Legislature(2013 - 2014)SENATE FINANCE 532
03/06/2013 01:30 PM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB21 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | SB 16 | TELECONFERENCED | |
| += | SB 21 | TELECONFERENCED | |
SENATE FINANCE COMMITTEE
March 6, 2013
1:32 p.m.
1:32:45 PM
CALL TO ORDER
Vice-Chair Fairclough called the Senate Finance Committee
meeting to order at 1:32 p.m.
MEMBERS PRESENT
Senator Pete Kelly, Co-Chair
Senator Anna Fairclough, Vice-Chair
Senator Click Bishop
Senator Mike Dunleavy
MEMBERS ABSENT
Senator Kevin Meyer, Co-Chair
Senator Lyman Hoffman
Senator Donny Olson
ALSO PRESENT
Michael Pawlowski, Advisor, Petroleum Fiscal Systems,
Department of Revenue; Barry Pulliam, Managing Director,
Econ One Research, Inc.; Joe Balash, Deputy Commissioner,
Department of Natural Resources; Senator Hollis French.
SUMMARY
SB 21 OIL AND GAS PRODUCTION TAX
SB 21 was HEARD and HELD in committee for further
consideration.
SENATE BILL NO. 21
"An Act relating to appropriations from taxes paid
under the Alaska Net Income Tax Act; relating to the
oil and gas production tax rate; relating to gas used
in the state; relating to monthly installment payments
of the oil and gas production tax; relating to oil and
gas production tax credits for certain losses and
expenditures; relating to oil and gas production tax
credit certificates; relating to nontransferable tax
credits based on production; relating to the oil and
gas tax credit fund; relating to annual statements by
producers and explorers; relating to the determination
of annual oil and gas production tax values including
adjustments based on a percentage of gross value at
the point of production from certain leases or
properties; making conforming amendments; and
providing for an effective date."
1:33:07 PM
Vice-Chair Fairclough communicated that the meeting would
include invited testimony from the Department of Revenue
(DOR), Department of Natural Resources (DNR), and Econ One.
She shared that public testimony would begin in the
following meeting at 3:00 p.m.
MICHAEL PAWLOWSKI, ADVISOR, PETROLEUM FISCAL SYSTEMS,
DEPARTMENT OF REVENUE, relayed that the administration had
been asked to provide responses to initial questions on the
legislation and on the relationship between gross revenue
exclusions (GRE) and credits in particular.
BARRY PULLIAM, MANAGING DIRECTOR, ECON ONE RESEARCH, INC.,
provided a PowerPoint presentation titled "Comments to
Senate Finance SB21/SRES CS SB 21" (copy on file). He
shared that the goal was to address members' questions on
how various credits would work and interact with one
another. He pointed to slide 2 titled "North Slope Tax Rate
under SRES CS SB21 with $5/bbl Production Allowance." The
administration had heard some concern about the 35 percent
base rate (an increase over the 25 percent rate). He
explained that under the proposed system the rate would
work in tandem with the $5 per barrel production allowance,
which would lower the rate. He stated that in reality the
35 percent rate would never apply (as indicated on slide 2,
which included a net taxable value scale of $0.00 to $200
per barrel).
Co-Chair Kelly asked if the chart showed the production tax
or the overall state tax. Mr. Pulliam responded that the
chart only showed production tax.
Co-Chair Kelly asked for verification that slide 2 did not
include the royalty. Mr. Pulliam replied in the
affirmative. He elaborated that the slide illustrated the
tax rate that would apply on the production tax at various
prices; it was possible to translate the values into West
Coast prices by adding approximately $40 per barrel.
