Legislature(2015 - 2016)BARNES 124
03/02/2016 01:00 PM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| HB247 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 247 | TELECONFERENCED | |
| + | TELECONFERENCED |
HB 247-TAX;CREDITS;INTEREST;REFUNDS;O & G
1:02:55 PM
CO-CHAIR NAGEAK announced that the only order of business is
HOUSE BILL NO. 247, "An Act relating to confidential information
status and public record status of information in the possession
of the Department of Revenue; relating to interest applicable to
delinquent tax; relating to disclosure of oil and gas production
tax credit information; relating to refunds for the gas storage
facility tax credit, the liquefied natural gas storage facility
tax credit, and the qualified in-state oil refinery
infrastructure expenditures tax credit; relating to the minimum
tax for certain oil and gas production; relating to the minimum
tax calculation for monthly installment payments of estimated
tax; relating to interest on monthly installment payments of
estimated tax; relating to limitations for the application of
tax credits; relating to oil and gas production tax credits for
certain losses and expenditures; relating to limitations for
nontransferable oil and gas production tax credits based on oil
production and the alternative tax credit for oil and gas
exploration; relating to purchase of tax credit certificates
from the oil and gas tax credit fund; relating to a minimum for
gross value at the point of production; relating to lease
expenditures and tax credits for municipal entities; adding a
definition for "qualified capital expenditure"; adding a
definition for "outstanding liability to the state"; repealing
oil and gas exploration incentive credits; repealing the
limitation on the application of credits against tax liability
for lease expenditures incurred before January 1, 2011;
repealing provisions related to the monthly installment payments
for estimated tax for oil and gas produced before January 1,
2014; repealing the oil and gas production tax credit for
qualified capital expenditures and certain well expenditures;
repealing the calculation for certain lease expenditures
applicable before January 1, 2011; making conforming amendments;
and providing for an effective date."
1:04:20 PM
JARED GREEN, President, ENSTAR Natural Gas Company, assisted in
providing a PowerPoint presentation to the committee about the
company's use of Cook Inlet gas. Turning to slide 2, "Natural
Gas Supply Needs," he said ENSTAR Natural Gas Company ("ENSTAR")
is the largest purchaser of natural gas in the Cook Inlet today.
Ultimately, he pointed out, ENSTAR's customers are a beneficiary
of the tax credit program that has been in place since 2012.
The customers of ENSTAR depend on natural gas from the Cook
Inlet to heat their homes, businesses, schools, hospitals, and
industries. Fundamentally, ENSTAR's interest is in the
fostering of a stable and appealing natural gas environment for
the Cook Inlet. This environment needs to exist in the short,
medium, and long term. ENSTAR's number one priority is safe,
reliable natural gas service to its customers. The company was
founded in 1959, the same year as statehood.
MR. GREEN noted that ENSTAR's customers use, on average, about
33 billion cubic feet (Bcf) of gas a year. In a really warm
year that can drop to as low as 30 Bcf and in a really cold year
it can be as high 35 Bcf. He recalled that enalytica, the
legislature's consultant, has said that the total in-state use
is about 80 Bcf. So, on average, ENSTAR is about 33 of that 80
Bcf a year. He explained that ENSTAR has very high seasonality
to its gas needs, varying from about a 12 to 1 ratio of winter
to summer gas needs. There is also the aspect of substantial
daily variability in gas demand due to weather. With its
current customer base ENSTAR has a potential daily gas demand of
287 million cubic feet per day (MMcf/d) during a cold snap in
January. But, during a warm snap on that very same day in
January, ENSTAR has the potential of burning less than 100
MMcf/d; for example, the system is currently at 102.5 MMcf/d.
1:06:59 PM
MR. GREEN explained that when ENSTAR plans its natural gas
portfolio it looks many years in advance. Because ENSTAR
operates in a small, closed supply network, very long lead times
are required when putting together what the portfolio will be.
The utility needs to know that it will have firm gas set for its
customers at least two years in advance; anything less puts the
marketplace at risk to supply shortages. No matter what, ENSTAR
must have gas available for its customers on those coldest days.
When it is 20 degrees below zero in January and dark, every
single one of ENSTAR's 140,935 customers must have their full
gas needs met. These customers represent over 50 percent of
Alaska's population.
MR. GREEN stated it is challenging to be a natural gas supplier
in the Cook Inlet today. The largest purchaser of natural gas,
ENSTAR has very demanding needs. Between the Cook Inlet Natural
Gas Storage Alaska (CINGSA) facility and producer contracts,
ENSTAR needs to have that 287 MMcf/d available. However, ENSTAR
does not need this amount each and every day. This means that
the producers and CINGSA need to have the significant capacity
well beyond what the average production rates are. It also
means that ENSTAR's producers need to have the operational
capability to ramp up their production but then also throttle it
back when weather is getting warmer. This is a very different
world than in the Lower 48, he stressed, which has an integrated
transmission and storage network. Producers in the Lower 48 can
simply drill a well, open up their taps 100 percent, and the
very large market absorbs it.
MR. GREEN added that from the utility perspective it is also a
nice easy world in the Lower 48. Utilities have lineups of
marketers trying to sell them gas. If a utility has a contract
in place that isn't fulfilled for any reason, the utility can
simply go back to its trading screen and source the gas from one
of the other thousands of suppliers. But that luxury is not had
up here. [Southcentral Alaska] is a very small and illiquid
market with a handful of buyers and an even smaller number of
suppliers. Layered onto that is that ConocoPhillips Alaska,
Inc., is selling its assets in the Cook Inlet, taking another
supplier out of the market. It also shrinks the buying side
because it effectively makes Municipal Light & Power (ML&P)
self-supplied; ML&P will no longer be purchasing from the active
market, leaving ENSTAR with a very delicate marketplace.
1:09:43 PM
MR. GREEN stressed he is not saying the sky is falling as ENSTAR
is in a much better place than it was in 2012. The utility has
transitioned from a time when it was looking at shortages, both
from a total supply and a deliverability perspective. A key
contract to ENSTAR's gas supply portfolio has been signed with
Hilcorp Alaska, LLC ("Hilcorp"). This contract will take ENSTAR
out through 2023, which is just beyond the short-term window of
what ENSTAR looks at. Right now ENSTAR has very good visibility
out to 2021 as to where its gas is going to come from and decent
visibility out to 2023. With continued activity by Hilcorp and
others, and hopefully new players entering the marketplace,
ENSTAR is optimistic that its supply horizons will move out past
2025. But, that statement hinges on the continued activity of
these and new producers in Cook Inlet; an environment that keeps
the producers engaged must be encouraged and fostered.
MR. GREEN said he strongly feels that the utilities have a very
significant role and responsibility in encouraging this
marketplace. He said ENSTAR has designed its portfolio to
balance its number one priority of safe, reliable natural gas
service with the need to foster the long-term viability of the
inlet. The utility has put its support behind development of
the Kitchen Lights Unit, but ENSTAR has also left open 10
percent of its supply portfolio for other producers to be able
to come into. Since 2012 the state has also provided a huge
support to the viability of the market in the Cook Inlet. While
cognizant of the short-term budget challenges currently facing
the state, ENSTAR would love to see the state continue to help
the encouragement of this marketplace in whatever form that
encouragement may be to keep this as an attractive investment
for producers.
1:11:56 PM
MR. GREEN stated that things are in a relatively good place in
the Cook Inlet right now. However, he pointed out, weather has
been very advantageous for ENSTAR over the last two years and so
far in 2016 as well. If [Southcentral Alaska] had experienced
three cold winters the current facilities may have been
stretched. He reminded members that there is one well into the
Kitchen Lights Unit, no gas-producing wells into the new
Cosmopolitan play, and four very large fields that are very old
and aging more every single year. There is no contingency of
significant backup alternatives should there be cold weather or
if one of the existing platforms or fields has an issue. There
are no interties to the Lower 48 or to Canada and ENSTAR is 100
percent dependent on this small, illiquid market to keep half of
the state's population warm.
