Legislature(2013 - 2014)BARNES 124
01/23/2013 08:00 AM House ENERGY
| Audio | Topic |
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| Start | |
| Overview (s): Cook Inlet Gas Supply Study 2012 Update | |
| 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
January 23, 2013
8:04 a.m.
MEMBERS PRESENT
Representative Doug Isaacson, Co-Chair
Representative Charisse Millett, Co-Chair
Representative Neal Foster
Representative Pete Higgins
Representative Shelley Hughes
Representative Benjamin Nageak
Representative Andrew Josephson
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Representative Mike Hawker
COMMITTEE CALENDAR
OVERVIEW (S): COOK INLET GAS SUPPLY STUDY - 2012 UPDATE
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
DAN SULLIVAN, Mayor
Municipality of Anchorage
Anchorage, Alaska
POSITION STATEMENT: Gave introductory comments related to the
Cook Inlet Gas Supply Study 2012 Update.
WILLIAM VAN DYKE, Petroleum Engineer
Petrotechnical Resources Alaska (PRA)
Anchorage, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation
entitled, "Cook Inlet Natural Gas Study 2012 Update" at the
request of Anchorage Municipal Light & Power (ML&P).
MOIRA SMITH, Vice President and General Counsel
ENSTAR Natural Gas Company
Anchorage, Alaska
POSITION STATEMENT: Provided the PowerPoint presentation
entitled, "Long-term Gas Supply Work Group."
BRADLEY EVANS, Chief Executive Officer
Chugach Electric Association
Anchorage, Alaska
POSITION STATEMENT: Answered questions during the presentation
entitled, "Long-term Gas Supply Work Group."
JAMES M. POSEY, General Manager
Anchorage Municipal Light & Power (ML&P)
Anchorage, Alaska
POSITION STATEMENT: Answered a question during the presentation
entitled, "Long-term Gas Supply Work Group."
ACTION NARRATIVE
8:04:21 AM
CO-CHAIR CHARISSE MILLETT called the House Special Committee on
Energy meeting to order at 8:04 a.m. Representatives Foster,
Higgins, Hughes, Nageak, Josephson, Isaacson, and Millett were
present at the call to order. Also in attendance was
Representative Hawker.
^OVERVIEW (S): COOK INLET GAS SUPPLY STUDY 2012 update
OVERVIEW (S): COOK INLET GAS SUPPLY STUDY 2012 update
8:05:55 AM
CO-CHAIR MILLETT announced that the only order of business would
be presentations on the Cook Inlet Gas Supply Study 2012 update.
8:06:10 AM
DAN SULLIVAN, Mayor, Municipality of Anchorage, gave
introductory comments prior to the presentation. He said
securing a long-term energy future for Southcentral is one of
his top priorities, and is an issue across the state wherever
energy costs are very high or there are shortages of fuel. The
Mayor's Energy Task Force has been working for the past three
years, planning for the worst case scenario to ensure that if
there is a disruption, the utilities, the producers, and the
large users are prepared. In fact, last December temperatures
were low enough that Anchorage came close to having an incident.
He observed that although emergency planning is important, the
task force seeks to work in a preventive mode and secure energy
to avoid emergencies. One way to do this is voluntary
conservation by the public which - in some instances - could
"save the day." He recognized the legislature for its work on
effective oil and gas legislation in 2010, and specifically for
the gas storage facility which came online this year. Mayor
Sullivan acknowledged that there is a tremendous amount of oil
and gas activity in Cook Inlet; nevertheless, there remain
shortages in production and deliverability thus Southcentral
must look at options for gas that may not come from Cook Inlet.
He expressed concern that the utilities do not have sufficient
gas under contract to provide heat and light to their customers
for the winter of 2014-15; however, Hilcorp Energy Company has
purchased Chevron and Marathon's assets in Cook Inlet, and will
be surveying the utilities to see what it can do in terms of gas
supply.
8:10:01 AM
CO-CHAIR MILLETT invited Mr. Van Dyke to begin the presentation.