1:37:00 PM
Mr. Pulliam looked at slide 3 titled "GRE Equivalent Value
from Specified Production Allowance (35% Tax Rate)." He
addressed that the various mechanisms (operating at a
single tax rate) were designed to achieve a system that was
not regressive; a system that had a slight progressive
component that countered the regressive effect of the
royalty. The system could be accomplished with a GRE, per
barrel allowance, or capital credit. He discussed the
relationship between the per barrel allowance and GRE. The
current CS included a $5 per barrel allowance and a 30
percent GRE for new oil. The $5 per barrel allowance
represented by the blue line on slide 2 showed what kind of
GRE it achieved. He elaborated that the allowance could be
thought of as a GRE; it declined as price rose and rose as
the price fell because the fixed barrel allowance remained
the same. For example, under the CS at approximately $80
per barrel the $5 allowance crossed the 20 percent GRE
mark. The chart illustrated that an allowance level of $10
per barrel would be equivalent to a 40 percent GRE at the
$80 per barrel price; the allowance level at $15 per barrel
was equivalent to a 60 percent GRE at the $80 price. He
reiterated that the allowance percentage would decline as
the price rose. The concepts were similar but were
structured differently; the GRE provided a percentage off
of the value of the oil, whereas the per barrel allowance
provided a varying percentage off the value of the oil. He
reiterated the different structures.
1:40:56 PM
Vice-Chair Fairclough welcomed Senator Hollis French to the
committee room.
Mr. Pulliam turned to slide 4 titled "Capital Credit
Equivalent Value at Specified Production Allowance." He
relayed that the per barrel analysis could also be looked
at on a capital credit equivalent. The slide showed the $5,
$10, and $15 dollar per barrel allowances to indicate how
they would translate into a capital credit. The slide
indicated that at a $10 cost in capital a $5 allowance was
equal to a 50 percent capital credit; a $10 per barrel
allowance at a $10 cost in capital would equal a 100
percent capital credit. As capital spending increased the
fixed per barrel percentage declined. The allowance was
mechanically different than a capital credit, but it
accomplished some of the same things. He pointed to a key
difference of the capital credit under ACES where a 20
percent credit was paid upfront; whereas, the allowance
would only be earned as oil was produced. He elaborated
that the items had a different net present value (NPV)
effect, but they worked towards the same goal.
1:43:06 PM
Mr. Pulliam moved to slide 5 titled "Annual State Revenues
and Producer Cash Flows at $100 West Coast ANS ($2012)
Lower Cost Oil Alaska Development New Participant in
Alaska" illustrated the cash flow differences between ACES
and the CSSB 21(RES). He directed attention to the lower
graph showing state revenues; the blue bars represented the
state's cash flows under ACES. The negative cash flow as
development on the field got underway corresponded with the
state's purchase of credits and net operating losses from
the new participant; the combination of the two equaled
approximately 45 percent of the development costs in the
early years. As production began later in the fourth year
and into the fifth year, positive revenues began to be
collected under ACES. The green bars represented CSSB
21(RES); there were no outflows from the state given that
it was not purchasing credits. The net operating losses
were carried forward and recovered later against the tax
obligation. The tax rate was lower under the CS; therefore,
the green bars shown were lower. He pointed out that the
timing of the different mechanisms under ACES and the CS
was different; ACES provided the credits upfront; whereas,
under the CS the credits and allowances were given as oil
was produced.
Mr. Pulliam moved to slide 6 titled "Annual State Revenues
and Producer Cash Flows at $100 West Coast ANS ($2012)
Lower Cost Oil Alaska Development Incumbent Participant in
Alaska." The lower graph related to state revenues showed a
loss under ACES for the first years of development due to
the purchase of credits and a loss in tax revenue. He
relayed that the net difference to the state for an
incumbent was larger in the early years than it was for a
new participant. He explained that an incumbent investing
in a new field would have the ability to deduct expenses
against their tax obligation. He detailed that the
incumbent would not be able to buy down the rate, but
expenses would be deducted at the 35 percent. There was a
different effect on the incumbent than on a new producer.
1:47:12 PM
Mr. Pulliam continued on slide 9 titled "Producer and State
Economics under Alternative Systems New Participant
Investment in 50 MMBO Field $20/Bbl Development Capex,
16.67% Royalty Rate." The slide showed how the different
allowances and their duration would affect the producer and
the state in a hypothetical development of a 50 million
barrel field in and around the legacy fields. The first
column showed the present value to the producer on a per
barrel basis under the CS at the 35 percent base rate
combined with the $5 per barrel allowance; at $100 per
barrel West Coast ANS price the development would have a
NPV of $3.60. Columns 2 and 3 showed the effect of the 30
percent GRE; the NPV increased to $4.59 shown in column 2,
which represented a 10-year period. Column 3 showed the
impact of providing the 30 percent GRE for the life of
production; the NPV increased to $4.86. He detailed that
the change between columns 2 and 3 was not as great as it
was in the first 10 years given that the bulk of a field's
oil was produced in the early years and nearer-term was
more valuable on a NPV basis. He believed the analysis
would help with any discussion on how cutting off the GRE
or some of the allowances would impact various items. The
data showed that the majority of the benefits would be
obtained by allowing the GRE for the first 10 years of a
field's life.
