Legislature(2005 - 2006)SENATE FINANCE 532
04/06/2006 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB305 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 305 | TELECONFERENCED | |
| + | TELECONFERENCED |
MINUTES
SENATE FINANCE COMMITTEE
April 6, 2006
9:05 a.m.
CALL TO ORDER
Co-Chair Lyda Green convened the meeting at approximately
9:05:53 AM.
PRESENT
Senator Lyda Green, Co-Chair
Senator Gary Wilken, Co-Chair
Senator Con Bunde, Vice Chair
Senator Fred Dyson
Senator Bert Stedman
Senator Donny Olson
Senator Lyman Hoffman
Also Attending: JOHN P. ZAGER, General Manager, Chevron Alaska;
JOHN A BARNES, Production Manager, Marathon Oil Company
Attending via Teleconference: From an Offnet Location: KEN
THOMPSON, Managing Director, Alaska Venture Capital Group
SUMMARY INFORMATION
SB 305-OIL AND GAS PRODUCTION TAX
The Committee heard testimony from Chevron Alaska, Marathon Oil,
and Alaska Venture Capital Group. The bill was held in
Committee.
Co-Chair Wilken announced that public testimony on the FY 2007
operating budget would commence that evening and continue
through Saturday, April 8, 2006.
CS FOR SENATE BILL NO. 305(RES)
"An Act providing for a production tax on oil and gas;
repealing the oil and gas production (severance) tax;
relating to the calculation of the gross value at the point
of production of oil or gas and to the determination of the
value of oil and gas for purposes of the production tax on
oil and gas; providing for tax credits against the tax for
certain expenditures and losses; relating to the
relationship of the production tax on oil and gas to other
taxes, to the dates those tax payments and surcharges are
due, to interest on overpayments of the tax, and to the
treatment of the tax in a producer's settlement with the
royalty owners; relating to flared gas, and to oil and gas
used in the operation of a lease or property under the
production tax; relating to the prevailing value of oil or
gas under the production tax; relating to surcharges on
oil; relating to statements or other information required
to be filed with or furnished to the Department of Revenue,
to the penalty for failure to file certain reports for the
tax, to the powers of the Department of Revenue, and to the
disclosure of certain information required to be furnished
to the Department of Revenue as applicable to the
administration of the tax; relating to criminal penalties
for violating conditions governing access to and use of
confidential information relating to the tax, and to the
deposit of tax money collected by the Department of
Revenue; amending the definitions of 'gas,' 'oil,' and
certain other terms for purposes of the production tax, and
as the definition of the term 'gas' applies in the Alaska
Stranded Gas Development Act, and adding further
definitions; making conforming amendments; and providing
for an effective date."
This was the sixth hearing for this bill in the Senate Finance
Committee.
Co-Chair Green announced that three oil and gas companies would
be presenting testimony regarding this petroleum production tax
(PPT) legislation.
JOHN P. ZAGER, General Manager, Chevron Alaska, informed the
Committee that his remarks would be accompanied by a power point
presentation [copy on file] dated April 6, 2006.
[Note: Each page of Chevron's power point presentation contained
two diagrams; thus each diagram is referenced by both a page
number and its location at either the upper or lower portion of
the page. For reference purposes, the Senate Finance Committee
Secretary made a notation on each page of the corresponding
timestamp in which that page was addressed in this hearing.
General descriptive information of each page is provided in the
body of these minutes when feasible. A copy of the handout can
be obtained by contacting the Legislative Research Library at
(907)465-3808.]
9:07:17 AM
Page 1(lower diagram)
Chevron's Alaska Presence
· Current Asset base is formed by combination of
heritage Chevron and Unocal assets.
*Both companies have been active in Alaska for
many years.
· 4th largest producer in state
· 3rd largest operator
· 382 employees or full time contractors
*272 on the Kenai Peninsula
*Payroll of > $45 million
· Key customers: Tesoro, Enstar, Chugach Electric,
Agrium, Aurora
· Chevron is the only producer in the state with a
relative balance of assets in Cook Inlet and on the
North Slope
*Both production streams are large enough to
trigger PPT
· Chevron's Cook Inlet offshore assets are uniquely
positioned to suffer from the proposed PPT
Mr. Zager overviewed Chevron's activities in the State. He noted
that Chevron acquired Unocal's Alaska operations in August 2005.
Both companies had conducted "downstream" activities in the
State since the late 1800s. Exploration and production
activities in Cook Inlet and on the North Slope have existed
since oil and gas activities first occurred in the State.
Chevron's employees were based in Anchorage and on the Kenai
Peninsula.
Mr. Zager noted that Chevron provided oil and gas commodities to
a variety of customers including the Tesoro refinery in Nikiski,
the Enstar Natural Gas Company which supplies natural gas for
home heating, the Agrium fertilizer plant in Nikiski, and to
Chugach Electric and Aurora Power.
Mr. Zager specified that Chevron's Alaska operations, which are
fairly split between Cook Inlet and the North Slope, would be
large enough "to trigger" the PPT. "Chevron's position in Cook
Inlet, and Cook Inlet in general, is uniquely positioned to
suffer under the proposed tax regime."
Page 2 (upper diagram)
Alaska North Slope Fields
[This map depicts the locations of the North Slope oil and
gas producing fields that Chevron is involved in. Its Net
Production on the North Slope is 16,000 Barrels of Oil
Equivalent (BOE) per day.]
Mr. Zager characterized the company's holdings on the North
Slope "as a mile wide and an inch deep" in that it had a one
percent interest in the Alpine field, a five percent interest in
the Greater Kuparuk field, a one percent interest in Prudhoe
Bay, an 11 percent interest in the Endicott field, a 25 percent
interest in Point Thomson, and a "50 percent owner/operator of
the leases that are currently held" within the Arctic National
Wildlife Refuge (ANWR). At a recent State lease sale, the
company, which "was one of the most active bidders", spent
approximately seven million dollars to acquire, for exploration
purposes, a large parcel of acreage in an area south of the
Greater Kuparuk region.
9:10:00 AM
Page 2 (lower diagram)
Cook Inlet - CVX Asset Description
[This map depicts the location of the company's assets in
Cook Inlet.]
Cook Inlet Offshore:
· 3 fields (all op.)
· 10 Platforms
· 145 wells
· 2 onshore plants
· 42 mile PL
· 10,900 BOEPD
Cook Inlet Onshore:
· 8 fields (6 op.)
· 60 wells
· 2 gas storage fields
· WI% in 4 PLs
· 14,100 BOEPD
Net Production
Offshore Oil 6,300 BOPD
Gas 112 MMCFPD
25,000 BOEPD
Mr. Zager informed the Committee that Chevron was the largest
offshore operator in Cook Inlet. It operated ten of the total 15
offshore platforms in Cook Inlet. Eight of the ten were in
production, including the McCarthy River field which was the
largest offshore field in Cook Inlet. Chevron held a 52 percent
interest in that field. Overall, Chevron operated 72 percent of
the oil production in Cook Inlet.
Mr. Zager stated that Chevron's gas activities in Cook Inlet
included a 33 percent interest in the Beluga River field, a 100
percent interest in the Swanson River field which was the
State's original oil field, a 40 percent interest in Ninilchik
which was operated by Marathon Oil, and a 100 percent interest
in Happy Valley. The Ninilchik and Happy Valley fields, which
began producing after 2001, significantly increased gas
production in Cook Inlet.
Page 3 (upper diagram)
Trading Bay Unit
[This was a collage of pictures depicting platforms and
production facilities in the Trading Bay unit of Cook
Inlet.]
Mr. Zager stated the purpose of this pictorial was to remind
people that the operating environment in the Trading Bay unit
could be as harsh as those on the North Slope. Facilities in
Trading Bay were approximately 40 years old; tremendous
maintenance would be required to meet the safe operation and
environmental protection levels sought by Chevron. Ice floes
were environmental obstacles of concern.
Page 3 (upper diagram)
Cook Inlet Offshore
[This "production graph … depicts a history of offshore
Cook Inlet production" from the early 1970s through 2006.]
Mr. Zager stated that the green line on the graph represented
Cook Inlet oil production in barrels per day. The graph's
vertical axis depicted oil volume in logarithmic scale units of
1,000, 10,000, 100,000 and 200,000. During the field's initial
years, daily oil production was approximately 200,000 barrels.
Production has since declined to approximately 12,000 barrels
per day, and consequently, platforms are only producing a
fraction of the production they were designed for.
Mr. Zager pointed out that the solid blue line in the box at the
top of the diagram reflected "the water cut line" or percentage
of water in the oil. Fluids produced during Cook Inlet's initial
years were 100 percent oil and zero percent water. However,
overtime, the ratio has changed to being 90 percent water and
only ten percent oil even though the same amount of fluid were
being produced. Operating costs incurred by the separating,
treating, and disposing of that water oil are significantly
affecting costs in Cook Inlet.
Page 4 (upper diagram)
Trading Bay Unit
[This diagram mirrors the information of the previous
diagram, however, it is specific to the production and
water cut line of the Trading Bay unit in Cook Inlet.]
Mr. Zager pointed out that at its peak the Trading Bay unit,
which produced approximately 120,000 barrels per day, was the
biggest producer in Cook Inlet. Its production has declined to
approximately 8,000 barrels per day with a water cut of
approximately 92 percent. This information would substantiate
that Cook Inlet is "very challenged" in this phase of its life
cycle. The North Slope has been likened to being in the teenage
or young adult years of its life cycle; while Cook Inlet "is
already collecting social security".
Page 4 (lower diagram)
Cook Inlet Oil Production History
[This chart depicts the production history of Cook Inlet.
Net production has declined from 12.7 million barrels in
1997 to 6.4 million in 2005.]
Mr. Zager reviewed the information.
9:14:33 AM
Page 5 (upper diagram)
Cook Inlet Offshore Oil
· Cook Inlet is very high cost
* Direct lift cost $20 - $25 per BOE
* Currently breakeven on Cash Flow @ ~ $30/BOE
* Currently breakeven on Earnings @ ~ $40 - $45/BOE
* Further production declines will raise breakeven
prices
· Significant operational risks
* Two platforms are currently shut-in
* Must maintain critical mass of operations
· Cook Inlet Offshore cannot afford an additional tax
burden
Mr. Zager summarized Chevron's Cook Inlet activities. The
breakeven on cash flow point, which is calculated to be
approximately $30 barrel of oil equivalent (BOE), was
significantly higher than other production areas in the State.
Since the goal of business is to make money, any tax, such as
the PPT, that would affect a company's cash flow, would
negatively impact the financial market's view of the business,
as it would affect company earnings.
9:15:08 AM
Mr. Zager noted that the affect of the PPT on cash flow on
Chevron's offshore Cook Inlet activities, in conjunction with
"the depreciation that's required in the earnings contract",
would increase the breakeven amount on earnings to $40 to $45
dollars. While the company might choose not to abandon its Cook
Inlet activities based on the earnings calculations, it would be
a consideration in future investment decisions.
9:15:57 AM
Mr. Zager disclosed that activities on two of Chevron's Cook
Inlet platforms were halted several years ago when oil prices
were too low to support them. Other platforms might also have
been "shut in" since then had oil prices not increased to their
current levels.
Mr. Zager advised that platforms are "co-dependent on each
other" because the costs of such things as onshore facilities,
helicopters, and boats are shared between them. Consequently
when one is shut down, costs are allocated to the remaining
platforms. This could be likened to a "domino effect" in that
closing one platform could lead to the closure of others.
9:16:46 AM
Mr. Zager contended "the Cook Inlet offshore could not afford an
additional tax."
9:17:01 AM
Page 5 (lower diagram)
Chevron Cook Inlet Strategic Study
· August 10, 2005 Chevron acquires Unocal
* Much speculation about Cook Inlet asset fit in
Chevron Portfolio
· October 2005 - January 2006 - Strategy work completed
* Determined that there are incremental investment
opportunities in the Cook Inlet although they are in
the lowest quartile of Chevron's investment portfolio,
many projects did not make the cut
· February 2006 - Great news - announce decision that
Chevron will retain all Cook Inlet assets with the
intent to begin a multiyear investment program
* Chevron will retain the current office locations
Mr. Zager stated that when Chevron acquired Unocal in August
2005 there was wide speculation that it would sell Unocal's Cook
Inlet assets. After conducting an internal study, Chevron
concluded 35 to 50 projects were infeasible and would not be
undertaken; however, there were approximately 35 to 50 other
"incremental investment opportunities in the Cook Inlet". Thus,
Chevron and its partners planned to spend approximately $200
million during the next four years on off-shore oil projects.
9:18:18 AM
Mr. Zager continued that Chevron's announcement in February 2006
that it would retain all of its Cook Inlet assets was a shift
from its initial business plan. The decision was also made to
continue to conduct technical and other work in its offices in
Kenai and Anchorage rather than to consolidate that work in
Houston Texas and other oil centers. These decisions were good
not only for company employees but also for the State.
9:19:02 AM
Page 6 (upper diagram)
Great news, so what's the problem?
