Legislature(2009 - 2010)BARNES 124
03/17/2009 03:00 PM House ENERGY
| Audio | Topic |
|---|---|
| Start | |
| Overview(s): Cook Inlet Natural Gas | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON ENERGY
March 17, 2009
3:06 p.m.
MEMBERS PRESENT
Representative Bryce Edgmon, Co-Chair
Representative Charisse Millett, Co-Chair
Representative Nancy Dahlstrom
Representative Jay Ramras
Representative Pete Petersen
Representative Chris Tuck
MEMBERS ABSENT
Representative Kyle Johansen
COMMITTEE CALENDAR
Overview: Cook Inlet Natural Gas Presentations by Kevin Banks,
Director, Alaska Division of Oil & Gas; Jim Posey, General
Manager, Anchorage Municipal Light and Power; Brad Evans, CEO,
Chugach Electric Association.
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
KEVIN BANKS, Director
Central Office
Division of Oil & Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Presented an overview of Cook Inlet natural
gas.
JULIE HOULE, Resource Evaluation Section Chief
Central Office
Division of Oil & Gas
Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Participated in the PowerPoint presentation
on Cook Inlet natural gas.
BRADLEY EVANS, CEO
Chugach Electric Association
Anchorage, Alaska
POSITION STATEMENT: Testified during the hearing on Cook Inlet
natural gas.
JAMES POSEY, General Manager
Anchorage Municipal Light and Power
Anchorage, Alaska
POSITION STATEMENT: Testified during the hearing on Cook Inlet
natural gas.
ACTION NARRATIVE
CO-CHAIR CHARISSE MILLETT called the House Special Committee on
Energy meeting to order at 3:06 p.m. Representatives Petersen,
Tuck, Edgmon, and Millett were present at the call to order.
Representatives Ramras and Dahlstrom arrived as the meeting was
in progress.
^OVERVIEW(S): COOK INLET NATURAL GAS
3:06:56 PM
CO-CHAIR MILLETT announced that the first order of business
would be an overview of Cook Inlet natural gas with
presentations by Kevin Banks, Director, Alaska Division of Oil &
Gas, Department of Natural Resources; Jim Posey, General
Manager, Anchorage Municipal Light & Power; and Brad Evans, CEO,
Chugach Electric Association.
3:07:26 PM
KEVIN BANKS, Director, Central Office, Division of Oil & Gas,
Department of Natural Resources (DNR), described the scope of
the PowerPoint presentation that followed.
3:08:55 PM
MS. HOULE, Resource Evaluation Section Chief, Central Office,
Division of Oil & Gas, Department of Natural Resources, informed
the committee she would present the geology of Cook Inlet from
an exploration geologist's point of view for future gas
potential. She stated there is more gas to be found in Cook
Inlet's existing gas fields and in new exploration play types.
Most of the developed fields are in the major structures that
were found during the '60s by using 2-D seismic; however, new
exploration will utilize stratigraphic plays and 3-D seismic.
Ms. Houle said she would address hurdles to future development
such as land access, data gathering, and drilling costs.
3:10:57 PM
MS. HOULE displayed slide 42 "Cook Inlet Gas Exploration
Statistics" that indicated 85 percent of the gas discovered in
Cook Inlet was discovered while drilling for oil early in the
exploration cycle. She explained the gas "sits on top of the
oil," thus the gas was encountered on route to drilling for oil
prospects on large structures. However, present day 3-D seismic
[technology] is expected to reveal undeveloped resources from
stratigraphic trap potential. She said the major gas field
producers are the biggest fields; in fact, four of the largest
fields in Cook Inlet hold 86 percent of the gas reserves. Ms.
