Legislature(2015 - 2016)SENATE FINANCE 532
04/13/2016 05:00 PM Senate FINANCE
Note: the audio ![]()
and video ![]()
recordings are distinct records and are obtained from different sources. As such there may be key differences between the two. The audio recordings are captured by our records offices as the official record of the meeting and will have more accurate timestamps. Use the icons to switch between them.
| Audio | Topic |
|---|---|
| Start | |
| HB254 | |
| HB314 | |
| SB206 | |
| SB130 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | HB 254 | TELECONFERENCED | |
| + | HB 314 | TELECONFERENCED | |
| + | SB 206 | TELECONFERENCED | |
| += | SB 130 | TELECONFERENCED | |
| += | HB 247 | TELECONFERENCED | |
| + | TELECONFERENCED |
SENATE BILL NO. 130
"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."
6:23:55 PM
BENJAMIN JOHNSON, CEO, BLUECREST ENERGY, DALLAS, TEXAS (via
teleconference), read from a prepared statement "BlueCrest
Testimony to Senate Finance Committee" (copy on file) on a
PowerPoint presentation:
Good afternoon Madam Chair and members of the
Committee.
For the record, my name is J. Benjamin Johnson, and
I'm the president and CEO of BlueCrest Energy Inc.
Since BlueCrest only has operations in the Cook Inlet
at this time, I will only speak to the issues
particular to the Cook Inlet, with a specific focus on
the following points:
First, I want to emphasize that, specifically with
regard to what BlueCrest is doing in the Cook Inlet,
the tax credit program is an extremely good investment
for the State.
Second, the State's investment in Cosmopolitan through
the credit program will provide significant future
positive value to the State, even at low oil prices.
And it is the State's investment through the tax
credits that has facilitated success in the
Cosmopolitan Unit. I'm going to show you that the
State's investments in the Cosmopolitan tax credits
will provide high returns even at low oil prices. In
fact, the tax credit investments under the current
laws can actually provide higher rates of return to
the State than the average investments in the
Permanent Fund.
Third, I will speak to several specific issues we have
identified in SB 130 and the CS from Resources.
Slide 2:
For your reference, the Cosmopolitan Unit is located
about three miles offshore in the Cook Inlet, a few
miles north of Anchor Point. All of the productive
area in the unit is on State leases.
Slide 3:
The Cosmopolitan Unit actually consists of two
separate development projects. There are numerous
productive gas zones directly above underlying oil
zones, and the gas reservoirs are not connected to the
oil reservoirs.
We haven't yet started developing the Cosmopolitan gas
zones. The offshore Cosmopolitan gas development is
now on hold, due to economic questions on tax credits,
costs and confirmation of stable long-term market
demand.
But development of the deeper oil reservoirs was more
straightforward. And two years ago, based on the tax
regime in the Cook Inlet under current laws, we
committed to begin development of the oil reserves.
BlueCrest is a small private company with a singular
focus of developing the Cosmopolitan Unit, and we are
very careful in development of our business plans.
This is a large project for our company, and we were
faced with the challenge of how to pay for development
of the new field. We teamed up with a group of oil
industry investors, and we very carefully created our
plan with them for financing the development of
Cosmopolitan.
Slide 4:
I have shown this conceptual slide in previous
testimony, so I won't go into the details. However,
the main point to see here is that any oil and gas
development is a long process. It takes a lot of
spending just to get to the point where we are
bringing in enough cash to cover our monthly costs
without additional investment or borrowing.
We estimate that it will have taken investments of
over $500 million to reach that point for
Cosmopolitan, and BlueCrest is within about 6-9 months
of getting there.
As you can see, we still have considerable additional
investments to make in drilling a few new wells later
this year that should provide enough cash flow to at
least make our debt service payments going forward.
And we've already committed to that spending, based on
the existing tax credit structure. So the timing of
any changes over the next few months is very important
to us.
Slide 5:
So let's talk specifically about Cosmopolitan. We've
been working on the oil development for over two
years, and right now, we are literally a few days away
from the very first commercial production of oil.
Next, we will bring in our new specialized drilling
rig and start drilling new wells to bring on the
production that can finally start paying off our
loans. And that new drilling cannot begin until the
second half of this year.
These photos show the progress we have made so far
with the onshore Cosmo production facility. The total
site is 38 acres, and contains the drill sites for up
to 20 wells and the facilities to process the oil. We
are almost complete in our construction process, and
we are now running the final operational tests today.
We will have our new drilling rig in place to begin
drilling the new wells by July 1 of this year.
Slide 6:
So let's look at what the tax credits from a
successful development project like Cosmopolitan
actually mean to Alaska. When the tax credits are used
for development of new proven reserves in the State,
they are - without question - a valuable low-risk
investment. The tax credits make new projects work,
and they bring new sources of long-term revenues to
the State for decades into the future. At Cosmo, we
are sitting on a large proven resource of future oil
and gas that now simply requires additional new
investments to bring it to full production.