· The Cook Inlet reinvestment program was evaluated
using the current severance tax assumptions (zero
severance tax)
· When modeled under the proposed 20/20 PPT the
economics on some projects are degraded, some projects
are improved, overall poorer economics for the program
* Oil production taxes will go up dramatically
* Will cause investment decision to be reconsidered
* Higher taxes will cause less capital to be spent
* Enhanced PPT terms could significantly expand the
list of economic projects in the investment program
and significantly extend the life of offshore oil
production
Mr. Zager pointed out that these decisions were based upon the
State's current tax regime, the Economic Limit Factor (ELF),
which had basically lowered the severance tax on oil production
in Cook Inlet to zero. When re-factoring Cook Inlet economics
under the 20 tax rate and 20 percent credit (20/20) provisions
in the original PPT bill (SB 305) proposed by the Governor, the
determination was that under its tax and incentive increases,
the economics of the best of the 35 to 50 projects deemed
feasible under ELF, "got poorer", as the tax on the those
projects would increase. "Conversely, the projects that were the
poorest in the portfolio actually got a little better because
they weren't generating as much profit, but the investment
incentives were helping them." Therefore, the PPT "tended to
level the portfolio. But overall, the economics of the entire
program went down".
Mr. Zager noted that the 25 percent tax and 20 percent credit
(25/20) provisions proposed in the Senate resources committee
substitute, CSSB 305(RES) [NOTE: this bill is referred to as
CSSB 305 in these minutes] would incur "a more significant
impact on degrading the value of that overall investment
package". This increased tax would result in investment
decisions being reconsidered. "Higher taxes would ultimately
cause less investment to occur."
9:20:39 AM
Mr. Zager noted however that were the PPT terms "enhanced", some
of the economics of the 35 to 50 projects which had initially
not made the economic cutoff might improve. Numerous things
could be affected by "the ratio of the tax to the credits".
9:21:10 AM
Co-Chair Green asked whether the term "enhanced PPT terms" would
be further defined.
Mr. Zager replied in the affirmative. This term would be
addressed later in the presentation.
9:21:22 AM
Page 6 (lower diagram)
Cook Inlet Production Forecast with Four-Year Capital Plan
[This graph depicts projected Cook Inlet oil and gas
offshore production absent further investment. In this
case, production would decline "fairly dramatically and by
2009, numerous offshore platforms might be shut down. This
information had also been presented to Chevron's senior
management.]
Mr. Zager communicated that the goal of the four year investment
program would be to stabilize production above 10,000 barrels
per day for four years. The hope was that during this four-year
timeframe, additional projects would be identified and
investments in the field would continue for several more years.
9:22:25 AM
Page 7 (upper diagram)
Alaska Oil Production
January 2006
BOPD
[This bar graph compares oil production of Cook Inlet to
that of the North Slope. January 2006 North Slope oil
production exceeded 810,000 barrels of oil per day (BOPD)
compared to approximately 18,000 BOPD in Cook Inlet.
Mr. Zager communicated that the purpose of this graph was to
depict Cook Inlet "in perspective" to the North Slope. Cook
Inlet's January 2006 oil production amounted to approximately
two percent of the total oil production in the State. Thus, the
impact of the PPT on the oil production of Cook Inlet would be
minimal. Were the PPT a net profits tax, the North Slope
production would be significantly more profitable than that of
Cook Inlet.
Page 7 (lower diagram)
Alaska Oil Production
January 2006
BOEPD
[This chart compares the January 2006 barrels of oil
equivalent per day (BOEPD) production for oil on the North
Slope to that for both gas and oil in Cook Inlet.]
Mr. Zager stated that the annual average gas production in Cook
Inlet would be slightly less than that depicted in the chart as
January was one of its peak gas production months. Cook Inlets'
combined oil and gas 112,000 BOEPD would equate to approximately
12 percent of the State's total production "on a BOE basis".
Mr. Zager noted that gas produced in Cook Inlet was utilized to
heat homes in Anchorage, to power area electrical utilities, and
to support "commercial activities in South Central Alaska
"including commercial users such as the liquefied natural gas
(LNG) plant and the Agrium nitrogen fertilizer plant. In other
words, there was a large "economic multiplier on this gas". "The
economy of Alaska in its current form" was dependent on having
gas support the economy of South Central.
9:24:29 AM
Page 8 (upper diagram)
Chevron Cook Inlet Government Take Allocation
Combined Oil and Gas Production
[This pie chart indicates the percentage breakout of the
total government take on oil and gas production in Cook
Inlet: federal tax seven percent; property tax 11 percent;
production tax eight percent; and State royalties 74
percent.]
Mr. Zager cautioned that in the endeavor to increase the State's
portion of the revenue, the "pie" size could shrink were
decisions made to lower investments made in the State. This
would be true not only for Cook Inlet, but possibly for every
area of the State.
9:25:18 AM
Page 8 (lower diagram)
Reasons to Lower Taxes and Provide Incentives for
Additional Cook Inlet Investment
· Gas is running out
* Home heating, electrical generation, industrial
consumption
* Additional gas supply is critical to state's economy
* Other options are much more expensive than Cook
Inlet gas
· Production tax is a pass through on most utility
contracts
* Tax increase represents increase in gas price to
consumers
· Oil redevelopment will maintain and add new jobs and
will extend field life
· Cook Inlet competes for capital with other areas in
North America, does not compete for global capital
* Under PPT Alaska will have the worst fiscal terms in
U.S.
Mr. Zager communicated that these reasons support the position
that a lower tax should be applicable to operations in Cook
Inlet as its operations differed from those on the North Slope.
A lower tax would encourage additional investment there. Gas
supplies in Cook Inlet were dwindling. This past winter, gas
production could not meet the demand and the Agruim fertilizer
plant was forced to close for ten days. The option of importing
LNG would not only be expensive, but it would ship money out of
the State rather than spending it in-state. Another expensive
option would be to construct a spur line. He would not
anticipate such lines being commercial projects. In other words
the State would be required to build them as there would be no
other alternative to get gas to Anchorage.
9:26:54 AM
Senator Bunde noted that companies typically do not absorb
taxes; they instead pass that expense on to customers. To that
point, he questioned why an increase in the tax would discourage
a company from investing in the State.
Mr. Zager replied that the tax would be passed on to the
consumer in the case of gas being sold to a gas utility.
However, the majority of gas being produced in Cook Inlet was
sold to commercial businesses. The production tax should be
considered in the "broad" sense."
9:28:14 AM
Senator Stedman asked the reason that State corporate income tax
had not reflected on the "Chevron Cook Inlet Government Take
Allocation" pie chart. He concluded that the pie chart was
incomplete as two pieces were not reflected, those being "the
net to the producer and the cost". While it was helpful to see
"the breakdown of the government take numbers, it is not that
meaningful" unless the whole pie was accounted for.
9:29:18 AM
Mr. Zager understood that corporate income tax was reflected in
the federal tax percentage.
Senator Stedman advised that the State corporate income tax
should also be reflected.
Mr. Zager agreed.
Senator Stedman understood pie chart reflected fiscal year 2005
numbers.
Mr. Zager affirmed.
9:30:02 AM
Senator Stedman communicated that industry numbers, as a whole,
were available. It was understandable that Chevron would not
desire to depict their individual percentage take.
Senator Stedman referred back to the Cook Inlet Offshore Oil
information depicted on page 5 of the presentation. It could be
interpreted from the current break even on earnings price of $40
and $45 BOE depicted on that page that any price "above that
would create shareholder wealth".
Mr. Zager responded that could be the interpretation if
shareholder wealth was defined "in the terms that you would have
positive earnings per share".
Senator Stedman communicated that his question pertained to CSSB
305's Progressivity provision's "trigger point" which was set at
a price of $40 per barrel. Two issues have been raised in
regards to Progressivity. The industry's "fundamental" concern
was to the impact the Progressivity element would have on their
earnings as the desire would be to not "retard their growth of
shareholder wealth". The second concern was to what price would
be the appropriate trigger point. The current $40 barrel trigger
point seemed to be "a reasonable arena". A trigger point of $40
to $45 would be more appropriate than a $30 or $35 per barrel
price.
9:31:52 AM
Senator Dyson voiced appreciation for a separate discussion he
had with Mr. Zager. To that point, he hoped Mr. Zager would
address the effect of a recent Regulatory Commission of Alaska
(RCA) "decision to let new gas float to the Henry Hub prices";
specifically how that decision might impact Chevron's
exploration activities in Cook Inlet in light of the "present
limited market" conditions that exist due to long term contracts
that have been in play there.
9:32:40 AM
Mr. Zager first addressed "the impact of Henry Hub pricing".
Some of the remarks made by the Governor Frank Murkowski
Administration could be interpreted to imply that Cook Inlet gas
was sold at Henry Hub prices; however, "that is categorically
not true". Henry Hub prices today range upwards of seven dollars
per 1,000 Cubic Feet of Natural Gas (MCF). Chevrons' contracted
gas prices with Enstar Natural Gas Company of $6.19 MCF could be
some of the highest priced gas in Cook Inlet. In 2005,
approximately 20 percent of Chevron's gas was sold to Enstar at
that price and the remaining 80 percent was sold to the Agruim
fertilizer plant.
Mr. Zager disclosed that this year, Chevron would be selling
approximately 50 percent of its Cook Inlet gas production to
Enstar with the balance going to other markets including Agruim.
Even though certain price information was privileged for
competitive reasons, "it would be fair to say that the price to
Agruim is far below seven dollars." The public record would
reflect that in an Agruim recent request for proposals (RFP) for
gas, they requested bids be in the range of three dollars an
MCF. The price of longer term gas contracts with other utilities
and the LNG plant vary. "This gas is certainly not being sold
for seven dollars; it's far below that on an average basis."
9:34:49 AM
Mr. Zager stated that increased prices in the past several years
could explain the increase in exploration that has occurred in
Cook Inlet. Nonetheless, Cook Inlet could not attract investors'
capital unless prices were competitive with projects in the
continental United States. "Costs are higher, conditions are
rough, and "the exploration risk is every bit as tough as it is
down south". Thus gas price levels of one, two, or three dollars
would not attract investors. "That's an economic realty that's
not too hard to understand."
Mr. Zager stated that another effect of long term contracts with
set prices and "a certain market" for the gas was that it would
provide a base upon which a producer might decide to spend
money. However "on the flip side" it would make it difficult for
companies without contracts or a selling market, to conduct
exploration activities.
Mr. Zager stressed that the structure of Cook Inlet
traditionally included long term contracts with utility
companies as such agreements assured utilities "they would have
gas out into the future". Were Cook Inlet prices to follow the
Henry Hub spot price for gas, "prices would fluctuate much more
wildly".
Mr. Zager also communicated that due to the affects of Hurricane
Katrina in the Gulf of Mexico area of the country in 2005, "Cook
Inlet consumers are now going to see a slight increase in their
price". He reminded that Alaska could have its own set of
natural disasters such as an earthquake that could affect
production. Such things would affect a spot price system. Thus,
long term contracts would provide "assurance over the long term
that your prices are going to be relatively stable and
predictable".
9:36:56 AM
Senator Dyson communicated that the purpose of his inquiry had
been to alert fellow Legislators that, rather than the
government take being the sole consideration, numerous factors
were involved in Chevron's "economic analyses". Long term
contracts would provide stability but would also limit what
could be charged for a product as costs increased. Conversely,
"new explorers who don't have a guaranteed market to sell their
gas into" would also have challenges.
Senator Dyson asked Chevron to provide a timeline as to when
Cook Inlet's long term contracts would terminate. The subsequent
renegotiation process would reflect more current commodity
values.
9:38:01 AM
Mr. Zager could speak to Chevron's contracts. Their current
contract with Enstar was volume rather than time based. The
volume for that contract was set at 450 billion cubic feet of
natural gas (BCF); 50 BCF had been utilized to date. Were this
volume trend to continue, the contract could be in effect for
another 20 years. Furthermore, that contract was renewable.
Chevron's relationship with Chugiak Electric historically
allowed five-year contract extensions. Chugiak Electric recently
issued an RFP for additional gas in approximately 2011. One
aspect of the Cook Inlet gas scenario which dramatically
differed from that of the Lower 48 was that a new gas discovery
in the Lower 48 could typically be hooked up and sold within a
few weeks or months. In addition, the volume could be sold at
capacity at current market prices. Conversely, "a company could
not fully "enjoy the upside" of a very large discovery in Cook
Inlet, "because you can't put it to a market. You've got to wait
and stretch it out over 20 years. So there's a lot of give and
take that makes the Cook Inlet gas business very unique." It is
the "only market constrained environment in North America". The
irony is that we "are talking about shortages and market
constraints" at the same time.
9:40:15 AM
Senator Dyson asked when the present operating permits
associated with Agruim would terminate.
Mr. Zager understood Agrium was not operating under a permit
process. Their operation would continue indefinitely provided
they could receive sufficient quantities of gas at a price which
would allow them to operate profitably. Their current contract
with Chevron would terminate in October 2006. He understood
Agruim was "soliciting additional gas for 2006 and 2007".
Limited gas supplies prohibit Agruim's ability to sign long term
contracts.
Senator Dyson asked whether any conditions in Agruim's RFP would
restrain the price of gas. In addition, he asked for information
regarding Chevron's plans regarding LNG exports.
Mr. Zager noted that Agruim's fertilizing products were sold on
the world market and therefore their price must be competitive.
That would affect the price they would be willing to pay for
gas. Any contracts established with Agruim would be finalized
after a negotiation process.
Mr. Zager stated that the LNG export question would be more
appropriately addressed by John Barnes with Marathon Oil during
his forthcoming presentation. That was "his field of business".
Senator Dyson acknowledged.
Mr. Zager refocused Committee attention to the "Reasons to Lower
Taxes and Provide Incentives for Additional Cook Inlet
Investment" information on page 8 of the presentation. Any
increase in the production tax would be passed on to a utility
company's consumers. Additional Cook Inlet oil development would
maintain and add new jobs and thereby extend field life. This
would be a major component of a healthy economy; particularly in
the Kenai area.
