Legislature(2003 - 2004)
03/26/2004 03:40 PM Senate RES
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
SB 312-CONVENTIONAL & NONCONVENTIONAL GAS LEASES
CHAIR SCOTT OGAN announced SB 312 to be up for consideration. He
recapped that the committee had a conceptual amendment that
wasn't adopted and he intended to finish that discussion and
work on getting a CS to consider.
SENATOR ELTON noted that he was having a difficult time dealing
with the conceptual amendment and the bill of rights that was
drafted in non-bill form and asked Legislative Legal Services to
draft an amendment incorporating most of its elements. He wasn't
going to move the amendment today, but wanted to make sure
everybody saw it. An accompanying memo explains the different
elements that didn't go as far as the drafters of the property
owners' bill of rights wanted it to go, but Legislative Legal
Services pointed out (6)(i) and constitutional problems.
CHAIR OGAN stated for the record that on two occasions two
separate individuals who are associated with leadership of a
group in the Mat-Su Valley threatened him.
One said you pass this through both bodies and we'll
call off the dogs - and they're referring to my recall
- and the other person said that the recall would go
away in a heartbeat if I just do this legislation for
them.
I just want to state very clearly for the record that
this committee is always about good state policy and I
think, for the most part, with some maybe minor
exceptions, I think to a great degree I want to really
commend the members of this committee that when we
walk in this door, I think most of our partisan
differences get left behind. I really salute the
minority for working with me. I try to work with the
minority as well as all majority committee members. I
will always do what I believe is the best thing
policy-wise for the state regardless of the heat I
get.
SENATOR ELTON added:
Because of those remarks, I think it's important that
I note for the record that none of those people have
talked to my office. I had the amendment drafted, not
because of any representations that were made to me by
anybody in the Valley, but simply because I was having
a very difficult time dealing with how you take
something that is in non-legal form and incorporate it
conceptually. For me, I needed to have something in
writing in amendment form. That's the reason I have
brought the amendment to this table, not for any other
purpose such as the purposes that you suggested that
some people have mentioned to you.
CHAIR OGAN said he didn't mean to infer that Senator Elton had
the amendment drafted for any other reason. "I believe you have
been very honorable in this committee as all the other members
have...."
MR. KEN BOYD, Chairman, Land Exploration and Operations
Committee, Alaska Oil and Gas Association (AOGA), said it is a
private non-profit trade association whose 19 member companies
represent the majority of oil and gas operations in this state.
AOGA is on record supporting the concept of a best
interest finding for oil and gas leasing and
exploration licensing as contained in SB 312. While we
believe there are adequate safeguards for shallow gas
leasing under existing law, we also believe a higher
level of public policy is achieved by adopting a time-
tested best interest finding approach for dispositions
of state land. A best interest finding is used in all
other oil and gas programs in Alaska and works well
for both the members of the public and the private
companies interested in investing in Alaska.
The best interest findings process allows the state to
incorporate all public input into a single document
that will address all concerns in a comprehensive
manner. We've not had the opportunity to thoroughly
review what has been referred to as the Alaska
Property Owners' Bill of Rights. However, a first and
very quick reading indicates both legal challenges and
perhaps some misunderstandings - for instance, about
the extent of current protection for property owners,
the extent of state laws, local laws, regulations and
mitigation measures that already protect Alaska's air,
water, fish and wildlife resources, and lastly, the
historic benefits to all the citizens of the state
when the state owns the subsurface of its selected
lands.
As many of you, I presume all of you, know [split-
estate] is one of the state issues that is common
throughout the western United States. Indeed, there
are more than 100 years of case law laying out the
rights of both the surface and subsurface owners. One
estate occurs when one party owns the surface, which
is usually a private citizen or a number of private
citizens and one other party owns the subsurface. The
subsurface owner is often the federal government or
the state, but in Alaska it can also be a Native
Regional Corporation. The challenge always is to
protect the rights of access to the subsurface while
protecting the rights of owners of the surface. In
fact, in most cases, agreement has been reached
between the surface and subsurface owners.