On February 19, the DOR provided its analysis of the
financial impact to the State on development of a new
Cook Inlet oil field, assuming that no changes are
ever made to the existing tax laws. DOR's analysis
modeled an "example" Cook Inlet field that happens to
be somewhat similar to Cosmopolitan - but is more
expensive and less productive than the actual
Cosmopolitan oil development. So the DOR's
calculations are, in fact, conservative with regard to
Cosmo.
Slide 7:
This chart is a summary of the calculations the DOR
provided for their "example" field. It shows the total
net future benefit received by the State and
municipalities, as a function of various future oil
prices. It shows that, even for this conservative
example, the State would receive back 100% of its
investments in the tax credits if oil prices over the
entire field life average only about $35 per barrel
(assuming no changes to the current law). At about $59
per barrel average oil price, the State would receive
back triple its investment in the tax credits.
Slide 8:
The DOR also provided discounted-cash-flow
calculations for this example field, with a head-to-
head comparison to the investments by the Permanent
Fund. At any point on this chart greater than zero,
the State would earn a better return through its
investments in the tax credits than its investments in
the Permanent Fund.
This chart shows that, even in the case where there
are never any changes to the tax system in the Cook
Inlet, the State's investment in those tax credits for
the example field is still better than the average
investment in the Permanent
Fund as long as oil prices over the next 30 years
average only $44 per barrel.
Slide 9:
Now I'd like to show you BlueCrest's internal analysis
of the value to the State in keeping the Qualified
Capital and Well Lease Expenditure credits as they
apply to new oil wells drilled at Cosmopolitan. We
projected the net return to the State using a
conservative calculation including only the
incremental royalty for each single new Cosmopolitan
oil well drilled.
This chart shows the calculated return on investment
to the State from the WLE and QCE. A 100% return on
investment means that 100% of the tax credit would be
repaid to the State at an average oil price of only
$24 per barrel. At $40 per barrel, the total return
would be about 170%, and at $60 per barrel, the return
would be about 250%. So you can see that these
credits, at least for Cosmo, are likely to be a very
good low-risk investment for the State.
Slide 10:
The bottom line here is that, in periods of low oil
prices, the QCE and WLE credits allow us to continue
drilling the Cosmopolitan oil wells at approximately
$10 lower oil prices than without the credits. This is
likely to be an important factor over the next few
years and may allow us to continue drilling instead of
shutting down the rig.
For us, the NOL credit is less important as we begin
producing. So the most important credit for
continuation of drilling in a development like Cosmo
is the WLE.
Slide 11:
Under the CS, the tax credit repurchases would receive
priority for payment based on the resident hire
percentage in the prior year. While we certainly agree
that we want to hire Alaskans for our operations,
imposition of any reductions in credit payments for
expenditures that were made prior to the effective
date of a new law is truly a retroactive tax change.
For credits filed in 2016 (for 2015 expenditures) and
those filed in 2017 (for 2016 expenditures prior to
the new law taking effect), there would have been no
way for us to even keep records. Retroactively
changing the laws is grossly unreasonable. If this
provision is adopted, a longer transition time should
be considered.
Slide 12:
For the record, BlueCrest is strongly committed to
hiring Alaskans. At this point, 100% of all our long-
term operations employees are Alaskans. But making the
future credit payments subject to hiring in the past
is probably impossible to even measure. We can do it
going forward, but I don't know how we go back in
time.
Slide 13:
Another factor in SB 130 was setting a limitation in
the credits that can be paid annually. If this limit
is too low, it would be particularly damaging to small
companies like BlueCrest who have already invested in
good faith, based on the tax policy in existence when
we entered into the commitments for our investments.
We came to Alaska based on the credits. We invested
our cash, and we have borrowed a lot of money and
committed to spending a lot more - all based on the
tax credits. And the timing of the receipt of those
payments for the credits is paramount in our ability
to make the payments on the loan obtained for those
investments.
Slide 14:
Most important of any of these provisions to BlueCrest
is the timing of implementation of any changes,
whatever they may be. It is now April, and the
proposed changes in the original SB130 were supposed
to take place on July 1. The CS has somewhat moved
that date back, which would certainly help but may not
completely solve the problem.
It's important to understand that, before we ever
started the oil development project, we made sure that
we would have enough funds to allow us to complete
construction of the onshore drill site, production
facilities, bring in the most powerful drilling rig in
Alaska, and use that rig to drill at least the first
two new oil wells. We calculated that we would need
approximately $525 million to reach that point of
self-sufficiency (where we no longer have to keep
borrowing additional money to put into the project).
The timing here is very important, because we expect
that should happen in the first half of 2017.
As I mentioned a few minutes ago, based on existing
law, we very carefully planned how we could pay for
development of the Cosmo project before we ever
started. Our shareholders invested approximately $200
million in cash. We borrowed $30 million from AIDEA
for a loan on the drilling rig (kind of like a car
loan but for a drilling rig). We have already received
a total of $24 million to date in tax credits. Under
current laws, $121 million would come from future
payment of credits earned for 2015 and 2016 spending
(that's the total for two years). We then made up the
difference by securing a $150 million high-interest
development loan. We have spent a lot of money to get
to the point where we can now start drilling these new
wells, but an abrupt termination of the tax credits on
which we have based our entire financial planning
would be devastating. Any reduction in the credits for
our spending through at least early 2017 would mean
that we have to come up with that money from some
other source. That's not easy in this oil price
environment, and it may just simply be unworkable.