Mr. Zager addressed the issue of how Alaska's proposed tax
regime would affect its ability to compete in the global market
for capital investment. While that was a consideration for
activities on the North Slope, he was "absolutely sure" that
this issue would not apply to Cook Inlet as Cook Inlet projects
did not compete "for capital against a major international
project, it's competing for capital against lower 48
businesses". Cook Inlet competed with "Wyoming, New Mexico, and
Texas for the investment dollar".
Mr. Zager communicated that Chevrons' activities in Alaska
report to the company's business component which "allocates
capital to North America". The 25 percent PPT tax proposed in
CSSB 305 would place Alaska and the Cook Inlet number one in
having the "worst fiscal terms" in the United States. Alaska
would also have "some of the most expensive and difficult
operating conditions at the same time…" He cautioned against
implementing any tax regime change in the Cook Inlet.
9:44:18 AM
Senator Hoffman asked the percent of gas produced in Cook Inlet
which is used for residential rather than industrial
consumption.
Mr. Zager recalled that approximately 50 to 60 percent of the
gas produced in Cook Inlet is utilized to support industrial
activities.
Senator Hoffman asked whether the expectation is that that
percentage would remain constant as Cook Inlet production
diminished, as depicted in the "Cook Inlet Production Forecast
with Four Year Capital Plan" on page 6 of the presentation.
Mr. Zager communicated that the LNG and Agruim fertilizer plants
would continue to utilize a significant percentage of the gas
produced in Cook Inlet. Were one of those operations to cease,
the percentage "would shift in favor of the utilities". Were
both the LNG plant and Agruim to close, gas would be available
for small commercial users or home usages.
Senator Hoffman asked the usage forecast for Agruim.
Mr. Zager clarified that the purpose of the Production Forecast
chart on page 6 was to provide an offshore oil and gas
production forecast. Continuing, he conveyed that the Agruim
fertilizer plant could at peak capacity consume approximately
165 MCF per day. Current operations were at half capacity or 80
MCF per day. Half of the plant had been shut down since the fall
of 2005. During cold winters, their usage was less than that as
gas supplies were not available. The plant could not produce
products for a period of ten days in January 2006 due to a lack
of gas. He understood that Agruim's plan would be to run at half
capacity as long as gas was available.
9:48:01 AM
Page 9 (upper diagram)
Cook Inlet Provisions to Date
· House Resources - None
· Senate Resources - "5,000 BOPD exemption"
* Fails to provide any real help to Cook Inlet
* May be a "small company provision", but is not a
"Cook Inlet provision"
· Any "Cook Inlet Provision" should be specific to the
Cook Inlet
· Reasons given not to consider Cook Inlet provision
* Adds complication
o Some additional complication to help Cook
Inlet is justified
* System must be uniform over entire state
o We already have statutes that distinguish
geographic areas
Mr. Zager addressed the PPT provisions included in the House and
Senate committee substitutes. He noted that when Chevron became
aware of the proposed PPT bill, it quickly alerted the
Administration and the Legislature of issues pertinent to Cook
Inlet. They were assured by those entities "that those
differences were recognized" and would be reflected in the bill.
Continuing, he noted that the House PPT committee substitute,
CSHB 488(RES) [NOTE: This bill is referred to as CSHB 488 in
these minutes] did not include any Cook Inlet provisions. CSSB
305 included a 5,000 barrel per day exemption, which had been
referred to as the Cook Inlet exemption. However, he took
exception to that because it would "fail to provide any real
help" to Cook Inlet.
Mr. Zager noted the 5,000 barrel per day exemption could be
regarded as "a small company provision but it is not a Cook
Inlet provision". Any consideration of Cook Inlet should be
specifically identified as such. This could include provisions
pertinent to "anything south of the Brooks Range". He reiterated
that the different environment in Cook Inlet should be
considered.
Mr. Zager noted that several arguments against applying
differing provisions to Cook Inlet had been presented. One
position was that it would complicate the bill. While this might
be true, the complications could be minimal. As a representative
of his company and its employees, he would be uncomfortable
communicating to those employees that the effort to address Cook
Inlet activities was halted because it proved to be "too
complicated". This would not be accepted as "a good enough
reason" not to address it.
Mr. Zager communicated another argument being made was that a
single tax system should apply to the entire State. Even
"outside consultants" had voiced how difficult it was to apply
"a one size fits all system" to Alaska. Cook Inlet was a perfect
example of that. Thus, the argument in favor of a single tax
structure would also be unacceptable. Geographic differences are
already recognized in State Statute as evidenced by such things
as royalty reductions and expiration incentives pertinent to oil
and gas activity in Cook Inlet.
9:50:39 AM
Senator Stedman communicated that this issue had been discussed
in the Senate Resources Committee and an amendment containing a
tax formula had been adopted as a result.
Mr. Zager noted that the Senate Resources Committee amendment
formula would be discussed in the next diagram.
Senator Stedman asked that in the discussion of that diagram,
Mr. Zager specifically suggest a solution to the issue.
9:51:26 AM
Page 9 (lower diagram)
Senate CS - BOE Exempted
[This chart depicts how the producing companies in Cook
Inlet would be affected by the up to 5,000 barrels per day
exemption with a 0.2 modifier as proposed in CSSB 305 and a
0.1 modifier as initially considered by the Senate
Resources Committee. The Exemption BOEPD is presented on
the vertical axis and the Production BOEPD is reflected on
the horizontal axis.]
Mr. Zager explained the chart. The reddish-purple line at the
top left of the chart reflected the up to 5,000 barrel per day
exemption with the 0.1 modifier initially proposed by the Senate
Resources Committee. Under this scenario, the exemption would be
zero for a company with a 55,000 barrel Average Daily Production
(ADP). Chevron with a statewide production of approximately
40,000 barrels would have received a 187 barrel per day credit
under that formula. That would not have been an incentive. He
had assumed, when told the 0.1 formula would be modified, that
the modifications "would be favorable" to Chevron. However, the
modification was to change the modifier from 0.1 to 0.2. The
affect of that change was reflected as the blue line on the
chart. The 0.2 modifier served to zero the incentive out at a
30,000 ADP rather than the 55,000 ADP under the 0.1 modifier. In
addition, Chevron's 187 barrel credit would change to zero.
Mr. Zager noted that the impact of the formula on all producing
companies in Cook Inlet was depicted on the graph. The only two
companies that would receive the full benefit of the credit
would be Aurora and XTO, which each produced less than 5,000
barrels ADP. The company, Forest, which produced approximately
7,000 barrels ADP would receive slightly less credits than
Aurora and XTO. Marathon Oil with a daily production of
approximately 30,000 barrels ADP would have had a 500 barrel per
day credit under the 0.1 formula and less than a 100 barrel per
day credit under the 0.2 formula. Chevron, Exxon, and
ConocoPhillips would receive "no deductions at all" under the
0.2 formula.
Mr. Zager pointed out that "94 percent of Cook Inlet production
is operated by companies that are not eligible for a significant
exemption. So, to say that this is a Cook Inlet exemption" would
be "stretching quite a bit".
Page 10 (upper diagram)
Senate Resources CS - The unique value and challenged
position of the Cook Inlet is not adequately addressed
· Revisions as proposed in the CS lowers the economics of
capital investments in the Cook Inlet
o Puts Chevron's four year capital program in jeopardy
o At the very least, increased taxes will lower
investment
o Without capital McArthur River Field is gone in ~ 4
years
o Critical mass for Cook Inlet oil industry is gone
Mr. Zager was disappointed that the House or Senate committee
substitutes did not really contain provisions that would address
the situation in Cook Inlet "in a meaningful way". The PPT would
cause Chevron "to re-examine its capital investment program, and
at the very least, the increased taxes will put negative
pressure on the amount of capital that's spent. Without
additional capital, the McCarthy River Field" would likely shut
down in approximately four years. Its closure would eliminate a
"critical mass" that is supporting the Cook Inlet industry oil
business.
Page 10 (lower diagram)
Recommendation on Cook Inlet
Consider the following options:
· Carve out Cook Inlet
o Leave under current system
· Apply PPT methodology to keep taxes near current
levels
o Adjust tax rates lower (5%)
o Retain overall incentive rates (20%)
Mr. Zager pointed out that these two recommendations could
address the Cook Inlet dilemma. Eliminating Cook Inlet from the
provisions of the PPT and leaving the current structure in place
would negate increasing taxes in Cook Inlet, and operations
would continue as long as they were economically viable.
However, continuing the status quo would not incentivize
investment which he believed would be "warranted given the very
critical nature of the gas supply in Cook Inlet".
9:55:06 AM
Mr. Zager stated that the other recommendation would be to apply
the PPT methodology on a statewide basis, but "lower the front
end tax rate to the point where the tax in Cook Inlet would be
more or less neutral on the current taxes" being paid. That
would equate to approximately a five percent tax rate. Adding
this minor complication would "solve a lot of the problems" and
retain "the incentives available to encourage additional
exploration and development".
Co-Chair Green asked whether the second recommendation had been
embodied in any version of a Senate Resources PPT committee
substitute.
Mr. Zager replied "no".
9:56:12 AM
Senator Dyson recalled previous [unspecified] testimony before
the Committee which expressed that the companies operating in
Cook Inlet should like any of the PPT versions because of the
"credits or incentives for exploration and development" they
provided. He asked Mr. Zager to comment on this as a separate
issue from the tax rate.
Mr. Zager stated that "the investment incentives are a positive"
if viewed "in isolation … or as part of an exploration program,
but we all know there's no free lunch. If the State's getting
more, the companies are getting less". While the upfront risk to
a company would be lowered, the PPT would "take out the profits
on the backside when you're successful". Thus the returns on a
project would be lower, "although in an NPV [Net Present Value]
sense, the projects are getting smaller" in that a company would
be required to invest less capital upfront "because the State's
subsidizing and you are getting less on the back side cause the
State's taking more".
Mr. Zager also noted that "some of the numbers in terms of
return on investment may not change significantly: on some
projects they may get better, on some they'll get worse, but
overall the projects are getting smaller on a NPV basis."
Mr. Zager communicated that the companies in this industry "are
in the risk business. They are capable of funding the projects
as long as they receive the full exposure to the results". Thus,
"incentives would be an important part of it certainly, when you
couple it with the increased taxes, but incentives alone can't
compensate for taking the tax rate higher".
Senator Dyson understood however, that under any of the PPT
versions being discussed, a company would be able "to write off
much of its unsuccessful exploration costs". They were unable to
do that under the current tax structure.
Mr. Zager affirmed that was correct. "In terms of investment
incentives, allowing all capital to be counted as a credit is a
vast improvement over the current system" which only provided
advantages for successful exploration wells. Between 70 and 90
percent of the time, exploration efforts fail, and thus, no
investment incentive was provided currently on the exploration
side.
9:59:26 AM
Page 11 (upper diagram)
General Comments on CS
· 25% tax rate is too high and will discourage
investment, a return to 20% overall rate is in the
best interest of Alaska
· Prefer $12 million credit to 5,000 BOEPD exemption
· Transition capital must be earned again on 2:1 basis
o Prefer original proposal, this is better than
nothing, suggest extending time period to 10
years
· April 1, commencement rate, not practical, punitive
penalty and interest rate
· Progressivity - do not support - taking away the
"windfalls", no matter how you couch it, lowers
expected value to investors, and therefore will lower
overall investments
Mr. Zager communicated that, at this point, he would address the
CSSB 305 PPT bill "in general" rather than continuing to dwell
on its impact on Cook Inlet.
Mr. Zager deemed the 25 percent tax rate to be "too high". The
company's analysis indicated that a 25/20 rate would reduce "the
overall economics of a project". CSHB 488's PPT proposal
allowing for a $12 million credit would be preferred over the
5,000 BOEPD in CSSB 305. Since the tax would be on profits,
which was dollars, it would "make sense" to include "an
exemption based on dollars and not on barrels". The 5,000 BOEPD
"exemption at high prices could be worth significantly more" to
"a highly profitable" company; conversely, it would "be worth a
lot less" to a company that is not highly profitable.
Mr. Zager addressed the transition capital provision included in
CSSB 305 which would be earned on a two to one basis. He
preferred the provisions in SB 305 which "recognized past
investments". While acknowledging that the inclusion of the two
for one provision would be preferable to that of eliminating it
entirely, he communicated that the two for one "step up in
spending to recover your money is pretty darn aggressive".
Accepting the two for one ratio would be easier were the time
period increased to ten years, for, "by the time you want to
invest and get exploration going, ten years would, for most
people, … still represent a very healthy investment program
especially" in consideration of the fact that any year in which
oil prices fell below $40 would be ineligible.
Mr. Zager stated that a significant tax increase would be
experienced were the retroactive April first effective date
adopted. He noted that British Petroleum addressed this issue at
great length during it April fifth presentation to the
Committee. He deemed "the nature of this penalty when we're
kinda guessing what our taxes are as we go along… is a bit heavy
handed".
10:01:51 AM
Page 11 (lower diagram)
Alternate Progressivity (Windfall Profit) Provision
· Reason for the state to support progressivity
o To get a "fair share" when there is a price run up
accompanied by large profits
o NOT to raise taxes if the price increase is gradual
over time and is accompanied by increases in costs
and thus not accompanied by increased profits - NOT
a creeping tax increase
· Problems with progressivity as currently proposed
o "Trigger" price tied to WTI (or Henry Hub) is not
inflated
· Over time prices and costs will rise - 30 years
is a long time
o "High Cost" oil will be produced in increasing
quantities
o Over the long term a fixed trigger price will not
work as intended
· Consider changing the trigger from commodity price to
a "net profits" trigger
Mr. Zager did not support the inclusion of the Progressivity
provision in the bill. Testimony had been provided regarding the
inherent risks companies face when investing in this industry.
