on behalf of the House
Resources Standing Committee, which she co-chairs.
MARK MYERS, Director
Division of Oil & Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Testified in support of HB 531 on behalf of
DNR and the administration; answered questions.
REPRESENTATIVE PAUL SEATON
Alaska State Legislature
Juneau, Alaska
POSITION STATEMENT: Asked questions relating to HB 531 and
inquired about adding language to the bill.
PATRICIA MACK
Wasilla, Alaska
POSITION STATEMENT: Expressed concerns relating to HB 531.
ROBERTA HIGHLAND
Kachemak Bay Property Owners Association
Homer, Alaska
POSITION STATEMENT: Testified in support of the intention of
HB 531, but also asked legislators to address the situation
involving the thousands of acres already leased.
ACTION NARRATIVE
TAPE 04-9, SIDE A
Number 0001
CHAIR VIC KOHRING called the House Special Committee on Oil and
Gas meeting to order at 3:15 p.m. Representatives Kohring,
Holm, Rokeberg, and Heinze were present at the call to order;
Representative Kerttula arrived shortly thereafter.
Representative Crawford arrived as the meeting was in progress.
SB 264-REPEAL PIPELINE PREAPPLICATION DEADLINE
CHAIR KOHRING announced that the first order of business would
be SENATE BILL NO. 264, "An Act repealing the time limitation on
the authority of the Department of Natural Resources to enter
into agreements with a person or persons desiring to own an oil
or natural gas pipeline proposed to be located on state land for
the purposes of providing for payment of the reasonable costs
incurred in preparing for activities before receipt of an
application under the Alaska Right-of-Way Leasing Act; and
providing for an effective date." [SB 264 was sponsored by the
Senate Rules Standing Committee by request of the governor.]
Number 0135
MARTY RUTHERFORD, Deputy Commissioner, Office of the
Commissioner, Department of Natural Resources (DNR), presented
SB 264 and testified in support of it. She explained that its
purpose is to repeal the sunset date in AS 38.35.145(c), a
statute that allows DNR to enter into agreements with
prospective lessees to recover the costs for their preliminary
work, which DNR calls "preapplication work," on a pipeline
right-of-way lease application. This particular provision ended
December 31, 2003.
MS. RUTHERFORD noted that pipeline right-of-way lease applicants
must submit detailed applications; this requires significant
engineering and design work, at a significant cost. Applicants
have found it very useful to have agencies involved in the
preapplication process so they are fully aware of permitting
issues at an early stage and can address them in their
applications. Furthermore, [DNR] has found that such agency
participation ultimately expedites project review and approval.
She said this provision was used recently for preapplication
work on the Point Thomson project before it was delayed and on
the Kenai Kachemak Pipeline extension.
MS. RUTHERFORD listed examples of agency assistance:
identification and explanation of applicable state laws and
regulations and the regulatory process; identification of state,
federal, and private land ownership; identification of
restrictions on affected state lands that might interfere with
authorizing a right-of-way lease or might hinder an applicant's
construction, including third-party interests such as a utility
right-of-way or even the existence of an archeological site;
identification of potential environmental issues such a
difficult stream crossings; assistance when an applicant reaches
out to other affected parties such as utilities or other land
owners so the applicant better understands the third-party
interests and issues; and assistance with actual development of
the project application. And for a large project, she said the
ability to enter into a reimbursement agreement for
preapplication work allows [DNR] to "staff up" the Joint
Pipeline Office in a timely fashion.
MS. RUTHERFORD emphasized that this preapplication is completely
applicant-initiated; an applicant may initiate a request for
preapplication services, but is under no obligation to do so.
Without this legislation, however, DNR cannot work with an
applicant until it receives the application. She said the
fiscal impact of the bill is zero, whereas the impact of not
passing it would be rather significant. Without it, [DNR]
cannot enter into reimbursement agreements with applicants in a
"preapplication mode" and has no general funds available to
provide this assistance.
Number 0539
REPRESENTATIVE HEINZE mentioned stranded gas and related money
being sent [to DNR]. She asked whether any of that work would
be in this application.
MS. RUTHERFORD replied no; that work is totally focused on
analyzing and developing a fiscal contract under the stranded
gas Act, and none of the people who put in applications under
the stranded gas Act are at the point of being prepared to move
a right-of-way application forward.
REPRESENTATIVE HEINZE asked whether DNR has the staff to handle
these applications and do this work.
MS. RUTHERFORD answered that it depends on the size of the
project. For a very large one, it would be critical [for DNR]
to have this vehicle available if an applicant chose to work
with [DNR] on three applications, for example, in order to be
able to staff up; a [major] gas line is the type of project that
would require hiring new staff. For a reasonably small project
such as the Kenai Kachemak Pipeline, however, [DNR] can handle
it with staff that aren't focused on either another project or
TAPS [Trans-Alaska Pipeline System] oversight activity.
CHAIR KOHRING announced the arrival of Representative Crawford.
Number 0677
CHAIR KOHRING requested confirmation that this just removes the
date of December 31, 2003, from statute and leaves it open-
ended.
MS. RUTHERFORD said that's the proposal in the bill.
CHAIR KOHRING surmised that it's legally acceptable to do this
retroactively, even though the deadline has passed.
MS. RUTHERFORD replied that removing that date allows [DNR] to
once again accept reimbursement agreements and work
preapplication activities. During the period between
December 31 and now, it hasn't been doing so, and removing that
date simply gives [DNR] the authorization without any end date.
CHAIR KOHRING asked whether anyone else wished to testify.
[There was no response.] He said he'd like to move the bill.
Number 0800
REPRESENTATIVE HEINZE moved to report SB 264 out of committee
with individual recommendations and the accompanying [zero
fiscal note]. There being no objection, SB 264 was reported
from the House Special Committee on Oil and Gas.
HB 531-CONVENTIONAL & NONCONVENTIONAL GAS LEASES
[Contains discussion relating to SB 312, the companion bill, and
to SSHB 364]
Number 0850
CHAIR KOHRING announced that the final order of business would
be HOUSE BILL NO. 531, "An Act relating to natural gas
exploration and development and to nonconventional gas, and
amending the section under which shallow natural gas leases may
be issued; and providing for an effective date."
CHAIR KOHRING invited Representative Seaton to join members at
the table.
Number 0888
REPRESENTATIVE BEVERLY MASEK, Alaska State Legislature,
presented HB 531 on behalf of the House Resources Standing
Committee, which she co-chairs. She brought attention to the
new proposed committee substitute (CS), Version D.