1:13:05 PM
MOIRA SMITH, Vice President, General Counsel, ENSTAR Natural Gas
Company, drew attention to slide 3, "Supply and Demand." She
said the graph illustrates why ENSTAR is a challenging customer
for producers of natural gas in Cook Inlet. She related that
any producer will say it would like to produce wells at a
consistent rate - open up the flow, sell into a liquid market,
and let the market bear what the price will be. But, ENSTAR
does not purchase gas that way; the graph shows the variability
in the daily demand of ENSTAR's customers, as well as ENSTAR's
actual daily supply in 2014 and 2015. The graph is actual data
as to which companies supplied gas on a day-to-day basis. The
black line that tops off most days on the graph depicts how much
gas was consumed on each day of the two years.
MS. SMITH pointed out the day-to-day variability seen on the
graph, noting that [demand] changes every day as the temperature
changes. She further pointed out the seasonal variability - the
peaks and valleys on the chart associated with winter and summer
demand. In winter, she explained, ENSTAR customers can consume
as much as 12 times more gas in a day than they do in the
summer. She noted the blue color at the bottom of the graph
represents CINGSA injections and withdrawals, injections being
seen below the line and withdrawals above the bottom line. On
cold days ENSTAR withdrew significant volumes of gas from CINGSA
to meet customer demand. For example, cold weather occurred in
mid-November 2015 and the peak in the graph represents those
cold days. Similarly, the winter of 2015 was pretty warm, but a
cold snap in mid-February is directly represented on the graph.
On warm days ENSTAR injects gas into CINGSA. The withdrawal
ability from CINGSA is 91 MMcf/d, about one-third of that key
number of 287 MMcf/d. The rest of ENSTAR's daily withdrawal
ability has to be contracted under firm contracts with producers
in the Cook Inlet. Having CINGSA available is critical in light
of the declining deliverability available out of Cook Inlet
wells, which was detailed by enalytica at a previous hearing.
Ms. Smith brought attention to the orange line at the top of the
graph, noting it represents the golden 287 MMcf/d that is needed
on the coldest of cold days. Such a day only comes along once
every 10 years or so, with four such days in ENSTAR's history.
But, when that day comes, ENSTAR must be there with reliable gas
to keep its pipelines pressurized and serving all its customers.
1:16:17 PM
MS. SMITH said the bar chart on slide 4, "Seasonal Average
Deliverability," further illustrates the seasonality of ENSTAR's
demand, showing ENSTAR's average daily deliverability in each
month in 2019. She reiterated that ENSTAR's goal is to have 287
MMcf/d under contract or available from storage on each and
every day of the year. The dark blue in each bar represents
firm deliveries under the Hilcorp contract and the light blue is
the optional volumes that can be pulled from that contract.
Stacked on top of that are the firm deliveries [dark green] and
the optional volumes (light green) under the new contract with
Furie Operating Alaska, LLC ("Furie"). Looking throughout the
year, it can be seen that ENSTAR's demand from producers in the
middle of winter is quite different from its demand in summer
and producers must be prepared to deliver that on a day-to-day
basis. In addition are the withdrawals from CINGSA. The chart
shows that in January, typically the coldest month, ENSTAR only
has 150 MMcf/d under contract in 2019. When the 91 MMcf/d of
contracted withdrawal capacity from CINGSA is added to that
ENSTAR is still only at 241 MMcf/d, leaving a gap of 46 MMcf/d
that ENSTAR will be looking to fill in the marketplace.
MS. SMITH turned to the bar chart on slide 5, "Supply Contracts
2016-23," to discuss ENSTAR's projected gas supply. The years
2016 and 2017 have a lot of different contracts, she noted, all
of which will taper off in 2018. She recalled that in late 2014
ENSTAR faced a future wherein there was sort of a cliff with no
gas under contract as of 2018 and beyond. The utility sent out
a request for proposals (RFP) and a request for bids from all
producers, potential and otherwise, in Cook Inlet asking them to
provide ENSTAR with a bid to provide all of that firm gas for
ENSTAR's customers. The utility then engaged in intensive,
protracted negotiations with multiple producers and potential
producers throughout 2015 on up until [2/26/16]. The first
priority was to secure an anchor contract at reasonable prices
which could form the foundation for gas supply in the post-2018
world. These negotiations took a year and resulted in APL-14,
the contract with Hilcorp that was just filed on [2/29/16] with
the Regulatory Commission of Alaska (RCA) for its approval.
1:19:12 PM
MS. SMITH addressed slide 6, "(TA 280-4) APL-14 GSA," explaining
that APL-14 is the new agreement [with Hilcorp] under which
deliveries will commence on 4/1/18. The agreement will supply
about 70 percent of ENSTAR customers' needs from 2018-2023. On
a firm basis APL-14 will supply about 22 Bcf per year of gas.
The optional volumes under this agreement will help ENSTAR to
manage its weather-related variability. Customers might consume
29 Bcf in a year or they might consume 35 Bcf. From a planning
perspective this is challenging, so this contract will help
ENSTAR adjust its takes to ensure it is not over-purchasing or
under-purchasing as the circumstances may provide. Another key
element of this contract is its reasonable price. In 2013 the
State of Alaska entered into a consent decree with Hilcorp which
resolved an anti-trust investigation and set price caps for the
sale of natural gas to Cook Inlet utilities. The price caps
escalate at 4 percent annually. The weighted average annual
price for the last years under the APL-12 contract with Hilcorp
will be $8.33/Mcf. By contrast, the weighted average annual
price for firm deliveries during the first contract year of APL-
14 will be $7.56/Mcf, an almost 10 percent decrease.
MS. SMITH noted that perhaps the most important feature of the
APL-14 contract is that it doesn't meet all of ENSTAR's gas
supply requirements. Until ENSTAR signed its contract with
Furie last week, 30 percent of the utility's supply portfolio
was available for other producers to fill. As a public utility
ENSTAR values safety and reliability above all else. Therefore
ENSTAR understands the need to have a diversified supply
portfolio. This diversifies supplier risk as well as helps to
foster investment in drilling, which is good news for the long-
term stability of Cook Inlet supply.
MS. SMITH stated that between APL-14 and the new Furie contract,
ENSTAR now has 90 percent of its needs met through 2021. To
ensure that the market has a second chance to participate,
ENSTAR sent a second RFP to producers on [2/26/16] to try to
acquire supply for the remaining 10 percent of ENSTAR's
portfolio. The utility believes this contract represents a huge
measure of stability in the Cook Inlet gas market. If approved,
it will be the most significant gas contract ENSTAR has had
approved in 15 years. Assuming commission approval, ENSTAR will
have laid the foundation of its gas supply well into the next
decade, which is very good news given where the utility was just
three years ago.
1:22:07 PM
MR. GREEN concluded the presentation by stressing that ENSTAR is
working with a very delicate market - a small number of buyers
and a very small number of producers. Contracts are had that
meet most of ENSTAR's needs through 2021-2023, but the utility
will need to negotiate extensions on those contracts within a
few years. It is very important for all of Southcentral Alaska
that there is a capable producer marketplace that will be there
to provide the gas molecules and the deliverability that the
region needs.
1:22:44 PM
REPRESENTATIVE JOSEPHSON asked about the docket calendaring on
the application to the RCA.
MS. SMITH replied that ENSTAR filed the application on [2/29/16]
and public comment is due within 30 days.
REPRESENTATIVE JOSEPHSON inquired as to an expected timeline for
the ruling.