Houle then displayed slide 17 "Cook Inlet Industry Activity" and
said the first of the five largest producing fields is the
Beluga River Unit, with an annual production of 43 billion cubic
feet (bcf). The highest producing wells in the Beluga River
were drilled prior to 2005; however, ConocoPhillips Alaska, Inc.
drilled two new wells that are not online at this time. The
second largest field is the North Cook Inlet Unit, with a 2008
annual production of about 23 bcf; again, most of the producing
wells were drilled prior to 2005, and three new wells are not
yet online. The Trading Bay Unit produced 23 bcf, also from
wells drilled prior to 2005. Additionally, the Ninilchik Unit
produced 19 bcf last year, and 46 percent of its wells were
drilled between 2005 and 2008. Ms. Houle pointed out that the
area of the Ninilchik Unit is an anticline with a surface
structure. Marathon Oil Corporation and Chevron/Unocal have
"gone through" this area, combined with the neighboring fields
of the Grassim Oskolkoff (GO)/Susan Dionne/Paxton Participating
Area, and the new drilling by Marathon and Chevron/Unocal is
adding to the reserves. This well-by-well, additional drilling
within an existing field does a good job of incrementally adding
to the reserves. For clarification, she explained the
department uses the following Alaska Oil and Gas Conservation
Commission (AOGCC) regulatory definition of an exploratory well:
An exploratory well means a well drilled to discover or
delineate a pool. Ms. Houle remarked:
When you drill one well, say in the '60s and you had a
discovery of gas or oil, then, but nobody did anything
because it wasn't economic, later when another company
came in and they drilled another well, to delineate
it, to see how big it was, because the sands are
discontinuous. ... Then maybe it was commercially
brought online, but it you look at some of these
discovery dates, they're way earlier then the field
came online, and [the Cosmopolitan Unit] is an example
of that.
MS. HOULE, returning to the producing gas fields in Cook Inlet,
said the fifth largest producing area is the Kenai Unit located
on federal land. Forty-six percent of its producing wells were
drilled between 2005 and 2008, and its annual production is
about 19 bcf.
3:16:34 PM
MS. HOULE presented slide 4 that showed the volcanic activity on
the Kenai Peninsula and the Aleutian Chain islands known as the
"ring of fire." Cook Inlet is unique in that active volcanism
and sandstone formed from volcanic rocks are not usually a good
reservoir for gas and oil. Slide 5 "Upper Cook Inlet Basin,
Basin/Reservoir Origins" indicated that Cook Inlet Basin is
located in an active subduction zone. The subduction zone is a
slab of mineral-laden earth that slides down under the lighter
continental crust. Slide 6 showed the volcanic area next to
Cook Inlet Basin and the Forearc Basin, where sediments are
deposited. The primary depositional fabrics in Cook Inlet are
fluvial, or rivers, and the area coming off of the Volcanic Arc
is a very coarse-grained alluvial fan, that is coming from the
west and is deposited to the east. Further, there is a
meandering river system along the basin axis, and there is
evidence of tectonics with active faulting and subsidence. She
said that the "take home message" is that the sandstones in Cook
Inlet are very discontinuous and are at about 150 feet, which is
generally below seismic resolution, although 3-D seismic will
have improved resolution.
3:20:44 PM
CO-CHAIR EDGMON asked whether most of the gas developed today
was the product of 2-D seismic activity.
MS. HOULE indicated yes. She added that 2-D seismic mapping
done in the 1960s showed the anticlinal structures because they
are very large structures that run along Cook Inlet. In further
response to Co-Chair Edgmon, she explained 3-D seismic is more
of a tool in the North Slope; however, there were three 3-D
surveys completed in Cook Inlet: in the Beluga Field, in the
Ninilchik Area, and in north Cook Inlet. These surveys were of
existing fields and "the advantage there is they have a lot of
well control, in order to look at their seismic, and see the
correlation between the sands and the wells, because they are
very closely spaced ...." She said the department would like to
see 3-D seismic shot in the Cook Inlet in a similar manner to
Chevron's activity at the White Hills on the North Slope. Slide
7 "Tertiary Basin Depositional Systems" showed an aerial view of
the meandering rivers of the Susitna Valley. She explained how
this geology leads to the discontinuous nature of sand deposits.