Number 0923
REPRESENTATIVE HEINZE moved [to adopt the proposed CS, Version
23-LS1818\D, Chenoweth, 3/12/04, as a work draft]. There being
no objection, Version D was before the committee.
REPRESENTATIVE MASEK explained that the shallow natural gas
program was adopted by the legislature in 1996 to provide a
clean-burning, inexpensive source of fuel for rural communities
and remote locations. This over-the-counter application program
has required the Department of Natural Resources (DNR) to issue
a shallow natural gas lease if the director determines the
discovery of a local source of natural gas would benefit the
residents of an area. Under the program, no best interest
finding has been required, however.
REPRESENTATIVE MASEK said although the program has been used in
a few areas for its original intended purposes, in other areas
it has been used for large-scale commercial operations in
nonrural settings. This has led to a series of unintended
consequences; for example, in 2003 approximately 98 percent of
shallow natural gas leases and applications were in higher-
population locations such as the Big Delta, Matanuska-Susitna
("Mat-Su"), and Homer areas. Representative Masek said the lack
of discretion given to the director on issuing leases, along
with the occurrence of applications in higher-density areas, has
led to heightened public concern about the program.
Number 1055
REPRESENTATIVE MASEK conveyed her belief that [Version D]
resolves four fundamental problems with the program: lack of
public notice and participation prior to issuance of a lease;
"over-the-counter discretion" in issuing a lease once the
application is received; use of over-the-counter applications,
rather than competitive bidding; and problems such as pooling
once a lease reaches production. It replaces over-the-counter
shallow gas leases with a gas-only option, exploration
licensing, and areawide leasing; she indicated the latter two
are existing programs that require a best interest finding,
which involves the public at the beginning of the process. She
said these programs give the director discretion about whether
to issue a lease and whether to exclude certain lands from a
lease such as those where the surface contains a school.
REPRESENTATIVE MASEK reported that the bill provides that
nonconventional gas developers enjoy the same lower rent and
royalty rates currently in the shallow gas leasing program.
Replacing over-the-counter leases with exploration licensing and
areawide leasing provides DNR with much greater public input, as
well as agency control and discretion to determine whether
exploration and development are appropriate in certain areas.
Both leasing and licensing processes are competitive, she noted,
ensuring maximum value to the state.
REPRESENTATIVE MASEK said the bill creates a gas-only selection
of areawide leasing and exploration licensing "identified in a
best interest finding by DNR." It also differentiates between
conventional and nonconventional gas resources for the purpose
of lease and rent royalties. Furthermore, it encourages
exploration licenses with a [best interest finding] as a method
for nonconventional gas exploration outside of the areawide
leasing, which she said is mainly in rural Alaska. It
recognizes that lease rights shouldn't be determined by depth
only. Representative Masek concluded by saying [Version D]
incorporates the foregoing and that experts from DNR on
teleconference could answer technical questions.
Number 1316
MARK MYERS, Director, Division of Oil & Gas, Department of
Natural Resources, specified that DNR and the administration
support this legislation. Referring to public workshops in the
Mat-Su area and concerns heard from Homer and other areas, he
reported that one chief public concern about the shallow gas
leasing program has been an unintended consequence of the
program, that very little actual notice occurs up front prior to
issuance of the lease. One main concern expressed in the
workshops has been the desire to have a process that includes a
best interest finding.
MR. MYERS explained that a best interest finding is a document
like an environmental impact statement (EIS) in which the state
weighs the values and looks at the environmental issues as a
"major, full public process" with a lot of public input; the
draft decision document then is available for public comment by
not only citizens, but also local governments and so forth. In
response to that, the final decision must incorporate all those
comments and answer any questions that have been brought up or
else modify the proposed lease sale for that area.
MR. MYERS said that process has worked very well; is
established, court-tested, and well accepted; and has "the
balancing test of the state's best interests" as its true
measure. He opined that this has allowed a very successful
program for areawide leasing, and said a modified but very
similar process is used in exploration licenses. He remarked:
Through those two processes, we believe we can
accomplish pretty much everything that is accomplished
with the shallow gas program in terms of encouraging
exploration for and development of coal bed methane to
provide that additional public input that's been
sought for the public process elsewhere.
Number 1460
MR. MYERS explained that one big thing this legislation does is
allow that upfront planning process. Acknowledging it's more
work for the department, he nonetheless remarked that when [DNR]
is done with it, it will have really taken the public concerns
and done a balancing test, and will be able to say the leasing
is appropriate; it also gives [DNR] a longer, better-defined
process to put in stipulations and mitigation measures for
environmental protection. He reiterated that he believes it's a
solid, time-tested process.
MR. MYERS highlighted advantageous provisions for the lessee.
For example, by replacing shallow gas leasing with either
conventional leasing or exploration licensing, the program
allows applicants to have a much longer period of time; the
three-year period for shallow gas leases has been problematic in
that it's hard to actually do development work in a three-year
period, which has led to less value for the leases.
MR. MYERS reported that another problem with leases has been the
shallows depths; he acknowledged that the legislature has
struggled with whether it should be 3,000 or 4,000 feet, or
should be part of the field above 3,000 feet and continue to
deeper depths. He remarked, "We think the best way to lease
land is to provide ... the gas potential at all depths; in that
sense, then, the correlative rights of all parties are
protected, at least the maximum production from the lease." He
mentioned that there'd potentially be fewer facilities built and
thus less of an impact.
Number 1566
MR. MYERS noted that one concern about those who produce or
explore for shallow gas or other nonconventional types of gas
has been the economic structure of the leasing program.
Conventional lease rentals start at $1 an acre and go up to $3.
He pointed out that exploration costs and the economics for coal
bed methane or other nonconventional gas such as gas hydrates or
gas-producing fractured shales are different from those for with
conventional reservoirs. To encourage that activity, he said,
this bill provides a mechanism whereby if the lessee makes a
showing that the gas potential on the lease is nonconventional,
[the lessee] can retain a $1-an-acre rental; if the gas doesn't
compete with other gas, the 6.25 percent royalty share can also
be retained that is part of the shallow gas leasing program.
MR. MYERS concluded by saying this bill should stimulate the
shallow gas and coal bed methane industry; provides a balancing;
has a mechanism for the state to recognize the difference in
economics and to give a better lease term; is for all depths and
for a longer period of time; will lead to more rational
development; should bring in more money to the state; provides a
best interest finding and public input; creates a situation in
which, to his belief, the leases are a better value for
applicants; and deals with some problems relating to the limited
depths of the shallow gas leasing program. He stated support
[from DNR and the administration] for those reasons.
Number 1686
REPRESENTATIVE KERTTULA asked what kind of notice is given. She
expressed concern that there still isn't direct notice to
landowners, although it could happen.