Risks were weighed against a distribution of outcomes. A "very
good outcome" would be when a company discovered a lot of oil
and was able to sell it at a high price. A variety of outcomes
were factored into a company's investment decisions. Thus, when
you "start clipping out the high part of the distributions, it
does affect in a significant way your attitudes towards the
investments." The inclusion of progressivity in the PPT was not
welcome, "because taking away those windfalls is going to affect
people's investment decisions. We're in the risk business and
we're happy to take those risks as long as we get the full
distribution of the outcomes. So, having said that, I'm pretty
concerned" about the current progressivity discussion.
To that point, Mr. Zager proposed a different way to consider
progressivity, especially its trigger point. He understood that
the Progressivity provision was included to assure that the
State would "get a fair share when" prices increases were
accompanied by large profits. An example of this would be when
oil prices increased to $100, but costs to the industry did not
increase. This would generate a significant level of profit for
the company. The purpose of progressivity "was not to raise
taxes" when price increases were "gradual over a long period of
time" and were simultaneously accompanied by an increase in
costs. In other words progressivity was not meant "to be a
creeping tax increase that is triggered by inflationary
pressures". Its intent was "to capture windfall profits".
Mr. Zager pointed out that a significant amount of discussion
has occurred in regards to what should be the appropriate
trigger for the Progressivity factor. To date, the trigger
options that have discussed have included such things as West
Texas Intermediate (WTI) oil prices, Henry Hub prices, ANS
prices, or wellhead prices. His concern was that whatever option
was identified as the trigger "would be locked in for 30 years".
No one could predict what might occur during that timeframe. In
the 1960s, a price of five dollars might have been considered
the appropriate trigger point for windfall profits. A price
indexed for inflation would include issues regarding what would
be considered the appropriate inflation marker. For example,
utilizing the national Gross Domestic Product (GDP) might not be
appropriate because it "is not necessarily related to oil
prices".
Mr. Zager identified another issue pertinent to a 30 year time.
That would be that "lower and lower quality prospects and higher
and higher costs" would come into play. "Higher oil prices may
not be connected to higher profitability….Over the long term, a
fixed price trigger is a disaster waiting to happen".
10:05:11 AM
Senator Bunde concluded therefore that a company in this risk
industry would be opposed to Progressivity because the company
taking "the risk should get the profit". However, a large
portion of the PPT delved into reducing the risks investors
would be taking. While the industry felt that 30 years was a
long time, it was asking the State to provide "30 years of
certainty". To that point, he stated that "when you're in the
risk business, certainty costs money." He identified that as
being "one of the arguments for Progressivity: that if you're
going to get some bottom line certainty, there has to be some
flexibility for windfall".
Senator Bunde found the trigger point information very
interesting and worthy of further discussion. However, he asked
the industry to consider the "certainty" factor when analyzing
Progressivity.
Mr. Zager responded, "in general it's hard to disagree that
certainty will cost some money if that's what's being
requested".
10:06:30 AM
Senator Stedman corrected some information in Chevron's
presentation: the transition language included in CSSB 305
specified a five-year look-back and "a two for one credit going
forward, but there's no $40 price on it below which you can't
use it". That provision was in SB 305, but was not included in
CSSB 305.
Mr. Zager appreciated the clarifications.
Senator Stedman voiced discomfort with applying an "indexation"
element to Progressivity, as there were "inherent problems" with
that process. The State's current six billion dollar spending
limit was an example of those "inherent problems". The problem
of utilizing indexation in the PPT would be further compounded
since "oil prices and inflation are lowly correlated".
Senator Stedman expressed, however, that Progressivity was
included in the PPT "to maintain" the "sharing relationship"
between the government take, specifically that of the State and
the industry as oil "prices advance forward from $60 to $80 to
$100 a barrel". Absent the Progressivity factor, the State would
be "leveraged" in that its percent of the pie would diminish and
the producers' would increase. "And they're already in the area
where they're enhancing shareholder wealth". That share would
continue to be "magnified". Thus, the State should endeavor "to
neutralize that so we aren't leveraged".
Senator Stedman continued that a mechanism must be developed to
maintain that sharing relationship balance over time. Otherwise,
the State could find itself in "the disadvantaged" position it
is in today under ELF. While he could appreciate the industry's
position against including a Progressivity factor in the PPT,
"it's not in the best interest of the State to remove it".
Mr. Zager acknowledged Senator Stedman's position, but expressed
that, even though the industry does not support the inclusion of
a Progressivity element in the PPT, it recognized that its
inclusion might be inevitable. In consideration of that, the
industry would like to suggest implementing "net profits" as "an
alternate" Progressivity trigger.
10:09:34 AM
Page 12 (upper diagram)
How would a "net profits" trigger work?
· Each company already will calculate a "net profits"
every month
o Divide monthly net profits by production to get a
"net profits/boe"
· Set trigger point and escalation factor based on "net
profits/boe"
o Suggest $50/boe net profits trigger and 2.0% for
each $10 increase in profits
o Minimum general rate of 20% tax on net profit
o Maximum general rate of 30% tax on net profit
· Advantages
o Self correcting for inflation, costs, commodity,
high cost production (avoid discussion of WTI, ANS,
Henry Hub, well head etc)
o Fully captures the "windfall" upside, without
creating unintended consequences
o System is fair, since taxes and progressivity will
only be attached to actual company profits
Mr. Zager explained that the "net profits" trigger proposal
would be preferred to a WTI trigger. Companies routinely
calculate their net profits on a monthly basis. That figure
would be divided by the company's production level to achieve a
number referred to as the "net profits/BOE". Thus, a specified
"net profits" level could replace language the WIT Progressivity
trigger price in CSSB 305. "The beauty of this system is that it
is self-correcting." For example, if the WTI price increased but
costs did not, companies would experience a direct increase in
profits. The tax would be triggered at a higher ratio. However,
in 20 years, for example, were oil prices to increase to $100
per barrel and costs to increase from $20 per barrel to $80 a
barrel, a company would not experience an increase in profits.
Mr. Zager also noted that the net profits trigger could be
appropriately applied to a company conducting a heavy oil
project whose costs might be double or triple those of light oil
projects. The net profits trigger would also be appropriate for
gas projects. Progressivity could be applied to any company
regardless of whether they were in the gas, heavy oil or light
oil industry, when their profitability level met the
progressivity component qualifications.
10:12:01 AM
Co-Chair Green asked whether the calculation formula currently
utilized to determine a company's net profits could be used or
whether it would require changes.
Mr. Zager anticipated "that the exact same net profits" formula
currently utilized to pay the industry net profits tax would be
used.
Senator Stedman clarified that while the WTI price had initially
been considered as the trigger for Progressivity by the Senate
Resources Committee, the Committee ultimately decided to specify
ANS West Coast as the trigger even though WTI "is more actively
traded and less likely to be manipulated because it is a very
active market and there is a lot of financial derivatives off of
it". ANS "is basically Alaska oil at Los Angeles".
Mr. Zager stated he had used WTI solely as an example, as
various Progressivity benchmarks had been considered. CSSB 488
specified Henry Hub as the benchmark for gas Progressivity. He
reiterated that Cook Inlet companies were concerned about their
"contracts that are fixed over a number of years being connected
to Henry Hub".
Mr. Zager suggested the benchmark for the net profits
Progressivity tax be $50 a barrel, with a minimum tax rate of 20
percent. Each ten dollar increase in profits could subject the
rate to an additional two percent tax, with a maximum tax rate
of 30 percent. This maximum tax level "is an important feature"
for it would provide "investors some assurance that at least a
bigger percent of the upside would remain … and business could
be planned a little better for sharing in the increased profits
between those ranges".
Mr. Zager summarized the advantages provided by a net profits
trigger. "It would be self correcting for inflation, costs, what
commodity you're producing, if you decide to get into higher
cost type of production. We don't know what could be coming out
there in the future". Basing the trigger on net profits would be
easier to implement than WTI, ANS, Henry Hub, or wellhead
prices. It would also "fully capture the windfall upside without
creating unintended consequences of simply increasing taxes
because price of oil has gone up" without being connected to
increased profitability. This would be a "fair system since
taxes and Progressivity will only be attached to actual
profits".
Page 12 (lower diagram)
Examples of "Net Profits" Trigger
1. Windfall Case - Price double - Costs fixed
Average Rev/BOE 60.00 110.00
Expense Per BOE 7.00 7.00
Capital Per BOE
(incl. Cap. Credit) 3.00 3.00
Net "Profit" per BOE 50.00 100.00
PPT% 20.0% 30.0%
Actual Tax per BOE 10.00 $ 30.00
2. Increase Profits - Price double- Costs up
Average Rev/BOE 60.00 110.00
Expense Per BOE 7.00 37.00
Capital Per BOE
(incl. Cap. Credit) 3.00 3.00
Net "Profit" per BOE 50.00 70.00
PPT% 20.0% 24.0%
Actual Tax per BOE 10.00 $ 16.80
3. Constant Profit - Price double - Costs keep pace
Average Rev/BOE 60.00 110.00
Expense Per BOE 7.00 57.00
Capital Per BOE
(incl. Cap. Credit) 3.00 3.00
Net "Profit" per BOE 50.00 50.00
PPT% 20.0% 20.0%
Actual Tax per BOE 10.00 $ 10.00
Mr. Zager reviewed three examples of how the suggested net
profits Progressivity trigger would work. Example 1 would
reflect a "true windfall profits" scenario with barrel prices
increasing from $60 to $110. Fixed costs remained at ten
dollars. $60 less the ten dollars of fixed costs would result in
a net profit of $50. That would be subject to a 20 percent tax
equating to ten dollars. A $110 barrel price less the ten
dollars in fixed costs would result in a net profit of $100.
This would be subject to a maximum 30 percent tax rate for an
actual BOE tax of $30.
Mr. Zager stated that Example 2 would reflect a situation in
which both the BOE price and expenses increased: BOE prices
increased from $60 to $110 and expenses increased from seven
dollars to $37. Capital investment remained constant at three
dollars BOE. The next profit would be $70 BOE at the $110 price.
This would qualify for a 24 percent PPT tax equating to $16.80
BOE.
Mr. Zager noted that Example 3 would reflect a situation in
which both BOE prices and expenses significantly increased in
alignment, resulting in a constant net profit level. Absent the
net profits Progressivity approach, and were the PPT "tied only
to oil" prices, a company's profitability would not increase,
but the tax percent could increase "dramatically". That would be
"fundamentally unfair because it's a net profits tax; the
escalator should be tied to tax and not just to gross revenue".
10:18:24 AM
Senator Stedman assured that this issue was being addressed.
While Mr. Zager had presented advantages of basing the
Progressivity trigger on net profits, the advantage of it being
based on gross should also be discussed. One was "that it's less
likely to be manipulated"; it would be "un-impacted by moving
expenditures" or credits. "Credits can be triggered, if they're
accumulated, when they want to be triggered". There was also the
potential impact of expenditures "moving from quarter to
quarter, month to month". That would affect the bottom line. It
was "a generally accepted concept" that "a corporation would try
to minimize their tax and maximize their profit". A
progressivity trigger based on gross dollars would eliminate the
possibility of such manipulation.
Senator Stedman stated the reason the Progressivity trigger was
initially based on WTI oil prices instead of ANS West Coast was
that placing it on a more active market would remove possible
manipulations. The historical two dollar difference between the
two markets would be accounted for when setting the trigger
price. A third "benefit" of basing the trigger on the gross was
that it would be "much more predictable" in the effort of
keeping the government share percentage relatively constant at
various price ranges.
10:20:32 AM
Senator Stedman acknowledged there being advantages and
disadvantages to both approaches; however, it would be in the
"State's best interest" to base the trigger on gross rather than
net profits. The trigger and the slope of the tax could be
adjusted to address concerns. The State must avoid a situation
in which "expenditures and credits could be moved around to try
to impact" the tax rate. The effort should be to hold the
government's take constant.
Senator Stedman reminded the Committee that the effect of the
credits on the tax was unknown. He shared that Dr. Pedro van
Meurs, an economic consultant to the Administration, had
communicated to him his concern that the impact of the credits
on the State's revenue "could be substantial". Economic analyses
should be conducted to determine how the State's revenue would
be affected by a net profits trigger. An in-depth discussion
with State economic consultants should occur before any changes
were considered in this regard as it was a complex issue and the
impacts might not be "readily apparent".
10:21:59 AM
Senator Hoffman voiced concern that under Example 3 the risk to
the State could increase were expenses to exceed beyond $57 BOE
to approximately $70 BOE. At a 20 percent tax rate, the actual
amount of revenue the State would receive could be zero under
the net profits Progressivity formula.
Mr. Zager expressed that that scenario could occur under the PPT
regardless of the Progressivity formula. He clarified that the
net profits methodology being proposed was specific "to the
Progressivity feature of the formula". Were a company's profits
to reduce to zero, the State's take would also be zero. His
effort was to address "how to capture this windfall" and what
would be "the fairest way to implement the windfall trigger".
There would be problems were the trigger simply "pegged to
something like WTI" without being connected to profitability;
"this is a tax on profits, it's not a tax on gross revenue".