In fact, linear sand deposits left on top of each other during
different periods in history are called amalgamated, and are
better reservoirs than isolated sands. She also noted there are
a lot of coals in Cook Inlet, and "coals reek havoc on seismic
interpretation." Slide 8 "Sand Distribution in a Fluvial
system" illustrated five wells and the reservoir correlation
along the structural crest. If the pressure in the sand is the
same at different wells, this is an indication that the sand
reservoirs are connected; however, the illustration clearly
showed that all of the sands do not hit all of the wells.
3:25:01 PM
CO-CHAIR EDGMON asked whether 3-D seismic activities "play out
with the "beluga [whale habitat] issue."
MS. HOULE agreed that there is an issue with the designated
beluga habitat area. In addition, the problem with shooting
seismic is not only the habitat issue, but also the time
constraints dictated by the extreme tides. She presented slide
9 and said the most producing stratigraphies in the Cook Inlet
are the Sterling, the Beluga, the Tyonek, and the Hemlock. The
Hemlock is oil-prone, the Tyonek has oil in the lower [section]
and gas in the upper, and the Beluga and Sterling are
exclusively gas. The one reflector seen well in Cook Inlet is
the Sterling to Beluga transition, because the Sterling sands
are thicker and the sandstone packages of the rivers are
accreted. The Sterling reservoir also does not have a lot of
coal. The Beluga is thinner-bedded and has more coal, but is
still a good gas reservoir. The Tyonek also has coals and
varied thicknesses of sand. Slide 10 illustrated the
discontinuous nature of sands and that one well would not
necessarily penetrate every [layer of] sand on a structure;
therefore, it is necessary to drill delineation wells.
Additional wells drilled between existing wells, if successful,
are called "bypass pay." Two common problems with older wells
are plugged up perforations and wells that can not be restarted
due to water.
3:28:21 PM
MS. HOULE presented slide 11 "EW-1 Granite pt" that showed large
structures revealed by early seismic data. Slide 12, "NCI
field, Low Hanging Fruit" showed the fields located on the sides
of structures and that have three-way closure; she opined these
are a good target for exploration. Slide 13, "NCI field flat-
spots" showed an area that "slows down your seismic ... [and]
that can be an indicator of gas." Slide 14 "New Gas from New
Exploration Play Types; Oil and Gas Trapping Mechanisms"
illustrated the following: Anticline structures have been
discovered; some fault traps have been discovered; and
stratigraphic traps are more elusive, but promise gas in Cook
Inlet. Slide 15 was a seismic picture of subtle stratigraphic
traps. Slide 16 "Tight Gas Sands" indicated that the sands in
the Tyonek and the Beluga look good because they have a lot of
volcanics, they are less than 65 million years old, and they are
less than 10,000 feet deep, thus have not been compacted.
3:31:57 PM
REPRESENTATIVE TUCK asked for clarification of slide 16.
MS. HOULE explained slide 16 is a picture of two pieces of
sandstone rock fragments that were cut into slabs and put under
a microscope. The "blue areas in here are porosity, so that
would be where your oil would move through or your gas would be
stored." Slide 18 showed that the thickest sediment in Cook
Inlet Basin is 25,000 feet. Slides 20 through 25 showed the
location of federal land, CIRI land, Mental Health Land Trust
land, Beluga Habitat, and the areas under lease sales. She
pointed out the "sweet spot" of Cook Inlet is leased;
furthermore, other land that is a potential resource in the
inlet is not available.