Mr. Pulliam addressed what would happen if an allowance was
used without the GRE (slide 9). Columns 4 and 5 illustrated
an increase in the allowance by $5 per barrel for new
production. The additional $5 allowance would increase the
NPV, although not as significantly as the 30 percent GRE.
Columns 6 and 7 showed how an additional $10 allowance
would increase the NPV. Columns 8 and 9 demonstrated how
using only a capital credit allowance on top of the base
system would impact the NPV. He stated that the capital
credit was consistent with what was provided under ACES;
the credit could be claimed immediately as opposed to being
carried forward.
1:52:32 PM
Mr. Pulliam explained that columns 10 and 11 on slide 9
showed the NPV under ACES and without any production tax
respectively. He detailed that ACES and a no production tax
scenario were both used when evaluating whether the various
mechanisms made sense economically for the state. He
addressed conclusions based on the chart. He shared that
the scenarios providing a GRE or an allowance included in
the CS substantially improved producer economics unless the
price of oil was very low; in the $80 range the CS did not
improve economics relative to ACES. He noted that ACES had
the highest NPV at $1.26 (column 10); however, the state's
NPV was negative and it turned out to be a more favorable
system for producers. He surmised that the scenario was not
positive for the state.
Mr. Pulliam turned to the second section on slide 9, which
showed the impact on government take. For example, a new
producer developing a field with the characteristics on
slide 9 and qualifying for the GRE would fall under column
3; government take would be just below 60 percent in the
$100 to $120 per barrel range. An additional $5 per barrel
allowance would put government take at approximately 62
percent to 63 percent (column 5). The scenario would not be
as generous to the producer, but it would still fall within
a competitive range. He communicated that there were
various ways to benefit producers' economics with the GRE
and per barrel allowance without providing upfront state
funding.
1:56:28 PM
Senator Bishop asked which of the scenarios on slide 9
would provide producers with the best advantage for the
most oil production at $100 per barrel. Mr. Pawlowski asked
for clarification on the question. Senator Bishop explained
his question.
Mr. Pawlowski responded that he would look for any scenario
that provided the highest NPV; column 11) "no production
tax" would provide the highest NPV for a producer. Out of
the proposed options, column 3 (the lifetime 30 percent
GRE) would provide producers with the highest NPV.
Vice-Chair Fairclough remarked that the response was
contrary to testimony from current producers in relation to
legacy fields. She detailed the new explorers were happier
with the Senate Resources Committee CS, but that other
industry testimony had been in support of the capital
credits, despite the higher NPV under the lifetime 30
percent GRE shown in the Econ One presentation.
Mr. Pawlowski clarified that the slide included an analysis
for new participants only. He pointed out that the Alaska
Oil and Gas Association (AOGA) had testified that a system
should avoid the tendency to pick winners and losers. He
stressed that the economics shown on slide 9 completely
changed for a company with an existing tax liability that
could write its expenditures off. The incentives were about
creating a level playing field between new entrants and
existing producers. He believed that the administration had
more work to do with the committee on the topic of what was
fair for legacy production.
1:59:57 PM
Mr. Pulliam turned back in the presentation to slide 7
titled "Producer and State Economics under Alternative
Systems Incumbent Investment in 50 MMBO Field $20/Bbl
Development Capex, 12.5% Royalty Rate." The slide was
structured the same as slide 9; however, incumbent
investment had an existing tax obligation and any
incremental decisions impacted the obligation. He pointed
out that at $100 per barrel the NPV under ACES was $5.98
(shown under column 10); the figure was close to the no
production tax scenario NPV of $6.12. He stated that it was
a pretty good place for producers to be. Column 1
demonstrated that the NPV would be $4.57 without the GRE,
which was not as favorable. He referred to prior testimony
that the GRE did not apply to new oil within legacy fields
compared to columns 2 and 3 where the enhanced economics
were applied and the NPV increased above the ACES number.