The existing shallow gas-leasing program was crafted
with bi-partisan support during a democratic
administration. This support was justified since this
program has the potential to bring new sources of
clean, efficient energy to the state as well as
providing jobs and taxes for local economies. It can
be done in an environmentally safe manner under
current law and can be done in a manner that respects
the rights of both private property owners and the
lessee of the subsurface. In fact, the Department of
Natural Resources has conducted extensive workshops
and discussions [indisc.] the coalbed methane (CBM)
shallow gas development in the Mat-Su Valley and in
Homer. We are hopeful that further discussion of these
issues will facilitate a better understanding of the
environmental and property right protections already
in place in a historical success of split estate
development. Thanks for your time, Mr. Chairman and
members of the committee. AOGA looks forward to this
being part of the informed decision-making on this
subject and that concludes my testimony.
CHAIR OGAN asked him for his background in the oil and gas
industry and in the public sector.
MR. BOYD responded that he was deputy director of the Division
of Oil and Gas from 1990 - 1995 and was director of it from 1995
- 2001. In the private sector, he was an exploration
geophysicist for 20 years.
CHAIR OGAN said the property owner consent provision of the
conceptual amendment basically says that the property owner can
just say no and the state must also provide a legal fund for
them to hire legal counsel. They must also be protected from
retaliatory lawsuits by developers.
CHAIR OGAN asked:
What effect has it on resource development if surface
owners could basically say no? Isn't that like just a
transfer of an asset that they didn't buy - the
subsurface - into their control?
MR. BOYD replied:
Well, in my opinion, Mr. Chairman, I don't think you
can make good public policy by demands raised by small
groups of citizens, no matter how well-meaning they
may be. If I had to base decisions based on every
document that came across my desk when I was director,
the state would be a hodge-podge of conflicting
opinions and conflicting rules and nobody would
benefit from that. That's why AOGA and me, personally,
support the notion of a best interest finding.
I believe, Mr. Chairman, when I look at the bill of
rights, that we can agree on numbers 4 and 10. Let's
have competitive bidding and your bill does that. And
in order to have competitive bidding, then we need to
have a best interest finding. Fine, let's do that,
too. Then let's take the other numbers and let the
state go through its process, which they have already
begun, in a sense. I mean they've already had a bunch
of hearings in a lot of different affected communities
- and take these issues one by one, decide what's in
the best interest of the state and put it into a
legally defensible document and then you have
something you can work with instead of a hodge-podge
of conflicting notions.
CHAIR OGAN asked if he wanted to comment on the buyback
provisions.
MR. BOYD replied that he probably shouldn't comment, but he
personally has listened to the director of the Division of Oil
and Gas, Mark Myers', testimony and agreed with him that a
buyback would come at a cost to the state. He also heard
something about the state not getting its full value if it buys
back leases for more than it paid for them and refuted, "That's
nonsense."
I mean, what would you value Prudhoe Bay at then? What
should we have leased Prudhoe Bay at - $150 billion -
and had no takers? Companies have to take risks and
they put money on the table to take that risk. I think
the state, you know, owes them something for that risk
and we collect our 12.5 percent share. So, I can't
talk to a number, Mr. Chairman. I don't know what the
number is. Whatever Mark says, I would support it
assuming that he has the backup and I'm sure that he
does. So, it will cost him more than just saying, gee,
you came to a lease-sale; here's your money back.
Here, take your leases. I don't think that's fair. I
don't think it's right. I think it's a lousy and
terrible precedent for the state.
CHAIR OGAN asked if a buyback had happened in the past - in
lower Cook Inlet.
MR. BOYD replied that happened a long time ago, but he noted
that the Legislature made Kachemak Bay off limits to gas leasing
and it remains off limits to this day. The only buyback he is
familiar with is the federal sale in Bristol Bay that was held
about 15 years ago when millions and millions of dollars had to
be paid back to the companies.
SENATOR WAGONER remembered a Chevron lease buyback in 1972.
SENATOR ELTON recollected that happened in the Hammond
administration in 1974.
CHAIR OGAN explained that the Property Owners' Bill of Rights
advocates that all 74 leases be bought back and asked what would
happen if the state did that. Also, a program on Channel 2
indicated the Agrium Plant might pull out of Cook Inlet because
of gas supply issues.
MR. BOYD replied he wasn't sure how Agrium's decision related to
this issue, but a buyback just says the state can't be trusted.
A lease sale is more than just expending money. A
lease sale, I mean, people don't even want you to know
where they are going to bid. And when they have bid,
of course, they've shown their cards, basically.