MR. MYERS answered that there is no notification at the time of
leasing to all residents in the area, but there is full
notification to any resident who provides his/her name for the
mailing list; to all municipal governments and community
councils; and [to the general public through] the local
newspaper, [notification posted] at the post office, and so
forth. Mr. Myers said he doesn't know of any state program that
notifies all residents in an area that the state is doing a
disposal. He explained:
We have difficulty because we have no qualified lists
of residents. We have tax records in some places, but
that goes to the owner, not to the resident. And in
other unorganized boroughs, we really don't have those
lists. ... We can attempt it, but we haven't
traditionally, in our programs.
MR. MYERS said other than for the shallow gas program, [DNR]
hasn't had this as a major complaint. He pointed out, though,
that there is a requirement before any operations occur that all
residents be notified; at that stage, they "go on the ground and
physically require that notification."
Number 1794
REPRESENTATIVE KERTTULA asked how onerous it would be to notify
the owners instead of the residents prior to leasing, and
whether a list could be obtained from the courts, for example.
MR. MYERS answered [that DNR] has looked at using available
lists including court lists, tax records, and so forth, but
records in most areas aren't all that good and it would add
costs to the programs. With the shallow gas program, for
example, the estimate is about $70,000 a year if [notification]
is via certified mail; he offered to provide a breakdown. He
noted that commercial mailing lists could be tried, said
contracting it out has been looked at, and highlighted the
substantial cost. Although it's possible, he said, he didn't
have confidence about [the ability to notify] all residents of
an area, based on the historical quality of the data sets. He
added that probably the best records [DNR] has seen are some
commercial mail-outs for coupons, but it costs money and takes
time. It also could be done under contract.
Number 1870
REPRESENTATIVE KERTTULA asked, "What if the list were simply to
owners and we figured out some fairly simple way to do that and
it was not certified?" She surmised this would lower the cost.
MR. MYERS answered affirmatively, estimating that for the
shallow gas program it would cost about $10,000 using regular
mail. He mentioned concern about being sued if someone doesn't
get a letter. Indicating DNR tries its best to notify people,
he said the preferred method is to put out the notice and have
[concerned citizens contact the department]; if there is any
activity at all in their area, DNR will then notify them, thus
ensuring that "the folks that really care about it" receive
notification. He said notifying people prior to a disposal
isn't current state policy on conventional leasing, (indisc.),
or any other disposals of the state; however, it's something
[DNR] could look into if the legislature so desires.
REPRESENTATIVE KERTTULA suggested it's certainly worth the
legislature's thinking about it very hard because of events of
last year relating to shallow natural gas.
Number 1970
REPRESENTATIVE ROKEBERG recalled seeing a schematic of a
distribution plan for Fort Yukon to take advantage of nearby
potential shallow gas to distribute to that village, one
intention of the original [shallow gas] legislation. He asked
whether HB 531 provides a choice between exploration licensing
or an areawide leasing plan. If there were a small, discrete
area around that village, for example, he asked how Mr. Myers
would recommend that work under this proposed legislation.
MR. MYERS said that's a good question. He recalled that the
shallow gas legislation passed the same year as exploration
licensing; thus there wasn't a vehicle outside of the areawide
sale areas to allow for leasing and development.
REPRESENTATIVE ROKEBERG remarked, "That was before areawide
leasing too."
MR. MYERS agreed, saying there were conventional sales where
[DNR] did a finding. Remarking that areawide leasing certainly
would apply in areas where he thinks the department's intent
would be to extend the current areawide sales, he mentioned
north and south Cook Inlet and at least looking at those
possibilities.
MR. MYERS pointed out that the other mechanism, the most
appropriate in rural Alaska, is where the intent is for
(indisc.) energy: either the applicant would apply or the state
would open an area for exploration licensing - it has been done
both ways. Although it can be applicant-driven, the applicant
has to compete for that license in terms of dollars of work
commitment spent for the area. He noted that a license can be
for as few as 10,000 acres, essentially two shallow gas leases.
Also, an applicant can request the area and [DNR] can grant the
license without a competitive process, since no one else has
competed for it. He remarked, "We're not seeing a lot of
competition in the exploration licensing."
MR. MYERS elaborated, saying an applicant can come forward any
April and propose a license in an area, and [DNR] will start the
process. Or the state, at any point, can decide to "go out for
a license" in a specific area, often in response to a request.
In Bristol Bay, for example, there was a lot of local interest
and the state "self-proposed" it. The mechanism in rural Alaska
would be an exploration license application. Suggesting the
applicant's cost would be far cheaper than for a shallow gas
lease, with a longer-term license, he added, "What they're
bidding on is really a work commitment to evaluate leases, which
is what we want anyway."
MR. MYERS explained that at the end of the license period is a
right to noncompetitively convert to a conventional lease at
12.5 percent. Under this program, for an area like Fort Yukon
where [DNR] sees no oil potential, a gas-only lease could be
applied for and negotiated. For coal bed methane, a showing
could be made to [DNR] and then the royalty and rental terms
would "stay at the dollar, and it would be the 6.25 [percent]."
Thus economic terms at Fort Yukon would be obtained that are
similar to those under shallow gas leases, except there'd be
better terms because of the 7 to 10 years to explore and the
exclusive right to explore before going to a lease.
MR. MYERS added that overall, review of all the cases of shallow
gas leases [has shown that] under this, the applicants would
have been better off with actual exploration licenses; he
mentioned the Red Dog area and some other areas. Having worked
through the process, he said, he believes this is a more
effective way to get unique areas like Fort Yukon under lease,
because there is a best interest finding up front that includes
the public process and will protect [lessees] from litigation.
Number 2280
REPRESENTATIVE ROKEBERG noted that the best interest finding has
to be completed for both the exploration licensing and any
conventional or areawide leasing. He asked Mr. Myers whether
DNR's costs would be lower to prepare a best interest finding in
a rural area with a relatively small amount of acreage, or
whether there is a usually a fixed cost because of the breadth
of any best interest finding that must be prepared.
MR. MYERS said he believes the answer has two parts. If the
area is geographically small or constrained, the finding is more
constrained; it is easier to do a finding for 10,000 acres than
for 0.5 million acres because of the research needed. It has
been found, however, through the process of shallow gas leasing
and developing stipulations and mitigation measures, that it
still requires a substantial amount of research. Prior to
issuing a lease, he said, [DNR] goes through the full public
process.