3:37:03 PM
MR. BANKS presented slide 27 "Oil & Gas Cook Inlet Milestones:
1800s-1040s" that indicated the location and date of oil
discoveries up to 1949. Interest in oil development in the Cook
Inlet began in the late 19th century and accelerated with the
discovery at Swanson River in 1955. By 1958, Swanson Oil Field
production began. Slide 38 showed the wells drilled from 1950
to 2008, and indicated the greatest activity took place during
the mid '60s; in fact, the largest oil discovery was at the
McArthur River field in 1965, and gas was found there as a by-
product of oil exploration. Consequently, in the late '60s,
producers in the Cook Inlet had to monetize gas resources and
developed the Agrium, Inc., fertilizer plant and the liquefied
natural gas (LNG) facility. The slide also indicated that the
new activity beginning in1995 includes wells drilled for gas
exploration and delineation. Slide 39 showed that a steady
number of Cook Inlet development wells were drilled after the
highest peak in the late '60s. Slide 40 showed the number and
dates of the installation of offshore oil and gas platforms in
Cook Inlet, ending with the Osprey oil platform in 2000. Slide
41 "Cook Inlet - State Acres Leased" was a bar graph that
indicated a steady number of acres were purchased by potential
production and exploration companies; in fact, about 25 percent
of the available land in Cook Inlet is under lease, and Mr.
Banks opined there is a need to get greater access to land in
the Kenai National Wildlife Refuge or to land owned by others.
3:41:53 PM
REPRESENTATIVE EDGMON asked when the Beluga Habitat was
established.
MR. BANKS said U.S. Fish and Wildlife Service has laid out
critical habitat areas, with certain restrictions, within the
last two years; in addition, the beluga whale was listed as an
endangered species, which may change how the critical habitat is
managed.
REPRESENTATIVE EDGMON asked what the restrictions mean to gas
exploration and seismic activity in the Cook Inlet.
MR. BANKS responded access to those areas will be, in some
instances, completely prohibited north of the North Cook Inlet
Unit; in other areas access may be seasonally restricted for
"conflict avoidance" and activity offshore will have to be
"worked around" the presence of whales. In response to Co-Chair
Millett, he said 3-D seismic was shot at North Cook Inlet, the
Beluga River, and Ninilchik last year.
3:44:26 PM
MR. BANKS continued to slide 43 "Gas Field Size Distribution
Cook Inlet." As expected, there are many small fields and fewer
big fields found in an oil and gas basin; therefore, the
department expects more gas to be found in fields similar to the
Ninilchik Unit and its participating areas. Therefore, drilling
and exploration in the future should yield more gas fields that
produce in the range of 300 bcf to 1,300 bcf. Referring again
to land access, he noted the Cosmopolitan Unit is an oil field
with a gas cap; however, because of restrictions to access from
the surface, the wells are being drilled directionally from
onshore. This means the wells will traverse under the gas cap
and only oil will be produced.
3:47:13 PM
MR. BANKS presented slide 46 "Cook Inlet Demand and
Deliverability Forecast" that was a graph showing the
theoretical capacity of the production of gas within the
existing units. This production capacity declines dramatically,
beginning about 2009. This prediction is based on an assumption
that no further investments are made in Cook Inlet and that gas
is produced only from existing wells. The "history" line on the
graph represents an annual average production of gas; the
"capacity" line at any given point on the graph is greater than
the history line because the production can be much greater than
the average on very cold days. Mr. Banks continued to slide 47
"Historic Deliverability" that indicated on 2/3/99, one of the
coldest days of the year, 763 million cubic feet (mcf) was
delivered to the market. On 1/3/09, 380 mcf was delivered to
the market; however, in 2009, average production was 150 bcf per
day. Returning to slide 46, he pointed out that from 2009-2011,
LNG exports in the amount of about 49-50 bcf per year will be
allowed. After 2011, the graph assumes that no exports will be
allowed and the forecasted demand levels out at just below 100
bcf per year. Shown on the graph in yellow are the P-2
reserves, known as "behind the pipe reserves." This is gas in
the discontinuous sands that has not been reached by the
existing wells. The graph estimates that more drilling in
existing fields could produce as much as another 470 bcf of gas.
Mr. Banks noted that this additional capacity includes gas that
is expected from two new wells in the Beluga River Unit and
three new wells in the North Cook Inlet Unit; in addition,
there is the potential for new gas from continued development
drilling in existing fields. This potential increase in gas
would supply the utility and electricity demand from Cook Inlet
until 2019. Mr. Banks stated the department will continue to
refine these projections. He then explained the area to the
left of the yellow on the graph will come from brand new
exploration.