They've said we're willing to pay this many dollars
for these acres. When that's done, that goes on a map
that becomes a public document and everybody gets to
see it - all their competitors. I mean, you've really
bared your soul. And then to say oh well, thank you
very much, here's your bid back; we already know your
strategy. What will you do in the future then? Who's
going to trust anybody to do something like that? I
think it creates a very bad precedent for the state,
Mr. Chairman, and if we're talking about Cook Inlet
and the Mat-Su Valley, and I'll just speak very
frankly, I think the stakes in terms of dollars are
relatively low. But if you take the same situation to
the Slope, and I have no reason to believe that if you
do it here, you won't do it there, then I think the
stakes become enormously high.
CHAIR OGAN said he suspected a buyback would put the state in a
bit of a tight position. He invited Mr. Norman to comment.
MR. JOHN NORMAN, Commissioner, Alaska Oil and Gas Conservation
Commission (AOGCC), said he had practiced as a lawyer for 33
years and would address the Property Owner's Bill of Rights.
In section 8, which addresses water protection, there
are four things that are sought to be accomplished as
I read it. One of them is to prohibit production of
coalbed methane from aquifers. A second is to prohibit
the use of toxic hydraulic fracturing fluids and the
third is to require the deep injection of liquids and
waste produced in conjunction with coalbed methane. A
fourth is to insure that there is no hydrologic
connection - no communication between injection zones
and fresh water sources. So, looking at those, all of
these, I think are attainable goals and many of them,
in fact, are consistent with existing law right now.
A prohibition on production from aquifers used as a
source of existing or future water perhaps is not good
public policy if it were to find its way into law as a
blanket prohibition. In some areas, this coalbed
methane may be very welcome as the first local fuel
that many communities have had and so the commission
would suggest that if we were to rule out production
from what we refer to as a same source aquifer, that
there be an exception for an operator to petition the
AOGCC and the commission to make a finding that
production would not in any way degrade the aquifer as
a source of fresh water. I think we are very confident
that we could provide a forum and offer a fair hearing
and reach a determination and, if it looked like it
would degrade the aquifer, then the exception
requested would not be granted, but we would avoid
having Alaska paint itself into a corner, because very
often aquifers cover large areas and it would not be
advisable to rule that out.
As to the second thing, prohibiting the use of toxic
hydraulic fracturing fluids - we're certainly
supportive of that in this area. If this does make its
way into an actual amendment, then we would perhaps
have some fine-tuning on the wording to offer, but we
see that as doable.
The third objective in section 8 is to require deep
underground injection of the liquids and waste
produced and we would, here, suggest that it would not
be advisable, again, to make a blanket rule that would
absolutely require all produced water, for example, to
be reinjected, that there are certainly occasions and
examples where the water coming out is of very good
quality and might be put to a beneficial use on the
surface. But, insofar as injection is the choice of
the operator and the land owner and is the sensible
thing to do, then we think it's very workable that
that requirement would be imposed - to be injected
deeply, the idea being that it would be well below any
aquifer that's used as a source of fresh water.
The term 'existing or future water wells' is used and,
of course, future water wells is open-ended and we
might suggest 'existing or which could reasonably be
expected as a source of future fresh water' be
substituted.
Finally, a fourth objective is insure no hydrological
connection between the waste water injection zones and
present and future drinking water sources. And here,
we have no problem with that; in fact, we do that
already and have done that and the statutory authority
for that already exists in AS 31.050.30, (d)(3).
In summary, on section 8, we think there are some
goals there that if the committee did want to move
this forward, they're attainable and we'd be happy to
work with you to fine-tune the wording of the bill to
make sure it's workable.
I guess working backwards in numerical order, then,
the next section 6 is local control and in principle,
the AOGCC has no opposition to providing for a measure
of local control. We would want to make sure that
there is coordination with the AOGCC. Our primary area
of jurisdiction is subsurface regulatory activity and
also, we would want to make sure that the local
control did not result in waste of a resource.
CHAIR OGAN asked Mr. Norman if he was a geologist by profession
and to touch on the water protection issues.
MR. NORMAN replied that he has worked in the industry, but the
other AOGCC commissioner, Dan Seamount, is a geologist and Mr.
Bob Crandall is one of AOGCC's senior geologists.
CHAIR OGAN asked, "To your knowledge, has any toxic fluid been
used for hydraulic fracturing for coalbed methane in Alaska?"
MR. BOB CRANDALL, AOGCC Petroleum Geologist, replied as far as
he knows toxic fluids haven't been used for hydraulic
fracturing.
There has been a treatment to the well prior to
fracturing called an acid wash where a relatively
small volume of dilute hydrochloric acid is used to
clear the perforations in the well prior to injecting
the hydraulic fracturing fluid.