10:23:26 AM
Senator Stedman qualified that CSSB 305 would implement a 25
percent tax rate rather than the 20 percent rate depicted in the
presentation. Nonetheless, the concept being discussed was
valid. The details could be addressed later.
10:24:00 AM
Senator Stedman also noted that "imbedded" in the CSSB 305
Progressivity formula, "is the impact of having it deductible by
one less the tax rate". In effect, a company "would get a tax
deduction indirectly, but clearly it is a tax on gross". It was
"intentionally set that way".
Co-Chair Green understood the State currently recognized net
profits as the basis for determining a business's State
corporate tax. Thus, basing the Progressivity feature on net
profits would not be "a new contrived formula; it's an accepted
calculation".
Senator Stedman affirmed; however, expressed that introducing
the credit mechanism into the tax formula would alter things as
a company with credits "could move its income around". Any
proposal to incorporate a net profits Progressivity trigger must
be first thoroughly discussed with the State's consultants. He
maintained his position that it would be in the State's best
interest to base the Progressivity feature on gross revenue.
Were it determined in the future that it was a deterrent "to
getting the commodity out of the ground", it could be revisited
and adjusted. "It would be virtually impossible to come up with
something that would last the test of time without some minor
adjustments; otherwise we're going to have our necks stuck out
ten miles."
10:26:32 AM
Senator Olson observed that, as a businessman, he had hired
accountants to deal with the complications accompanying such
things as depreciation schedules, deductions, and credits.
Manipulation of numbers could occur in the endeavor to avoid
paying taxes. Thus, he was uncomfortable with the proposal to
utilize net profits in the Progressivity component.
10:27:03 AM
Mr. Zager reiterated that the PPT was a net profits tax.
Therefore, proposing to base the Progressivity trigger on net
profits "is no more subject to manipulation than the basic
monthly tax payment. Whatever it is, it's going to be highly
scrutinized." He questioned how this could "add another layer of
manipulation" since the trigger would be based on an already
agreed upon level of tax owed by a company. A net profits
trigger formula would recognize each month that, when a company
was highly profitable, the State could take a higher percent of
the profits. Conversely it would recognize when a company's
"profits didn't go up cause your costs went up as much as your
revenue, and therefore you shouldn't be subject to a higher
percentage tax".
Senator Stedman referred the Committee to an April 5, 2006
presentation [NOTE: See April 5, 2006 House Finance Committee
minutes on HB 488] in which Barry Pulliam and Dr. Anthony
Finizza, consultants with Econ Research, the economic research
and consulting firm hired by the Administration, reviewed a
chart [copy not provided] which depicted their estimates of how
the credits in the PPT would the impact the State's revenue at
oil prices ranging from $25 to $70 as affected by the tax rates
proposed in SB 305, CSSB 305 and CSHB 488. The credits proposed
in the bill would decrease the tax rates. Decisions must be made
carefully as numerous things must be considered in the decision
making process. He suggested that Econ One present their
findings in regards to additional investment in the State would
affect the effective tax rate under the provisions of CSSB 305.
10:29:51 AM
Mr. Zager determined that "having a lot of credits to deal with
would be a good thing", as that would indicate "a lot of
investment" was occurring. It would equate to "growing the pie
and that royalty piece over there's getting a lot bigger". Thus,
he agreed with Senator Stedman "that the credits can have a
significant affect here, but it could only be a positive affect
from the State's perspective if we're investing so much money
that our severance tax is going down". There were tradeoffs.
There was danger in looking at pieces of the proposal in
isolation.
Co-Chair Green interjected to note that the Committee would meet
until 11:00 AM and then reconvene at approximately 3:00 PM.
10:30:54 AM
General Comments on CS
· Debate between "get it now" and "grow the pie"
o "Get it now" option will balloon short term revenue
creating a state windfall that must be well managed
o "Grow the pie" option will create long term
opportunities for investors and for Alaska
o I am optimistic about the ingenuity and technology
available in out industry and the people of Alaska
to greatly extend oil production for the next
generation
· Consultants will one day leave and we will be left to
deal with our decisions
o First you vote on behalf of the people of Alaska
o Then over the coming years investors vote with their
dollars
· Original industry support was astounding
· However, Investors big and small, old and new,
are now saying that the Senate Resources CS
structure will discourage investment in Alaska
Mr. Zager overviewed the information. Chevron believed it would
be in the best interests of the State to "grow the pie".
10:31:13 AM
Summary Comments on CS
· Chevron cannot support the Senate Resources CS in its
current form
· Urge return to original PPT terms, while inserting a
5/20 Cook Inlet provision
· Recommend inclusion of an additional capital credit
for heavy oil or tertiary recovery (CO2) projects
statewide
· Chevron has been in Alaska for many years and intends
to continue an active exploration and production
operation in the state if a sound and stable fiscal
regime can be offered
Mr. Zager shared that Chevron did not support the 25 percent tax
rate proposed in CSSB 305 and urged the Committee to further the
provisions of SB 305 with the inclusion of a five percent tax
rate and 20 percent credit on Cook Inlet activities. Additional
credits for heavy oil and other tertiary projects should also be
added to the bill. Chevron hoped to continue its operations in
Alaska.
10:31:59 AM
Senator Bunde asked whether Chevron desired the five percent
tax/20 percent credit provisions to apply solely to existing
activity in Cook Inlet or to both existing and new activity
there.
Mr. Zager expressed the desire that the five percent tax/20
percent credit apply uniformly to all activity in Cook Inlet.
This would encourage more activity. A higher tax rate would be a
disincentive. In addition, the five percent tax/20 percent
credit would "encourage investors and owners to try new things"
they might not try otherwise.
10:32:57 AM
Senator Hoffman asked whether the application of a five percent
tax/20 percent credit should be extended to other new fields in
the State including those in the Tanana Basin and Bristol Bay.
Mr. Zager thought this should be a policy call of the State. His
"immediate interest" was to Cook Inlet. However, other "virgin
basins" such as the Nenana Basin near Fairbanks could be
included as it was a "challenged" field. At this time, he had
"no opinion" on how the State should address Bristol Bay.
10:33:37 AM
Co-Chair Wilken appreciated both the presentation and Chevron's
recognition and assistance in addressing some of the decisions
the Committee must make.
Co-Chair Wilken asked whether, in an effort to "realize
economies of scale" that would benefit the various entities,
Chevron had long term operating agreements with, for example,
Marathon Oil Company, Exxon, ConocoPhillips, and Forest in its
exploration, production, and operation activities in Cook Inlet
and on the North Slope.
Mr. Zager responded that Chevron had numerous agreements in Cook
Inlet. Each field or recognized government unit that had more
than one owner would "be governed by a joint operating
agreement". Some agreements had been in effect since the 1960s.
However, such agreements were primarily "confined to the
operations within the given unit" such as the Trading Bay Unit
or the Granite Point Unit. "Specific rules that govern who does
what, who pays what, etc. etc." On occasion, Area of Mutual
Interest agreements (AMIs), which are "fairly transient, shorter
term, come and go as companies see fit", were made for "larger
areas usually outside of existing units." They were typically
exploration agreements in which parties "agree to work together
to explore". Chevron was not currently involved in any
"significant" AMI outside of its current units. He was aware
however that other companies had AMIs to conduct work in Cook
Inlet.
Co-Chair Wilken shared the basis for his question: he was
troubled about "this notion of a 30 year" or longer commitment
without a re-opener. "It would seem to me that those that
operate in unit agreements and AMIs are fairly comfortable with
re-openers if the terms of the re-opener are agreed to" before
the agreement was signed. He asked whether he was drawing the
wrong analogy between unit agreements and AMIs and how the oil
companies talk and interact with each other. "Why that wouldn't
be applicable to the State and the producers entering into re-
openers given we struggled through the terms for those?" The
point was that since the industry routinely operated in this
matter, it would not be "foreign territory".
10:36:48 AM
Mr. Zager was unaware of any re-openers in the industry's joint
operating agreements (JOAs). Issues might become contentious
were one party to feel that a JOA was no longer working.
Unfortunately when a contract agreed upon in the 1960s, for
example, was no longer working, areas of conflict and possibly
litigation could develop. A common term used in the 1960s would
have been "how much money can you spend without your partner's
approval". While that amount might have been $10,000 in the
1960s, it would not accomplish anything substantial today. Such
things had been addressed from time to time in recognition that
changes must be made. Difficulties would arise were partners to
disagree on the changes.
Co-Chair Wilken appreciated this insight as it helped clarify
the re-opener relationship in terms of the industry and to the
State.
There being no further questions, Mr. Zager concluded his
presentation.
AT EASE 10:38:19 AM / 10:43:44 AM
State of Alaska Petroleum Production Tax
Testimony to Senate Finance Committee
(SB 305 RES)
John A Barnes, Marathon
April 6, 2006
[Note: The pages in this document are not numbered; therefore,
for reference purposes, the Senate Finance Committee Secretary
made a notation on each page of the corresponding timestamp in
which that page was addressed in this hearing. General
descriptive information of each page is provided in the body of
these minutes when feasible. A copy of the handout can be
obtained by contacting the Legislative Research Library at
(907)465-3808.]
10:43:49 AM
JOHN A BARNES, Production Manager, Marathon Oil Company,
informed the Committee that Marathon's activity in the State was
limited to natural gas production in Cook Inlet. The company had
operated in the State for more than 50 years. He appreciated
this opportunity to present Marathon's perspectives on CSSB 305.
He also noted that the information provided by Chevron was very
informative.
Mr. Barnes stressed it was impossible to compare the PPT's
impact on gas production in Cook Inlet to other global markets,
as Cook Inlet does not have "world class exploration potential".
Cook Inlet was "disadvantaged by price" and the future
projections of its "types of reserves and resources".
10:45:05 AM
Marathon Testimony - Alaska PPT
Impact of SB 305(RES) on Alaska Natural Gas
· Cook inlet Natural Gas summary: Pre PPT
· Financial Impacts of PPT
· Consequences of PPT
· What is Needed
Mr. Barnes stated that these four issues would be the focus of
this presentation (copy on file).
10:45:24 AM
Cook Inlet Natural Gas Summary: Pre PPT
· Declining reserves and production rate.
· High operating and capital costs as compared to lower
48 natural gas provinces.
· Difficult permitting and regulatory arena.
· Need for additional exploration and development to
moderate price increase to consumers and to continue
to provide industrial feedstock.
· Historic price differential to Henry Hub.
Mr. Barnes reviewed existing conditions in Cook Inlet.
10:46:09 AM
Mr. Barnes shared some "Cook Inlet Areawide Lease sale Results"
for the years 2000 to 2004 which were compiled by the Division
of Oil and Gas, Alaska Department of Natural Resources. The
information could be summarized as "encouragement for the
Inlet". He remarked favorably about the State's lease sale
program conducted in Cook Inlet. The number of tracts sold
increased from 27 in the year 2000 to 72 in 2004. In addition,
the increase in the number of multiple bids on tracts would
indicate there being increased interest in the development of
gas in the Cook Inlet.
10:46:45 AM
Timeline of Cook Inlet Exploration
[This graph depicts a timeline of the exploration
activities in Cook Inlet between 1950 and 2004. Exploration
activities peaked in the late 1960s and early 1970s.
Exploration activities declined and remained steady
thereafter. Increased exploration activities began to occur
shortly after the year 2000.]
Mr. Barnes noted that the State experienced a boom in
exploration activities in the 1960s and 1970s. At that time,
Cook Inlet "was truly a world class opportunity". Lean years
followed that boom. An increase in gas exploration wells drilled
has occurred during the last several years. While "seven wells
is a pretty good step", it was not enough. It was however, a
good indicator that some of the incentives and lease programs
the State implemented have been beneficial. Higher gas sales
prices also assisted in increasing well activity.
10:47:27 AM
Mr. Barnes stated that the comparison chart depicted on the
graph titled "Historic HH, Department of Revenue PV and DNR
Royalty Value" depicted Henry Hub (HH) prices, Department of
Revenue (DOR) Cook Inlet Prevailing Values (PV), and Department
of Natural Resources (DNR) royalty values from January 2001
through January 2005. As reflected on the chart, Henry Hub
prices could be "very volatile". While gas prices ranged from
approximately $1.50 per MCF to $8.00 per MCF during this
timeframe, Henry Hub gas prices spiked to $18 in the year 2005
as a result of the immense impact of that year's hurricane
season. The DOR PVs and the DNR royalty value lines on the chart
were recognized as "very good proxies for any type of indexing
or snapshot about what's really going on in the Cook Inlet". Gas
prices have trended upward in recent years due "to indexing of
old legacy contracts as well as new contracts" such as the
Chevron gas contract with Enstar Natural Gas Company.
10:48:27 AM
Future of Supply
· We have moved from an "Excess Supply" market to a
"Supply & Demand" market
o Cost of Natural Gas will go up
o More supply contracts are needed and will likely
be for smaller volumes
o Supply contracts will likely be more complicated
o Pipeline system will be more complicated to
operate
· We are working to identify and evaluate options to
meet future demand
o LNG imports may be economic at some point
o Storage options are being explored for peaking
purposes
o We have achieved Federal support for an in-depth
DOE study of In-State demand and for conceptual
engineering of a spur pipeline to Nenana
Basin/Fairbanks
Source: Enstar Natural Gas Company - Energy Supply in South
Central Alaska, November 14, 2005
Mr. Barnes stated that this information indicated that "the
energy situation in Cook Inlet is being recognized by all
parties. Enstar is working diligently to try to provide new
opportunities, new incentives, to bring gas to the Cook Inlet".