We have finally reached the point - by completing all
this work and spending all this money- to where we
will finally have our rig ready to drill in the second
half of this year. We need the production from the
first new wells to pay for the costs we have spent so
far. Those drilling costs - at least through early
2017 - are all based upon the assumption that we will
be able to obtain the credits under existing law for
those investments. We have done all this work and
spent all this money to date, and it seems only
reasonable for us to be able to claim the existing
credits for the spending that is the result of our
investments based on the expectation that the State
would honor its share of the investments. We need to
be able to be able to get to the finish line. If the
date for changes is too soon, we won't have the full
funding for finishing the project, although we have
already committed those investments. We've signed
contracts, bought a drilling rig, built facilities -
all based on the current laws in effect.
Slide 15:
In conclusion, I'd like to reemphasize the importance
of phasing-into any changes over a reasonable time
period.
Everyone in Alaska understands that when we are
driving on slippery icy roads, the most dangerous
thing we can do is suddenly slam on the brakes.
Thank you.
6:33:44 PM
Co-Chair MacKinnon pointed to slide 14 and mentioned the
Alaska Industrial Development and Export Authority (AIDEA)
loan that the state provided for $30 million. She wondered
if the development loan was with an entity other than the
State of Alaska.
Mr. Johnson responded, "Yes, the development loan is with a
private lender".
Co-Chair MacKinnon referred to the tax credits received to-
date wondering if she should subtract the amount from the
2015-2016 time period or if it was in addition.
Mr. Johnson replied that it was in addition and that the
total credits associated with the project would equal $145
million.
Co-Chair MacKinnon wanted to confirm her math.
Vice-Chair Micciche asked if Mr. Johnson could provide
slide 7 and slide 8 without the municipal revenues. He
wanted to see the state royalty figures by themselves.
Mr. Johnson explained that the slides were a result of the
Department of Revenue's calculations. He thought Director
Alper would be able to supply the information. He did not
have the underlying data, only the final numbers.
6:35:48 PM
BRUCE WEBB, FURIE OPERATING ALASKA, ANCHORAGE (via
teleconference), relayed that Furie came into existence
through Escopeta Oil Company in 2010. Since that time,
Furie brought the first jack-up rig to Alaska. Furie
recently installed the first offshore platform in about 2
decades. It was comprised of 16 miles of subsea pipeline
and a new gas processing facility in Nikiski, Alaska. Over
the previous 5 years the company had invested approximately
$700 million in the wells, pipeline, and processing
facility. During the peak of construction the company
employed over 300 people in Alaska and invested about $200
million. He mentioned that the offshore season in the Cook
Inlet was from April 15th to October 31st of every year.
During the period outside of the drilling season Furie
still had to pay for storage for the jack-up drilling rig.
Offshore development was very expensive. At the beginning
of the project Furie viewed the State of Alaska as a
partner. The company made all of its financial decisions
based on the tax system in effect at the time.
Mr. Webb continued that the result of the company's impacts
on exploration and development was the local Cook Inlet gas
market. The company recently signed contracts with Homer
Electric Association, Inc. and ENSTAR Natural Gas Company.
As a result of those contracts beginning in April 2016 the
cost of energy to consumers in the Kenai Peninsula was
lowered by 12 percent. In 2018 the cost would be about 16
percent lower than the cost in 2015. He furthered that
Furies' contract with ENSTAR Natural Gas Company would
begin in 2018. In 2018 the cost of gas to ENSTAR customers,
roughly half of the population of Alaska, would be reduced
by 17 percent. Aside from the direct influence Furie has
had on the local gas market the company had also seen it
trickle down to other companies. The Chugach Electric -
Hilcorp contract resulted and would lead to an 8 percent
reduction in costs to their customers. He explained that
the reductions were due to the competition Furie and other
small independents brought to the market.
Mr. Webb opined that without the tax credit program Furie
would not have been able to undertake the project.
Otherwise, it would have been too risky in the beginning
and too expensive towards the end of development. The tax
program was needed in order to meet obligations Furie
entered into years ago. Going forward, if there was a
change in the tax credit program the company would have
time to adjust. He noted that the way the governor's bill
was currently structured. The tax credit program would
change in 2016 and would be devastating to the company.
Some certainty through the rest of the current year was
necessary in order for Furie to fulfill its commitments
that were made in 2013 and 2014. He deferred to David Elder
to provide further testimony on Furie's behalf.
6:39:37 PM
DAVID ELDER, CEO, FURIE OPERATING ALASKA, HOUSTON, TEXAS
(via teleconference), had three important points he wanted
to cover in terms of tax credits and the proposed changes.
The tax credits were intended to incentivize companies to
make investments in the industry. Furie moved quickly and
raised capital to come to Alaska. The company brought the
first major production to Nikiski and the Anchorage area
from the Cook Inlet since the 80's.