MS. SMITH responded that the RCA could approve it in 45 days'
time if the commission chooses not to suspend it into a docket,
which is what ENSTAR has requested. If the RCA feels the need
to investigate, the commission can suspend it into a docket and
would then have six months after that time to approve or reject
the contract.
1:23:35 PM
REPRESENTATIVE OLSON asked whether the 2023 date is a result of
the RCA limiting the length of the contracts or is a reluctance
on the part of the producers to commit to something in 2023
without knowing what the tax regime will be at that time.
MS. SMITH answered she is not sure anything can be inferred from
the timeline in the sense that the producers were very willing
to sit down with ENSTAR and have conversations about extended-
term contracts. There is a fair amount of supply uncertainty as
to what is going to happen in the mid-2020s. If anything,
ENSTAR was the one who said to get a good chunk of time in
there. But, who knows what is going to happen in Cook Inlet and
who knows about the pipeline from the North Slope?
1:24:35 PM
REPRESENTATIVE SEATON recalled that the legislature's analysts
have advised the committee that $5-$7/Mcf is sufficient to
produce the most expensive gas in other jurisdictions around the
world, such as Egypt and offshore Argentina. He also recalled
that under the 2009 consent decree the price is averaging $6 and
over and that ENSTAR has negotiated a price of [$7.56] through
2023. He inquired whether ENSTAR agrees that $5-$7/Mcf is
sufficient to produce the most expensive gas and that the market
is ample for economic development of gas for ENSTAR.
MR. GREEN replied that enalytica put out the cost to develop the
most expensive gas available, the drilling and lifting cost.
But there is the assumption that a producer is able to produce
at full capability of its productions, can crystallize the
production coming on, can produce the gas and sell it right
away. Directing attention to the graph on slide 3, "Supply and
Demand," he pointed out that within the Southcentral Alaska
marketplace there is a lot of time, summer months in particular,
where the producers have to just sit on the wells and not
produce any gas at all. Three or four years ago there was the
ConocoPhillips liquefied natural gas (LNG) export facility, and
a year ago that facility was exporting gas through the summer
months. That created a much better balance for producers being
able to produce relatively evenly throughout the year, but that
is effectively gone right now. April prices for LNG are
currently at about $4.65, not a great market for that facility
to be selling off to. Because ENSTAR is the largest buyer in
this area, producers are stuck with ENSTAR's buying patterns and
this has an impact on the overall price because producers are
unable to do as much volume in this tight, illiquid market. A
couple decades ago was a world where ENSTAR was noise, which is
ideal. A utility wants to be just easy noise because utilities
have very challenging demand profiles. When there are big
industrial loads a utility is just a blip in the profile and can
be easily taken care of, and prices are reflective of that.
When a utility with very demanding needs is the main load it
creates a very challenging environment to be in. That enhances
the need for storage, so the CINGSA storage facility that was
put in place in 2012 is an absolute key and integral asset for
the Cook Inlet. The storage facility knocks off about one-third
of the deliverability needed by ENSTAR, but ENSTAR still needs a
lot more coming from that marketplace. There is a cost that
comes with building assets and having them ready to deliver but
then not being able to sell.
1:28:26 PM
REPRESENTATIVE SEATON further recalled that enalytica provided
the committee with three scenarios. The first scenario was a
constrained market where large projects are drilled and then sit
idle. No matter the price in this first scenario, putting in
massive amounts of credits would be a net loss to the state.
The second scenario was export, an unconstrained market if the
export facility can make a profit. He opined that he doesn't
think the state wants to be subsidizing an export facility just
to ensure that the facility is making price. The third scenario
was infield drilling, which enalytica found to be economic in
all cases. So, he posited, the economics of those balance
unless [the legislature] wants to invest $200-$300 million of
the people's money every year to sit in the ground and just be
available for whenever. Representative Seaton asked whether
ENSTAR sees the policy decision being looked at by the
legislature as being infield drilling, which is economic, or a
producer doing its own massive project if there is unconstrained
supply, or a massive project just sitting there waiting for
someone to turn on the spigot.
MR. GREEN responded that ENSTAR does need excess redundancy for
backup needs and for those cold peak days; there needs to be
natural gas available for the basic needs of the Southcentral
Alaska population. Under the scenarios that enalytica looked
at, whether it is export or a large industrial, being able to
average it out reduces the profile and the slopes of ENSTAR's
demand needs and makes the need for the excesses smaller.
Having other industries is very good for ENSTAR. Having no
other demanders of natural gas puts ENSTAR in a position where
there will need to be significant excess gas that is available
for the climate of Southcentral Alaska.
1:31:13 PM
REPRESENTATIVE TARR understood the current storage capacity of
the CINGSA facility is 11 Bcf with a future expansion capability
to 17 Bcf. She inquired whether members should be thinking
about opportunities for more storage if an anchor tenant, such
as an export facility or an Agrium plant, does not come back on
line in addition to ENSTAR, which is a major user given it is a
utility. She further asked whether opportunities for more
storage would help the profile at all.
MR. GREEN answered yes. If a very, very closed network
continues, he said, all options have to be looked at and be
available. Storage is a very useful facility, but is not free
and comes with a cost. He explained that ENSTAR has about 70
percent of CINGSA committed under its firm contracts and most of
the cost of using CINGSA is under a 20-year take-or-pay
contract. In warm years when much of that deliverability is not
needed ENSTAR still has to use the infrastructure because it is
ENSTAR's backup piece. It is incredibly important to have it
there in case a cold snap occurs. Looking at an enhancement or
expansion of that facility going into the future should be part
of what will be needed if ENSTAR is in a place of not seeing the
producers being able to come to the table. The contracts, along
with CINGSA in its current state, are working for ENSTAR's
existing needs.
1:33:06 PM
REPRESENTATIVE TARR understood that four utilities are currently
involved in the CINGSA facility. She asked whether there is
additional interest from other utilities in the nearby region,
such as Seward or Homer.
MR. GREEN replied that Homer is connected into the ENSTAR system
and therefore has access to the CINGSA facility. Seward does
not currently have natural gas, so a distribution system would
have to be installed into Seward. At this time, he continued,
there have not been requests for additional use from the CINGSA
facility outside of the four utilities that have signed up for
the firm service. Of those, Chugach Electric Association, Inc.,
has a significant amount of it, as does ENSTAR. The facility is
a key asset for Homer Electric Association, Inc. (HEA), but HEA
is a relatively small subscriber, as is Municipal Light & Power
(ML&P) of Anchorage.
1:34:33 PM
The committee took a brief at-ease.
1:35:49 PM
BRIAN CLEMENZ, Chair, Government Affairs Committee, Board of
Directors, Alaska Support Industry Alliance ("Alliance"), noted
he is president-elect of the Alliance. Turning to slide 2,
"Today's key messages," he stated that the Alliance is about
responsible resource development for the benefit of Alaska and
Alaskans. The Alliance is composed of nearly 600 Alaska
businesses that provide goods and services to resource
developers and that employ over 30,000 Alaskans. Since the
Alliance's inception, exploration and producing companies have
not been allowed to be members of the organization.
MR. CLEMENZ said that in recent weeks there have been people
taking positions and making decisions based on the premise that
Alaska is done as an oil and gas economy. But, he countered,
great potential still exists in Alaska. None of the other
revenue streams being discussed can come close to generating the
revenue that resource development does. Instead of putting the
last nail in the coffin of the oil and gas industry, the state
should be doing its best to incentivize future production.
During each of the five previous times that oil taxes have been
changed over the last ten years, the message has always been the
same - a stable investment climate is needed. The message is
still the same as this sixth change is considered. Instead of
asking how much more can the state take, legislators should ask
themselves what the state's policy is to ensure that a
partnership with industry is maintained that benefits Alaskans.