8:10:35 AM
WILLIAM VAN DYKE, Petroleum Engineer, Petrotechnical Resources
Alaska (PRA), informed the committee he was presenting the Cook
Inlet Natural Gas Study Update 2012, at the request of Anchorage
Municipal Light & Power (ML&P). He noted that the primary
author of the study was Peter Stokes of PRA. Mr. Van Dyke said
he would focus on the first item - Southcentral Alaska Gas
Supply/Demand 2012-2020 - and noted that PRA began its study of
the Cook Inlet gas supply in 2010 at the request of a utility
group consisting of ENSTAR Natural Gas Company, Chugach Electric
Association, and ML&P. The purpose of the study was to look at
the Cook Inlet gas supply and to review other related studies.
When looking at proven gas reserves, the numbers from the
Department of Natural Resources (DNR) study [in 2009] and the
PRA study are "very close;" however, the DNR study also looked
at probable and possible reserves, contingent resources, and
other categories of gas that may be in the inlet, but the
utility group was interested in proven reserves because
contracts with producers can be signed only on proven reserves.
8:13:09 AM
The committee took an at-ease from 8:13 a.m. to 8:14 a.m.
8:14:47 AM
MR. VAN DYKE continued to slide 4, entitled "Annual Supply - DNR
2009 Report," which was a chart showing the historical
production of gas for 1995-2010, and production forecasts for
different categories of gas for 2010-2035. Proven reserves
forecast by DNR match the PRA study, although Material Balance
Reserve calculations are difficult in Cook Inlet because there
is water in the gas. Slide 5 was a comparison of the DNR and
PRA studies on Decline Curve Analysis (DCA) and he advised the
differences between the studies are insignificant. Slide 6 was
the PRA study summary of historical production, and a production
forecast up to 2020, which indicated in 2020 "... there's a big
difference between what we need in supply, and what we forecast
production is going to be." Again from a DNR study [2011],
slide 7 indicated the amount of investment needed to rely on a
supply of gas from Cook Inlet, and he cautioned that PRA does
not consider the New Wells Pay Category Geologic Analysis
portion of the forecast to be proven reserves because, "if you
are a utility, and you want guaranteed gas supply, you really
can't count on the green part [New Wells Pay Category Geologic
Analysis] of that production forecast or the grey part
[Development Leads] or even all of the orange part [Base Decline
Reserves]."
MR. VAN DYKE said in 2012 PRA was asked to update the 2010 study
and look at new wells, drilling, and compression. In 2010, the
shortfall was predicted for 2013; but as a result of additional
drilling and compression, the shortfall at this time is forecast
for 2014. Slide 9 illustrated the PRA actual production
forecast base case with no added investment, assuming no
additional wells are drilled, and with the existing compression
in the fields. Slide 10 showed the projected users of gas for
2014-2019, and Mr. Van Dyke pointed out that oil and gas fields
and the Tesoro refinery use fuel also. The expected demand over
the next few years is about 80 billion cubic feet (BCF) per year
with a jump in 2020 after Donlin Creek gold mine opens. Slide
11 indicated that the utilities are very much reliant on a
supply of natural gas in the amount of over 60 BCF per year.
Slide 12 indicated the volume of gas that has existing contracts
and the volume that is needed that is not under contract,
beginning in 2013.
8:19:54 AM
CO-CHAIR ISAACSON asked Mr. Van Dyke to explain the declining
utilization of gas on slide 12.
MR. VAN DYKE answered that gas under contract means the
producers have agreed to supply a certain amount of gas in a
certain year. Because production from the fields is declining,
the amount of gas available to put under contract declines.
CO-CHAIR ISAACSON clarified that on slide 12, gas not under
contract is demand, not available gas.
8:21:27 AM
CO-CHAIR MILLETT anticipated many questions for PRA and the
commissioner of DNR on the true and actual gas supplies in Cook
Inlet, because there seems to be conflicting information and an
ongoing debate. She expressed her hope that the discussion at
this meeting will point out the fundamental disconnect between
the administration and the utilities.
MR. VAN DYKE turned to slide 13 which indicated the natural
decline of the gas fields. All fields are at a 16-17 percent
annual decline as a result of the depletion of the gas from the
reservoir which reduces pressure, deliverability, and volume.
This is a loss of tens of millions of cubic feet of
deliverability per year, therefore, keeping production flat
requires finding a lot of new gas.
CO-CHAIR MILLETT asked for clarification between DNR's stance
that there is an unlimited supply of gas in Cook Inlet, and
PRA's forecast of an annual decline rate of 16 percent. The
utilities and PRA are talking about importing gas causing
concern among her constituents.