Mr. Elder relayed his second point. Furie was in the final
phases of its project that began in 2013. In Furie's
business it had to plan several years ahead in order to
meet logistics of such a project. In addition, the company
had to enter into financing commitments in 2013 and 2014.
Furie needed certainty going forward and the opportunity to
at least finish what it started based on the existing law.
Mr. Elder' third point was that the tax credits had been an
important source of liquidity and had enabled Furie, a
development stage company, to obtained economical
financing. Thanks to the tax credit program Furie had seen
its financing costs drop from about a 20 percent range to
an 8 percent financing cost. As a result of the uncertainty
of what legislation might pass and whether credits filed
for in the previous year would be paid, it was more
difficult to secure financing. People had pulled away from
the markets. The most recent bid for financing off of the
current year's tax credits was about 60 percent of the face
value of the credits. He was certain the legislature and
the people of Alaska would rather see the additional 40
percent invested in important infrastructure and energy
production which would result in employment and other
activities. Moving forward, Furie was asking the
legislature for some certainty to make sure Furie was
funded for expenditures already made and to allow the
company to complete the project without mid-year changes to
the tax credit structure. He was available for questions.
Co-Chair MacKinnon indicated that there were no questions
for members and thanked him for his statement. She invited
the next testifier to begin his testimony.
6:43:25 PM
TONY IZZO, GENERAL MANAGER, MATANUSKA ELECTRIC ASSOCIATION,
ANCHORAGE (via teleconference), explained that the utility
was the second largest electric utility and the third
largest buyer of natural gas in the Cook Inlet. His
background included having been at ENSTAR Natural Gas
(ENSTAR) from the late 90's to about 2007, serving as the
president from 2001 through 2006. His testimony was
intended to give his perspective as a buyer of gas in the
Cook Inlet and about cause and effect. The business was a
long lead time capital-intensive business. He spoke to
witnessing the changes in the Cook Inlet market. He noticed
that the excess natural gas discovered while exploring for
oil in the late 50's and 60's was coming to an end. Gas
could not be purchased under the terms the state had been
able to for prior decades nor could gas be found for sale
under legacy terms. He continued that something different
occurred when the market shifted - a Henry Hubb linked
contract in the amount of 450 Bcf [billions of cubic feet]
was entered into in 2000 or 2001. It had a trailing average
of Lower 48 prices which was currently in the $2 range.
Unfortunately, regulators, some members of the public, and
certain legislators responded negatively about linking Cook
Inlet gas to a market that the state was not physically
connected to. As a buyer he was negotiating with entities
based outside of Alaska who had choices of where they were
going to invest their capital such as Alaska, the Lower 48,
or in other places in the world. He reported being able to
enter into a long-term contract that required millions of
dollars in investment. He thought the number was exceeded
by a factor of three. As a result of some negative public
reactions to prices being linked to the Lower 48, ENSTAR
entered into another 36-month contract in 2005 with
Marathon and would have filled all of ENSTAR's gas
requirements through 2016 at a price of the 12 month
trailing average of the Lower 48. As a buyer he was
currently paying $7.42 for gas. If Lower 48 prices were
available he would pay about $2.00 for gas. The perception
of the contract and the pricing mechanism was so negative
that it was not approved. He observed that the state sent a
signal to the market and to investors that it was no longer
open for business. Over the following few years the
investments slowly dried up and assets in the inlet were
sold. In 2009 and 2010 the utility was looking at importing
LNG because only 20 percent of the contract fulfilled the
utility's demand for more than 1 or 2 years at a time. To
the legislature's credit the Cook Inlet Recovery Act
created and fostered an environment that brought investment
and new players back to Alaska. He found that prior to
Hilcorp purchasing the Marathon and Chevron assets he could
only purchase 20 percent to 25 percent of the gas Matanuska
Electric at about $10 per MCF [million cubic feet]. Upon
Hilcorp's arrival in the aging and mature fields they
improved production and made gas supply available for
purchase to utilities through 2018 which Matanuska Electric
took part.
6:49:30 PM
Mr. Izzo continued that the price was negotiated by the
attorney general through a consent decree to address a
Federal Trade Commission concern. He thought Hilcorp had
done a great job. However, currently the state had new
players investing real capitol. He reviewed some of the
industry companies that have brought on production. He was
afraid of sending the wrong signal to industry investors
which would likely lead to dried up investment. The
unintended consequence was insecurity. He thought the good
and bad news was that the state had temporary energy
security. Many of the new reserves were not behind pipe
which required millions of dollars in investments. It would
be in the better interest of his customers for him to
purchase imported LNG at the right price than to risk
entering into the exploration and production business to
bring new reserves online. He concluded that, based on his
experience, uncertainty was the enemy of energy security.
He believed the state was very close to seeing real results
from the Cook Inlet Recovery Act and the tax credits in
place currently. He clarified his understanding of the
monumental task before the legislature regarding the
state's fiscal gap. He hoped the legislature would take
action that would minimize uncertainty and help to get to
the results that were sought in growing the market.