10:48:49 AM
Residential Costs by Region
Natural Gas Cost ($/Mcf)
Western States:
Washington, Oregon and California … $14.87
Montana, Idaho, Wyoming, Nevada, Utah, Colorado, Arizona,
and New Mexico … $11.63
Midwest:
North Dakota, Minnesota, South Dakota, Nebraska, Kansas,
Iowa, and Missouri … $15.33
Oklahoma, Arkansas, Texas, and Louisiana … $16.45
Wisconsin, Michigan, Illinois, Indiana, and Ohio … $15.63
Kentucky, Tennessee, Mississippi, and Alabama … $17.78
East:
New Hampshire, Maine, Massachusetts, New York,
Pennsylvania, Connecticut, Rhode Island, New Jersey …$19,67
West Virginia, Virginia, Delaware, Maryland, Washington DC,
North Carolina, South Carolina, Georgia, and Florida …
$19.39
Alaska $6.70
Source: Enstar Natural Gas Company: Energy Supply in South
Central Alaska November 14, 2005
Mr. Barnes stated that the price ranges of residential costs of
delivered gas in various regions of the country would indicate
"the disconnect that exists in the gas business between Cook
Inlet and the Lower 48 gas provinces." Delivered gas prices
included such things as transportation fees, storage, and
delivery of gas by a local distributing company (LDC). The $6.70
price of delivered gas in Alaska was less than half of
practically every other state's price. Western states gas prices
were lower than other continental gas province prices because of
less demand and the fact that some of those areas had their own
gas exploration. The prices depicted were the delivered price to
consumers rather than the prices gas producers received. This
chart demonstrated the benefits consumers of Cook Inlet gas
received now and would receive in the future were sufficient
exploration activity to occur.
10:49:46 AM
Senator Hoffman understood that the $6.70 delivered gas price
depicted for Alaska was solely relative to Cook Inlet.
Mr. Barnes affirmed.
Senator Olson asked for confirmation that the gas prices
depicted for the contiguous states were to delivered gas.
Mr. Barnes stated that the entirety of prices depicted was
delivered gas to the consumer. The price of gas in Cook Inlet
benefited the area.
10:50:35 AM
Conceptual Competitive Comparison
Common Input - Per Well Analysis
Recoverable Reserves 5 BCF
Development Cost (Capital) $5 million
Operating Cost $.050/mcf
Royalty 1/8
Based on House PPT (SB305,RES) and domestic severance tax
rates
Competitiveness Comparison:
Cook Inlet Natural Gas Investments
Disadvantaged Against Competition
[This analysis compares the BFIT Profit/Inv. for Alaska to
that of Oklahoma, Texas, Wyoming, and Louisiana.]
Based on Senate PPT (SB305, RES) and domestic severance tax
rates
[NOTE: The presentation incorrectly specified that the
analysis was based on the provisions of CSHB 488. It was
actually based on the provisions of CSSB 305.]
Mr. Barnes informed the Committee that this analysis presented
the conceptual economics of a well drilled in Alaska to
opportunities in other parts of the country. The comparison was
based on recoverable reserves of five billion cubic feet (BCF);
development costs of five million dollars; operating costs of 50
cents per million cubic feet (MCF), and, for Alaska, a
one/eighth royalty share. The effective domestic severance tax
rate pertinent to each of the other states was used in the
comparison. Oklahoma, Texas, Wyoming, and Louisiana were chosen
for this comparison analysis because they were areas in which
companies could drill for natural gas.
Mr. Barnes informed the Committee that the analysis was based on
the provisions of CSSB 305 rather than CSHB 488 as incorrectly
reflected on the chart.
10:51:44 AM
Mr. Barnes reminded the Committee that Henry Hub gas prices were
approximately six or seven dollars MCF while Cook Inlet prices
were in the three dollar MCF range. A Cook Inlet MCF price of
four dollars was used in this comparison to determine the "BFIT
Profit to Investment" (Profit/Inv.) reflected on the vertical
axis. Cook Inlet gas was also factored at a MCF price of seven
dollars in order to compare it to other markers. "BFIT
Profit/Inv." was defined as "for every dollar after you've taken
out your capital costs" and royalty and PPT severance taxes,
"that's the profit that you would make before you go through a
tax calculation". It was important to note that under the Cook
Inlet four dollar and other markets seven dollar price scenario,
a project in Alaska would yield slightly more than $1.50 profit;
other markets would yield profits exceeding four dollars. When
Cook Inlet gas was factored at a seven dollar price, its profit
exceeded $3.50. Cook Inlet's profit levels, when compared to
those of other markets, would substantiate the claim that Cook
Inlet gas was "disadvantaged". "All things being equal", it was
obvious where investors would spend their money. However, in
spite of this economic background, "money is being spent in the
Inlet" for a variety of reasons.
10:53:10 AM
Cook Inlet Competitive Analysis
· Must compare Cook Inlet to N American gas
opportunities
o Cook Inlet does not have world class exploration
opportunities
o However, viable smaller exploration opportunities
exist
· Good access to lands
· Disadvantaged by high costs
· Disadvantaged by permitting and regulatory burden
· Disadvantaged by price and closed market
· Disadvantaged or incentivized by fiscal regime??????
Mr. Barnes reviewed the competitive advantages and disadvantages
of Cook Inlet.
10:54:10 AM
Consequences of SB 305 (RES) - Cook Inlet Gas
· Existing Fields
o Nothing wrong with ELF for Cook Inlet natural gas
o Loss of ELF and higher tax rate in low gas price
environment will result in
ƒHigher rate required to pay for costs
(economic limit)
ƒFields will be shut in at higher production
rates
ƒReserves will be lost
· New Exploration and Development
o Higher taxes will result in:
· Less competitive opportunities compared to N
American gas provinces
· Renewed decline in Cook Inlet exploration and
development
· Cancelled projects
· NO NEW RESERVES DEVELOPED
· Loss of industrials and jobs
· Higher and volatile costs to utility customers
Mr. Barnes claimed there was nothing wrong with the existing
Cook Inlet gas ELF tax regime. "It's keeping old fields that are
very much near their economic limit producing. It was put in
place to moderate State take in recognition of the desire to
keep the field on production." Changing the current ELF tax
regime would require the amount of money generated by the field
to increase. Absent this, uneconomic fields would become be shut
in and reserves would be lost. He reviewed the information
regarding the impact the PPT would have on exploration and
development in Cook Inlet.
10:55:58 AM
Senator Dyson asked Mr. Barnes his view of the provisions in the
PPT which would allow credits for unsuccessful exploration and
development efforts occurring within three miles from shore. ELF
did not allow such credits.
Mr. Barnes presented his view of how the credits should work.
They credits should encourage companies to spend money on
drilling efforts to find new gas. Further information on the
credits proposed in CSSB 305 for successful explorations were
included in his presentation's Competitive Comparison chart [See
Time Stamp 10:50:35 AM]. While the credits increased the
economic merit, they did not increase it beyond the threshold of
being competitive. A dry hole credit would be helpful once or
twice, but he voiced that few companies would desire to have
unsuccessful wells beyond that number, as "you don't make a lot
of money drilling dry holes."
Mr. Barnes concluded therefore that the exploration credit would
"not drive the business". Marathon had some alternate Cook Inlet
tax proposal recommendations similar to those suggested by Mr.
Zager. The goal would be to "balance the State take and then the
credit opportunity which clearly would be part of an economic
analysis".
10:57:48 AM
Senator Hoffman recalled ConocoPhillips stating that the vast
majority of available production on the North Slope was in
existing fields. Known discoveries were located in four percent
of the fields and exploration activities were occurring in three
percent of the fields. Furthering that point, he anticipated
that the level of exploration activities in Cook Inlet was lower
than that occurring on the North Slope.
Mr. Barnes disclosed that exploration activity in Cook Inlet
slightly exceeded that of the North Slope as the result of such
things as incentives provided by the State. 50 MCF per day of
new gas was brought to market in the last few years from Cook
Inlet: the Ninilchik field produced approximately 40 MCF per day
and the Happy Valley field might produce approximately 10 MCF
per day. Marathon anticipated having a new field at Kasilof in
production around the end of this year.
Senator Hoffman defined those fields as "known discoveries"
rather than new exploration fields.
Mr. Barnes estimated that approximately ten percent of the
current gas production in Cook Inlet was new gas.
Senator Hoffman communicated that the intent of his question was
to determine the "piece of the pie" that would be classified as
exploration. This would assist in understanding the potential
for projects occurring there. He would appreciate this
information being provided.
Mr. Barnes responded that an attempt would be made to provide
such information. To further clarify Senator Hoffman's request,
he advised there being two issues: "one is recent new gas or
activity level and then maybe a projection of what the future
might look like as to cancelled projects.
Senator Hoffman qualified the issue to consist of "known
discoveries and future exploration".
11:00:40 AM
Mr. Barnes noted that another issue of concern with CSSB 305 was
the "pass through" of expenses to consumers. Approximately 50
percent of the severance taxes in Cook Inlet were "passed onto
industrials" and approximately 50 percent were passed on to
consumers. Any tax increase under the PPT would be passed on.
The amount could increase were gas Cook Inlet "linked" or
"indexed" to "a volatile outside market"; thus he would
discourage that linkage. It would also create additional
problems associated with the monthly calculations of an index
for the utilities. Dialogue should occur with utilities in
regards to how they would determine their rate structure in
consideration of this volatility. "Most utilities prefer to
understand for their upcoming year what their cost of gas will
be." Problems would be anticipated were the utility to
incorporate a monthly variable into the equation as to what
would be charged to consumers.
11:02:04 AM
Cook Inlet - What is Needed
· Problems with Progressivity
o Potential higher tax rate at lower margins
o Must not link Cook Inlet PPT to volatile non-
related index
o Link to Cook Inlet Department of Revenue
Prevailing Value
· Must include provision for marginal low rate fields
o 5/20 Plan for Cook Inlet
· Prioritize efforts to incentivize, not hinder
exploration and development
o Include some form of transitional investments
credits
· Actions by this Legislature will have immediate and
measurable impact on Cook Inlet oil and gas industry
Mr. Barnes reviewed the information. He supported including a
Cook Inlet specific five percent tax/20 percent credit provision
in the PPT. The average tax currently paid in Cook Inlet was
approximately five percent.
Mr. Barnes reiterated that when production in Cook Inlet was
analyzed under a 20 percent PPT tax rate, the incentives were
insufficient to maintain viability in Cook Inlet. He estimated
that the impacts of the PPT would be "felt sooner" in Cook Inlet
than they would on the North Slope.
Senator Hoffman recalled that approximately $1.5 billion in
investments were being made on the North Slope. The proposed
credits could increase that amount to $2.5 billion. To that
point, he asked the current and forecasted investment scenario
for gas in Cook Inlet.
Mr. Barnes was uncertain of the overall Cook Inlet investment
picture. He recalled Chevron stating they might invest $200
million over the next four years. That number would not be
"dissimilar to what Marathon has spent over the last several
years" in its drilling activities. Marathon drilled 50 wells in
the last five years, several fields were brought into
production, and a new pipeline was laid. A similar level of
activity would be anticipated in the future. That was really
"what's at stake".
Mr. Barnes noted that Cook Inlet "currently burns" approximately
200 BCF annually. In order to replace reserves at a 50 cent
exploration and development cost, $100 million a year must be
spent "just on your wells". That activity level had not been
occurring. However, the construction of exploration wells was
one of "many good signs" of increased activity in Cook Inlet.
Co-Chair Wilken requested that information provided by the
Department of Revenue and other presenters to be made available
on the internet. He also asked that a meeting be scheduled to
allow "invited" individuals to testify on the PPT via
teleconference, as there were some who could not attend in
person.
Co-Chair Green concurred.
Co-Chair Green specified that the Committee would recess and
reconvene at approximately 1:00 PM. She noted that public
testimony on the PPT bill would be held Saturday, April 8th.
Co-Chair Wilken announced the tentative schedule for the
Operating Budget hearings.
RECESS TO CALL OF CHAIR 11:07:51 AM / 1:09:55 PM
Co-Chair Green called the Committee back to order.
KEN THOMPSON, Managing Director, Alaska Venture Capital Group,
testified via teleconference from an offnet location. He read
his testimony [copy on file] as follows.
April 6, 2006, Comments to Alaska Senate Finance Committee
CS For SB305 - Petroleum Production Tax
By Ken Thompson
Introduction
For the record, my name is Ken Thompson. I reside in
Anchorage. I am the Managing Director of Alaska Venture
Capital Group, or AVCG, an independent oil exploration
company with a focus on the North Slope of Alaska. AVCG is
a consortium of 15 independent oil and gas companies and
individuals from Kansas and my personally owned company,
Pacific Star Energy, here in Alaska. AVCG has a technical
and operational services' subsidiary company called Brooks
Range Petroleum, with newly opened offices in Anchorage.
Many of you know me as the former President of ARCO Alaska,
Inc., and a past Executive Vice-President over ARCO's Asia
Pacific region.
Mr. Thompson had 12 years of professional experience on the
North Slope and Cook Inlet.
AVCG has been very active in the past six North Slope (NS)
areawide lease sales and we have acquired over 160,000
acres of exploration leases in five exploration prospect
areas, including new acreage we acquired in the recent
March 1, 2006, NS lease sale. Our exploration strategy is
to explore in the central part of the North Slope for
fields in the 25-150+ million barrels range, fields that
may be too small for the giant producers but fields that
can be produced profitably by smaller companies like ours.