8:24:37 AM
MR. VAN DYKE explained that there are different approaches to
the studies that were done; for example, DNR looked at
"theoretically how much gas could be in Cook Inlet," and -
hypothetically - how much could be developed and produced. The
utilities are interested in how much gas could be found and
produced in the future, but for the utilities "... it comes down
to 'What can the wells produce next year, what can they produce
in 2015, what can they produce in 2020?' It's not theoretically
if we drilled a couple hundred exploration wells how much gas
might we find."
8:25:55 AM
REPRESENTATIVE HAWKER recalled the commissioner of DNR said the
prospect of sizeable gas reserves in Cook Inlet coming to market
would undermine the need for other long-term solutions such as a
small diameter gas line from the North Slope, or the import
option currently being discussed by the utilities. He asked
whether Mr. Van Dyke would bet the energy security of his
community on the speculative prospects of major gas finds and
development in the inlet.
MR. VAN DYKE said no, and added that utilities need a guaranteed
gas supply. He gave two examples of wells that were drilled
that have never produced oil: Mukluk on the North Slope and
Sunfish in Cook Inlet by ARCO.
CO-CHAIR MILLETT observed that Cook Inlet gas supplies are
critically low, yet for five years [the legislature] has been
assured that the fields in Cook Inlet are prolific. She
stressed that importing liquefied natural gas [LNG] is a
possibility without the construction of an instate gas pipeline
to provide the gas supply to her community.
REPRESENTATIVE HIGGINS, upon learning that Mukluk was drilled in
the early '80s and Sunfish was drilled in the early '90s, stated
that technology today has advanced in the past ten years. He
surmised DNR has science behind its forecast.
8:31:00 AM
MR. VAN DYKE questioned whether DNR is relatively certain about
the presence of gas. The department's studies are
probabilistic; no wells have been drilled, no gas has been
discovered. These probabilistic studies do not meet a high
enough standard for the utilities to use as a business plan.
8:31:46 AM
REPRESENTATIVE HAWKER recalled a year ago Furie Operating
Alaska-Escopeta Oil Co. announced a mega-find of 3.5 trillion
cubic feet (TCF) of natural gas which was not proven, and has
now been reduced to a maximum estimate of .75 TCF in place.
8:32:36 AM
MR. VAN DYKE agreed with Representative Hawker's statement. In
further response to Representative Hawker, he said PRA's future
projections include "everything that we - in our professional
opinions - thought was proven gas, proven reserves." Mr. Van
Dyke continued to slide 14, explaining that the red line on the
graph plots the total Cook Inlet demand, the blue line plots the
production forecast for the base case, and the red bars are the
shortfall per year.
8:34:20 AM
CO-CHAIR MILLETT, noting that Southcentral needs gas in 2014,
asked what could "fill that gap."
MR. VAN DYKE answered that production could be accelerated in
the existing fields by drilling more wells, which may solve the
problem for the next couple of years; however, there would then
be less gas afterward. Also, there may be gas from exploration
wells online from the Kenai Peninsula, where there is existing
infrastructure. In further response to Co-Chair Millett, he
concurred this is speculative. In fact, slide 15 shows that
eight gas wells completed from November 2011 to October 2012
averaged new production of about 3.6 million cubic feet (MMCF)
per day. However, the decline rate was about the same.
Petrotechnical Resources Alaska anticipates there will be
additional drilling, but the base case does not assume new
drilling in order to depict various scenarios. The scenario on
slide 16 begins with the base case and adds 10 million standard
cubic feet (MMSCF) of production per day for each of the next
seven years, which amounts to an addition of about 150 BCF of
gas to the Cook Inlet gas supply, some of which may be
exploration gas and behind-pipe gas as projected by DNR. He
opined this is a reasonable assumption, but the shortfall
remains. Similarly, the scenario illustrated on slide 17 adds
20 MMSCF per day for each year over a seven-year period, adding
about 350 BCF of new gas - a significant addition - but which
still does not produce the way out of a shortfall. There is a
"good chance" this is possible, but the message here is that a
lot of activity does not eliminate the predicament.
CO-CHAIR ISAACSON asked for a realistic picture for expanding
the current supply of gas.