6:52:41 PM
Co-Chair MacKinnon wondered if the legislature should
institute a tax on all rate payers so the state could pay
the credits to secure the energy.
Mr. Izzo replied that a tax would be like a fuel surcharge.
He was not taking a position that the state should leave
the credits alone or significantly change them. His
recommendation was that whatever action, it should be taken
sooner rather than later to eliminate uncertainty. He added
that when the governor postponed paying the $200 million in
tax credits with a veto a gas deal between Matanuska
Electric and a new Cook Inlet producer evaporated. It was a
combined supply with another utility that would have saved
$10 million per year.
SCOTT JEPSON, VICE PRESIDENT, EXTERNAL AFFAIRS, CONOCO
PHILLIPS, ANCHORAGE (via teleconference), noted that Conoco
Phillips was not a member of AOGA. He introduced the
PowerPoint presentation, "Senate Finance Committee CSSB130
- April 13, 2016." He turned to slide 2: "Agenda." He took
a few minutes to discuss the current economic environment
and what had happened since the passage of SB 21
[Legislation passed in 2013 - Short Title: Oil and Gas
Production Tax]. He relayed he would also be talking about
the company's concerns with SB130 and the committee
substitute.
Mr. Jepsen addressed slide 3, "Activities Since Tax Reform
(MAPA) Passed." He reported that since MAPA was passed
Conoco Phillips had followed through on what the company
stated could happen with a more attractive investment
climate on the North Slope. The company had added a number
of rigs to its fleet as well as two new-build rigs. Conoco
had taken delivery of one of the rigs and was expecting to
take possession of the second later in the current year.
Since the passage of SB 21 the company had gone from 3 rigs
in the western North Slope rig fleet to between 5 and 6
rigs. Currently, Conoco had 4 running and anticipated 5
running later in the year when it took delivery of one of
its new rigs.
Mr. Jepsen continued reporting that Conoco only had 3 rigs
operating in the remainder of the United States. The
company's activities in Alaska were differential at
present. He had a list of other investments that Conoco
Phillips had made since the passage of SB 21. He would not
review it but would briefly discuss activities in the
National Petroleum Reserve Alaska (NPRA). The company
currently had a new field in progress, Greater Moose's
Tooth 1 (GMT1), and there was another field 9 miles from
GMT1 called Greater Moose's Tooth 2 (GMT2) which was in the
process of being permitted. He noted that none of Conoco's
new fields that came on stream since SB 21 was passed were
receiving the gross value reduction (GVR). Some of the
production on CD5 and drill site 2S could qualify for the
GVR. However, some of the requirements necessary made it
not cost effective for Conoco to pursue.
6:57:14 PM
Mr. Jepsen advanced to slide 4, "Capital Spending Trends."
He explained that the slide addressed what was happening
with the capital spend as a corporation operating in Alaska
as well as oil price. He figured everyone was very familiar
with what had happened with oil prices. He pointed to the
plot in the upper left-hand corner which showed the effects
of the decrease in oil prices on Conoco's capital
investment. There was a commensurate drop in the company's
capital investments. On the right-hand side there were some
statistics outlining the company's activities in Alaska.
The company's capital spend peaked in 2014, but even with
the decline in oil prices it still anticipated spending
about $1 billion in 2016. He noted that the amount spent
during the years of Alaska's Clear and Equitable Share
(ACES), a time when oil prices were considerably higher,
was about 25 percent less that in 2016. He directed
attention to the bottom right-hand part of the slide that
showed what percentage of Conoco's corporate capital was
being spent in Alaska. It was clear the company was making
a substantial investment in the state.
Mr. Jepsen discussed slide 5, "North Slope Investors
Negative at Current Pricing." He explained that the slide
was derived from the 2016 Revenue Sources Book. The left
side, the "Y" axis, represented net cash flow, and the "X"
axis represented ANS West Coast price. The chart showed the
relative position of the state compared to the producers at
current pricing as prices increased. Regardless of oil
price the state was always in a positive cash flow position
excluding reimbursable tax credits that might pay out. The
chart did not include the tax credits but included the per
barrel credits. Investors were in a negative cash flow
position. He stressed that it would difficult to increase
taxes on an industry that was in a negative cash flow
position without it impacting investments. In 2015, Conoco
Phillips experienced a negative cash flow of more than a $1
million negative cash flow in Alaska. The company did not
incur any net operating losses (NOL's). He was uncertain if
the company would be in the same position in 2016.
6:59:41 PM
PAUL RUSCH, VICE PRESIDENT, FINANCE DIVISION, CONOCO
PHILLIPS, ANCHORAGE (via teleconference), turned to slide
6, "Key Concerns with Original SB 130 Bill." The slide
identified areas associated with SB 130 that caused the
greatest concerns for Conoco Phillips and had the greatest
potential to negatively impact its investment in Alaska.
His comments would address the original bill but, he would
make a few comments regarding the committee substitute. He
relayed that the case made against the increase in the
minimum from 4 percent to 5 percent was made in the
previous slide. He reiterated that the industry was
currently in a negative cash flow position and would remain
so at prices up to approximately $50 per barrel of oil.