CHAIR OGAN asked if acid reacts to the formation by neutralizing
it into CO2, salt and water.
MR. CRANDALL replied that's true, but he doesn't see that as a
significant toxic component.
CHAIR OGAN asked if it worked something like baking soda
neutralizing acid.
MR. CRANDALL replied basically that's right.
CHAIR OGAN stated for the record that a libelous article was
printed by a couple of local papers that talked about how an
operator used hydrochloric acid gas in Texas wells to enhance
production and it somehow leaked out and killed a lot of people.
He thought the article's author was mistakenly calling hydrogen
sulphide (H2S) hydrochloric acid gas. He asked Mr. Crandall to
clarify that.
MR. CRANDALL answered:
The occurrence of H2S is in a Tyonek formation, which
has been a target for coalbed methane in the Mat-Su
Valley. It has only been encountered in undetectable
levels in the wells that have been drilled so far.
There is no history of H2S in the Mat-Su Valley based
on previous drilling. In future drilling, there will
be H2S detectors and that, of course, even though it
hasn't been observed in the past, will always be
treated by us as a potential threat. I think you're
correct.
As far as the reference in the article that you
referred to as a gas, that's something that I'm really
not aware of. Sometimes large concentrations of H2S is
present in natural gas. That happens frequently, for
instance, in the Canadian Rockies, and that's referred
to typically in the industry as sour gas.
CHAIR OGAN interrupted to say there is some of that in Texas.
MR. CRANDALL agreed and added, "Acid gas, I think, is a
misstatement by someone."
TAPE 04-30, SIDE B
4:30
CHAIR OGAN said the fear in some places is that diesel is used
to "frac," but all the petroleum engineers he talked to say that
diesel is commonly used for oil wells, because it has an oil
base; it is rarely used, if ever, for coalbed methane. He asked
what the likelihood was for other toxic fluids being used for
fracturing.
MR. CRANDALL replied that petroleum-based frac fluids are not
used in Alaska for coalbed methane. It is not commonly used in
any coalbed methane operations.
In fact, there is a memorandum of understanding (MOU)
between the two largest commercial well fracing
companies in the EPA that they will not use
hydrocarbon-based frac fluids in USDWs, which is the
EPA term for water that has less than 10,000 parts per
million total dissolved solids. There is this
recognition by the industry that by and large, diesel-
based frac fluids are inappropriate for coalbed
methane.
CHAIR OGAN asked if the theory is that you can use it in water
that's already polluted, but you can't use it in anything fresh.
MR. CRANDALL replied that the underground injection control is
in the Safe Drinking Water Act. He thought the EPA established
the total dissolved solids threshold at 10,000 parts per million
because that represents the type of water that's good enough to
be treated for human consumption.
CHAIR OGAN moved on to another issue.
One of the criticisms has been that there isn't
specific statutory requirements to inject water. My
understanding is that, while it's not addressed
specifically in the statutes, it is required to inject
the water if you get a certain amount of dissolved
solids and I don't know if that's 10,000 parts per
million or what. So, there is a requirement to inject
it unless you're getting drinking water quality and
then you can get an NPDS permit to discharge on the
surface along with DEC and Fish and Game and a few
other things. Could you clarify what is required now
if it's produced water.
MR. NORMAN stepped in and said:
It's generally exactly as you stated it, that if it is
of drinking water quality, it can be disposed of on
the surface. Otherwise, it's reinjected into wells and
those wells, the State of Alaska has been given, and
specifically this agency, the AOGCC, primacy for
oversight over these labeled class 2 wells. The water
is injected and those wells are very carefully
monitored and it's the responsibility and, I believe,
carried out very well, to insure that when water is
reinjected, it absolutely will not pollute fresh water
in any way.
CHAIR OGAN said another requirement is to reinject all liquids
and wastes including ground-up rock from drilling the hole.
MR. NORMAN agreed.
CHAIR OGAN said if this requirement was drafted literally, it
would require that the ground-up rock be reinjected and coalbed
methane wells don't have annular rings [the pad area that
remains after a well hole is drilled through it] like the deep-
hole, high-pressure wells on the North Slope and Cook Inlet. He
asked if it was technically possible to reinject ground-up rock
into a well.
MR. CRANDALL answered:
There is a very large-scale slurry injection project
up on the North Slope where exactly that happens -
where old reserved beds are ground-up very small and,
then, injected through the well into the subsurface.