3:52:32 PM
REPRESENTATIVE PETERSEN asked whether directional drilling was
being used in Cook Inlet.
MR. BANKS said yes. For example, any platform has wells "are
literally feet apart" thus in order to reach the fields, wells
are drilled directionally. Horizontal wells are not as common,
because the wells attempt to hit as many sand bodies as possible
as they travel through the resource. He pointed out the 470 bcf
to 500 bcf of gas reserves will only be drilled for if there is
a market waiting for it. He opined a producer will not drill a
well if the market is unknown; in fact, producers usually enter
into a supply contract with a customer intending to meet the
supply requirements by additional drilling - exploration will
not happen before the market exists. If there were the
assumption that LNG exports will be allowed beyond the next
license period, some of the gas to supply the LNG might come
from gas reserves, at the expense of local demand. Mr. Banks
recommended that discussions with exporters should elicit
commitments to replacing and augmenting the reserves.
3:55:08 PM
MR. BANKS continued to slide 48 "Cook Inlet Daily Gas Demand"
and explained one issue for Cook Inlet is, because of the
climate, there is almost 14 times as much gas delivered into the
market on "needle-peaking days" than on warm summer days. In
the past, there was sufficient capacity to adjust for this
increase in demand; however, it is more difficult to make this
adjustment now that the productivity of the wells and the fields
has declined. For example, in anticipation of an increase in
demand, ENSTAR has begun to pump gas into the pipeline for
additional storage; this is called a "line pack." Other
methods to address peak demands are: storing gas in three
exhausted gas pools in the summer; adding compression; adding
more wells; and "swinging the load of gas taken up by LNG
exports." He stated the market creates a different challenge;
for example, gas storage can be offered to third parties, as is
common in the Lower 48. Mr. Banks presented slide 49
"Industrial Base Load" that showed the industrial base load peak
swing from a warm day to a cold day is now 200 percent. This is
an increase from a peak swing of 50 percent when gas was also
marketed to the LNG plant and to the Agrium fertilizer plant.
He stressed the advantage of reducing the peak swing by having
an industrial or export market for gas; for example, the
additional market would keep the wells online year around and
prevent the problem of "watering out" wells from temporary
closures.
3:58:37 PM
REPRESENTATIVE RAMRAS thanked Mr. Banks for his assistance. He
then asked whether Cook Inlet production is down from 200,000
barrels of oil per day at its maximum, to 10,000 to 20,000
barrels per day.
MR. BANKS agreed production is down to about 20,000 to 25,000
barrels per day. In further response to Representative Ramras,
he agreed that in the '70s the price of gas was probably 15
cents per mcf and oil production taxes were 10 percent of
production.
REPRESENTATIVE RAMRAS recalled testimony from the Armstrong Oil
company that it found gas in Cook Inlet and the price of
"lifting" that gas is estimated to be $7 to $10. He pointed out
the RCA issues permits for gas sales tied to the Henry Hub
[index] and other indices in the $3.85 to $4 range. He
concluded that there is the ability to find more gas, but not at
the historically attractive prices Cook Inlet gas has yielded in
the past.
MR. BANKS opined exploration in Cook Inlet will be an expensive
enterprise. He expressed his intent to "provide you with much
better information ... perhaps [by] looking at some of the tax
information that we're acquiring through [Alaska's Clear and
Equitable Share (ACES) legislation] to get a handle on what
onshore drilling costs are like ... [and] working with our
lessees or hiring in folks to look at what it would take to do
drilling offshore." The expense will be higher than in the
past, particularly to move forward in developing a stratographic
play, even if the initial wells are not as successful as hoped.
In addition, access is an issue, as state lands have been
"picked over" and the state must engage the federal government,
and others, for access to their land.