8:40:06 AM
MR. VAN DYKE opined that the utility group is using an average
between the slide 16 and slide 17 scenarios. In either case,
however, there are shortfalls, and slide 17 depicts the maximum
possibilities for new gas. In further response to Co-Chair
Isaacson, he explained that an operator must first drill one to
three wells to delineate the reservoir, and then follows the
permitting process and final investment decisions. The
timetable for development onshore along the Kenai Peninsula is
two to three years, but on the more remote west side of Cook
Inlet, three to four years.
CO-CHAIR ISAACSON surmised the shortfall in each of the models
accounts for the lag time from discovery, to permit, to delivery
to the utility.
MR. VAN DYKE said this is not a direct calculation, but the
scenario adds an additional volume of gas each year, beginning
in 2013; the 2013 gas that was added must be from development
finished in 2012.
CO-CHAIR ISAACSON said, "So this is a realistic time projection
- it's not an optimistic one, in and of itself."
MR. VAN DYKE further explained that the scenario assumes there
is ongoing exploration every year and that an exploration-
delineation-development continuum is always in motion. This is
evidenced by slide 15 which shows wells were being completed
each year from 2001; however, the new gas is not available in
the volume needed to prevent the shortfall.
8:44:05 AM
REPRESENTATIVE HAWKER acknowledged that eight new gas wells were
completed last year, but his understanding is that most of the
exploration taking place is for oil, not gas. He asked whether
this interest could be turned to gas and if so, the amount of
investment required by the industry to complete six to eight new
successful wells.
MR. VAN DYKE said his work experience leads him to believe that
the completion of six to eight new wells is very realistic with
an investment of $75 million per year; the cost is also
dependent on the location of the find. He agreed that oil is
"where the money is," but expressed certainty that gas prices
will go up in the next five years and the gas market will become
more attractive to producers. Possible explorers are: Hilcorp,
Cook Inlet Energy, and ConocoPhillips Alaska. In response to
Representative Hawker, Mr. Van Dyke advised that there will be a
mix of infield drilling in existing fields, to locate gas
pockets that are not producing right now, and exploration.
REPRESENTATIVE JOSEPHSON asked how much LNG has been imported
into Alaska since the 1950s.
MR. VAN DYKE said none.
REPRESENTATIVE JOSEPHSON then asked what the price to the
consumer would be if LNG is imported.
MR. VAN DYKE deferred to the representatives of the utility
group who will be speaking later in the meeting. In further
response to Representative Josephson, he said liquid fuels and
propane are currently imported.
8:49:07 AM
REPRESENTATIVE JOSEPHSON observed that the decline in the supply
of gas is not entirely correctable in the short term, and asked
whether there is a political undercurrent that "a great oil-
producing state shouldn't be importing LNG."
MR. VAN DYKE said he was unsure whether importing natural gas
gives the state "a black eye," but opined that is a better
choice than a blackout.
CO-CHAIR MILLETT assumed importing LNG will affect the cost of
gas in Anchorage and the Railbelt.
MR. VAN DYKE deferred to representatives of the utilities to
respond. He called attention to slide 18 which depicted a map
from the DNR, Division of Oil & Gas web site. Possible
exploration and infield development to accelerate production,
such as behind-pipe gas reserves, were listed.
CO-CHAIR MILLETT sought the probability - not the possibility -
of curbing a 16 percent decline before 2014.
MR. VAN DYKE opined the projection illustrated on slide 17 of
adding 20 MMSCF per day of gas for each of the next 7 years is
the best case; even with that, the utilities need to address a
shortfall. Slide 19 listed possible infield development and
accelerated production, and slide 20 listed current onshore
explorations that are underway.
8:54:25 AM
CO-CHAIR MILLETT asked what the timeline would be to develop new
fields from exploration to the time of delivery.
MR. VAN DYKE estimated that on the Kenai Peninsula it would be
two to three years to find, permit, delineate, develop, and put
gas online. Permitting on state land in Cook Inlet "has been
going [well]."
CO-CHAIR MILLETT concluded that the new gas would be online in
2016, at the earliest.
MR. VAN DYKE noted that some new gas will be available this year
and next.
REPRESENTATIVE HUGHES called attention to slide 19, and pointed
out that Hilcorp is investing $203 million in 2012 to develop
oil and gas.