CHAIR OGAN said a literal interpretation of that is, then, that
a coalbed methane operation, no matter where it was located,
would have to get one of those wells on-line and grind up rock
in a slurry and reinject it.
MR. CRANDALL responded that's how he reads this and that is not
a practical requirement.
CHAIR OGAN asked what class well that would be.
MR. CRANDALL replied that is labeled a class 2 injection well. A
class 1 is for hazardous sorts of waste.
CHAIR OGAN asked what a class 2 well costs to build.
MR. CRANDALL replied that it could be very expensive. It would
depend on the stratography, the sequence of rocks in an area and
a number of other things. His experience indicates having a
large number of class 2 disposal wells wouldn't be practical.
CHAIR OGAN asked if the life of the well would be fairly short
since the slurry would be pumped into it.
MR. CRANDALL replied, again, that would depend on the nature of
the formations. "Wells on the Slope actually perform quite
well."
CHAIR OGAN asked what other items were under the AOGCC purview.
MR. NORMAN briefed the committee that the commission sees local
control as an attainable goal and encouraged:
... a close coordination with the AOGCC and other
regulatory agencies so we don't bump into each other
and we get into questions of conflicts with state law
and we would also encourage that coordination and try
to minimize, eliminate and prevent waste - that is the
waste of a valuable resource. We think there are ways
to do that and I think, on the subject of local
control, I'll just leave it there and see if there are
any questions.
CHAIR OGAN said the Mat-Su Borough is proposing an ordinance
that would require well spacing no closer than 360 acres or one
per section. What would happen if that passed and the commission
determined that well spacing that far apart would create waste?
Is that a local control override?
MR. NORMAN replied that could happen right now.
I'm assuming the 360 is actually intended to be 320.
Half of a 640-acre section would be 320.... There is
the potential for conflict. I think what needs to be
clarified is our regulation of spacing and the
professional staff here normally thinks in terms of
subsurface spacing patterns.... It's a pretty
fundamental distinction. Whereas, I think, probably
the borough, and the proponents of the bill of rights,
are more concerned with surface spacing and
facilities. That's a first distinction that has to be
kept in mind and sorted through in properly drafting
any legislation. But it is possible that if the
spacing were such depending upon the host reservoir,
it could result in waste.
An operator would probably try to drill as efficiently
as they could. The nature of the industry has been to
have a smaller and smaller footprint and there have
been magnificent strides in the area of directional
drilling and production from lateral wells. So, there
are an awful lot of technological innovations that
right now even in a few years may give operators the
ability to reach out. Coalbed methane is slightly
different, but the area where we would see it might
bump in - that's one potential area - is on the
spacing of wells.
CHAIR OGAN remembered Jack Chenoweth's (Legislative Legal
Services) testimony that state authority is already implied in
the statutes and constitution to override local control in
situations like this. He asked if directional drilling is
feasible with coalbed methane operations.
MR. NORMAN replied that Mr. Chenoweth referred to the doctrine
of preemption, which states if a superior government entity - in
this case, the State of Alaska - has a body of law in place for
a purpose for the benefit of all the citizens of the state, then
a lesser (a more confined geographic area) governmental entity
generally should not be allowed to interfere with that larger
state purpose.
I think, probably, there would be a way to work with
the borough to enact an ordinance to insure that waste
would not take place.
On directional drilling, of course, on conventional
[vertical] wells in production there have been some
truly mind-boggling innovations in that area. In so
far as coalbed methane and directional drilling is
concerned, my understanding...is that probably we will
see those, but I don't think we have quite the
directional drilling capability now in the area of
coalbed methane that we see, for example, on the North
Slope, where you can have these very small footprints
that reach out or even in Cook Inlet or other areas
where you're drilling for deeper oil or conventional
gas.
MR. NORMAN asked Mr. Seamount, with his experience, if he wanted
to comment on the ability for directional drilling with coalbed
methane development.
MR. DAN SEAMOUNT, AOGCC Commissioner, added that incredible
drilling patterns have been made from one mother bore in some
areas of the country. But, the geology of the Mat-Su area has up
to 24 different coal seams and he doubted that technology was
ready for areas like that at this time. He elaborated that
economic production has already happened from a conventional
type well bore before technological experimentation has taken
place. Actually, very economic producing wells have happened
through drilling patterns that look like herring-bones and
feathers.
MR. NORMAN concluded that the last section of the proposed bill
of rights that would interface with the powers and duties of the
commission is section 5, baseline studies.