We believe there are hundreds of millions if not billions
of barrels of oil left on the North Slope in smaller fields
of this size and these fields near infrastructure can be
brought on more quickly. Our first exploration well in
partnership with Pioneer Natural Resources - the Cronus #1
about 10 miles southwest of the large Kuparuk Field -
completed drilling last week but results will remain
confidential for some time.
AVCG plans two NS exploration wells next winter and two
wells the following winter. Our 3-year exploration budget
is $46 million and with any future discovery success, we
could have a gross development budget of $500 million to $1
billion in future years.
Let me now focus my comments on the CS for Senate Bill 305.
As background, I reluctantly supported the Governor's
proposed 20/20 PPT and even many details of the initial
House version of the bill, HB 488. But, somehow, things are
beginning to derail. The CS SB 305 and CS HB 488 with their
revisions from the original draft of a simple petroleum
profits tax have evolved into very complex bills that are
no longer a win-win for the State and industry, in my
opinion. I don't fully understand how things began to
derail into such complexity…perhaps it was due to anger at
the Big 3 producers and the Governor for not revealing the
natural gas contract details before demanding a new oil tax
fiscal structure. Perhaps its anger at the Big 3 companies
who are demanding tax certainty for 30 years when asking
for three full decades of certainty truly is an
unreasonable demand with Alaska's legislative type of
democracy.
1:14:05 PM
Mr. Thompson clarified that AVCG and other independent oil
exploration companies "are not asking for 30 years of certainty.
We realize the world and circumstances do change".
1:14:14 PM
I don't understand all the dynamics of the past three weeks
in the legislature, but this I do know. The CS for SB 305
needs to be greatly simplified and it needs to move
somewhere between what it is now and the Governor's
proposal if a win-win solution is to be the end result that
balances more revenue share for the State but in balance
with attracting more new entrants and increased investment
amounts.
I am an optimist. I personally think there is still time to
avoid a train wreck in this complicated business of
restructuring Alaska's petroleum taxation system … if the
Senate Finance Committee acts quickly. I, for one, have not
given up hope that there is a version - easier to
understand and to implement - that can be a win-win for
both the State and the industry. There is a simpler and
better way, in my opinion, for the State to improve
government take while not dampening exploration and
development investment. Let me outline my suggestions for a
win-win and my suggestions for simplification.
1:15:30 PM
AVCG Owners' Perspectives
First, however, let me say that while I am Managing
Director of AVCG, our other owners disagree strongly that
any change should be made to the 20/20 PPT formula proposed
by the Governor. The 20% PPT tax rate and the 20% credit
originally presented in the Governor's bill should be the
tax rate and credit enacted. Some of the AVCG owners,
however, do not even support the PPT concept and believe
the petroleum tax should be as simple as 10-14% of revenues
and exclude any economic limit factor.
Quite honestly, the AVCG owners listened in disbelief when
I told them the production profits tax rate being
considered in the current CS to SB305 draft could add a
"surcharge" at high prices that could significantly ramp up
the additional taxes above the base PPT rate of 25%. And
this surcharge will be in addition to the higher other
revenues the State and Federal governments will already
benefit from at higher oil prices: the State's 12.5-16.7%
royalty, the ad valorem property tax, the 3-9% corporate
income tax, lease bonus bid amounts, the ongoing annual
lease rental amounts, and the Federal income tax rates
averaging 20-35% of taxable income.
It all adds up, and AVCG Owners are saying, "enough is
enough."
When I was communicating the latest CS to SB305 details to
the AVCG owners by teleconference and email recently, I
felt two overwhelming emotions. The first emotion was
discouragement. My business judgment tells me the State
crossed the line to excessive taxation that will dampen
capital investment. Why invest in Alaska where you loose
the upside gain at high oil prices to offset exploration
risk when the government take will exceed 60%? There are
politically secure opportunities in other U.S. states,
Canada, the Gulf of Mexico offshore, the U.K., and other
nations where government take is 55% or less. CS to SB305
takes away too much of the upside potential from the
investor who is taking the risk.
But I also found interesting another strong emotion during
that teleconference which surprised me a great deal. I was
embarrassed. Here I was, telling a group of outside
investors that recently put all of their focus and personal
exploration budgets on the North Slope of Alaska, and now I
was telling them that Alaska was creating the most complex,
confusing production tax bill ever created since the
disastrous Federal windfall profits tax. The windfall
profits tax - structured similarly to the CS SB 305 revenue
surcharge - stalled investment in the U.S. oil and gas
industry, resulting in an alarming increase in U.S. foreign
oil imports which our nation lives with to this day. I was
telling them that Alaska was levying the highest tax rate
and government take in North America.
1:19:27 PM
Mr. Thompson expressed his love for the State. It was his home
and he hoped it would prosper. However, he was embarrassed to
tell AVCG's investors the State was considering implementing the
highest severance tax in North America.
To back my points up, please let me cite some statistics.
Currently, the total Alaska and Federal governments' take
is just over 50%.
Mr. Thompson understood and supported the State's desire to
increase "its share of the take at higher prices".
The Governor's proposal moved this to 53% or so then the
original SB 305 moved the government take closer to 55%.
Then the CS to HB 488 [NOTE: SB 305 was incorrectly
referenced in the written testimony] moved the government
take closer to 55 %. Then the CS to SB 305 with a 25% PPT
boosted the government take to over 60% with its
"surcharge." This compares to following total government
take including Federal government shares:
Alaska currently 50%+ or less, dependent on
oil price and field size
Alaska Governor's bill 53%
Alaska original HB488 55%
Alaska CS SB305 60%+
U.S. Gulf of Mexico 45%
Colorado 51%
Wyoming 52%
Kansas 53%
Texas 53%
New Mexico 53%
Oklahoma 53%
California 53%
Louisiana 57%
These tax rates apply to newer fields. Older, more mature
fields at low production rates typically get exempted from
these maximum tax percentages in various ways.
Mr. Thompson noted that the average state tax rate was
approximately 53 percent.
U.K. 50%
Canada 39-56%
The lower rates in Canada apply to the oil sands projects
where billions of dollars for new investment are occurring
with Canada's vision to lower government take on this
resource base.
1:21:44 PM
Mr. Thompson noted that the 39 percent tax rate in Canada was
"typically the result of incentives in the very viscous oil
sands". He found it "interesting how capital varies" in the
differing tax regimes. Capital investments between $1.5 billion
and two billion had been annually invested in Alaska's oil and
gas industry under its current tax structure. Those amounts
would increase due to tax credits. The investment in the United
States Gulf of Mexico (GoM) with a 45 percent government take
had experienced annual five to ten billion dollar investments
and on occasion $15 billion a year. Lower government take had
been accompanied by continued investment to improve production.
Mr. Thompson noted that a March 28, 2006 New York Times article
specified that major companies had committed ten billion dollars
a year for the next ten years in capital spending to the Alberta
oil sands. While those fields had immense prospectivity and
reserve potentials, the 39 percent government tax rate was also
an important factor in that investment.
1:22:47 PM
My overall key recommendation in my comments today is this:
the State should not exceed a threshold of 55% total
government take, 45% producer take. The State does own the
resource and may be due more than a 50% take. On the other
hand, it is the producer who is taking the capital risks
and deserves at least 45% for making things happen … for
moving an innovative exploration or development idea into
production without which no revenues would flow.
Let me say that I'm excited about what's happening in
Alaska's oil patch right now, and let's not dampen the
spirit. The current versions of SB 305 and HB 488 have
dampened my spirit. I am discouraged. Let's have a new tax
bill that encourages, not discourages new entrants. But I
do believe it is time the State share more in the take at
high prices but there is a much simpler way.
1:24:07 PM
My Personal Perspective
Now let me shift gears in my comments to you. Because I
could not get buy-in for any alternatives from the AVCG
owners except the 20/20 case, I have decided to speak out
alone. As an Alaskan, I am concerned and feel I must try to
share a personal perspective trying to balance what is best
for my continued involvement in Alaska's oil and gas
industry in balance with how the State must change its
system to be competitive in the world and realize a higher
government share.
So, let me turn my attention to what key changes I would
make to the CS of SB 305. Again, my views are not supported
by AVCG owners or others in industry; rather they are my
personal views.
1:25:28 PM
Mr. Thompson stated that were a bumper sticker created to
reflect his foremost position on the appropriate State take, it
would be "55/45". A 55 percent government take would increase
revenue to the State without dampening capital investment in the
oil and gas industry. He provided an overview of five
suggestions as to how to accomplish the "55/45" tax regime. Each
of the five suggestions were addressed individually as follows.
1:27:27 PM
1) Make Tax Rate Progressive But Greatly Simplify The
Taxation Formula
When the Governor's office first announced a 25% tax rate
then amended that to 20%, I could see the move by
legislators to somehow bridge the gap from 20% to 25%.
However, the approach used by the legislative committees
based on the legislature's outside consultants' work is
simply too complex and will be arduous to implement. I
think - and perhaps all of you think - the Federal tax code
is too complex. The changes to SB 305 are also too complex
and will lead to different interpretation, "gamesmanship"
possibly by some companies because of the unwieldy
progressive tax structure formula, and future costly
lawsuits when the State disagrees with a company's
calculations. And the number of accountants to keep track
of these complexities on both sides will balloon! I urge
you to simplify, simplify, simplify...yet still have some
progression at higher prices.
For my company which drills the smaller oil traps that may
add up, we do not have a lot of upside potential in seeing
these smaller fields grow much larger in reserves over time
in contrast to the giant Prudhoe Bay and Kuparuk fields. So
our main upside is in oil price escalation to offset
exploration risks and to offset the cycles of oil prices
downward, a reality over time for any commodity. I urge you
to consider a PPT rate of 20% at lower prices but gradually
escalating to the 25% level only at higher prices.
I found it so interesting to see the Econ1 consultants and
consultant Daniel Johnston saying the government should
take more and more at high prices when not one member of
the legislature asked them a very important question they
should have been asked: "how much are you and your company
investing in Alaska?" I was shocked to see that these
consultants, when calculating the future revenues to the
State at various escalating rates, used the same oil
production curves. In reality, less capital will be spent
by industry at exorbitant production profits tax rates (tax
rates above 25% when coupled with all other payments such
as royalty, corporate income tax, ad valorem tax, lease
costs and rentals, etc.). With less capital spending, the
production curve will be lower … an increasingly higher tax
rate may not in the end yield the forecasted revenues for
the State.
1:31:03 PM
Mr. Thompson reiterated that capital spending in Canada and the
GoM, which were areas with lower government take percentages
than Alaska, far exceeded capital investments made in Alaska.
1:31:26 PM
On a related note, our company plans to go into the private
or public equity markets to raise capital for future
development. Such equity investors invest in the oil
markets to be fully exposed to crude price upside. When
they look at investments all over the world, and see that
Alaska could tax with an escalating "surcharge" when others
have a predictable flat tax, they will place their capital
elsewhere to continue their exposure to higher crude
prices. The consultants did not address this issue of the
private and public equity markets and the desire for such
investors to fully benefit from upside commodity price
swings without hedging or escalated taxation at high
prices. This was indeed a major oversight by Econ 1 and
Daniel Johnston.
1:32:59 PM
I also could not believe that the consultants failed to
show capital spending elasticity graphs from different
countries. They did the legislature a disservice by not
doing so. By convincing legislative committees to adopt a
complex progressive tax rate structure, or windfall profits
tax, the consultants may feel they have been successful,
but not one of these consultants will be around to defend
their views in the future when capital spending declines at
increasingly higher tax rates above the 25% level.
1:33:55 PM
So, what is a simpler alternative? What is an alternative
to yield more revenues to the State at higher oil prices
with a balance to attract increased investment?
I suggest that the Finance Committee revise the bill to
keep the production profits tax simply that … a tax on
production profits, and not a complex way to further burden
gross revenues with a surcharge. A simpler way in getting
the progressive rate from 20% to 25% without the surcharge
treatment complexity is to adopt a graduated PPT that does
accomplish a higher State take at higher prices, yet leaves
a reasonable producer take.
I recommend the following production profits tax schedule
as a suggested one to "simulate" revenue results somewhere
between the Governor's proposal and the CS to SB 305
proposal. It is one that everyone could easily understand
and implement with the State realizing upside at higher oil
prices yet not too much upside is taken away from
explorers/producers for re-investment:
1:34:39 PM
Up to monthly average wellhead
price of $50/barrel for a company: PPT rate of 20%
1:34:48 PM
When monthly average wellhead
price is between $50-75/barrel: PPT rate of 22.5%
When monthly average wellhead
price exceeds $75/barrel: PPT rate of 25%
1:35:17 PM
Let's be honest with ourselves: the surcharge is simply a
windfall profits tax under a different name. I highly
respect industry consultant Daniel Yergin who has an
excellent reputation among industry personnel and
government officials alike. In November, 2005, Mr. Yergin
said this about a windfall profits tax: "What a windfall
profits tax does is introduce a lot of distortion. It
reduces investment, it increases a sense of political risk
and it doesn't achieve the goal that is intended … it will
really lead to decreased supply."
I urge the Finance Committee to seriously consider this
simpler approach. I personally ask that you have the
Department of Revenue run the above case to compare the
State revenues from the Governor's proposal to the current
CS SB305 proposal, and to the existing ELF severance tax
program. But when DOR models this approach, also ask them
to run some sensitivity cases to reduced capital
expenditures and reduced future oil production levels if CS
SB305 stays in its current form. Please greatly simplify
the bill. The complexity is simply not needed.