MR. MYERS reported that, in retrospect, for the shallow gas
leasing program more effort has been spent than if the findings
had been done up front. He mentioned the Holitna basin, the
Healy-Cantwell area, and a desire of people there to have public
input and a public process. In reality, he said, there has been
little discretion to change things, even though there hasn't
been a public process. He offered his belief that it's not a
whole lot more work to actually do the [best interest] finding
and have public input up front.
MR. MYERS explained that also different under the licensing
proposal is an ability to negotiate with applicants to remove
acreage that is environmentally sensitive or that has a low
probability of finding gas. Perhaps 90 percent of problems are
eliminated by eliminating 5-10 percent of the acreage, but the
applicant doesn't necessarily know that. Thus having a process
that includes discussion with the agency and a shaping of the
license area has been a huge success; he cited a Susitna license
as an example, saying there was little public concern because it
was shaped with the applicant to avoid "hot-spot" areas.
Returning to balancing, he mentioned the cost of licensing,
leasing, and the best interest finding. He pointed out that
while it takes about a minimum of a year to issue a finding, it
takes [DNR] longer than that to issue shallow gas leases now.
Number 2443
REPRESENTATIVE ROKEBERG asked what it typically costs to do a
best interest finding.
MR. MYERS replied that including staff time and depending on the
amount of travel, $250,000 is an estimate for a typical
exploration license. For a smaller one, it would probably be
considerably less. If [DNR] does multiple ones in the same
area, however, a lot of basic data is there and so it can cost
much less. He reiterated that for shallow gas leasing, [the
department] isn't spending a whole lot less, or perhaps is
spending no less, if staff time is included.
Number 2498
REPRESENTATIVE ROKEBERG asked what switching to areawide leasing
and avoiding 5-year renewals on best interest findings saves the
department over the years.
MR. MYERS replied that the 10-year "shelf life" has saved
millions of dollars and cut the staff for best interest findings
to perhaps 20 percent of what was required before.
REPRESENTATIVE ROKEBERG said he'd been looking for that answer
since introducing an areawide leasing bill a few years ago.
Number 2531
REPRESENTATIVE ROKEBERG expressed concern, stating his
understanding that Mr. Myers had said one method for handling
this type of nonconventional gas would be to extend the
geographic boundaries of the current areawide leasing offerings.
He asked, "If you were to do that, would that not either extend
them or create new ones - like in Bristol Bay you basically
created a new areawide lease area, as I understand it?"
MR. MYERS answered in the affirmative. He said that would occur
in the Cook Inlet areawide findings, due in 2007; the 10-year
period would be up, so [DNR] would review it anyway in that
timeframe, would look at areas it is aware of in the valley that
would have coal bed methane potential, and would extend those
further to the north. He added:
In the meantime, if someone were to apply for a
license in the area that's currently not, we could go
through the process. ... Someone could lease that [at]
this point in time, prior to that finding being
completed ... or the announcement that we were going
to extend it in the 2007 period. So I don't think
under this program, in the interim time, any land ...
is off-limits that isn't planned to be off-limits for
areawide leasing, like in the Bristol Bay region.
So we wouldn't anticipate a mineral closing or
anything else in the valley. That ... would be open
for licensing; again, it would provide that public
process along with it. And then our ultimate goal
would be, then, to extend the areawide further ... to
the north there, certainly, and that would provide
that best interest finding process, but still have ...
a chance to develop the coal bed methane resources up
there.
Number 2625
REPRESENTATIVE ROKEBERG conveyed his understanding that when the
Cook Inlet areawide leasing was established, the boundaries were
adjusted during regulatory rule making; the "Kachemak Bay
uplands" were excluded and thus became available for leasing
under the shallow gas [program], which has created somewhat of a
problem by the fact of their exclusion. He asked whether [DNR]
has plans relating to extension of the areawide leasing
boundaries there or in the [Mat-Su area]. He also asked about
impacts relating to the costs and the regulatory rule making,
and whether [DNR] will go through the whole public hearing
[process] again when there is a renewal of the best interest
findings at the 10-year [renewal point in 2007].
MR. MYERS addressed the last question first, saying the 10-year
period starts with a brand-new best interest finding along with
a decision by the commissioner on what area will be included in
the finding. In the 1997 finding, he noted, then-Commissioner
Shively made a determination that limits the area to the south;
however, there is no real documentation of the policy call at
the time. Mr. Myers said those limits could be subject to the
commissioner's discretion at the time the finding is done. If
the finding didn't include that area to the north and south, it
would still be open for exploration licensing under this
program.
MR. MYERS reiterated that the major concern heard from folks in
the [Mat-Su area] and Homer is the lack of public process. Even
with a license, he said, there'd still be a best interest
finding process and the ability to "size and shape" the area to
eliminate areas of major public concern "if the findings
reported it." The public process would be there in either case.
Mr. Myers went on to say that, at this point, he believes DNR's
intent is to incorporate a "larger areawide leasing" because
it's supported now by the geology and the technology. The
discussion of what should or shouldn't be in the sale, the sale
area, mitigation measures, surface occupancy standards, and so
forth would be worked out through the public process, the
findings, and the weighing of the state's best interests.
Number 2771
REPRESENTATIVE ROKEBERG asked whether an applicant could request
a gas-only lease under this bill if the areawide leasing
boundaries were expanded in Cook Inlet to the south and north,
for example.
MR. MYERS answered that for those particular areas, DNR's
commissioner would have to make a determination, if it was
within an areawide sale, as to whether to issue a gas-only
lease. There are qualifications as to how it would be done, but
he said the logical implications are that the potential and the
environmental sensitivities are what would be looked at. For an
area by Homer where there is a lot of concern about oil-spill
issues, for instance, it might be appropriate to issue a gas-
only lease because of environmental sensitivity. The
commissioner would have to work that out; it would be explained
and argued in the findings, and would be determined by the
findings process.
MR. MYERS explained that the other case where a commissioner
would do this is if an area really had no oil potential. If the
area underneath had a lot of oil potential as well as gas
potential, or had even moderate oil potential, Mr. Myers said he
doubted that the commissioner would make a determination to
issue a gas-only lease unless it was determined,
environmentally, to be the only way to properly lease it, to
balance the state's best interests.
Number 2858
REPRESENTATIVE ROKEBERG inquired what the economics would be if
there was drilling for shallow gas or coal bed methane within
areawide leasing geography. He asked what the economic impact
would be if there was a lower-production shallow gas operation
versus more conventional gas.
MR. MYERS responded that conventional gas - the kind of gas
typically explored for on the Kenai Peninsula or most of the
known North Slope reserves - has superior economics and requires
fewer wells. The gas resources are typically at higher
pressure, for instance, and the rate from an individual well is
much higher. The cost of drilling a well is also higher, but
overall the economics are generally a little better. Pointing
out that the economics for coal bed methane are very good in
some areas, Mr. Myers said he thinks that determination will be
based on the cost of drilling; the approximation to
infrastructure and the cost of getting the gas to market; and
the productivity of the coals, which can vary.