Increasing taxes while the company was experiencing losses
would lead to reduced investment.
Mr. Rusch next argued that hardening the minimum tax floor
effectively served as a tax increase. Under SB 21 companies
were currently allowed to reduce their tax below the
minimum with the use of NOL's resulting directly from
losses businesses were incurring in Alaska. The particular
treatment was consistent with federal income tax treatment
which allowed recognition of losses and periods where a
company was no longer in a loss position. Eliminating or
delaying the use of the NOL's would result in companies
reducing expenditures in Alaska for which they would no
longer be receiving a tax deduction. Although it was an
important issue for the industry to help support investment
during periods of low prices, the size of the future
obligation had likely been exaggerated by the DOR in some
of their recent testimony. There were companies that would
adjust to the lower prices and would not continue to
experience losses at the projected levels. Conoco Phillips
did not have an NOL in 2015 and current prices were more
challenging.
Mr. Rusch moved to the next item which surrounded the
increase in the interest rate. He highlighted that
increasing the interest rate on lower or under paid taxes
was an issue due to the lengthy time involved in completing
and closing out audits. The issue was caused by the current
6-year statute of limitations. He provided two related
examples. Conoco Phillips just recently received its 2009
production tax audit - 6 years and 3 months after the
completion of the tax year. The company also recently
closed out its 2006 production tax audit - 9 years after
the end of the audit. It could lead to tax assessments when
the interest component was as much or greater than the
underlying audit findings. The Senate Resources' committee
substitute was an improvement, as it reduced the interest
period to 3 years and could lead to shorter audit periods.
The company was concerned that the applicable interest rate
was still too high. The federal rate was approximately 3
percent compared to the 7 percent plus the federal discount
rate in the committee substitute.
Mr. Rusch argued that restricting the use of per barrel and
other tax credits to a specific month contradicted the
underlying principle of an annual tax. He noted that the
slide referenced per barrel credits. However, expressed
earlier in Exon's testimony, it potentially had much
broader implications. It was discussed in detail in prior
testimony by the DOR. The concern the department raised was
that companies were migrating per barrel credits between
months. Conoco Phillips completely disagreed with the
characterization. It was clear in the statutes and in
regulations that the production tax was a yearly tax with
monthly installments made. He emphasized that it was an
annual tax and any attempt to characterize it differently
was incorrect. The proposed changes by the administration
was a radical from the principle of a yearly tax.
Mr. Rusch brought up that the confidentiality and
disclosure provisions were much too broad in SB 130. The
company recognized the desire for greater transparency,
particularly around reimbursable credits. As currently
written, SB 130 could potentially lead to the disclosure of
all tax payer information which violated competitiveness
and potentially conflicted with Internal Revenue Service,
FCC, and other regulations.
7:04:48 PM
Mr. Jepsen addressed slide 7, "Observations." Conoco
Phillips favored the committee substitute over the original
bill. However, the company had some concerns. First, there
were concerns about the interest terms. There were also
concerns about the time limitations on the use of the GVR
which negatively impacted the economics of the development
of new oil and would be a consideration as the company
looked at its new investments. He added that it did not
help Alaska compete in Conoco Phillips' overall portfolio.
He also questioned the impacts of the removal of the
ceiling tax on North Slope gas used in-state. The company
was unclear about the goal of the policy and the potential
impact of their business on the North Slope.
Mr. Jepsen concluded that there had been several tax
changes in Alaska over the previous ten years. He advocated
for a stable, durable fiscal policy for oil investment and
investment on any major North Slope gas project. A stable
tax regime would foster confidence and further investment
in the state. It had only been 19 months since SB 21 had
been ratified by voters and another change to the tax
regime was being contemplated. Conoco Phillips appreciated
the challenge legislators had in front of them. His goal of
the presentation was to provide some insight in terms of
how tax policy affected the company's investments.
Vice-Chair Micciche wondered about the time limit on the
GVR and referred to slide 7. He noted that enalytica
[Legislative oil and gas consultant] had shown that the
lower the price of oil, the greater the impact for
companies over a longer period of time. At a higher price
the limit on the GVR would have less of an impact on the
value of the project. He wondered if an alternative time
limit would be better.
Mr. Jepsen answered that any kind of change to the time
limit was negative. He thought enalytica had done work to
show relative impacts. He would leave it to the committee
to determine the appropriate balance point. Obviously,
anything that reduced the time period reduced the
competitiveness of the project.
Co-Chair MacKinnon thanked the presenters from Conoco
Phillips. She invited the last presenter to begin his
testimony.
JARED GREEN, PRESIDENT, ENSTAR NATURAL GAS, ANCHORAGE (via
teleconference), introduced the PowerPoint, "Presentation
to the Senate Finance Committee, April 13, 2016" (copy on
file). ENSTAR was the largest purchaser of natural gas in
the Cook Inlet. Ultimately, their customers were
beneficiaries of the tax program that had been in place
since 2010. Their customers depended on natural gas from
the Cook Inlet to heat their homes, businesses, schools,
hospitals, and industries. Fundamentally, ENSTAR's interest
was in the fostering of a stable and appealing natural gas
environment in the Cook Inlet. He claimed that the
environment needed to exist in the short-term, medium-term,
and the long-term.