Recounting Governor Walker's statement that his administration
will continue to work with the legislature to make Alaska
attractive to investors, Mr. Clemenz argued that HB 247 does not
make Alaska attractive to investors.
MR. CLEMENZ addressed slide 3, "Thoughts on previous testimony,"
recalling that during testimony questions have been asked about
compromise on HB 247. He maintained there is no compromise, the
bill is just plain bad policy. There is no compromise, he said,
that would not result in significant job losses for Alaskans.
Any additional tax on the industry would have serious
consequences on the state's economy. Passage of HB 247 would
result in continued declining revenues to the state that cannot
be replaced. He further said he has repeatedly heard that
everybody needs to give. However, he asserted, this industry
has been doing the majority of the giving to the general fund
for years, not to mention the contributions to the communities
and nonprofits throughout the state by the Alliance's Alaskan
companies and their employees.
1:40:55 PM
DOUG SMITH, President, CEO, ASRC Construction Holding Company;
President, CEO, Little Red Services; Member, Board of Directors,
Alaska Support Industry Alliance, brought attention to slide 4,
"North Slope." He said he will address where service companies
are today by using his company as an example. He stressed that
service companies are currently in a state of crisis. He has
lived in Alaska through three oil price downturns - the 1980s,
1998 when oil was done to $9 a barrel, and now today's trough.
Having gone through those the general public recognizes that
things are in crisis mode when housing prices are low or crashed
and homes are sitting empty, and when there is an obvious
decrease in purchases of goods and services in communities.
MR. SMITH related that what has been learned over the years is
not to knee-jerk react to the price of oil in the industry, but
that is what has been done over the last 18 months. The first
thing industry did was to take it off the top line of its
profits. Little Red Services has not had a layoff of any
personnel since the peak of the recession in 2009 when his
company lost four people. Over the last few years the uptick in
prices and activity have benefitted his company and it has built
some new units and stimulated the economy by building those in
Anchorage. Little Red Services Company made a choice to protect
its market share and its jobs. The company's average employee
tenure is over six years, which is a very valuable resource.
So, his company took significant profit impacts and reduced its
rates. The hope was for recovery in price of oil, but since
January it has plummeted and now his company is at stage two.
Producers are in a bind with negative cash flow. Yesterday his
company underwent its first layoffs since 2009 and that is not
the end of it, he said. The layoffs are a loss of almost $2
million in payroll to the people the company had to release.
This is strictly activity driven, he noted, it is not to regain
profitability. This is pod oil units no longer working in the
field and transports no longer taking fluid to those units.
What does it mean to us as Alaskans? Little Red Services does
well intervention work - hot oil jobs on wells, clearing wells
of paraffin, and support acid jobs - things that have an
immediate potential production increase on wells. This work is
one of the last line of things that is trimmed out of a
producer's activity in a declining market and this is where
things are at now. He informed the committee that the state is
closely approaching a 60 percent decrease in rig activity from
just one year ago, and Little Red Services supports the rig
activity through freeze protection and other activities when the
wells come back on line.
MR. SMITH pointed out that right now his business is not about
profit but rather about protecting market share and customer
relationships. As an Alaskan he understands that this is the
same business decision legislators are in - whether to protect
Alaska's market share of resource development and protect the
future potential revenue of that market share or whether to take
from that market now and live with the consequences. He offered
his appreciation for having to make this tough decision but
cautioned that there are not any more levers to pull in the
industry. Industry is now at the crux where any additional cost
results in some type of reaction. The only reaction left right
now is to decrease activity or to take capital projects off the
table. His company will have to make the choices to move
forward, but those will not be without consequence if additional
tax revenue is pulled from the industry.
1:45:12 PM
REPRESENTATIVE JOSEPHSON asked whether the 60 percent decrease
in rig activity is for Mr. Smith's clients. He posited that it
would self-correct - that what could be more than $1 billion in
credits would, theoretically, become $400 million in credits.
MR. SMITH replied he cannot speak for oil companies, but he can
say that this is a wide range of activity. These vary from coil
units doing infield work and side-tracking existing wells. In
legacy fields these are rotary rigs and development rigs. It is
a wide bandwidth of activity that is being talked about as a
slowdown. Not all of that is in the line of credits. So, as
far as self-correcting and the potential threat of the credit
volume, it is a little bit of apples and oranges.
1:46:21 PM
REPRESENTATIVE SEATON said HB 247 has two policies. One is
taxes, 5 percent instead of 4 percent and whether a company can
write off against that floor. The second is credits, which is
the main aspect of the bill. He asked whether, when talking
about taxes, Mr. Smith was meaning the total of anything that is
done or only taxes and not the credits.
MR. SMITH responded it is both for his company. Little Red
Services is the sole supplier of this service across the North
Slope, he said. He has a unit working for Caelus Energy Alaska
("Caelus") right now that will be coming offline as Caelus wraps
up its exploration work. His company works with independents, a
group that is dependent [on credits] as new entrants. During
the consideration of Senate Bill 21 [passed in 2013 by the
Twenty-Eighth Alaska State Legislature], many legislators were
adamant about the importance of these new entrants and he agreed
with that. It has been a lot of his company's market
opportunity and he thinks it is a lot of Alaska's future.
Independents are in a different position than are the state's
legacy owners and those credits are very important. Regarding
net present value spoken about by Representative Seaton, he
noted he has spent millions of dollars purchasing equipment
during the last couple of years and that equipment is now idle.
His original net present value calculations are no longer valid
because [the equipment] has a 10-year-plus lifecycle. In
looking at the investment through credits the question is total
return. For example, a study of the Alaska Marine Highway
demonstrated the value of that system statewide. Everything
must be looked at when considering investments - jobs, trickle-
down economy, and eventual return. Oil will not be $30 forever,
it is going to be better someday, so the longer term versus the
nearer term must be looked at for these type investments.
1:48:42 PM
REPRESENTATIVE SEATON noted the net present value being looked
at was a 30-year lifespan of the entire fields.
MR. SMITH answered yes.
REPRESENTATIVE SEATON inquired whether instead of looking at
prices of $60-$80 a barrel, that higher prices in the future be
looked at and considered a good investment. He further inquired
as to the kind of projection looked at by Mr. Smith as far as
price per barrel and the activity that the price will generate.
MR. SMITH replied he understands the problem is the inability to
forecast prices, and said this extends to himself. Industry and
businesses have built a level of activity around a price range
of $100, he said. So, everyone is readjusting to survive in a
lower price environment. Regarding the future of credits and
investment, it is going to be a leaner, lower-cost industry
going forward because of this exercise. The recalibration of
cost to develop and recalibration of what it is going to cost to
operate is still finding its way to the top. Businesses are
looking in every corner for efficiency. Any model picked from
recent history to forecast what it will cost to produce oil is
probably not very sound right now. He said he thinks businesses
will be able to demonstrate the ability to be pretty effective
in the $70-$90 range given how much companies have trimmed and
will continue to trim.
1:50:52 PM
REPRESENTATIVE TARR recalled that 15 years ago during the era of
the Economic Limit Factor (ELF) there was not much early-stage
exploration activity. She asked where Mr. Smith's company fits
in that profile and whether his company was active during the
time period of ELF. In regard to how Mr. Smith thinks about his
investment decisions, she further asked whether the current
ability to borrow cheaply would make the purchase of big
equipment a desirable activity.
MR. SMITH responded that his company pays as it goes in that it
pays cash for its equipment and so does not pay any interest.
Regarding his company's longevity, he said Little Red Services
has been around since 1983. The company was active through the
2000s doing infield support work, providing freeze protection
and production stops, and basically being the fire department.