REPRESENTATIVE RAMRAS recalled Drue Pearce suggested that
ConocoPhillips Alaska, Inc. should approach the Federal Energy
Regulatory Commission (FERC) for a re-gas permit to import LNG
for its Cook Inlet plant. He asked Mr. Banks to discuss the
ramifications of how a re-gas facility would change the basin
and the flow of the LNG facility. "I will say for the record
that I'm not in favor of that, I'm a bullet line person," he
said. There is a possibility, however, that $3 or $4 gas may be
available through LNG, while the cost of lifting gas from the
basin may be $7 to $10.
4:05:01 PM
MR. BANKS said the situation with LNG exports is that the market
for gas from Cook Inlet is attached to some other market in the
world. This occurs because the pricing for gas for export
should have some influence on the price of gas within the basin.
Also, there is the question of the cost of drilling for gas.
Depending on how transparent the market is, in terms of sending
price signals to producers and consumers, the Cook Inlet market
is "hooked into" an export, or a world, LNG market. If
gasification were permitted, it would be just another way for
that connection to the world market to be established, depending
on the transparency of the pricing to the world marketplace.
Mr. Banks suggested if the imported LNG is cheaper for Alaska
consumers, it would be wrong to not consider importing; however,
before that happens there are a lot of other options including
gas from the North Slope and successful exploration in Cook
Inlet at a competitive price.
4:07:45 PM
CO-CHAIR MILLETT asked for suggestions for the state's role in
helping sustain a lower price in Cook Inlet outside of the
aggressive incentives for exploration that are already in place.
MR. BANKS pointed out the state's very attractive tax provisions
and the mechanisms in royalty [taxes] to protect the way
utilities are treated. Aside from an "out-right subsidy," he
suggested the state should first find out the potential for gas
development and compare that to other options. This information
would allow the legislature to determine the most cost-effective
new gas alternative for Cook Inlet.
4:09:45 PM
MR. BANKS, in response to Co-Chair Millett's request for
information related to the joint meeting of the House Resources
Standing Committee and the House Judiciary Standing Committee of
December 1, 2008, informed the committee DNR met with
representatives from Renaissance Energy Ltd., Escopeta Oil
Company, Pacific Energy Resources, Ltd., and ConocoPhillips,
shortly after the meeting. At that time, DNR asked the parties
to consider that forming a unit on a piece of land where there
is one owner and an amorphous potential for gas "doesn't really
satisfy the point." What a unit should do, in addition to
taking care of the rights of the various partners, is to limit
the requirements for facilities on the surface. The department
requested the parties to submit an agreement on how a drilling
agreement would be organized. However, last week Pacific Energy
went into Chapter 11 [reorganization under the Bankruptcy Code],
and recently Escopeta, the operator at the Kitchen Unit,
structured a deal in which it acquired an ownership interest in
the leases and came forward with a commitment to provide a plan
of exploration for the area. In fact, Escopeta has committed to
meet certain due dates or relinquish the leases.
4:12:23 PM
REPRESENTATIVE RAMRAS referred to slide 46 and suggested the
information on the slide shows the state continuing to go to
Cook Inlet for gas and that the Conoco export case "goes away."
He presented a scenario whereby in 2014, natural gas is coming
down from the North Slope to supply the need in Alaska, and
Conoco is continuing to export LNG from the Cook Inlet gas
fields at 75 bcf per year. He asked, "Can you articulate what
that future would look like ... [for] the depleting, mature Cook
Inlet?
4:13:43 PM
MR. BANKS surmised Representative Ramras was asking him for a
prediction. He speculated that a bullet line has the possible
impact of using the existing [LNG] facility to export gas, which
would limit the market for future gas from Cook Inlet.
Therefore, the question would be whether Cook Inlet can complete
with gas from the North Slope. He stressed that the unknown is
how much it will cost to get gas into the Southcentral region
and how the North Slope gas will compare.
REPRESENTATIVE RAMRAS re-stated his question.
MR. BANKS responded that it behooves the state to research all
of the options before participating in various solutions.