Mr. Green looked at slide 2, "Natural Gas Supply Needs."
141,075 Customers
Anchorage, Anchor Point, Big Lake, Girdwood, Homer,
Houston, Kenai, Palmer, Soldotna, Wasilla, and
Whittier
33 Bcf/year
Peak deliverability 287 MMcf/day
ENSTAR's number one priority was safe, reliable natural gas
service to its customers. The company was founded in 1959,
the same year as statehood. On average their customers used
about 33 BCF of Natural gas per year. In a warm year, such
as the previous year, use could be as low as 30 Bcf or in a
cold year upwards of 35 Bcf. Recently enalytica prepared a
report that indicated total state use at about 80 Bcf.
7:09:22 PM
Mr. Green addressed slide 3, "Supply and Demand." He
remarked that ENSTAR had a very high seasonality to its gas
needs. The company generally varied by roughly a 12 to 1
ratio of winter to summer gas needs which meant that their
customers burned about 12 times more gas on average in the
winter as what they did in the summer. He reported ENSTAR's
daily variability. Living in Alaska meant living in an
environment that could have substantial variability in gas
demands due to weather. With the current company customer
base they had a potential daily demand of 287 Bcf per day.
He pointed to the thin red line on the graph which
represented the 287 Bcf per day. Such a level of demand was
likely to occur in January of any given year. ENSTAR also
had the potential of meeting less than 100 Bcf per day if
there was a warm spell happening on the same day. There was
a significant variance to what could occur purely due to
weather. He highlighted the graph showing the variability
in their customers' daily demand as well as ENSTAR's daily
supply through the years 2014 and 2015. The chart contained
the actual data which the company supplied gas each of the
days listed for the years listed. Each of the natural gas
suppliers were represented by a different color on the
chart as well as how much gas was consumed on each day in
the 2-year period represented by the black line that
topped off the chart. He noted that the day-to-day
variability was marked. ENSTAR's customers' demands changed
as weather changed seen as the constant spike up and down.
The second piece was the seasonal variability. The 12 to 1
ration could be seen with the summer troughs and the hills
through the winter.
7:11:12 PM
Mr. Green looked at slide 4, "Supply Contracts 2016-23." He
stated that when ENSTAR planned its natural gas portfolio
they looked at many years in advance. Operating in such
small, closed supply networks such as the Cook Inlet
required very long lead times. The company needed to know
that there was firm gas supply for their customers at least
2 years in advance. Anything less put the market place at
risk of supply shortages. In ENSTAR's business they had to
have gas available for their customers on the coldest days
no matter the circumstance. He expanded that when it was 20
degrees Fahrenheit below zero on a dark January evening
every single one of 141,075 customers had to have their gas
needs met. Their number of customers represented over 50
percent of the population of Alaska.
Mr. Green posed the question of what it meant to be a
natural gas supplier to ENSTAR. There was no doubt that it
was challenging to supply natural gas in the Cook Inlet in
current times. ENSTAR was the largest purchaser of natural
gas and they had very demanding needs. Between the storage
facility, Cook Inlet Natural Gas Storage Alaska (CINGSA),
and their producer contracts the company needed to have the
287 MMcf of gas available in case it was needed. However,
they did not need it every day. It meant producers and
CINGSA needed to have significant capacity beyond the
average production rates. It also meant that producers
needed to have the operational capability to ramp up
production and also the ability to throttle it back. Alaska
was a very different world than the Lower 48. With the
integrated transmission and storage network, producers in
the Lower 48 could simply drill a well, open up the taps
100 percent, and the large market simply absorbed it. From
a utility perspective it was a nice, easy road. Utilities
had a line-up of marketers that were trying to sell them
gas. In a case where a contract was not fulfilled for any
reason the utility went back to their trading screen and
sourced the gas from one of the 1000 other suppliers lined
up to sell it to them. ENSTAR did not have that luxury in
Alaska.
Mr. Green explained that the market was very small and ill-
liquid, with only a handful of buyers and an even smaller
number of suppliers. Layer on to that the fact that Conoco
was selling its assets which would take another supplier
out of the market. It would also shrink the buying market
with Municipal Light and Power becoming largely self-
supplied. It left ENSTAR in an extremely delicate market
place. He was not saying that the sky was falling. The
company was in a much better place than in 2010.
Mr. Green continued that ENSTAR had transitioned from a
time where they were looking at shortages, the total
supply, and from a deliverability perspective. He was
pleased to inform the committee that in the current day
ENSTAR received the Regulatory Commission of Alaska's (RCA)
approval for their gas supply agreement with Hilcorp which
extended through 2023. The contract was a key foundation in
the company's supplier portfolio, as it provided both a
significant quantity of gas and a significant level of
winter deliverability. The Hilcorp contract would supply
approximately 70 percent of ENSTAR's customer needs from
2018 through 2023. It had both firm and optional volumes
and would supply approximately 22 Bcf per year of firm gas
supply. It also offered optional volumes to help the
company manage its' weather-related variability. It meant
that ENSTAR could ramp-up deliveries up or down depending
on customer needs - a key feature in light of their
variable annual demand.