If the Trans-Alaska Pipeline System (TAPS) is shut down, his
company goes out and freeze protects 2,000 wells. As new
entrants came into the market in Alaska, as ConocoPhillips
Alaska, Inc., has gone west, and as Point Thomson was developed,
his company has had the opportunity to extend its services into
those areas. Leading up to and after Senate Bill 21 there was
quite a bit of new spin infield and his company added about 30
employees in that range of time and that is when his company had
its last big equipment push. His company was committed to
building those in Anchorage and they were built in a small
fabrication shop that he went by the day before yesterday. The
shop had 60 employees when he built those units, but today it
has 7 working on the floor along with 3 staff and the doors are
just barely being kept open. This current condition has been
felt pretty deeply in the industry at all service levels. He
said 2016 is going to demonstrate some very visible things in
the way of housing; this industry is in a recession already.
1:53:47 PM
TOM WALSH, Geophysicist, Managing Partner, Petrotechnical
Resources of Alaska (PRA); Board of Directors, Alaska Support
Industry Alliance, noted that PRA is an integrated oil and gas
consulting firm. Turning to slide 5, "Middle Earth," he said
PRA has worked extensively with Doyon, Limited, in the
corporation's exploration of the Nenana Basin and Yukon Flats.
Currently, PRA is working on Doyon's drilling program that will
commence this summer in Nenana with another well. The policy
that generated Senate Bill 21 was very sound and is clearly
meeting its objectives, in his view, all over the state of
Alaska. There has been a very significant uptick in activity,
both exploration and development. Doyon, Ahtna, Incorporated,
and NANA Regional Corporation are all in various stages of
exploration in Middle Earth. Another exploration well is being
drilled this year by Doyon with the support of Middle Earth tax
credits and Ahtna is getting ready to drill its first well in
the Copper Center. Regarding potential, the Nenana Basin is
estimated to contain up to 234 million barrels of oil, as well
as 5.6 trillion cubic feet (Tcf) of gas. Although there has
been no commercial discovery in Nenana at this point, there is
significant potential. A well that finds oil and gas in Nenana
Basin would be a huge homerun for Doyon and the State of Alaska
in terms of jobs and fuel stability for these rural areas.
1:56:39 PM
MR. WALSH said that in regard to ongoing projects Doyon is the
poster child for successful Middle Earth investment driven by
tax credits. Doyon has invested every penny it has received in
tax credits in exploration. When Doyon gets the credit money
back it reinvests and has now gone through several cycles of
exploration in Nenana Basin. Doyon is an ideal case for the
function of these tax credits and the tax credits are very
critical going forward for Doyon. The proposed sunset of some
of the tax credits currently in effect would occur right in the
middle of Doyon's drilling season, and has caused great alarm
for Doyon's ongoing projects. Ahtna is in a similar situation
as Doyon. With its first well planned for this summer Ahtna is
at the beginning of its exploration cycle. The discovery of gas
or oil in Copper Center would be hugely impacting for Alaskans.
MR. WALSH stressed that the aforementioned projects are huge
potential benefit in terms of jobs for Alaskans and local and
rural fuel supply. The instability and proposed changes to the
tax structure are very damaging to those types of projects. He
appealed to the committee to not kill these projects through
either intentional or collateral impacts of HB 247. Doyon is
very focused on local hire and workforce development. Also, the
work of PRA and others would be significantly negatively
impacted by the changes that would be imposed by HB 247.
1:59:22 PM
MR. WALSH drew attention to slide 6, "Cook Inlet," and stated
that the incentives are working and have successfully brought
Southcentral Alaska to a point of stability in energy supply.
He said PRA produced a report in 2009 and updated it in 2012
that Cook Inlet Basin was running out of gas and it was thought
that LNG would have to be imported. But that is no longer the
case, he continued, because of the incentives that have been
offered and the activity that has occurred. Oil production has
risen form 7.5 million barrels a day in 2009 to almost 18
million barrels a day today. Gas production has stabilized, but
there is still a perceived shortage in the market beyond 2023.
In regard to the new contract just announced between ENSTAR and
Hilcorp, he noted that that gas is still in the ground.
Projects need to take place to produce that gas and funding is
required to carry out those projects. A change in tax
structure, particularly in terms of credits, will impact the
development of those gas molecules.
MR. WALSH pointed out that unemployment in Kenai declined from
11 percent to 7 percent over this recent period of activity.
The Alliance's membership in the Kenai area has grown from 40 to
102. There is lots of activity and lots of potential: 600
billion barrels of oil potential in Cook Inlet Basin and 1.18
Tcf of gas estimated to yet be developed. The benefit from
jobs, energy stability, and royalty is critical to the future of
the Middle Earth and Cook Inlet basins.
2:02:28 PM
REPRESENTATIVE TARR inquired about the envisioned infrastructure
and delivery system for the Middle Earth area should there be a
discovery.
MR. WALSH answered that the plans right now are dependent on
whether it is oil or gas that is discovered and how much. The
Nenana Basin is very close to TAPS and the idea for oil is to
bring it to TAPS. For gas, supply to the local market would be
very beneficial, although it would not be a big enough market to
make it a tremendous commercial success for Doyon. But tying
into export facilities or the grid would be the plan for either
a large or small gas find in the Nenana Basin.
2:03:34 PM
MR. CLEMENZ addressed slide 7, "A bit more about jobs," saying
that West Virginia has it right in considering a legislative
measure that would reduce the state's coal and natural gas tax
rates. The belief is that this measure would create jobs and
would put West Virginia at a more competitive advantage. The
proposals under HB 247 would do exactly the opposite for the
state of Alaska. Jobs are the future, but right now the support
industry is hemorrhaging jobs. According to a Department of
Labor & Workforce Development study, the industry lost around
1,000 jobs between December 2014 and December 2015. From a
survey of its members the Alliance believes the number is much
greater than 1,000. The survey also asked about the members'
expectations for the future and from the answers the Alliance
believes the job loss will significantly exceed 1,000 in 2016.
MR. CLEMENZ drew attention to slide 8, "Rig Personnel," pointing
out that it represents only one dimension regarding what is done
in the oil and gas industry. He explained that rigs are used
primarily for workovers to make existing wells flow better and
for explorations. The 44 positions shown on the slide for rig
personnel is a conservative number of positions that are
required to support a drilling operation for the drilling
contractor only. The total economic benefit through that
drilling company would be close to $2 million a month. The 44
positions are on the North Slope, but there is rotation so it is
88 jobs. Further, there is the drilling support that goes along
with that, such as hot oil, rig up, rig down, fluid and
equipment hauling at the well/drill site itself, which almost
doubles the number of folks that are impacted. Additionally
there is the in-near infrastructure and supporting jobs
associated with housing, billeting, feeding, camps,
transportation, security, housekeeping, and travel folks, plus
the multiplicative effect of all of that.
2:07:10 PM
REPRESENTATIVE SEATON requested Mr. Walsh to explain the $2,000
per month per position.
MR. CLEMENZ replied that that is the cost of labor at the very
round billing rate. The specific numbers on slide 8 are either
rounded up or down to the nearest $100-$200 for that particular
position for one day.
2:07:50 PM
MR. CLEMENZ returned to his presentation, pointing out that the
multiplicative effect even goes further. Many local folks are
supporting all of that infrastructure, he explained, as well as
those people who are deployed on the North Slope. Those folks
in turn are going to restaurants and merchants all the way down
to the coffee shop on the corner. Laying down a single rig
might reach 1,000 folks pretty quick for just the people who are
involved throughout the entire supply chain.
MR. CLEMENZ reported that there has been a 60 percent reduction
in rig activity due to low oil prices and a negative cash flow.