MR. VAN DYKE said Hilcorp and others are spending significant
amounts of money, "but I think for the most part that money is
chasing oil, rather than chasing gas."
REPRESENTATIVE HUGHES questioned whether $75 million in
investment per year needs to be specifically targeted for gas.
MR. VAN DYKE said yes, this would be the estimated "round
number" cost to drill six to eight new gas wells. He pointed
out that ConocoPhillips, ML&P, Armstrong, Buccaneer, and Hilcorp
are spending.
8:57:55 AM
REPRESENTATIVE HAWKER has heard statements that additional gas
from the North Slope through any diameter of pipe will derail
plans for additional exploration for gas in Cook Inlet.
However, last year during testimony on HB 9, all of the major
Cook Inlet explorers and producers said that additional gas from
the inlet would not compromise their efforts to explore. He
stressed that "more gas in the inlet ... creates a bigger,
stronger, more dynamic market for everyone." Representative
Hawker cited his experience with the utilities and asked what
the representatives of the utilities think needs to be done and
what their concerns are.
MR. VAN DYKE opined there will be a gas line, but not soon
enough to alleviate any shortfalls in 2015, 2018, or 2020. He
concluded by expressing his hope that the committee will
appreciate that the shortfalls are real and significant.
CO-CHAIR ISAACSON surmised from Mr. Van Dyke's testimony that
imported gas will cost utility users more in Cook Inlet. He
stated his concern that importing gas will reduce the incentive
to produce gas, thereby permanently reducing the oil and gas
industry's workforce in Alaska, as seen with the shutdown of
Agrium Inc., and at the Flint Hills Resources refinery. He
challenged the idea that consumers should pay whatever the
market will bear, and asked whether - after gas is imported -
the price for Cook Inlet gas will ever go down.
MR. VAN DYKE expressed his belief that exploration, development,
and production in Cook Inlet will always be competitive against
the price of imported gas; in fact, imported gas will not drive
local Cook Inlet operators out of business, although he was
unsure of how high future gas market prices will be.
REPRESENTATIVE HIGGINS returned attention to slide 23 and asked
whether North Slope LNG delivered by trucks could meet the
shortfall.
MR. VAN DYKE estimated that hundreds and hundreds of trucks and
700 or 800 truck drivers would be needed. In further response,
he acknowledged that this is one of the options under study -
and could be done - but may not be feasible.
9:05:47 AM
CO-CHAIR ISAACSON suggested that the use of the Alaska Railroad
from Fairbanks is a more conceivable scenario, depending upon
the capacity of the North Slope liquefaction plant.
MR. VAN DYKE pointed out that a truck and rail transportation
system requires more handling and more equipment.
REPRESENTATIVE HUGHES inquired how the cost of trucking gas
compares with the cost of importing gas to the consumer.
MR. VAN DYKE deferred to representatives of the utilities on the
price. He added that big liquefaction and gas conditioning
plants would be required on the North Slope, along with lots of
trucks and fuel.
9:07:16 AM
MOIRA SMITH, Vice President and General Counsel, ENSTAR Natural
Gas Company (ENSTAR), informed the committee members of the
Long-term Gas Supply Work Group - ENSTAR, Chugach Electric
Association, Inc. (Chugach), Anchorage Municipal Light & Power
(ML&P), Donlin Gold, Matanuska Electric Association (MEA), and
Homer Electric Association, Inc. (HEA) - are working very
closely together as a utility group to confront, address, and
assess the problem they are facing with Cook Inlet gas supply.
