[PPT] - Fiscal Solutions for a Sustainable Future Ken Alper, Tax Division PowerPoint Presentation

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Update from the Department of Revenue: Fiscal Solutions for a Sustainable Future

Ken Alper, Tax Division Director Presentation to the 12th Annual Alaska Oil and Gas Congress

September 20, 2016

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Director of the Tax Division, Department of Revenue

Supervises staff of about 100 in Juneau and Anchorage

responsible for collecting and administering 24 different taxes impacting many sectors of Alaska’s economy

Part of the Walker Administration’s fiscal team planning

for the transition to a sustainable revenue structure with a balanced budget

Carried HB247, the Oil and Gas Tax Credit reform bill,

through the 2016 Legislature

Legislative Staff for 10 years

Specialist in Oil and Gas Tax and Gasline issues,

mostly working for the House Minority

Small Business Owner in Juneau Originally from New Jersey

About me

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Update on Alaska’s oil and gas tax credits
What we’ve gained
Why the need for reform
Credits outstanding; impact of funding vetoes
Changes made via HB247 and HB100
Work that still needs to be done
Fitting this into the Overall Fiscal Plan
Balancing the budget
Using our savings
Reducing state’s reliance on one industry

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What I’m talking about today

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History of Oil and Gas Production Tax Credits

FY 2007 thru 2016, $8.0 Billion in Credits North Slope

$4.4 billion credits against tax liability
Major producers; mostly 20% capital credit in ACES

and per-taxable-barrel credit in SB21

$2.3 billion refunded credits
New producers and explorers developing new fields

Non-North Slope (Cook Inlet & Middle Earth)

$0.1 billion credits against tax liability
Another $500 to $800 million Cook Inlet tax reductions

(through 2013) due to the tax cap still tied to ELF

$1.2 billion refunded credits (most since 2013)

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Of the nearly $3.5 billion in state-refunded credits through the end of FY16:

$1.5 billion went to eight North Slope projects

that now have production

$0.8 billion went to 11 North Slope projects that

do not have any production. Some of these are abandoned, and some are in process

$0.9 million went to eight non-North Slope

projects that have production

$0.3 million went to eight non-North Slope

projects that do not have any production

History of Oil and Gas Production Tax Credits

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North Slope Refundable Credits

Previously said between FY07-FY16 spent

$1.5 billion supporting seven producing projects

Total production from these producers through

end of 2015 is 63 million barrels

Total credits = $24 / barrel
This number will decrease over time due to additional

production from these fields

Lease expenditures for these projects, through

FY15, were $6.0 billion

Credit support was 25% of lease expenditures

Credit Cost in Perspective

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Cook Inlet Refundable Credits

Previously said between FY07-FY16 spent $900

million supporting eight producing projects

Total production through end of FY15 is

73 million BOE (much of this was gas)

Total credits = $13 / BOE or about $2.10 / mcf
This number will decrease over time due to additional

production from these fields

Lease expenditures for these projects, through

FY15, were $2.3 billion

Credit support was 40% of lease expenditures

Credit Cost in Perspective

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Why the Need for Reform?

(because we just can’t afford it)

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Why the Need for Reform?

(because we just can’t afford it)

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Cash flow with credits for a 120,000 bbl /day field at $80 oil

Life Cycle Totals $Millions Production Tax Credits Cashed 2,797 Production Tax Paid 5,972 Net Production Tax 3,176 Production Tax NPV 6.15%

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Total Annual State Losses 2,520 Total Annual State Gains 13,868 Net State Gain (Loss) 11,348 State NPV 6.15% 2,660 Total Producer Cash Out 5,258 Total Producer Cash In 19,772 Net Producer Cash Flow 14,514 Producer Cash NPV 6.15% 2,803

$1,000
$800
$600
$400
$200

$0 $200 $400 $600

$ Millions Graph assumes: Capex = $13/bbl, Opex = $12/bbl, no small producer credit

Production Tax Credits Cashed / Production Tax Payments, 20% GVR, at $80 ANS Price

Project Years 1 - 40

$1,000
$500

$0 $500 $1,000 $1,500

$ Millions Graph assumes: Capex = $13/bbl, Opex = $12/bbl, no small producer credit

Annual State Net Gains and Losses, 20% GVR, at $80 ANS Price Royalty Property Tax Production Tax State Corp Income Tax

Project Years 1 - 40

$2,500
$2,000
$1,500
$1,000
$500

$0 $500 $1,000 $1,500 $2,000 $2,500

$ Millions Project Years 1 - 40

Total Producer Cash Flows, 20% GVR, at $80 ANS Price Red bars represent cash outflows by Producer; green bars represent cash inflows for Producer

Why the Need for Reform?