There seems to be an unsympathetic ear toward the oil companies
when they discuss their negative cash flow, he said. However, in
this environment of low prices the Alliance's member companies
are experiencing the same pressures. Companies have gone
through many rounds of looking at and reducing costs, then
looking at markups. Many of the Alliance's member companies are
already at break-even markups or are experiencing negative cash
flows. Companies must then look at wages and many companies
have either already reduced wages, are thinking about reducing
wages, or will be reducing wages in the near future. After
that, jobs are lost. So this is just the tip of the iceberg
right now with this low oil price environment and this impacts
working Alaskans from every district represented in Juneau.
2:10:08 PM
MR. CLEMENZ ended his presentation with slide 9, "Conclusions."
He said it can be asked whether HB 247 could impact an LNG
project. Any LNG project of any size or scope faces challenges,
including low commodity prices and lack of capital. However,
one factor that legislators can influence as policymakers is a
stable tax structure and HB 247 negatively impacts a future LNG
project for Alaska. Future oil production is the bridge to any
LNG project because the revenue stream generated is needed to
develop that pipeline; moving forward that healthy oil
production is needed in Alaska. The state and the industry
cannot control oil prices, but industry has weathered this storm
before and knows how to batten down the hatches until oil prices
recover. The state can sink the ship by over-taxing. He urged
that a policy not be invoked that further decreases jobs and
erodes the needed competencies required to respond when oil
prices and investment increase, which they will. Job losses are
already being experienced and HB 247 would create a high
likelihood that the last of the core competencies needed for
responding to future development will suddenly erode and be
gone. The question for legislators as policymakers is whether
slow progress is wanted or no progress.
2:12:03 PM
REPRESENTATIVE TARR observed from slide 8, "Rig Personnel," that
the two company representatives per rig are accounted at $2,000
[per position] per day for 30 days for a total of $60,000 a
month. She asked whether each of those representatives makes
$720,000 a year.
MR. CLEMENZ responded that the rotation is included in that.
This is the total economic benefit coming through the drilling
company into the economy. And, yes, higher-end rig personnel do
make very good money.
2:12:56 PM
REPRESENTATIVE SEATON offered his appreciation for the situation
the various companies are in and that the state is in. But, he
continued, it sounds like the recommendation is that companies
are going to cut costs while the state should not, the state
should continue to give. Last year the amount of refundable tax
credits to the oil industry was $628 million, two-thirds in Cook
Inlet and half on the North Slope. That was limited to $500
million. This last year it will be $623 million. Next year
when the state is running a $3.8 billion deficit [the
recommendation appears to be] that the state should raise other
taxes or go to some other source of money while continuing to
spend that money in refundable tax credits without any
limitations. He remarked that that is not giving the committee
much help in making a policy of no change in anything that the
state has been doing. He requested the Alliance to come forward
with some positive feedback on what kind of changes would be
least impactful but that would reduce the state's deficit. The
state cannot go forward and go bankrupt by paying out money for
something that may or may not be there in the future.
MR. CLEMENZ answered that from the Alliance's position it is all
about policy. He said he is not a tax expert either, but when
other states are hurting in this regard they are not taking away
from the incentives that will ensure that they are in a position
in the future to take advantage of future oil and gas
production. Instead, other states are either making it stable
or trying to create more incentives for the oil and gas industry
to stick around and continue their endeavors.
2:15:30 PM
CO-CHAIR NAGEAK commented that the cost of doing business is
much lower in the Lower 48 than in Alaska. The Lower 48 has
roads and infrastructure that make it much cheaper to do
business. So, he continued, when "decrying about that stuff ...
you're talking about apples and oranges, because it's a whole
lot cheaper down there and a whole lot more expensive up here."
2:16:04 PM
REPRESENTATIVE JOSEPHSON said he hopes the comment about being
unsympathetic was not about him, because he could not be more
sympathetic. If the Exxon Valdez oil spill on Good Friday of
March 1989 is excluded, he continued, it is all roses. He was
born in Alaska in 1964 and has seen how the industry has
transformed the state for the better and he wants to help.
However, since sitting down this afternoon the state has bled
$500 million in red ink. Regarding that there is no compromise
and following up on what Representative Seaton said, he said
there has to be a pathway forward. Fantastic arguments were
heard today and yesterday from Furie and Hilcorp and the
committee is trying to meld all that and achieve some win-win
result. The West Virginia model does not work for him, he
added, because that state has devastated its natural environment
and that is not somewhere he wants to go.
MR. WALSH recalled Representative Josephson's earlier inquiry
about whether this will be somewhat self-correcting. He pointed
out that reductions in activity have occurred because of the low
oil price and advised that those reductions in activity will be
compounded with changes in the tax structure. Projects are
ongoing right now that had their economics and commercial
analysis done based on the tax structure being stable. When PRA
does a commercial analysis or due diligence for someone and
projects forward the commercial viability of a project, PRA
assumes the tax structure is going to be stable because PRA
cannot guess. Also, PRA assumes some type of model for the oil
price because it cannot guess at that either. He said he would
like to think that PRA could assume that this tax structure is
going to be stable. Producers are in the middle of projects
that they have funded and sanctioned based on the current tax
structure. Changing that structure right now would blow them
out of the water and would give the State of Alaska poor
credibility. It really is the wrong thing to do as far as
policy. He said he thinks there will be self-correction because
of that lowering of activity and he expects that the
applications for credits will be lower in future years until
things turn around.
REPRESENTATIVE JOSEPHSON said the argument about pulling the rug
out is an outstanding argument and one he takes very seriously.
Relative to the tax scheme changes, he allowed there have been a
lot of changes although he was not a member of the legislature
for those. He offered his hope that those changes slow and said
he hears Mr. Walsh in that regard.
2:20:04 PM
REPRESENTATIVE SEATON offered his appreciation for those
comments. He inquired whether all projects, those that have and
those that have not reached final investment decision, should be
treated the same. For example, in Cook Inlet it was stated that
at some point success is declared and another tact is taken.
However, all that is being heard by the committee is to not
change anything, the state should stay in the same position and
spend itself into bankruptcy if it needs to. He said the
committee needs input from industry as to what policy parameters
should be put forth to lower the state's expenditure and yet
support the [industry] decisions that have been made.
MR. WALSH responded he understands, but explained that PRA works
throughout the basins in Alaska and these impacts are affecting
companies across the board, including his. The bottom line is
that stability creates investment and instability ruins
investment. The State of Alaska increases taxes when things are
good and the price of oil is high, and now when prices are low
and the state and industry are in dire straits the state is
trying to increase taxes again or reduce its investment in the
industry. The state cannot have it both ways - increase on the
high end and increase on the low end. The tax credit system for
oil and gas in Alaska is trying to be used as a hedge fund by
charging the oil industry more to cover the state's revenue
needs. But it is not a hedge fund. A national oil company
(NOC) like Saudi Arabia doesn't have anyone to be a scapegoat
for paying more taxes. Saudi Arabia owns the industry and is
dipping into its savings funds. People who want to believe that
Alaska is an owner state and that the state should have a bigger
share of the pie ought to look at those NOC's to see what they
are doing, and what they are doing is using their rainy day
funds. Saudi Arabia needs $85 a barrel to be healthy and it is
at $36. In his view, Alaska should be dipping into its savings
funds, not charging taxes at a higher rate.
2:24:14 PM
REPRESENTATIVE TALERICO stated his appreciation for the Alliance
coming forward and telling the committee what it thinks. He
said it is not his responsibility to tell the Alliance what to
think, rather he is here to listen to what the Alliance has to
tell the committee. He said he thinks there will be some type
of activity and something will have to be figured out. He
offered his understanding that it isn't easy for everyone to
come forward and give a point-blank honest evaluation. He
requested confirmation that the Alaska Support Industry Alliance
represents about 30,000 employees.
MR. CLEMENZ answered yes, nearly 600 companies and more than
30,000 employees.