Right now, we don't think it's workable and some
suggestions we would have is that rather than putting
the obligation on the state to measure the baseline,
that that obligation be placed upon an operator and
that would be just a part of the development project.
Secondly, we would think that that type of baseline
information could be required prior to commencement of
commercial production, because a lot of the wells
drilled will not involve any type of commercial
production. So, to avoid a lot of work that may not be
useful at all, we would recommend that it be tied to
commencement of commercial production and that the
sampling of wells involve a radius of about a quarter
mile around each producing well. There are different
ways to look at that, but if you think in terms of a
quarter mile radius around a well, that's a huge
volume of potential water under there and that
generally is a distance that the AOGCC works with when
we administer the Safe Drinking Water Act, for
example.
The request in here for a monitoring program on
methane seepage - we don't really think it's practical
and that it would really yield a lot of useful
information. That is, it tends to be somewhat sporadic
and, if you try to draw scientific conclusions from
some sort of a broad areawide sniffing of methane, it
would not be useful and so, should this make its way
in to law, we would recommend more that that focus be
upon monitoring wells and sampling for methane and
that is the most practical way to do this.
The proposal here in section 5 talks about a
possibility of an operation causing contamination
within a well and an allocation of the burden of
proof. I don't know that we have an opinion on the
burden of proof. I think you could argue that one
either way. An operator probably would be in
possession of the best information, but on the other
hand, a shifting of the burden of proof like this is
counter, generally, to what are considered general
principles of due process of law. But in any event, it
raises a question, then: would a property owner file
presumably in the Superior Court and, if so, it does
raise a specter of a number of possible filings. And
we think right now that the AOGCC, because of our
ongoing responsibilities to monitor from cradle to
grave, if you will, every well drilled, that this
agency would be in a position to take testimony from
citizens. And, after all, that's our ultimate client -
the citizens of the State of Alaska - and we could
serve as a forum to receive such complaints,
adjudicate them. Then, there would always be an appeal
right that any private property owner would have into
the court system. My thought is that that would be
preferable to allowing these to just be thrown into
the court system and then requiring individual
property owners to engage their hydrologists and the
company's. You might over a period of time get
inconsistent results. So, that is just a suggestion if
section 5 were to find its way in. I'll stop here, Mr.
Chairman, and we can answer questions on any of the
points that we've touched on.
CHAIR OGAN said that section 5 requires a baseline water quality
and quantity study on all surface and well waters that may be
affected and asked if that means everything in the lease would
be tested.
MR. NORMAN replied that he read the language to be even broader
than that.
It's not necessarily confined to the lease. As a
practical matter, this zone of influence - we're
suggesting a quarter mile - may or may not equate with
the lease.... It would make a lot more sense and be a
lot more efficient if it were tied to a producing
well. And once there was a producing well, prior to
production, they would have to secure this baseline
information and make that an operator responsibility
as a condition to commencement of commercial
production. I think we're set up to monitor that and
keep an eye on it and if the operations are on state
lands, certainly the State Division of Oil and Gas
could likewise do so.
CHAIR OGAN said that Article 8, Section 9, of the State
Constitution currently has a property owner's bill of rights
providing protection for surface owners in terms of trespass for
people who are unduly deprived of use of their property and
damages. He asked what would happen if a coalbed methane well
operation affects someone's well water in a negative way.
MR. NORMAN replied:
We think the likelihood of that occurring is not great
in the experience in other areas that we're familiar
with. That is an understandable bit of anxiousness on
the part of property owners, so I don't mean to
disparage that, but the reality of it we don't think
is high. But, if an operation did interfere with the
well and damaged that well, then, I think as an
agency, we would have the grid, the pattern of all the
wells and we could make a determination.
There are a couple of ways in which a well could
theoretically be interfered with. One of them would be
that there might be some methane that might find its
way into the water. Again, we don't think that would
occur given the constraints and requirements imposed
on drilling. But if it did, it's something that we are
certainly able to watch and to make a fair
determination on. I think we could do it in an
efficient way and a fair way to Alaskans.
The second part of that would be - let's say - that a
well flowed at a certain rate, so many gallons per
minute or per hour, and at some point, it went dry, in
an extreme example. Then the question is did that
occur because of the operations being conducted by the
coalbed methane operator or did the well simply go dry
and it might have gone dry anyway. Again, I think we
could monitor that and if it was necessary, we could
provide a forum; we have all the tools to issue the
subpoenas, to adjudicate fairly and to enter an order
and then there is always the possibility of judicial
oversight on that. To conclude on that, a property
owner potentially would have a claim for damages if
somehow their well were interfered with in that
unlikely event.