Furthermore, a better understanding of the resource potential
and the cost of the development of gas in Cook Inlet is part of
that research.
CO-CHAIR MILLETT turned the gavel over to Co-Chair Edgmon.
4:16:28 PM
REPRESENTATIVE PETERSEN asked about gas storage expansion plans.
MR. BANKS responded there are three facilities operated by
producers who own the gas they are putting in storage.
Discussions are underway with an applicant for a gas storage
lease and indications are that the applicant is interested in
creating storage for third party use. There are five to seven
other exhausted gas pools that could serve as storage; however,
their locations are not ideal.
CO-CHAIR EDGMON returned the gavel to Co-Chair Millett.
4:19:10 PM
CO-CHAIR EDGMON recalled previous testimony from a
representative of the Armstrong Oil company who concluded Cook
Inlet is underexplored, but that it has potential for gas
development even though costs are high. He asked Mr. Banks if
he agreed that today's presentation focused on the challenges to
be overcome for further development in Cook Inlet.
4:20:27 PM
MR. BANKS opined the Armstrong representative was "probably more
right than I am about the potential for gas development in Cook
Inlet."
4:21:21 PM
BRADLEY EVANS, CEO, Chugach Electric Association (Chugach),
informed the committee his family has been in Alaska since 1960
and he has an electrical engineering degree from the University
of Alaska Fairbanks. Mr. Evans has worked for the Department of
Transportation (DOTPF), Golden Valley Electric Association, and
Chugach Electric. He said he would portray Cook Inlet natural
gas through the "lens of a consumer." He expressed his belief
that the state has taken an abundant resource in Cook Inlet and
created an economic engine that powered Southcentral, Fairbanks,
and Fort Knox. This resource is also critically important to
Chugach Electric. However, historically, information about the
inlet has not been shared by all of the interested parties and
that is one of the recommendations made by his company. He
presented slide 3 "Chugach's fuel mix" that illustrated the fuel
mix today is 90 percent gas and 10 percent hydroelectric
(hydro); the vision for the future is for power generation from
10 percent gas and 90 percent renewable sources. He presented
slide 4 "Cook Inlet Supply Demand Situation Today" that
illustrated: Supply from reservoir harvesting and limited
exploration; supply management by diverting LNG back to retail
use in the inlet; demand from LNG exports, gas utilities,
electric utilities, and military bases; and demand management by
conservation and load interruptions. Slide 5, "Where will
future gas supply come from?," listed Cook Inlet exploration;
spur line; bullet line; LNG import; and alternative fuels. He
noted that some of these choices are not popular and have
commercial issues; however, the utilities' consumers want
"affordable power over pride of developing a resource that is
more expensive." Slide 6, "Without reserves growth, supply will
not meet gas demand for utility needs" was a graph that
indicated the base supply, base supply with reserves growth and
use for power generation and gas utility from 2003 to 2025. Mr.
Evans stated his company's intent to lower the use of gas for
power generation as "part of the solution, as well."
4:26:48 PM
MR. EVANS presented slide 7 that showed Chugach Electric's
recommendations for the establishment of a Cook Inlet Resource
Management Plan and a Cook Inlet Public Gas Authority.
Regarding the management plan, he agreed that "homework" needed
to be done to find out what was in the resource and where to
spend capital on exploration, storage, and resource management
activities. He opined doing the right homework will meet and
protect consumer needs. The management plan should also address
fuel supply security, increase transparency and information
sharing, and provide input for a Railbelt integrated resource
plan. Furthermore, the resource plan would provide guidance for
the utilities' investment decisions about storage options, would
optimize resource management in Cook Inlet, and would provide
information for rational policy decisions. He suggested the
aforementioned are the goals and objectives of the Cook Inlet
Resource Management Plan, but not the scope of the plan.