1:36:47 PM
2) "Trigger Points" For Escalating PPT Should Not be WTI
But Wellhead Value
Let me now address a second, very leveraging issue. The
"trigger point" that increases the PPT tax rate from 20%
should not be based on ANS West Coast (ANS) oil price. The
"trigger point" should be when a company's average realized
wellhead price in Alaska exceeds $50 per barrel. Some say
the trigger point should be at a lower price like in SB
305, but I do think there is strong merit that those who
have invested and taken exploration risk and exposure to
low prices should be able to benefit from the increased
profits at higher prices…"share the pain, share the
gain"…to this $50/barrel wellhead level. However, I
personally am fine with the State gradually increasing the
PPT tax rate eventually to a cap of 25% when wellhead
prices exceed $50/ barrel.
Why should the State tie the PPT calculation to a company's
realized wellhead price instead of to West Coast crude
price? In reality on the North Slope, not one company ever
sees West Coast crude prices. Every crude oil in Alaska is
different in quality with viscous crude receiving less than
the lighter crude oils, and oil produced from wells farther
away from infrastructure receiving less wellhead value due
to higher shipping costs. Conversely, oil in the Cook Inlet
is close to actual refining or on the water to ship out of
state and thus realizes on average a much higher wellhead
value than most North Slope crude oils, a substantial plus
to Cook Inlet operators who face higher operating costs
with maturing fields.
Mr. Thompson referenced Co-Chair Green's earlier question as to
whether the net profits calculation suggested by Chevron had
been included in any version of the PPT proposals. He suggested
that perhaps what she had in mind was actually to a company's
gross wellhead value.
1:38:56 PM
So I ask, why should the tax rate increase with a price
index such as West Coast price when there is such a
variance in crude oil pricing factors on the Slope at the
wellhead that directly affect each field's economics and
economic limit differently? The production profits tax
rate should not escalate at the same time for those who
produce viscous crude or oil from a farther distance as
compared to those who have good quality oil right next to
the TAPS line. If there is a "trigger point", it should be
one based on a company's average monthly realized wellhead
price for production.
1:40:05 PM
I recommend that the "trigger point" for PPT tax rate
escalation be $50 per barrel realized wellhead price based
on a company monthly average and not be based on $40 West
Coast price, thus allowing explorers and producers to share
in the upside profits at prices to this level with no
higher burden than the 20% PPT tax rate (plus burden of
royalty, corporate income tax, ad valorem tax, Federal tax,
etc.). Dr. Pedro van Meurs also recommended that the
threshold level of $40/bbl be re-considered. As also
recommended by Dr. van Meurs, this threshold price should
be linked with inflation.
1:41:37 PM
3) The Transitional Deductible Allowance
Jumping immediately from the prior ELF severance tax to the
PPT formula overnight wreaks havoc with a company's
budgeting and their forecast of available cash flow for
near-term capital investment. A transition adjustment of
some sort is appropriate and is fair.
I support the CS to SB305 that allows for a producer to
take a credit with part of a producer's transitional
investment expenditures between April 1, 2001, and before
April 1, 2006.
1:42:10 PM
4) The Tax Credit "Standard Allowance"
The Governor proposed a $73,000,000 annual allowance of
production profits that would not be taxed by the PPT,
essentially giving a $14.6 million tax credit per company.
The Senate Resources Committee revised this downward to a
$50,000,000 annual allowance as a reasonable compromise, or
a $10,000,000 tax credit; CS HB 488 further changed this to
a flat $12,000,000 annual credit. The CS to SB 305 further
proposed that this be changed to an annual "standard tax
credit allowance" for the first 5,000 barrels per day of
production.
This "standard deduction" is very important to a startup
company like AVCG/Brooks Range Petroleum trying to
establish a foothold in Alaska and someday contribute
substantial oil revenues to the State.
I favor the HB 488 solution of a $12,000,000 annual flat
tax credit exemption due to its simplicity and it is a
level playing field for producers of various crude oils
with different wellhead values.
1:43:59 PM
5) Institute A Tax Credit Repurchase Program
As protection for explorers and new entrants to Alaska, the
version of the profits tax in the House, CS to HB 488
devised a tax credit repurchasing program for those credits
a company earns on expenditures up to $10,000,000 per year
for investments in exploration and/or lease purchases in
Alaska.
This is important to explorers like AVCG who does not yet
have production revenues. Without such a repurchase
program, our company might be able to sell our annual tax
credits to one of the major producers but have to accept
only 90-95% on the dollar or less. On the other hand, the
State would not be giving up anything to repurchase the
credits at 100% of value because the major producers would
otherwise use the credits to reduce their tax bill and
reduce revenue to the State. But using the State repurchase
approach, the small explorer could turn around and re-
invest the State-refunded credit into new leases, seismic
or exploration drilling.
I recommend the Finance Committee support the tax credit
repurchase program outlined in the CS to HB 488 and amend
CS to SB 305 to incorporate a similar tax credit repurchase
program.
And the Alaska gas pipeline revenues will be significant.
The State should own 20%.
1:45:35 PM
Other Revenue Sources
As a concluding remark, I urge the State in this period of
high oil prices to not simply try to gain into that upside
by pulling only one lever excessively … the lever of
petroleum production taxes. The State could be well advised
to ensure they gain additional revenues from oil in Alaska
by being an entrepreneur and considering revenues from
other new related business, such as acquiring a 12.5%
interest in the TAPS pipeline and stop paying $3.70/barrel
profitable tariffs to major producers when you could be
sharing in those profits.
1:46:47 PM
And work with the Federal government now to ensure that
they share part of the Federal royalties with the State on
future offshore oil and gas production from the Beaufort
Sea which I consider to be of great potential as evidenced
by major leasing recently by Shell and other companies.
Other states are pursuing a share of Federal offshore
royalties.
1:47:36 PM
Mr. Thompson shared that Congress was currently considering
legislation, proposed by a senator from Louisiana, which would
allow energy producing states to receive 50 percent of the
federal revenue generated by oil and gas production off their
coasts. While he was uncertain of the degree this might apply to
Alaska, the adoption of this bill would provide Louisiana $600
million per year. In a decade or so, such revenues might be
provided to Alaska for activity occurring in the Beaufort Sea,
were the State to participate in that federal legislation.
Mr. Thompson expressed that the State could garner additional
revenues were it to adopt a tax regime of "55/45". It would also
benefit from revenues generated by an Alaska gas line. The State
should own a minimum of 20 percent in such a project.
1:48:47 PM
Concluding Remarks
The above comments are my personal views offered with a
hope that there can be an eventual win-win solution to this
complex subject of the State realizing more revenues at
higher prices while attracting exploration and development
investors who can also realize upside at higher prices. I
do believe the Senate Finance Committee can get things
"back on track" and better balanced.
I sincerely thank the Committee for the opportunity to
present my comments.
Mr. Thompson reiterated that a tax rate of "55/45" would be the
"winning" tax structure for the State. He concluded his remarks.
1:49:38 PM
Co-Chair Wilken acknowledged being educated about the term
"prospectivity" and its association with how the State was
graded for investment potential. He was surprised that potential
reserves in ANWR and NPR-A hade been ignored in this discussion.
Thus, he asked whether the State might be "selling ourselves
short by not recognizing those giant fields in our grade for
prospectivity".
1:51:06 PM
Mr. Thompson responded that entities from outside the State view
prospectivity in Alaska as having diminished "significantly".
While this might be true when considering the central portion of
the North Slope and the mature fields in Cook Inlet, he believed
there were "very very significant oil reserves" in NPR-A. He had
personally viewed "a large number of good looking stratographic"
seismic tracks there. He anticipated "major discoveries being
announced" there in the next few years. The prospectivity of
fields in near shore State waters was also promising. "One of
the best strategic moves" he had witnessed in the oil and gas
industry in several years was the "very bold strategic move by
Shell" to acquire Beaufort Sea leases. One reserve in that area
had "a proven 200 million barrels of reserves, yet was not
commercial at $18 because it was far from shore" in the Arctic
Icepack. Nonetheless, he thought Shell would be successful in
their endeavor. There was also increased interest in areas such
as Bristol Bay.
1:53:05 PM
Mr. Thompson suggested that in order to determine the
prospectivity of an area, the Committee should "look out the
window and see who's flying". In addition to Shell's recent
reentry in the Alaska marketplace, large companies from Italy
and France and large, respected independents such as Pioneer
Natural Resources were also active in the State. While some
people consider there to have been a prospectivity decline on
the central part of the North Slope, companies such as AVCG were
"playing" the area because "25 to 50 million barrels" was "a
company maker to us". Fields that size were not even reflected
as reserves in a major company's records.
Mr. Thompson considered the prospectivity of Alaska to have been
"sold short" by many. There could be the potential for another
hundred trillion cubic feet of natural gas yet to be found.
1:54:18 PM
Mr. Thompson urged the Committee to conduct an internet search
and view industry journals about the State's proposed PPT.
"Article after article" would be presented. "People are being
turned off by it: they don't understand it but they know it is
complex, they know it would increase taxes and take away some of
the upside at high prices". He was concerned that the effect of
the proposed tax would be to discourage newcomers in the
industry. A simpler method could be developed which would allow
a government take of 55 percent. A balance of "55/45" would
increase State revenue without discouraging industry from
operating in the State.
1:55:45 PM
Senator Dyson appreciated the comments. Earlier in today's
hearing, it was suggested that a different tax rate be applied
to Cook Inlet because exploration and production activities
there differed dramatically from those on the North Slope. He
asked Mr. Thompson to comment in that regard.
Mr. Thompson affirmed that Cook Inlet was "a very mature basin".
The tax rate comparisons he had shared earlier, which averaged
approximately 53 percent, were specific to new production. "Most
of those states have some type of exemption that can allow less
of a tax burden on more mature areas". He did not have any
recent experience in Cook Inlet, however, his "old view" was
that, while "something different needed to be done", it was not
that a different production tax structure should be applied
since that might require separate sets of accounting to occur.
He preferred there being different "investment tax credits to
try to spur on new exploration". There could be a "special
increased incentive for Cook Inlet exploration".
Mr. Thompson thought that "an experiment that has done wonders
for spending in the Gulf of Mexico" could be applied to Cook
Inlet. "That was a straight royalty reduction". While a royalty
reduction law was currently available in Alaska, it was complex
and a company must provide a significant amount of data and
paperwork to the State. The methodology utilized in the Gulf of
Mexico "simply" lowered the royalty from 12.5 to five percent.
The result was that capital "flew to that area" and
prospectivity increased. Thus, he suggested a blanket reduction
in royalties in Cook Inlet be considered. Nonetheless, he
deferred to the expertise of current Cook Inlet producers.
There being no further questions, Mr. Thompson concluded his
remarks.
2:00:10 PM
Co-Chair Green asked Committee members to advise her of any
issue they desired desire additional information about.
Suggestions for changes and other questions would also be
appreciated. The purpose would be to garner as much information
as possible going forward.
Co-Chair Green noted that the House of Representatives had
conducted a "very successful" PPT panel discussion earlier in
the day. She suggested that a similar event be considered by
this Committee.
2:01:34 PM
Co-Chair Wilken stated he had personally developed a list of 12
items he would like further information about. This list would
be provided to Co-Chair Green. Continuing, he shared his
understanding that the cost of transporting a barrel of oil from
Prudhoe Bay to the West Coast was $4.31. Within that $4.31 cost
was an item referred to as a "profit component" which was being
claimed by the producers. Thus his question to Senator Stedman
and Senator Dyson, who were members of the Senate Resources
Committee, was whether the State currently recognized "profit as
a cost and if so, was that a policy call or is that standard
procedure in the way we transport oil around the nation".
2:02:54 PM
Senator Stedman stated that while this issue had been discussed,
it was not addressed in great detail. The answer to "the issue
of a profit on a profit and the majors owning the Trans Alaska
Pipeline System (TAPS) and having a regulated profit in that and
then being able to layer another profit on top of that" was yes.
The Committee should explore the impact of that.
Co-Chair Wilken communicated that this question would be
included on his list, "cause it just doesn't make sense…" It
would be interesting to delve into the reasoning behind this.
Senator Stedman agreed it would be a good question to present to
the Department of Revenue and Econ One.
2:04:20 PM
Senator Hoffman communicated that the profit component was
included in the Transportation expense because the industry's
investment in the Trans Alaska Pipeline Service (TAPS) was
considered "a risk". He did not view this as an issue, as the
line had to be built. The question would not have been asked had
another company made that investment. Continuing, he stressed
that one of the reasons the State was interested in investing in
the proposed gas pipeline would be to make a profit, rather than
to "simply break even".
Co-Chair Green understood that investing in such an endeavor
would be considered "high risk".
Senator Hoffman affirmed.
Senator Stedman noted there was also concern about how TAPS
tariffs were levied and how that ultimately affected the State.
Co-Chair Green asked whether such things were regulated.
Senator Stedman stated they were, but communicated "that a
regulated return on that tariff gets to be a … contested issue".
Co-Chair Green was uncertain as to how action by the Legislature
could address that.
Senator Stedman concluded that the concern was to how these
things "play into the mathematical modeling". They might not
have any affect.
Co-Chair Wilken communicated that these questions could best be
addressed by Dan Dickinson, the consultant hired by the
Administration.
Co-Chair Green expected "lots more information" on the bill
would be forthcoming. The Committee would then dissect the bill
section by section.
There being no further discussion, Co-Chair Green ordered the
bill HELD in Committee.
AT EASE 2:07:30 PM / 2:07:47 PM
ADJOURNMENT
Co-Chair Lyda Green adjourned the meeting at 2:08:00 PM.
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