CHAIR OGAN pointed out that the presumption for water quality
in the property owners' bill of rights is:
Within five years after coalbed methane operations on
or around his or her property, there shall be a
presumption that such operations cause diminishment or
pollution and the coalbed methane operator shall carry
the burden of proving otherwise.
CHAIR OGAN called that a refutable presumption.
I personally know people whose wells have gone dry
after earthquakes and personally we don't have too
much of a problem with drought in Alaska, although I
know my well behavior has changed over the years. My
well doesn't produce as much water as it used to.
He thanked the AOGCC members for providing their time and
expertise to the committee. Next he took testimony from the Mat-
Su Valley.
MR. ROBERT HALL, Vice President, Houston Chamber of Commerce,
said Houston has four test wells recently drilled by Evergreen
Resources. In the late 1990s, Alaska's first CBM well was
drilled there by an Australian company.
Overall the experience has been positive. It's a new
industry and we recognize the need for additional
refined state regulations. We'd like to offer some
comments in three areas. One has to do with the
private surface owner property rights - and they vary
from state to state. Alaska doesn't have the strongest
surface property owner rights statute. We recognize
that what you do on private property might have some
impact on the North Slope and in other ways it's a
complicated issue. A couple of ideas - one is that if
the property owner and the subsurface lessee cannot
reach a surface owner agreement, the DNR should only
in essence institute one for them and allow them to
post a bond when there's no reasonable alternative....
Second, if they're allowed on the property, they
should be required to minimize the impact and only
impact the property as much as is reasonably
necessary.
Third, some reasonable compensation for loss of use
and enjoyment. An example is in some states that if
you have a farm and you lose - up here they grow
carrots and potatoes - and if you lose 30% of your
acreage, a couple of acres of farmland to the CBM
thing, you should receive some reasonable
compensation.
MR. HALL said there are a lot of misconceptions about what local
governments can and cannot do and that needs to be clarified. He
said the original purpose of the CBM program in Alaska was to
jump-start the industry, which it has done in the populated
areas of Southcentral, but it still needs to happen in the rural
areas. He suggested offering local governments the option to opt
in or opt out of the program or tailoring it to different
regions.
CHAIR OGAN said he was considering bifurcating the issue by
geology and population to minimize conflicts in highly populated
areas. Energy needs in rural Alaska need to be addressed;
there's just no economy at all in the central area. He admitted
there were some unintended consequences to the original program
and he didn't want to react to those without first thinking the
situation through. He then asked Ms. Kristin Ryan to comment on
the areas her department would have purview over.
MS. KRISTIN RYAN, Director, Division of Environmental Health,
Department of Environmental Conservation (DEC), replied that she
hadn't seen the conceptual amendment, but she could comment
based on testimony she has heard today. She corrected that the
federal legislation that allows the protection of surface water
is not the Safe Drinking Water Act; it's the Clean Water Act,
which determines what levels of certain contaminates can be
discharged to the surface water or into the ground that would
get into the ground water.
That determination is based on the use of the water.
Actually, drinking water usage is not the most
stringent standard - actually, fish habitat is. So,
depending on what the water body that the discharge
could potentially get into is what determines the
standard that has to be met and they vary
significantly based on the use of the water body.
CHAIR OGAN noted that someone stated produced water is required
to be reinjected and was assuming that it wouldn't be drinking
water or fish water quality.
MS. RYAN responded:
The standards could not be broken if the discharge was
to occur, but what could happen - they wouldn't have
to reinject it necessarily. They could treat the water
so that it met the minimum standards. The problem is
that tends to be more expensive than reinjecting it.
So, they choose to reinject, usually.
CHAIR OGAN asked if most of the produced water in Cook Inlet is
discharged into the Inlet after it's treated.
MS. RYAN replied that she wasn't familiar with those leases, but
was focused on the CBM development.
The concept that the rocks and solid material that
would come up in the exploratory phase as the well
developed - similar to our clean water standards. We
would not allow that material to be discharged onto
the surface if it violated any of the state's
standards for that kind of material. Sometimes, that
rock or debris can be low enough in any contaminants
or heavy metals that they may want to use it for
beneficial use - for example, building a road or work
on the pad. So, DEC is not supportive of a blanket
standard that would eliminate that function. The
standard for protection should be what's used to
determine the disposal method of a material.