2:25:11 PM
The committee took an at-ease from 2:25 p.m. to 2:29 p.m.
2:29:08 PM
PHIL STEYER, Director, Government Relations & Corporate
Communications, Chugach Electric Association, Inc., began a
PowerPoint presentation, "Chugach Electric Association's use of
natural gas for electric generation." He explained that his
role today is to provide a perspective on Chugach Electric
Association's ("Chugach") historic use of gas out of Cook Inlet,
while his colleague, Mark Fouts, will discuss today's use and
where the Association is headed in the future. Turning to slide
2, "The Railbelt, electrically," he said six different electric
utilities in the Railbelt provide retail service, and each of
those owns generation. Natural gas is the primary generation
fuel for five of the six utilities. The sixth utility, Golden
Valley Electric Association (GVEA), considers natural gas part
of its generation portfolio as well because it buys gas-
generated power from Southcentral utilities. So, natural gas is
vitally important to electric generation in the Railbelt. This
has been the case for decades and is foreseen as continuing.
All of Chugach Electric Association's gas supply comes out of
the Cook Inlet Basin. Mr. Steyer drew attention to the map on
slide 3 depicting the individual service territories of the six
electric utilities in the Railbelt. He said that while he and
Mr. Fouts will be commenting specifically for Chugach Electric
Association, by extension there is a great deal of commonality
between the five different electric utilities in the Railbelt
that use natural gas as their primary generation.
2:31:33 PM
MR. STEYER moved to slide 4, "Chugach's changing gas situation,"
and said Chugach's gas situation has changed quite a bit over
time. From the 1960s to the 1980s Chugach's contracts were very
large volumes, long-term, and with inexpensive gas. Three
separate producers were involved and provided full service in
that they did everything and were responsible for getting gas to
wherever Chugach needed it. The gas that Chugach bought met the
needs of multiple utilities because Chugach had long-term
contracts where it generated power and sold it to the other
utilities. From the 1980s to the 2010s things changed a bit.
Chugach was able to secure large volume, long-term contracts at
a reasonable price versus inexpensive. Another producer was
added, so during this time period Chugach had four producers
providing full service and the gas that Chugach purchased
continued to meet the needs of multiple utilities. Currently,
the 2010s to the 2020s, the contracts are for smaller volumes,
of shorter duration, and of limited service. Chugach does much
more of what is necessary to ensure it has gas delivered to the
point where it is burned. There are still multiple producers
and today the gas that Chugach purchases meets the needs of
Chugach retail customers as well as the Seward electric system.
Addressing Representative Tarr's earlier question about CINGSA,
Mr. Steyer explained that CINGSA gains a benefit through
Chugach's contractual share of CINGSA. So, the Seward electric
system benefits in CINGSA through Chugach's contract since
Chugach is Seward's wholesale power provider.
2:33:52 PM
REPRESENTATIVE JOSEPHSON requested an example of full service
versus limited service.
MR. STEYER replied that in the old days Chugach would say the
amount of gas that it needed per day and had multiple power
plants where it might burn that gas. The producers provided
that amount and delivered the gas where Chugach needed it.
These days, although perhaps over-simplified, Chugach now says
the amount of gas it needs per day and the producers say where
they can provide it and if Chugach wants to use it elsewhere it
is the utility's responsibility to have a contractual
arrangement with somebody who owns a pipeline along the way to
where Chugach wants to use the gas. There has been a shift to
the utility in better defining its daily requirements, actually
hour-by-hour requirements, and in arranging for a transmission
path that was formerly provided.
2:35:08 PM
MR. STEYER brought attention to the photographs on slide 5 to
point out that Chugach Electric Association is not solely, but
is mostly, dependent on natural gas. To some degree, he added,
this is true for the other utilities as well. Chugach has a
renewable energy portion of its generation portfolio that
accounts for 15-20 percent of the utility's generation need in
an average year. That is because that is all it is capable of
meeting. To some degree, Chugach needs less gas currently than
it used to because the utility makes more efficient use of gas.
For example, along with ML&P, Chugach built a new power plant
that uses only about three-fourths of the amount of gas to make
a kilowatt hour as the generation it replaced. In part in
recognition of the situation about the Cook Inlet Basin, Chugach
has tried to take steps to be as responsible a customer as it
can be. That said, natural gas is critically important to
electric generation in Southcentral Alaska.
MR. STEYER displayed slide 6, "Natural gas as a generation
fuel," stating that natural gas is the generation fuel that
provides about 85 percent of the needs of multiple utilities in
Southcentral and to some lesser degree in the Interior through
purchases of Southcentral generated gas. Uncertainty about the
supply or the deliverability of that gas creates concern.
MR. STEYER drew attention to slide 7, "What does [uncertainty]
look like?" He related that in 2009, Chugach, other utilities,
the Municipality of Anchorage, and the boroughs north and south
of Anchorage collaborated in putting together the Energy Watch
Program. A poster was put together with a chart [outlining the
actions for customers to take] because there was concern about
what happens if at any time, but especially during a cold dark
night, there is not enough gas deliverability to meet everyone's
needs. Preparation was made for an energy emergency, a place
that Chugach does not want to go back to.
2:37:52 PM
MARK FOUTS, Director, Corporate Planning & Analysis, Chugach
Electric Association, Inc., began his portion of the PowerPoint
presentation. He said that when he started with Chugach about
25 years ago, the utility signed a gas contract with a major
producer for 250 billion cubic feet (Bcf) to be used when
Chugach would like to. After that had been used up 20 years
later Chugach asked the producer for more gas and was told about
2 years with an option for 2 more at the producer's option. The
producer had found another place in the world to make more money
and was done with the gas business in Cook Inlet. Given the
price of oil in 2009 and 2010 that's where that producer went.
ConocoPhillips Alaska, Inc., ("ConocoPhillips") was also a major
producer at the time and offered Chugach three years but without
any swing, just flat gas. There was no storage facility in Cook
Inlet at the time that Chugach had to make that decision.
Addressing Representative Josephson's question about service, he
said Chugach had the full service. The dispatch centers for
electric didn't even schedule gas, they just showed up at the
power plants whenever Chugach needed it. By the time the major
producers had left, Chugach was doing the transport, storage,
swing, everything.
MR. FOUTS showed slide 8, "2 key terms," and said that what he
wants to share is not so much the story of what it was like in
2009 and 2010 when Chugach was looking for more gas supply for
another 20 years, but rather that it comes down to two key
terms: volume and deliverability.
MR. FOUTS noted that the chart on slide 9, "Cook Inlet Gas
Supply," was put out by the state in 2011 to explain that these
four major gas fields in Cook Inlet are declining. The decline
curve on the graph goes down to the right. In 2010 and 2011, in
recognition that Chevron and Marathon were leaving the Cook
Inlet, the state went to Houston [Texas] and looked for another
producer. That producer became Hilcorp. Not seen on this chart
for the last five years is what Hilcorp did - it stopped the
decline. "Five years ago," he said, "we had 1.2 Cs of P2 gas
and today we have 1.2 Ts." That was very valuable for Chugach
in terms of supply and volume.
2:41:05 PM
MR. FOUTS drew attention to the chart on slide 10, "Chugach
Electric's Gas Supply, Gas Supply by Contract and Ownership," to
show how much gas Chugach uses and where it gets its gas from.
This year, he said, part of Chugach's gas will come from
ConocoPhillips, the last year of a six-year contract. For the
next seven years Hilcorp will largely provide Chugach's gas
supply. Chugach is also part of a 10 percent interest in one of
the largest fields in Cook Inlet [Beluga Gas Field] to provide a
small portion of its gas supply. Of this 10 percent of the gas
being produced in Cook Inlet, Chugach uses that 10 percent. By
2023, that is it, that is seven years of supply. In 2010/2011
Chugach was four to five years away from running out of gas, so
to say. Actually, the problem was running out of people willing
to invest in Cook Inlet. The state solved that by bringing
Hilcorp to Alaska and Hilcorp made that investment of $200-$300
million every year and things are now where they are today.