He believed the testifier had thought that the bill
represented a tax increase at lower price levels and that
without the GRE they were being treated unfairly relative
to new producers/fields. The chart also included other
credit scenarios.
2:02:44 PM
Mr. Pawlowski clarified that the discussion pertained to an
incremental investment and its economics and not ongoing
production in the legacy fields. The administration had
distinguished its analysis between the two systems and had
looked at what an additional participating area (PA) or the
expansion of a PA would mean within a legacy field under
the CSSB 21(RES). He acknowledged that additional
opportunities existed that did not meet the criteria.
Mr. Pulliam directed attention to slide 8 titled "Producer
and State Economics under Alternative Systems New
Participant Investment in 50 MMBO Field $20/Bbl Development
Capex, 12.5% Royalty Rate." The slide showed information
for a new participant with a 12.5 percent royalty. He noted
that the variance between the 12.5 percent and 16 percent
royalty made a difference to the producer economics. He
detailed that under the 12.5 percent royalty a producer's
NPV was $4.26 under the base scenario in column 1 the $100
per barrel price; the NPV was $3.60 under the 16.67 percent
royalty (slide 9). The higher royalty resulted in higher
take and lower NPV. He elaborated that higher the royalty,
the less of a tax bite a producer would be able to
withstand in order to maintain similar economics. A
producer looking to develop a new field could always look
for royalty relief with DNR if the economics on a 16.67
lease were not working.
2:05:44 PM
Mr. Pawlowski believed it was important to address the
various metrics (e.g. NPV, government take, and other) for
the public's understanding. He added that it was important
to remember that NPV and government take were only two of
the metrics. He encouraged committee members to review
earlier presentations that had included cash margins and
internal rates of return. He referenced testimony that had
pointed out a balance between all of the metrics used by a
company when making investment decisions.
Mr. Pullium continued to address slide 8. The top section
illustrated the producer NPV and the section that followed
showed the government take. The three lower sections of the
slide pertained to the state including the NPV of the state
production tax, the NPV of the total state cash (including
production tax, royalties, income tax, and property taxes),
and the NPV of the total state cash where the state
received 50 percent of the royalties (e.g. the National
Petroleum Reserve - Alaska where 50 percent of the
royalties went to the federal government). He noted that in
the three lower sections the investment did not look any
different from the producer standpoint; however, the
scenarios were different from the state's standpoint. He
explained that ACES and SB 21 were both net tax systems
therefore the royalties were not taxable barrels yet the
cost of production was deductible. The NPV for the state
was lower in the scenarios in which the state only received
50 percent of the royalties.
2:08:32 PM
Mr. Pawlowski pointed out that stress tests against the no
production tax scenario hoped to identify situations where
the state had materially improved through its fiscal
system. The administration saw the scenario as a system
that went too far and could not be justified as a way to
incentivize production. Another concern related to how the
movement of the GRE, credits, and allowances affected the
production tax revenues. The NPV information on slide 8 had
been included to show where the state would win or lose
related to production tax revenues. Depending on the price
some of the scenarios did not produce a desirable outcome
for the state.
2:09:52 PM
Mr. Pulliam looked at slide 10 titled "Impact of "Interest"
on Loss Carry Forward 50 MMBO New Field With 16.67% Royalty
$20/BBL Development Cost, New Participant." The slide broke
out producer and state economics and showed what would
happen if there were different levels of interest; because
it pertained to new development a 30 percent GRE would be
provided to the producer. He pointed to column 4 that
showed the 15 percent carry forward increase under CSSB 21
(RES). At the $80 oil price level the producer economics
remained constant at $0.62 per barrel regardless of
different loss carry forward rates. He explained that the
carry forward provision included a 10-year sunset;
therefore, at very low prices all of the losses may not be
used. He noted that at $80 per barrel the state economics
were $307 million regardless of the loss carry forward rate
because a producer would not be able to use the entirety of
the loss carry forward. He detailed that the scenario would
change at $100 to $120 per barrel and the producer would
use the entire loss carry forward. He pointed out that at
$120 per barrel the producer NPV with no loss carry forward
was $8.25 compared to an $8.71 NPV with a 15 percent loss
carry forward. Column 6 showed a system where losses could
be deducted as expenditures were made. A 35 percent
deduction would be received up front and the NPV would
equal $9.06 at the $120 per barrel price. He compared
columns 4 and 6 and explained that a 15 percent loss carry
forward obtained a similar result as deducting the losses
right away.