CHAIR OGAN asked if she supported testing rocks coming out of
the wells.
MS. RYAN replied:
We just propose that there be that flexibility, that
based on the level of contamination determines the
usage of the material. The landfill out in Mat-Su
Valley has been approved to be a recipient of
hazardous waste. So, they may prefer to be the
recipient of the material because they can use it as
fill in their landfill, for example.
CHAIR OGAN remembered that the landfill received federal funding
to install a liner and recalled a press release justifying it
for coalbed methane waste disposal.
MS. RYAN said that is correct.
MR. LARRY OSTROVSKY, Assistant Attorney General, offered to
address any particulars the committee would like.
CHAIR OGAN asked if he agreed with Mr. Chenoweth that the
Property Owners' Bill Of Rights was going to run into
constitutional and statehood compact issues.
MR. OSTROVSKY said he agreed with him.
Giving surface owners a veto over the use of
subsurface mineral estate could be construed as a
partial alienation to surface owners of the state's
ownership of the mineral estate and I think it could
be contrary to the requirements of (6)(i) of the
Statehood Act that requires the state to retain
mineral ownership of lands granted to the state -
subject to leasing the mineral rights for development.
I think it does raise a significant issue.
CHAIR OGAN said he is looking for a way to help his constituents
and asked if a constitutional amendment giving the state the
ability to dispose of the subsurface was feasible and if the
state could sell subsurface estate to a surface owner who was
worried about development or a surface owner who wanted to
develop the subsurface.
MR. OSTROVSKY replied that such an amendment might be possible
if (6)(i) of the Statehood Act was amended first.
SENATOR FRED DYSON asked what issues are involved if the state,
as owner of the subsurface, declines to make available for lease
an area that promises to be rich in subsurface resources.
MR. OSTROVSKY replied:
Not every acre of state subsurface is open for lease.
I mean, the state does areawide plans and designates
certain areas as critical habitat areas, parks,
etc....
SENATOR DYSON asked if issues are involved if a landowner takes
action against the State of Alaska to force DNR to make
available some of their subsurface treasure arguing that not
putting it on the market denies him a beneficial use.
MR. OSTROVSKY replied:
I believe the Legislature could, under the
constitution. Really, the Legislature manages the
disposition of the state resources.
SENATOR DYSON asked if citizens have no recourse except through
the Legislature to bring an action to get their resources
developed if DNR does not make them available.
MR. OSTROVSKY replied that it wouldn't be a viable lawsuit. "I
think ultimately it's a legislative determination that in some
cases its decisions are delegated to a state agency...."
SENATOR DYSON asked if citizens could bring an action if they
believe the DNR has opened land that is inappropriate for
critical habitat or that there is a detrimental effect to the
surface owners.
MR. OSTROVSKY replied that issue could have standing. People
challenge DNR decisions all the time regarding oil and gas lease
sales, mining permits, etc.
TAPE 04-32, SIDE A
SENATOR DYSON asked if someone could bring action if he thought
DNR inappropriately listed an areawide lease sale.
MR. OSTROVSKY replied that he did not think DNR inappropriately
listed property. Theoretically a person could take that
position, but he would have little chance of prevailing.
CHAIR OGAN asked if the state enters into a lease with a
producer and the state buys back that lease, "Is that a
violation of the contract?"
MR. OSTROVSKY replied that would be condemnation or use of
eminent domain.
Right now, I don't think DNR has legislative authority
to use eminent domain power. That's something they
would have to be given by statute and, of course, we
haven't had a situation quite like this in Alaska, but
normally, eminent domain, the state would buy property
back at fair market value - what a willing seller
would sell for and what a willing buyer would buy it
for. And, of course, there would likely be disputes
over what that value is.
CHAIR OGAN asked if some of the disputes could be loss of
potential income from resources.
MR. OSTROVSKY replied that would depend to some degree on the
work that was done on a particular lease. For example, if the
company had obtained a lease and done exploratory work that
showed there was value to that lease, using eminent domain, a
willing buyer would probably pay a premium for that lease. On
the other hand, it could be that the work has shown there was no
value in the lease. It could really go in either direction.
CHAIR OGAN assumed that value would be pretty subjective if no
exploration had been done. He thanked everyone for their
patience and testimony on this issue. There being no further
business to come before the committee, he adjourned the meeting
at 5:22 p.m.
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