She began a PowerPoint presentation entitled, "Long-term Gas
Supply Work Group" dated January 23, 2013. Ms. Smith stated her
intention is to provide the utilities' perspective on the gas
supply decline curve. Slide 2 was a graph of the existing local
gas available and the contract volumes that are needed from 2012
to 2020. As an aside, she noted that the utilities have been
granted certificates of public convenience and necessity from
the Regulatory Commission of Alaska (RCA), thus the
responsibility of serving Southcentral Alaska with its gas needs
rests with them. Speaking for ENSTAR, she said ENSTAR has been
serving Southcentral since 1961 using only Cook Inlet gas; it is
ENSTAR's primary goal to continue to do that at a reasonable
price for its customers. However, the decline curve shown on
slide 2 points out the need to ensure a supply of gas. Slide 3
was the PRA update "middle case" scenario of current production
and additional production of 10 MMSCF per day. In response to
Representative Isaacson's question, she said ENSTAR would
contract for any new gas immediately. Although commercial
arrangements between the utilities and the producers are
complex, there is strong cooperation between the parties at this
time to deliver gas to customers. Slide 4 opened a discussion
of the Cook Inlet Natural Gas Storage Alaska (CINGSA) facility,
which was provided for by the Cook Inlet Recovery Act (CIRA)
legislation passed in 2010. Built and operated by ENSTAR, the
facility's customers are Chugach, ML&P, and ENSTAR. The storage
facility was built in anticipation of needing additional gas
deliverability. It is important to understand the difference
between a volumetric shortfall - how much gas is produced in
Cook Inlet in a year, and a deliverability shortfall - how much
gas can be delivered on a given day. Deliverability problems on
very cold days are expected, thus the need for a storage
facility. Gas injections into CINGSA began in April 2012, and
ENSTAR began withdrawing gas from storage on November 9, 2012.
The graph on slide 4 illustrated ENSTAR's purchases of gas and
withdrawals of gas out of CINGSA from 12/15/12 to 12/23/12.
9:13:02 AM
CO-CHAIR ISAACSON asked for a summary of CINGSA.
MS. SMITH gave a brief background on CINGSA. The facility was
built from an almost-depleted natural gas reservoir in the
Cannery Loop Unit, south of the city of Kenai. Industry experts
identified the reservoir as an ideal storage facility and
injected pad gas, which stays in the reservoir, and the working
gas, of which Chugach, ML&P, and ENSTAR each have a certain
contracted quantity to withdraw as needed. The facility will
not solve a volumetric shortfall problem, but was designed to
address a deliverability shortfall. As a result of the cold
weather in December 2012, ENSTAR was drawing gas from CINSGA to
meet its basic needs, because not enough gas could be purchased
through the daily bid process. She cautioned that from a
deliverability point of view, the situation this winter
indicates that the system works on a very close margin, with
little of the redundancy or flexibility of the past.
9:17:03 AM
REPRESENTATIVE NAGEAK asked for an explanation of the purchases
and withdrawals of gas.
MS. SMITH explained that CINGSA, which is a public utility, owns
the reservoir and has contracted out capacity to the utilities.
9:18:39 AM
REPRESENTATIVE FOSTER asked for the current volume stored in
CINGSA at this time.
MS. SMITH answered that ENSTAR has about 3.4 BCF of gas stored,
and added that the reservoir is not filled to capacity.
CO-CHAIR MILLETT asked whether CINGSA can be filled to capacity
next summer.
MS. SMITH said that depends on variables such as weather,
commercial decisions made by the producers, and plans for the
LNG export facility. The storage capability will allow the
utilities to evenly purchase a gas supply all summer even though
demand is low.
CO-CHAIR MILLETT asked, "If say, February is the coldest month
in history and we really do have a deliverability problem, how
much is CINGSA helping you, and when is it not?"
MS. SMITH advised that the contracted withdrawal quantity from
CINGSA is 136 million [cubic feet] per day. The largest
withdrawal last December was about 70 [mmcf]. However,
production failures or compression failures would lead to a
"diesel situation." She acknowledged it is possible ENSTAR
could deplete its CINGSA volumes and be unable to meet
deliverability.
REPRESENTATIVE HIGGINS asked whether withdrawals from CINGSA
result in higher utility bills for customers.
MS. SMITH said yes. The CINGSA rate is structured to include
both a storage reservation fee to "rent" the space in the
reservoir, and an injection withdrawal fee. In response to
Representative Nageak, she confirmed that the charge is passed
on to the consumer. Ms. Smith assured the committee that
operators in Cook Inlet are actively working and are in close
communication with the utilities, and that wells are being
drilled, although she could not say what percentage are oil or
gas. For their part, the utilities have acted by building
CINGSA, the Southcentral Power Project (SPP), and Fire Island
Wind.
9:25:03 AM
BRADLEY EVANS, Chief Executive Officer, Chugach Electric
Association, informed the committee that the utilities have
taken other paths to diversify the "demand side of the problem."
Capital expenditures have been used to bring online the state's
largest wind farm, which is offsetting power that can be put in
storage in order to maximize the benefit of the storage system.