2:14:09 PM
Mr. Pulliam turned to slide 11 titled "Average Government
Take ACES v. SB21/HB72 and SRES CS SB21 for All Existing
Producers (FY2015-FY2019) and Other Jurisdictions." The
slide illustrated the difference between the take for
ongoing operations compared to the take for new production.
The graph looked at the government take projected over a 5-
year period (FY 15 to FY 19) from ongoing operations on the
North Slope. He noted that while some new investment would
occur, the investment was dominated by ongoing production
and legacy fields. Under CSSB 21 (RES) the government take
began at low prices in the mid-60 percent range and
approached 65 percent as time went on. He relayed that
government take for new investment was typically lower in
the low-60 percent range, particularly related to the
allowance and GRE. He noted that the last couple of slides
related to development and the GRE; he turned the floor
over to Mr. Pawlowski.
Mr. Pawlowski asked DNR Deputy Commissioner Joe Balash to
discuss PAs, the GRE under the CS and time limitation
concept issues.
2:16:59 PM
JOE BALASH, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, pointed to a slide from a past Pioneer Natural
Resources presentation (slide 13) and asked the committee
to take the information into account if it was considering
the inclusion of a time limitation on the GRE. The slide
showed an image including the original offshore development
(represented in green); Pioneer was evaluating whether or
not to pursue the Nuna development (represented in purple
as a separate pool). The department was currently
considering whether to grant the company with a PA for the
development. He elaborated that original production had
begun in 2008 or 2009. He explained that any time limit
imposed would shorten the time under which the PA would
qualify for a GRE or additional dollar per barrel allowance
associated with the new areas. He urged the committee to
consider linking any time limitation to a PA to ensure that
the beginning of the limit was tied to the time production
began.
2:19:44 PM
Senator Bishop asked Mr. Balash to reiterate his testimony.
Mr. Balash communicated that production at Oooguruk began
in 2008/2009. He explained that if a 7-year clock had been
started at the time of the first production, it would run
out in 2015. He expounded that any additional production
within a unit would be bound by the clock if a GRE
limitation were placed at the unit level. He asked the
committee to consider placing any time limitation at the PA
level. He referenced the Pioneer slide and noted that a 7-
year clock would have run out by the time the Nuna Project
came into production.
Senator Bishop surmised that the light blue portion of the
image should not have a time limit. Mr. Balash replied in
the affirmative; that the clock would start over at each
PA.
Vice-Chair Fairclough pointed to the Pioneer slide (slide
13, but labeled slide 6) and noted that it could be argued
that the Nuna development would not qualify for a new PA if
it were 50 percent new. She asked how DNR would ensure that
a company could not create a new PA within an existing
field. She wondered about criteria the department would use
to keep subjectivity low for PA approval.
Mr. Balash replied that the slide showed a two dimensional
representation of the leases contributing to a unit;
however, the formations represented on the slide occurred
at depth as well. He elaborated that the green portion
showed the original sets of sands that were developed,
which represented a portion of the PA at Oooguruk. The Nuna
formation was in a different location and occurred at a
different depth; therefore, DNR was able to measure the
land by depth, longitude, and latitude. He believed the
department used section lines for the track numbers. He
detailed that it was relatively easy for the department to
keep two distinct PAs separate. The slide showed that
production from Nuna would come onshore at a different
location than the original offshore island Oooguruk had
produced from. He explained that metering would be straight
forward and barrels could be accounted for easily.
Mr. Balash discussed that it was more challenging when
original PAs were expanded in the legacy fields. He
explained that under CSSB 21 (RES) the burden would be on
the lessees to demonstrate that a new part of the reservoir
would contribute to production; a portion that had not
contributed previously because it had been inaccessible due
to old drilling technology or other. The producer would be
required to prove the area was new through seismic
information (4-D seismic) or through reservoir engineering
practices looking at fluid dynamics and pressures. Approval
to expand the PA would be provided if the producer could
prove the area was new. The second step would be for the
producer to prove to DOR that it was producing from the new
area and that it could account for the barrels produced
separately from the original production; if the producer
could not demonstrate these items, the area would not
qualify for the GRE.