MR. MYERS provided examples, saying the [Mat-Su area] has
existing infrastructure including roads, and is much cheaper to
explore than the Fort Yukon area; most of the economics are
pretty good in the [Mat-Su area], and pilot programs in the
Pioneer Unit there are in conventional, competitively bid,
standard oil and gas leases held by the Pioneer Unit itself.
Areas to the north of that have shallow gas leases. Mr. Myers
surmised that Evergreen Resources was comfortable drilling with
conventional lease terms. In the [Mat-Su area], he said, he
believed it would be a tossup whether conventional lease terms
would affect the economics, and didn't think they'd affect it
very negatively. He added that the differential in the royalty
rate, the 6.25 [percent], makes no difference because that gas
is fully competing in the market with other gas. In rural
Alaska, however, there is a high cost to develop infrastructure,
there are limited markets, and so forth.
TAPE 04-9, SIDE B
Number 2948
MR. MYERS mentioned potential for the lower rate [in rural
areas]. Turning to Homer, he noted that there are multiple
wells drilled in the Homer bench itself, many with good gas
shows, on a trend with normal gas fields; the shallow gas
potential there is actually conventional. Mr. Myers explained
that in such an area, [DNR] would probably argue that there's
more conventional gas potential; that it shouldn't be at the
lower royalty rate; and that someone could bid competitively for
those leases, successfully, and could afford the exploration and
development program.
Number 2948
REPRESENTATIVE HEINZE noted that some legislators had just
returned from the Energy Council [conference in Washington,
D.C.], where they looked at projected gas shortages in the U.S.
She asked, as companies look towards Alaska and its gas, and as
competition increases for these applications, whether Alaska
will "have enough area for these shallow gas leases."
MR. MYERS suggested looking at Alaska's long-term gas supplies
and basins with large potential; many of these areas are under
exploration licenses. He said the North Slope is under
traditional leasing, however, and significant potential exists
within North Slope foothills basins, in particular, for
undiscovered, large, conventional gas fields. Indicating a lot
of large gas producers are buying those leases, he cited
examples of companies with a long history of gas exploration and
mentioned the potential for a natural gas pipeline from the
North Slope.
MR. MYERS reported that further south, one of the more
outstanding candidates is the Nenana basin outside of Fairbanks,
where Andex [Resources LLC] has a license; that deep basin has
potential [in the trillions of cubic feet] but is under
exploration licensing. The Susitna basin has two different
exploration licenses with Forest Energy; characterizing it as
"sort of an extension of Cook Inlet to the north," he offered
the belief that this area is gas-prone, with the same formations
that produce gas in the Cook Inlet. Moving further south to the
northern extension of Cook Inlet, he said there is coal bed
methane activity in the Pioneer Unit and the shallow gas leases
adjoining that area to the north, and then Cook Inlet proper.
MR. MYERS provided details, concluding that there is a lot of
potential in the offshore Cook Inlet area, but it's expensive to
get to and the fields would have to be very large to support the
cost of development. Onshore there is a fair amount of
exploration activity - more than traditionally, on both sides of
the inlet - with some success for gas; however, those
discoveries cumulatively will only extend the life of Cook Inlet
[production] about another year. Mentioning about nine years of
reserves plus the possible one-year extension, he suggested the
unknown exploration potential there needs to be banked on if the
life is to be extended. He also indicated in Bristol Bay it's
believed a basin may have multiple [trillions of cubic feet] of
conventional gas "on state lands and state waters."
CHAIR KOHRING noted that Mr. Myers has a Ph.D. and speaks from a
lot of experience.
Number 2760
REPRESENTATIVE PAUL SEATON, Alaska State Legislature,
paraphrased from Version D, page 25 [amending
AS 38.05.180(f)(3)], which read:
(H) for nonconventional gas that will not be
produced in direct competition with gas on which a
royalty at a rate of at least 12.5 percent is payable,
a royalty share reserved to the state of at least 6.25
14 percent in amount or value of the production
removed or sold from the lease;
REPRESENTATIVE SEATON requested clarification, offering his
understanding that gas produced in most wells in Cook Inlet
until January of this year had a 5 percent royalty rate.
Number 2707
MR. MYERS replied that most gas in Cook Inlet is produced at a
12.5 percent royalty rate from state land. However, legislation
passed in 1994, which he believed sunsetted in January 2004,
gave a 5 percent royalty to certain "known but at that point
uneconomic" gas fields to spur development; the legislation
listed those fields and gave 10 years from the bill's effective
date for production to start. Mr. Myers recalled that the 5
percent was on the first 35 billion cubic feet of gas produced
from the field. Corresponding was that certain ones were oil
fields; for example, one platform got a 5 percent royalty until
it produced 25 million barrels.
MR. MYERS said for this program [under HB 531], in most of Cook
Inlet that has conventional oil and gas potential, the lower
royalty rate for the "gas-only" wouldn't be eligible. He added:
It's not eligible for it now, and it wouldn't get the
6.25 percent treatment. What was designed in this
bill was a mechanism, though, recognizing
Representative Rokeberg's Fort Yukon-type scenario
where there was a mechanism, if the gas was
unconventional, ... to get a 6.25 percent royalty for
local energy use.
Number 2595
REPRESENTATIVE SEATON noted that page 25 doesn't distinguish,
but talks about [competition] with gas with a royalty of at
least 12.5 percent. Saying there is a mixture in his own area
[Homer], where at least two fields just came on line prior to
January 1, he requested further clarification about how this
will apply to his area.
MR. MYERS responded that if gas was competing and came from the
Falls Creek Unit or several other units [listed in statute], it
would have a royalty of 12.5 percent, although in "the one case
... in the North Fork Unit" it would be 5 percent; that isn't
changed by this [bill]. If production occurred on one of the
current shallow gas leases in the Homer area and it was
competing with other gas, the royalty on those shallow gas
leases would be 12.5 percent; if it wasn't competing, it would
be 6.25 percent. This determination would be made at the time
of the discovery, he added.
Number 2490
REPRESENTATIVE SEATON asked, "So if it's competing with North
Fork gas, it's taxed at 5 percent?"
MR. MYERS replied that it would be 12.5 percent because of "the
standard on the lease."
REPRESENTATIVE SEATON asked if that's even though page 25 talks
about competition with gas with a royalty rate of at least
12.5 percent.