An even larger investment built the SPP which is 25-35 percent
more efficient than its predecessor. The first turbine spin for
the power plant was 10/18/12, and it led to a 25 percent
reduction in gas demand. Additional expansion at hydroelectric
facilities, conservation, and efficiencies will add up to about
a one-third reduction in Chugach's gas demand by 2015. These
actions show that Chugach has taken this problem seriously for
some time by making investments on the demand and supply sides.
All of these measures have been accounted for in the analytics
and are added on to the base case; however, the shortfall still
looms. Mr. Evans suggested that Chugach's biggest concern is an
obligation and responsibility to its membership to consider all
options, although there are not enough answers on which to make
decisions at this time.
9:28:47 AM
CO-CHAIR MILLETT recalled discussion about the decline in Cook
Inlet and asked whether Southcentral is in peril, even with all
of the options that are being considered. The Mayor's Energy
Task Force and the utility working group have been looking for
solutions but the committee continues to hear "two sides of the
story," from DNR and the utilities. She assumed Southcentral is
to the point of solutions of last resort - importing LNG or
trucking - because the situation has been neglected.
MR. EVANS recalled that his previous testimony over the past
years warned about this problem, but acknowledged, "I think I
fell prey to the optimism of the Cook Inlet renaissance."
However, now a rational decision must be made to put into play
what may be "a less than optimal solution." Science, analytics,
calculus, data, and experts have revealed a shortfall that must
be dealt with.
CO-CHAIR MILLETT observed that for the most part the general
public is not aware of Southcentral's dire situation; in fact,
the difficult decision to import LNG may become necessary to
prevent blackouts. She asked, "Do you think there is a general
understanding with your membership on exactly where we are in
our energy supply situation?"
MR. EVANS responded that Chugach has communicated to its
membership that there is a problem, but he agreed details and
the history of the situation are not understood. His utility
publishes a monthly newsletter and takes advantage of public
meetings to raise the awareness of members.
CO-CHAIR MILLETT surmised the tabletop exercises conducted by
the tri-borough mayors would have been better received had the
public been more aware of the gravity of the situation.
MR. EVANS opined the results were muted because the [energy
conservation] exercises are held in the fall, thus the 5 percent
saved on a voluntary basis does not have the same effect as
during a time of peak gas demand. Nevertheless, the response to
the exercises indicates that the public is aware of the problem.
After three and one-half years, the many steps in Chugach's
procedure for reducing demand have evolved.
REPRESENTATIVE HIGGINS asked what percentage of gas goes to the
turbines and what percentage goes to customers for heating.
9:37:54 AM
MS. SMITH referred to slide 10 of the PowerPoint presented by
PRA, pointing out that the third largest users of Southcentral's
future demand are oil and gas field operations [13 percent], and
Tesoro is listed as sixth [7 percent].
REPRESENTATIVE HIGGINS has heard that private enterprises are
"trying to put energy on the grid; they're having a hard time
doing it, for whatever reasons." He asked whether Mr. Evans
sees a problem there.
MR. EVANS responded that Chugach has engaged energy from
independent power producers (IPPs) such as Fire Island Wind, has
encouraged the expansion of the Bradley Lake Hydroelectric
plant, and supports the diversification of fuel sources. One
project under consideration is to unify the present multi-owner
grid system in order to facilitate the acceptance of independent
sources of power.
CO-CHAIR ISAACSON asked Mr. Evans to describe the difficulty in
getting excess capacity down the transmission lines from
Fairbanks to the Cook Inlet.
9:41:55 AM
MR. EVANS explained that the Railbelt consists of three load
centers: Fairbanks, the Southcentral/Matanuska-Susitna (Mat-Su)
area, and the Kenai Peninsula. Between these areas there are
small and weak interties thus power from a project produced by
an alternative fuel in one community cannot be easily moved to
another community because of the limitations of the interties.
There are proposed projects to strengthen the interties so
regions can help each other; now however, the utilities cannot
transfer all of their capability from one to another.
Strengthening the grid would also facilitate power from IPPs
coming into the system. In further response to Co-Chair
Isaacson, he said an optimistic estimate of the time needed to
strengthen the interties is a tough question - given the
uncertainty of permitting - but after financing, it is a three
to five year process.