Mr. Green informed committee members that one of the most
important features of the contract had to do with what it
did not do. It did not meet all of ENSTAR's gas supply
requirements. The company had left 30 percent of their
supply portfolio open for other producers to fill in. As a
public utility the company valued safety and reliability
above all and understood the need to have a diversified
supply portfolio. It not only diversified supplier risk but
also helped foster investment and drilling which was good
for the long-term stability of the Cook Inlet supply.
Mr. Green reiterated that the contract took ENSTAR through
2023, just beyond the short-term window. He mentioned
ENSTAR's 3-year gas supply contract with Furie. The
contract supplied about 20 percent, the signing of the
contract was key for Furie to continue the development of
its new Kitchen Lights Unit. ENSTAR wanted to see the
success of the field and wanted to see it brought into
production.
Mr. Green thought he had fairly good visibility into the
company's supply into 2021. He suggested that with the
continuation of activity by Hilcorp and by Furie along with
the hope of growth of the others in the Cook Inlet, he was
optimistic that the company could see its supply horizon
out to 2025. However, it hinged on the continued activities
of current and new producers. He opined that encouragement
and fostering of the environment would be necessary to keep
producers engaged. He strongly believed that the utilities
in the inlet had a responsibility for encouraging and
fostering the environment. He noted ENSTAR's contribution -
the company had provided support for Furie's development of
the Kitchen Lights Unit and left 10 percent of its supply
portfolio for other producers. The Regulatory Commission of
Alaska had also shown its commitment to the viability of
the long-term Cook Inlet gas supply with its approval of
the Hilcorp contract and its narrative in the letter
supporting ENSTAR's gas supply diversification approach.
The commission recognized that ENSTAR's approach set aside
and carved out a portion of its supply portfolio to
encourage the development of small independent producers.
Since 2010 the state had provided a huge support to the
viability of the gas supply market in the Cook Inlet.
Mr. Green acknowledged ENSTAR being cognizant of the short-
term budget challenges facing the state. The company would
love to see the state continue to help the encouragement of
the market place in whatever form that kept it as an
attractive investment.
Mr. Green concluded that ENSTAR was in a -good place in the
Cook Inlet at present. However, the company was sitting in
a position where there was one well going into the Kitchen
Lakes Unit. He emphasized that there were no production
wells in Cosmo. There were 4 large fields in the inlet that
were old and aging every year. With cold weather or even if
one of the existing platforms or fields had an issue,
ENSTAR did not have a large contingency of back-up
alternatives. He furthered that there were no interties to
the Lower 48 or Canada and they were 100 percent dependent
in the small ill-liquid market to keep half of the state's
population warm. He thanked members for their time.
7:18:12 PM
Vice-Chair Micciche queried the struggles prior to FY 16,
and the increase in supplies in Cook Inlet. He wanted to
better understand the credits' in improving the outlook as
well as the tax structure in Cook Inlet. Mr. Green replied
that much of the work that had been going on was with a gas
supply group. It was very much a joint project with all of
the utilities together from the Cook Inlet looking for the
solutions to a marketplace that was just looking for short-
-term contracts. Some of the gas the company had been
procuring was upwards of $23 per Mcf. The producers in the
marketplace were not willing to commit to long-term
contracts. ENSTAR was dancing along on a month-by-basis not
knowing whether the future would come together. There were
a few things that came into alignment with a lot of work.
There was the significant commitment and investment made by
ENSTAR's shareholders, Northern Natural, Siri, and First
Alaskan. They came together for the development of the
CINGSA storage facility, a key aspect in enhancing
deliverability in the inlet. The first winter that CINGSA
came online in 2012 was very cold. If the facility had not
been in operation both ENSTAR and Chugach Electric would
have had delivery shortfalls. Hilcorp coming to the market
place was also a very large component as well and their
commitment to getting their facilities working quickly. The
consent decree contracts that were put in place secured
ENSTAR's gas supply out to the first quarter of 2018. It
fashioned with some of the power utilities also. It was a
very real activity for the gas supply group to look at LNG
imports because ENSTAR was committed making sure its
customers had gas running through their meters. ENSTAR had
previously been in very dire straits looking for any
mechanism to get the methane molecules going through the
meters. The tax credits were integral in shoring up the
local market place with Hilcorp. Since then, Buccaneer
(currently in bankruptcy) drilled a well. Even though the
company was going bankrupt the molecules coming from their
well had been uninterrupted to ENSTAR for their contract.
Although there were financial challenges, the gas came
through.
Vice-Chair Micciche interrupted Mr. Green's testimony and
requested that he provide an illustration of the history
due to time constraints. Mr. Green agreed to provide that
information in the form of a timeline summary.
Co-Chair MacKinnon concluded the invited public testimony.
SB 130 was HEARD and HELD in committee for further
consideration.
She reviewed the agenda for the following day.