MR. MYERS affirmed that and explained that in this bill, the
royalty rate determined on those current shallow gas leases is
enshrined in statute. The bill's language doesn't directly
apply to the leases in the Homer area because, he said, "those
leases are established under the contract right and it's
enshrined in the lease under current statutes, under
[AS 38.05.]177."
Number 2442
REPRESENTATIVE SEATON sought clarification about a concern
expressed the previous week about [SSHB 364, which he
sponsored], relating to shallow gas leases in Homer, that there
is a problem with [DNR's] discretion to extend those leases if
they aren't being actively pursued. He asked Mr. Myers, "Would
you have any problem putting that same discretionary language in
this bill, as well, so that you would have the discretion and
the guidelines for reissuing the current shallow natural gas
leases in the Homer area?"
MR. MYERS shared his personal view, saying he'd have no problem
with the legislature's clarifying what that discretion is. "I
think the language you presented does it well and stays within
... the intent of the law," he said, and thus wouldn't be
considered the taking of a lease right. Unless activity was
occurring, he suggested, it probably would assure that those
shallow gas leases expired in three years; then, if the finding
was extended, the area "currently under exploration, under
shallow gas leases, ... if it was appropriate in the finding,"
could be included in an areawide sale for, potentially, a gas-
only lease. He added his belief that shortening that term and
limiting the discretion, or defining that discretion as that
bill [SSHB 364] does, wouldn't negatively affect this bill.
Number 2337
REPRESENTATIVE ROKEBERG brought up concerns raised by folks at
[Teck Cominco Limited, at the Red Dog mine] about a shale
discovery; he said they apparently have a current shallow gas
lease and concerns about how this bill relates to their future
operations. He asked whether there have been discussions with
them, whether any accommodation can be made for that situation,
and whether Mr. Myers believes this bill is adequate for their
purposes.
MR. MYERS answered that there are multiple issues involving
their particular leases and elaborated:
I did use the discretion of the director there to
extend their leases. They're past their three-year
primary term, so they ... have two years left ... on a
term that's actually going to end up being six years.
And the reason that that determination was made was
that they were doing a lot of good exploration and
work on adjoining, Native-owned leases. And that work
was directly appropriate for the development of the
fractured shale ... in their reservoir. So ... they
did, in fact, get an extension ... of term.
Realistically, for them to go into production, in my
opinion, it's going to require unitization. And
through unitization, they'd have the right to extend
those leases ... when they enter the unit. One of the
reasons you need to do unitization of the area is
because [of] the mixture of lease ownership, and you
have to worry about the correlative rights ... between
... NANA [Regional Corporation] and the state; those
are state lands. So it's the appropriate, normal way
to go. Under unitization, those leases would be
preserved as long as they are under production or
under a (indisc.) of exploration. So, again, normally
that's what we do with conventional leases; that would
follow there. And, really, it takes care ... of their
issue.
Barring that, if they decided not to go ahead with
future exploration, I think ... we'd be open to
considering an exploration license application for the
entire area that they're talking about. Again, I
think ... they're sort of the "poster activity" that
you want to see encouraged, that has local energy, ...
fractured shales, a nonconventional gas source. ...
Through the process of these bills, I believe, they
would actually end up with a better-quality product.
Some of their resource potential is, in fact, deeper
than the 3,000 feet, which creates some correlative-
rights problems in their area. That would be taken
care of if they had a license; they would have [a]
longer term for exploration, and then they would
convert to a conventional lease with known terms.
MR. MYERS said under this scenario he doesn't think there is any
conventional gas potential in the area; thus they could end up
applying for and being granted a nonconventional gas
[designation], and could get a royalty rate and rental structure
similar to the shallow gas program. He added:
In either case, ... when I ran ... through their
particular situation, I think they're fine if they
want to go through the process of unitization ... and
further development of shallow gas leases. They're
probably in good shape if they decided not to and
wanted to, again, go back and apply for an exploration
license. So I think we've worked through that,
particularly with their issues, but I don't really
want to speak for them. But we have had those
discussions.
Number 2157
REPRESENTATIVE ROKEBERG asked whether they could in some way
"top lease" it with an exploration license to protect themselves
before their current leases expire. He also inquired how that
transition would be handled so their investment is protected and
so forth.
MR. MYERS agreed they certainly could do that. The one risk
would be if someone outbid them for the work commitment. He
said he thinks it's possible but unlikely - if they own or
manage the mine operations, have the equipment there, and are
actively exploring on the surrounding lands - that someone else
would come in and bid more for the work. He said [DNR]
traditionally hasn't [offered] exploration licenses over shallow
gas leases because of correlative-rights issues, for example,
not wanting to deal with someone producing gas from 4,000 feet
that is geologically connected to [gas at] 3,000 feet.
MR. MYERS also suggested [the people at Teck Cominco Limited]
could relinquish their shallow gas lease at the same time they
applied for the exploration license, and then there wouldn't be
a problem. Given the state of their exploration program, he
said, it would be logical if they chose to apply for a unit;
then the only cost besides the demonstration of their work
commitment (indisc.) would be a $5,000 unit-application fee.
Number 2069
REPRESENTATIVE ROKEBERG inquired about drilling test holes or
having the position verified geologically.
MR. MYERS answered that they've drilled numerous core-hole
tests, but haven't had a long-term production test. He said one
reason he'd extended the lease was because of their intent to do
that; although the test probably would've been on adjoining,
non-state lands, the information would've demonstrated the
economics appropriate to the state lands. He added:
Under unitization, ... we would go ahead and unitize
both NANA and state lands out there, so there'd be ...
a joint unit, in which case the work activities
wouldn't have to exclusively occur on state land; it
would have to occur on the unit for the purpose of the
unitization. So I think, when you work through their
situation, they are normally ... where you might
expect someone to be in ... kind of a middle stage of
exploration, and we often form exploration units at
that point in time. Now, [if] the lease is
conventional or nonconventional, it wouldn't matter -
or shallow gas or conventional, areawide.
CHAIR KOHRING opened public testimony.
Number 1965
PATRICIA MACK informed members that she and her husband live in
the Mat-Su area. Saying she wished [the legislature] would be
as creative with that area's residential problems [relating to
shallow gas leases] as with the Red Dog mine, she remarked, "I
thought that was a very clean-sounding deal." She understands
units, she said, but also understands that unitization pulls in
people who are unwilling to participate in the plan, in what is
called "forced pooling." Responding to remarks from Mr. Myers,
she clarified that she was referring not to exploration, but to
the decision to actually start producing. Noting that the Mat-
Su situation involves small parcels of land, since perhaps 800
of the properties are one to five acres in size, she said more
than 12,000 families are being affected.