MS. SMITH, returning to slide 7 of the work group PowerPoint,
said the bottom line is that the utilities need to supplement
Cook Inlet gas production. She stressed that the ideal solution
must: avoid discouraging new Cook Inlet production; be scalable
to market needs in response to new production from Cook Inlet;
create price signals to encourage local supply; and be flexible
to allow for a portfolio of future options. Even though not
ideal, all of the closest solutions that have been found are
expensive. Any import project involves a major capital
investment, but a project that has minimal impact on the market
would only last five years, so amortization over a short period,
or paying for an escape clause, will be costly. Over the past
years, the work group's requests for information led to the
following options: three marine compressed natural gas (CNG)
providers; five marine LNG providers; and the possibility of LNG
trucking from the North Slope.
9:46:08 AM
CO-CHAIR MILLETT asked for the difference in cost to the
consumer between short- and long-term contracts for the
importation of CNG or LNG.
9:46:34 AM
MS. SMITH advised that the work group's analysis of costs will
be complete in February, and at this time, every option is being
considered. For example, the group received a proposal from a
marine CNG shipper based on a fifteen-year contract and has
requested another cost estimate based on a five-year contract.
She cautioned that Southcentral has benefitted from a low-cost
source of gas for a long time, but the new sources are sure to
be "a lot more, that's all we can say with certainty." She
continued to explain that the problem has been broken down into
short- and long-term timeframes due to the time needed to build
the necessary infrastructure.
CO-CHAIR ISAACSON asked whether using diesel fuel is a realistic
short-term alternative.
MS. SMITH deferred to Mr. Posey, because he manages the only
utility with a diesel option.
9:50:06 AM
JAMES M. POSEY, General Manager, Anchorage Municipal Light &
Power (ML&P), informed the committee ML&P can burn about 180
megawatts on a five to nine day schedule with the oil it has in
place; however, the system is over thirty-five years old and
cannot run continually without the risk of failure. Also, ML&P
is considering retrofitting its plants to burn diesel but that
poses air quality permitting problems.
MS. SMITH concluded that if diesel is chosen as a short-term
alternative, capital investments are needed. Another short-term
alternative are spot LNG imports.
REPRESENTATIVE NAGEAK asked if capital costs for new technology
are passed along to consumers.
MR. EVANS explained that costs for capital investments are
rolled into rates and passed on to consumers; any benefit
related to a capital investment affects the rates as well. For
example, the SPP project required a substantial investment but
reduced the consumption of fuel - although the decrease may not
offset the increase for the total cost of the improvements.
Furthermore, RCA regulates the utilities' rates to guarantee
against unwarranted increases.
9:53:51 AM
MS. SMITH returned to slide 11 and noted that long-term
solutions of ten to fifteen years include CNG/LNG/trucking
options with fuel from various sources. Slide 11 illustrated a
possible future supply scenario that would require significant
capital investment to convert SPP to a dual fuel facility,
improving ML&P's generation unit, and relying on MEA's diesel.
She warned of the permitting and air quality issues associated
with burning fuel oil. Ms. Smith concluded that the utility
group is completing an economic, engineering, and
political/regulatory analysis of all of the options presented
and anticipates receiving recommendations from its consultants
next month. At that time, the group will determine the most
economic and secure solution for Southcentral.
9:55:24 AM
REPRESENTATIVE HUGHES asked for the deadline that utilities set
to have signed contracts in place.
MR. EVANS answered that deadlines are different for each
utility; Chugach is isolated and cannot buy gas from its
neighbors, therefore it needs to have reserves. For Chugach,
"the rule of thumb" is about ten years ahead.
9:57:17 AM
CO-CHAIR MILLETT invited the utility group to return in February
after it has more information and to discuss contingency plans
and possible legislation. She restated the urgency of the issue
for Southcentral, acknowledging the diligent work being done by
the utilities and the Cook Inlet explorers.
9:58:46 AM
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Energy meeting was adjourned at 9:58 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Agenda Energy Committee 01232013.docx |
HENE 1/23/2013 8:00:00 AM |
Agenda |
| PRA (H) ENE 012313.pdf |
HENE 1/23/2013 8:00:00 AM |
PRA PowerPoint |
| ENSTAR-LTGS Legislative deck.pdf |
HENE 1/23/2013 8:00:00 AM |
ENSTAR/LTGS PowerPoint |