MR. FOUTS said his concern from having been at the negotiating
table five years ago with Marathon, Chevron, and ConocoPhillips
is that when producers get ready to pack their bags and leave
for someplace else, the first thing they do is to stop
investing. When the well waters up they don't do any more with
it, and that is exactly what happened. If in two to three years
Hilcorp, Furie, BlueCrest Energy, Inc., AIX Energy Inc., Aurora,
Cook Inlet Energy, or NordAq Energy Inc. all decide that there
is a better place to invest their money, in two years [Chugach]
will be right back where it was in 2010, which is five to six
years away from nobody willing to invest in Cook Inlet. Chugach
has made a $356 million investment with ML&P on a power plant
that is designed to last until 2048, and there is a seven-year
supply that is certain. Chugach would really like to have a
longer-term lead time than being lead time away to find an
alternative supply. In 2010 the electric utilities were meeting
weekly to try to figure out where they were going to get gas
from. The utilities talked to parties who could build ships and
to parties with sources of LNG and compressed natural gas (CNG)
from around the world. The story on supply is very important
and that story depends on investment.
2:43:34 PM
MR. FOUTS turned to the chart on slide 11, "Chugach Electric's
Gas Supply, Hourly Gas Demand for the Year," and said the other
aspect of Chugach's business is deliverability. He noted that
ENSTAR has expressed that it has almost all the deliverability
it needs. In the electric business, he explained, Chugach has
30 percent extra capacity in its generation so that when a
generator trips or equipment fails the utility still has enough
electricity to meet the need. Chugach subscribed to enough
deliverability from CINGSA to again provide that redundancy.
Chugach can meet the instantaneous peak seen on the chart, which
is an hourly projection of Chugach's gas needs with the base
depicted in blue and the peak in red. What ENSTAR was speaking
about was in terms of the daily rate, but on an hourly basis
even more swing is required. Chugach has purchased enough
deliverability from CINGSA to not only meet the need throughout
the winter but even weather and equipment failure when one or
two peaking units have to be turned on.
MR. FOUTS showed slide 12, "Gas Storage Meets Peak Gas Demand,"
to discuss how Chugach looks at each day when using its gas. He
explained that the gas is received on a continuous basis all day
long. During evening hours the electric load goes down because
the lights are out while people are asleep, but Chugach is still
getting that 22 Mcf a day so it is put into storage. When
everyone wakes up the load increases, but the supplier does not
provide enough gas and so that gas is pulled out of CINGSA.
Unlike ENSTAR that mainly uses CINGSA to meet the winter peak,
Chugach uses CINGSA every day. The CINGSA facility is critical
for meeting Chugach's load and provides the least-cost fuel
supply for Chugach because the utility is buying all its gas at
flat rates. Chugach has invested in CINGSA with a $100 million
commitment for 20 years. It would have been nice to have a 30
or 40 year commitment, but 20 was available.
2:46:08 PM
MR. FOUTS moved to slide 13, "Conclusion," and said his point is
that Chugach Electric Association has its gas needs met in terms
of volume for seven years, has its storage facility for another
16 years under contract, and has a generation asset that is good
until 2048. If Chugach finds itself in the situation of being
five years away from a fuel supply that is uncertain, Chugach
will be right back where it was in 2010. When the question is
asked about whether there is enough supply and enough
deliverability in Cook Inlet, he would say that when there is
enough supply to go out 15-20 years the problem is solved.
There are agreements to accommodate ENSTAR when it calls him to
say it is "10 short" and asks to borrow some of Chugach's gas
for the next eight hours. But, he said, his opinion in regard
to the state is that ENSTAR should be able to commercially go to
the marketplace in Cook Inlet and buy an extra 10 percent of
deliverability so that when a compressor goes down on a platform
ENSTAR can just call up the other platform owner and ask for an
extra 10 million a day. If there were metrics going forward, he
advised, there would be two new gas platforms, at least, in Cook
Inlet that could do 50 million a day, plus what Hilcorp is
doing, plus what CINGSA is doing, and then [the utilities] would
be covered.
MR. FOUTS recapped that in 2009-2011 the Department of Natural
Resources (DNR) came out with its study of the [Cook Inlet]
decline. Hilcorp came in and said it would cover [Chugach's]
volume and would almost cover [Chugach's] deliverability.
Deliverability is extremely expensive, he said. Spending $100
million and trying to get it back in 10 days on selling gas at
$7-$8 doesn't pay for itself. In 2015 the state said there was
1.2 Tcf of proved plus probable (2P) reserves, as was related by
enalytica last week. That is 0.7 Tcf of proven (the infill) and
0.5 of probable (what is hoped is there), a 50 percent
probability. So, there is five to ten years of gas that the
state believes is had. Hilcorp will do seven years. However,
Hilcorp will have to drill over the next five to seven years
because it doesn't have all this gas behind the pipe, and will
be drilling in the probable areas. As the committee heard from
Hilcorp yesterday, $12 million was spent drilling a well that
was unsuccessful. Hilcorp will be doing a lot more drilling as
these fields decline. There are lots of stories of looking for
gas that is being counted on, only to find zero. Security is
needed in Chugach's fuel supply and he is looking at the
committee as an opportunity to express Chugach Electric
Association's perspective that long-term security is needed.
Chugach should not have to have the uncertainty of how it is
going to meet its electric load.
2:49:39 PM
REPRESENTATIVE TARR commented that a part of this discussion
needs to be the work to integrate the Railbelt utilities. She
said she is aware of legislation that would build efficiency
into the system. She requested Mr. Fouts to provide an update
on the progress in this regard.
MR. FOUTS replied there are multiple efforts to reduce the
amount of gas being burned by the electric utilities. The most
certain effort is what all the utilities already did - put in
brand new, highly efficient generation. Five years ago [the
utilities] burned 33 Bcf [a year]. By the start of 2017, [the
utilities] will be burning 28 Bcf [a year], cutting off 5 Bcf of
gas. The utilities are currently studying the dispatching of
all the generation together, which would save another marginal
level of gas, not near as significant as the 5 Bcf. The
utilities have minimized the gas usage through almost $1 billion
in investment in new generation. By economically dispatching
together, a marginal amount more will be saved but most of the
savings have probably already been accrued.
REPRESENTATIVE TARR inquired about the terms that are used in
regard to the aforementioned.
MR. FOUTS responded that there are several terms, but in general
there is Independent System Operator (ISO) and Unified System
Operator (USO). The idea is that all the utilities dispatch all
their generation optimally so no gas or no fuel is wasted. That
is the ISO.
REPRESENTATIVE TARR understood that that is the ongoing piece
that will only be a marginal reduction.
MR. FOUTS answered that the amount of gas being used for next
year when all the new power plants are on should be on the order
of 28 Bcf [a year]. If the utilities optimize their dispatch
there could be another 0.5 Bcf or 1 Bcf of gas that also could
be saved. Saving 0.5 Bcf is $8 million and $8 million for
forever is a lot of money.
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HSE RES 3.2.16 HB 247 ENSTAR Natural Gas Company.pdf |
HRES 3/2/2016 1:00:00 PM |
HB 247 |
| HSE RES 3.2.16 HB 247 Chugach Electric Presentation.pdf |
HRES 3/2/2016 1:00:00 PM |
HB 247 |
| HSE RES 3.2.16 HB 247 - Alaska Support Industry Alliance.pdf |
HRES 3/2/2016 1:00:00 PM |
HB 247 |