2:26:10 PM
Senator Bishop surmised that there was a clear distinction
between the original Oooguruk field and the Nuna project.
Mr. Balash replied in the affirmative. He elaborated that
the areas were in different formations and locations and
likely had differing geochemistries.
Mr. Pawlowski addressed the Nuna example on slide 13. He
relayed that there were three criteria related to the GRE
under the CS (Sections 28 through 30). He read that "the
oil or gas is produced from a lease or property that does
not contain a lease that was within a unit on January 1,
2003" or oil and gas that was produced from a PA that was
within a unit formed before January 1, 2003 (Section 28,
page 26). Under the CS any new unit would receive a
permanent GRE; within units formed prior to January 1, 2003
the criteria were either a new PA or an expansion of the
PA. He relayed that modifications needed to be made in
Section 28 to the bill language if a time limit were placed
on the GRE in order to allow for distinguishment in the
future. The current CS language did not contemplate a
future situation where a unit would clock out on the GRE
and where a new PA would not be subject to the GRE.
Vice-Chair Fairclough asked for clarification on the bill
section. Mr. Pawlowski pointed to page 26, line 26 through
page 27, line 11 (Section 28). The particular language of
concern appeared on page 26, lines 29 through 31.
2:29:12 PM
Mr. Pawlowski turned to a Pioneer Natural Resources graph
on slide 14 [last slide in the presentation, labeled slide
11]. The slide showed a production profile for a new
development; the administration believed the slide helped
explain the clock related to drilling (i.e. how many years
it took to drill). He detailed that a 7-year time limit
would only allow for 1 to 2 years of GRE benefits given
that production would not actually begin until
approximately year 3. Consideration should be given to the
time it took to drill out a development and the potential
within the units to have multiple PAs located on top of
each other.
Mr. Pawlowski directed attention to a supplemental slide
titled "Production Tax Revenue Impacts of Various Base Tax
Rates FY 14 - FY 19" dated March 6, 2013 (copy on file). He
relayed that Senator Dunleavy had asked the administration
to provide a sheet showing the fiscal impacts of various
base rates across the projected production and price
forecasts in the fall 2012 Revenue Sources Book. The top of
the slide showed the estimated production tax revenue under
ACES for FY 14 through FY 19. He noted that the figures
included the credits paid out and all other mechanisms
existing under current law. The only piece not included was
the refunded credits (credits paid through the operating
budget to companies with tax credit certificates), which
was ultimately an expenditure and liability to the state as
opposed to a revenue impact.
Mr. Pawlowski pointed out the various base tax rates
ranging from 25 percent to 35 percent and projected
revenues based on the tax rate for FY 14 through FY 19. For
example, with a 27 percent tax rate the revenue for FY 15
would be $2.875 billion. He noted that the figures did not
include any additional credits or incentives that may be
offered in a bill. He relayed that the slide was intended
to give committee members a starting place to evaluate what
a base rate would generate and what incentives offered
against the rate. The lower portion of the table
illustrated the delta from the forecast revenues under
ACES. For example, with a 27 percent base rate the revenue
would be $532 million less than the ACES forecast. He
reiterated that the figures did not include any additional
credits.
2:33:41 PM
Vice-Chair Fairclough asked for verification that the slide
answered Senator Dunleavy's question. Senator Dunleavy
replied in the affirmative.
Vice-Chair Fairclough communicated that public testimony on
the bill would begin at 3:00 p.m.
2:34:34 PM
AT EASE
2:35:52 PM
RECONVENED
Vice-Chair Fairclough noted that the documents and past
presentations for SB 21 were available on BASIS.
SB 21 was HEARD and HELD in committee for further
consideration.
ADJOURNMENT
2:36:31 PM
The meeting was adjourned at 2:37 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 21 Econ One Presentation 3_6_13.pdf |
SFIN 3/6/2013 1:30:00 PM |
SB 21 |
| SB 21 Repsol Testimony for Senate Finance - CS SB 21Res -6 Mar 13.pdf |
SFIN 3/6/2013 1:30:00 PM |
SB 21 |
| SB 21 FW Constituent TestimonySB 21.msg |
SFIN 3/6/2013 1:30:00 PM |
SB 21 |