MR. MYERS answered that unitization occurs with respect to the
subsurface owner, and the owner of the subsurface mineral rights
generally won't be "force pooled" into that situation. He
added, "If you did, you would not be forced ... into the unit if
the state did not own the subsurface rights."
MS. MACK expressed concern, however, that "under your oil and
gas rules, you do have that clause."
MR. MYERS affirmed that, saying it protects adjoining
landowners. He explained:
In other words, if they drill a well within close
proximity to your land, it's just possible the gas
they remove from the ground may be ... from your land,
even if the well bore isn't on their land. You are
not compensated for that unless you're part of the
unit. ...
It's also designed to protect your rights, so that you
have ability to petition us for - in some cases,
petition the Alaska Oil and Gas Conservation
Commission [AOGCC] - so that ... your production of
the gas ... from your subsurface rights are protected.
So it's actually a process to protect you. ... If you
don't care, no one's going to force ... your
subsurface acreage into that unit.
Number 1673
MS. MACK asked, "So, I wouldn't have to have a well on my
property if I didn't want it."
MR. MYERS replied no and said it's the opposite: "If they drill
near your land, you can actually get credit and get royalties
off your land."
MS. MACK turned to another concern. She mentioned the DNR
commissioner's fiscal year 2001 budget and said:
You're using what's called the common law subsurface
access ... to minerals. But under the Alaska
constitution, we were provided rights for settlement,
and so we have equal rights to the surface; you have
rights to your subsurface. But the Supreme Court has
done several rulings; one was about 20 years ago
regarding coal and not coal bed methane, but they
stated that the state did not need to take every drop
out from under somebody's property. ...
The other statement that they made recently on the
East Coast, as far as ... Pennsylvania, ... they ruled
that the access to the property, based on the fact
that the state had watched the property being
developed and had not set aside space for their
development, ... was unreasonable and unnecessary.
And so that was what my questions were. In densely
populated areas like I live in, just the noise and the
racket and the disturbance is just going to be a
nightmare.
Number 1582
MR. MYERS responded that one of [DNR's] purposes with the
process in the valley is to work through these issues and work
on specific noise-abatement standards, setbacks, and so forth.
He indicated the department has heard loud and clear that people
there want more certainty on "the regulatory framework." From
public meetings there, he reported, a lot of information has
been received that is being collated. He continued:
I think ... some of your concerns will be taken care
of in that regulatory process. In addition, the
leases have stipulations and mitigation measures that
give DNR discretion to do that ... on our state lands.
We do not have that same discretion on non-state
lands, however. So if the subsurface owner is other
than the state, ... we don't have that same level of
protection. But on state lands, we have that process,
and ... we're aware of the issues.
I think that's one of the things that's still
recognized is, there are areas ... where if the state,
rather than applicant, is driving the process, we can
better customize what we lease and what we allow
surface occupancy for facilities on than we can in an
applicant-driven process.
Number 1505
MS. MACK expressed disappointment in this whole process, having
been to all those meetings; said she has never been more
disappointed in a group of [legislators] in her life; and noted
how horrible it has been to have a [shallow gas] well put in her
backyard. She continued:
I grew up in this state, and I was here when it became
a state. And they gave us our land here because ...
they wrote our constitution the way that they did
based on settlement and resources, because we were
being taken over by monopolies. ... And that's exactly
what you've created here, ... a monster you can't
control.
CHAIR KOHRING offered assurance to Ms. Mack that the committee
was trying to address her concerns. He said the constitution
also created the situation that allows the state to develop on
someone's land, although there are rigorous rules and hoops to
jump through. He voiced confidence that DNR will take great
care and use discretion to make sure that issues such as noise,
setbacks, "visual issues," pollution, and so forth are addressed
before permits are issued.
MS. MACK suggested the need to look at the constitution more
closely and said people will go to court when someone just shows
up in their yards [as happened with the shallow gas leases].
Number 1377
ROBERTA HIGHLAND, Kachemak Bay Property Owners Association,
Homer, said she appreciates and supports the intention of the
bill, which seems to attempt to correct bad legislation, HB 394
and HB 69, that has turned many people's lives upside down.
However, she said, HB 531 and SB 312 [the companion bill in the
Senate] do nothing to correct the problem of already leased land
in some very inappropriate areas including Homer's water
reservoir, a public school, churches, heavily populated areas,
and popular local ski trails. Noting how dearly people can pay
for bad legislation, Ms. Highland expressed concern that this
current legislation doesn't address the many thousands of acres
leased against the will of a lot of people. Asking that this be
passed, she also asked legislators to continue to strive to fix
the ongoing problems with the leased properties. She mentioned
a buy-back or land trade as two options.
CHAIR KOHRING asked whether anyone else wished to testify. He
then closed public testimony.
Number 1228
REPRESENTATIVE ROKEBERG requested clarification from Mr. Myers
about forced pooling. He cited an example of what he called
de facto forced pooling in Oklahoma.
MR. MYERS explained:
We effectively have the right of forced pooling, but
the cases it's used is ... the opposite of what ...
the public was testifying on. Typically what happens
is, it depends on the stage of a unit. Early in the
life of the unit, 'cause we don't know the size, the
shape, the accumulation, we have an exploration
prospect under a lot of unitization cases. ... We look
at the geology ... underneath it, and if it's
reasonable that there's a party involved ... whose
subsurface rights seem to be incorporated into that
prospect, that's in our ... best guess, we will
require the applicant for the unit to notify that
party and invite them into the unit at reasonable
terms.
They do not have to accept that at that stage. ...
Right there, ... the unit's operator or the applicant
is required to notify them and give them opportunity.
They're not required to accept, and that's it.
The next stage is, if you actually have production,
you form what's called a participating area. And
here's where Alaska law kind of has ... two branches.
... Either DNR deals with it -- a participating area
... is the surface area underlying the area that's
known to be underlain by the hydrocarbons, and it's
reasonably estimated to be able to produce in paying
quantities; so it's a commercial test that has to be
estimated, and it has to be known to be part of the
pool. But it's included in the smaller part of the
unit; it's actually allocated production that you're
talking about.
Now, a parallel process goes on with AOGCC where,
instead of looking at (indisc.), they use -- as in
Oklahoma, they use what's called a pool, and they will
define the outlines of that pool. ... If you picture
the pool pretty simplistically as ... a big circle and
you have a component of that circle whose landowner
chooses not to join that unit, we will not force
someone to join that unit. However, ... the operator
will have to accord them the opportunity.