4:28:53 PM
MR. EVANS presented slide 9, "Next Steps." Chugach Electric has
a good working relationship with the administration and supports
the administration taking the lead on this situation. He
encouraged the development of a steering committee, similar to
the one on the Railbelt Electrical Grid Authority (REGA), to
assure all of the parties of the quality of the shared
information and, through better understanding, to formulate
better decisions. He said he was unsure whether there was a
need for funding support from the legislature until the
administration issues a request. The last step would be
reporting to the legislature by date certain to assure
transparency in the process.
4:30:30 PM
MR. EVANS presented slide 10, "Cook Inlet Public Gas Authority"
and stated Chugach Electric, from the consumer side, is
interested in looking at organizations that combine the interest
of consumers, such as a large nonprofit agency that engages in
wholesale contracts and activities for end-users. He proposed
that members of this agency would include electric and gas
utilities. Mr. Evans clarified, "I'm not here to say that
everybody needs to join this, I'm saying it's a model that we
might want to look at to make sure that ... the interest of the
consumer is aligned ...." He stressed the wisdom of having a
balance of the interests of the consumer, the producer, and the
state.
4:31:53 PM
MR. EVANS expressed his support of the presentation by the DNR.
He summarized that the utilities are dependent on Cook Inlet
natural gas for their supply of electricity and that they would
like to keep rates affordable. He assured the committee,
although the gas demand is outpacing the supply of natural gas,
Chugach Electric is pursuing many demand reduction policies. He
said he was glad that the committee is focused on the "sense of
urgency" about this topic, even though the economics have
changed somewhat since last summer.
4:33:02 PM
CO-CHAIR EDGMON applauded Chugach Electric's efforts to keep
this topic "a front-burner issue." He asked how many customers
Chugach has compared to the other big utilities.
MR. EVANS said it has around 80,000 meters. He estimated
Chugach Electric represents about 60 percent of the energy
produced in the Railbelt. In further response to Co-Chair
Edgmon, he said its retail, wholesale, and customer base is
about 200,000 meters; including meters that receive intermittent
power. The peak load for Golden Valley Electric Association is
about 200 megawatts for 40,000 meters. He explained the number
of meters does not equal the "customer count" as some customers
have more than one meter.
4:36:09 PM
JAMES POSEY, General Manager, Anchorage Municipal Light and
Power, indicated his appreciation for the presentation by DNR;
however, he stressed that "the process [of] ... looking at the
Cook Inlet, needs to be turbo-charged." Mr. Posey opined the
problem must be resolved within three years by finding new gas,
not by harvesting the old fields. At this time, the [oil and
gas] companies are spending $40 million to $80 million per year
trying to do that, but the state must ensure that another
[trillion cubic feet] of gas is located. This would support the
region during the period between 2014 and 2020, until the
development of the bullet line or LNG imports. Mr. Posey noted
his experience in the oil and gas business for over 40 years and
recalled his expectation that the gas pipe line would have been
built by 1987. He stressed the importance for the state to play
a role in Cook Inlet exploration and that role will require an
allocation of resources. Furthermore, legislative action this
year and next will forestall "tight times" and ensure that the
industrial base and population are secure.
4:39:04 PM
MR. POSEY concluded that there are some areas of federal lands
that are prospective; however, the state and private interests
need to work to open this land and to ensure that a jack up rig
is drilling offshore to find the gas that is still left in the
inlet until the pipelines bring gas from the north. He
predicted finding gas from the inlet would not cost as much.
4:40:07 PM
CO-CHAIR MILLETT asked whether Mr. Posey supported a
comprehensive Cook Inlet Resource Management Plan.
MR. POSEY said he and Mr. Evans share the idea; however, it is
necessary to dedicate $10 million to $20 million to ensure the
supply of gas for domestic use and for the continued function of
the economic engines in Southcentral.
4:41:18 PM
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Energy meeting was adjourned at 4:41 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Kevin Banks House Energy 3.17.2009 FINAL.pdf |
HENE 3/17/2009 3:00:00 PM |
|
| CEA presentation 03172009.PDF |
HENE 3/17/2009 3:00:00 PM |