Now, ... the owner has state subsurface rights that
are being developed; they're primary rights. If they
don't petition us, we won't do anything. If they're
state's rights, we will probably make the argument for
forced pooling ... so that they gets its royalty
share. So the cases she was talking about, ... I
believe, the state owns either the surface or the
subsurface, and the applicant - the person on the land
- didn't want to see ... any production or didn't care
if they got any royalties allocated to their
production. We're not going to force a person in that
position to join the unit.
Number 0953
MR. MYERS continued:
There are other protections, though. If they drill
within a certain distance of that person's lease line,
with unleased acreage, AOGCC, if it's a certain
distance, has no authority. But if it's closer than
that distance -- and [typically], like an oil well,
for example, it's 500 feet. If they drill within 500
feet of the lease line, they must get an exception.
To get that exception, they generally have to hold a
public hearing, in which case that person can complain
about it or not. If that person doesn't complain
about it, they will grant the exception and they will
allow that person to be drained. ...
Generally, it's in that person's - who owns the
subsurface - interest to be accredited production from
their acreage, and there's a vehicle to get that. And
there's forced unitization or forced pooling allowed
to get to that point. If that person owns the
subsurface and chooses to be drained, essentially, I
don't think the state ... would "force pool" or
interfere. Does that make sense?
Number 0875
REPRESENTATIVE ROKEBERG asked, then, whether someone can
basically opt out of forced pooling under the state's statutes.
MR. MYERS affirmed that and said the opportunity would be there
if the person elected not to do it and the state didn't "have a
fight." He added, "It's a correlative-rights issue, where the
party chooses ... not to exercise their correlative rights."
Number 0839
REPRESENTATIVE ROKEBERG asked whether it's the geological
formation or the unit that will be the participant. He also
inquired whether it's usually AOGCC that looks at the pool and
determines the allocation of participatory rights, for example.
MR. MYERS characterized it as a "black hole" that has never been
cleaned up and said there are two parallel paths. He explained:
Under DNR's authority, we use participating areas,
which basically are the outline of the commercial part
of the reservoir, if you think about that, the surface
expression of that. ... We use "participating area"
for that surface expression of the reservoir or pool;
AOGCC uses the term "pool" for basically ... the same
reason. One of the differences is, DNR typically is a
royalty owner, but we still have a responsibility to
... prevent physical and economic waste. AOGCC has
similar statutes under their pool standard, which is a
slightly different but very similar standard. Of
course, they're not representing the state ... as
royalty owner. ...
So the process is roughly parallel. ... Within a unit
... if you form a PA [participating area], there's
often a parallel process of forming a pool. And
generally the pools and the PAs are identical or
nearly identical, and often we hold joint meetings
with the applicant to do that. ... The process is
driven by ... the formation of the unit, and the unit
is typically represented by the unit operator,
although through the process, anybody affected by the
unit is publicly noticed and they have ... the right
to petition us or a right to a hearing, typically.
And they have a similar right under AOGCC.
MR. MYERS acknowledged it's confusing, and reiterated that
they're almost parallel but slightly different processes.
Number 0675
REPRESENTATIVE ROKEBERG reported that at the recent Energy
Council meetings a presentation addressed what different states
have for damages to surface rights; he recalled that North
Dakota and Oklahoma have some of the more stringent
requirements. He asked whether Alaska has a statutory "damage-
recovery claim" or how it is dealt with otherwise.
MR. MYERS replied:
It depends on who owns the subsurface. Under state
subsurface, you are clearly entitled to damages
statutorily, but those damages ... are determined by
the courts. ... So the state has not quantified as to
what those damages are, but there's a ... history of
case law to sort of determine that. ... If the surface
owner and the subsurface owner are different and they
cannot reach a surface-access agreement, then DNR
holds a bond hearing to protect the surface owner and
that bond is held. And then if damages are claimed,
it goes to court, and the damages are protected and
paid for out of the bond. ... And that is statutorily
based.
There is no statutory base on non-state land. So if
it's private subsurface, with a different private
surface owner, there is nowhere in state statute; it's
generally based on ... court cases and case law. But
statutorily, they're not entitled to damages under
current state law.
REPRESENTATIVE ROKEBERG noted that in the Mat-Su area, for
example, there could be different types of subsurface ownership;
therefore, the surface estate may or may not be protected under
the statutory scheme here and the surface owner could only rely
on common law. He asked whether that's correct.
MR. MYERS affirmed that.
CHAIR KOHRING noted that time was running short for the meeting
and announced that the bill would be held over. He pointed out
that a possible amendment had been circulated.
Number 0333
REPRESENTATIVE CRAWFORD asked how this would work in the rare
instances when landowners have owned their land before statehood
and thus hold subsurface as well as surface rights.
MR. MYERS explained:
When they come to form a unit in royalty state land,
... if their land was appropriate to be in the unit,
as determined by DNR, we would require the applicant
to ... notify them and offer them the chance to join
the unit. If they refused to join the unit at that
point in time and later exploration demonstrated the
actual productive area, and they were defined as a
participating area - included their land - again, they
would ... have to be offered a chance to join the unit
to get production.
If they chose not to join the unit at that point in
time, then if wells are drilled within a certain
distance, ... they would have the opportunity before
AOGCC to disallow that drilling, basically, within a
full (indisc.) of their line, to prevent ... being
drained. So there's some protection there they would
have.
But, generally, AOGCC would make a ruling. ... It's
like, again, on oil: if ... someone proposed a well
within 500 feet, AOGCC would look at it and say, "You
have to get an exception." The exception will require
... that nearby landowner ... to say, "I don't want
that oil because it's going to drain my property."
And that would probably give AOGCC the reason not to
approve the exception, and they'd have to set the well
back further, at a distance generally designed in the
statute and regulation to assure that they can't be
drained.
... There's multiple levels of protection in there to
protect ... that person. But, again, through our
process of the participating area, it would require
that they be offered the opportunity ... to be part of
that ... unit and get allocated a percentage of
production, whether or not the well is on their land,
as long as they're affected or effectively being
drained. So there's multiple levels, actually, of
protection to get them into the unit. If they choose,
again, as the (indisc.) not to participate, I don't
think that we would force them -- if a company wants
you to accept it for AOGCC and ... it wasn't a
protest, AOGCC ... may well grant that.
MR. MYERS concluded by saying there is a possibility that non-
unitized acreage can be within a participating area, but he
didn't recall any cases where that happened. He added that it's
always in the applicants' interest to get their royalty share.
CHAIR KOHRING thanked participants. [HB 531 was held over.]
ADJOURNMENT
TAPE 04-10, SIDE A
Number 0006
There being no further business before the committee, the House
Special Committee on Oil and Gas meeting was adjourned at
5:00 p.m.
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