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Credits Outstanding and Impact of Vetoes

FY16 Appropriation Capped at $500 million
$498 million paid out by end of June
About $211 million North Slope, $287 million non-NS
$3 million left in fund with $4 million in-process claims
FY17 Legislature appropriated $460 million towards

expected demand of $775 million

Governor vetoed all but $30 million
Nearly entire $30 million paid out to “first tranche” of

issued credits: early 2015 quarterly QCE and WLE claims from outside the North Slope

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$505 million in certificates have been issued in FY17

Of these, about $70 million have either been:

Paid (from the roughly $30 million available funds);
Transferred (to be used against another company's

tax liability); or

Are ineligible for repurchase
Total remaining awaiting repurchase $435 million
Applications in-hand about $250 million
$85 million “023” credits
$165 million “025” credits
So total known demand is roughly $685 million
Additional $445 million forecasted for FY18

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Credits Outstanding and Impact of Vetoes

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Options for companies holding credit certificates

1. Wait for production (use against own taxes)
2. Wait for additional funding
3. Sell to a company with a tax liability
Limited demand with low oil prices- the major

producers are forecasted to have relatively low liability

.023 credits can only offset 20% of a company’s taxes
No restriction on use of .025 credits to offset taxes.

The bulk of large .025 credits will be issued next spring

4. Sell rights to credit cash, as suggested by former

AG Richards to the Permanent Fund Board

Possible statutory change to allow direct transfer of

credit certificates to 3rd parties

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Credits Outstanding and Impact of Vetoes

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Cook Inlet

Complete phase-out of NOL, QCE, and WLE by 2018
Extends “tax caps” on gas indefinitely, adds $1 / bbl oil tax
Municipal utility pro-ration of costs

Middle Earth

Reduces the NOL, QCE, and WLE credit rates
Extends “Frontier Basin” exploration credit to July 2017

North Slope

GVR “Graduation” provision after three to seven years
GVR can’t be used to increase the amount of an NOL

Statewide

$70 million per company per year cap ($61 with discount)
Interest rates increased for 3 years, then drops to zero
Transparency, local hire, state obligation offsets, surety bond

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HB247: Major Provisions & Regional Impacts

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Revenue

$0 to $25 million increase through FY21 due to loss of

Cook Inlet credits used against tax liability, plus new $1 / bbl oil tax

$40 to $115 million tax cut beginning FY22 due to above

plus $20 million from sunset of GVR tax break, but

ffset by extension of Cook Inlet gas tax caps

Spending

Full impact of credit cuts won’t be seen until FY19
Annual savings $65 to $115 million. Largest portion is

Cook Inlet cuts, less from the per-company cap and the fix to the GVR / NOL interaction issue

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Fiscal Impact of HB247

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Draft regs to be published this week Some issues that need to be clarified:

GVR Sunset Timing
Prioritization of Funds / Resident Hire
Per-Company Cap and “Haircut” Mechanism
Interest Rate Calculations
New $1 Cook Inlet Oil Tax
Publication of Credit data
Municipal Producer-Utility Gas Sales
Offset for Obligations to the State

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Regulations Implementing HB247

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HB100: New “Agrium” Tax Credit

Bill by Speaker Chenault, signed by Governor on

September 12

Credit against corporate income tax targeted at

reopening of Kenai fertilizer plant

Model for a smaller, results-oriented program
To earn value, Agrium must:
Invest roughly $250 million to renovate plant
Purchase large amounts of gas from state Cook Inlet

leases- estimated at 80 mmcf / day

Gas production will pay additional royalties and tax.

Income tax credit can’t be greater than the revenue from the purchased gas

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From July, 2016 Special Session

HB/SB 5005 was a smaller, more targeted credit reform and minimum tax package than HB247

Mainly: addresses “North Slope NOL” issue
Re-introduces several smaller parts of HB247 that

did not pass

Increases the minimum tax at certain prices
Technical fixes to HB247 sections that may have

implementation issues Administration may introduce a similar bill in the 2017 session

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Work Still Needed to Rebalance System

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1. North Slope Operating Loss (NOL) credit

phased out: 35% today to 15% in 2017 and zero in 2018

Impacts major producers by preventing credits from

carrying forward to be used in in future years, indirectly “hardening” the minimum tax floor

Impacts independents by eliminating credits earned

during the development stage prior to a company’s profitability

Effectively sets a tax rate that can’t go below zero for

non-profitable companies

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Major Features of HB/SB 5005

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Why we believe it is appropriate to eliminate Net Operating Loss credits

Production Tax is only part of the total fiscal system.

Both the state and federal corporate income taxes allow full carry-forward of losses

Production Tax is a hybrid system
Above about $80 / bbl it’s a true “net profits” tax
Between about $45 and $80 it’s a “gross” tax
Below $45 it reverts to a profits tax by giving full value
f losses at the 35% tax rate

Our plan is, instead, to make it a “zero” tax if the producer is not profitable

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Net Operating Loss Reform

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At the minimum (passed in the House version of HB247), the North Slope NOL should be reduced to 25%

The NOL lets explorer / developers get a comparable

benefit to producers who deduct lease expenditures

But nobody actually pays a 35% effective tax, because
f the per-barrel credit
The NOL in SB21, as originally introduced by Gov.

Parnell, was 25% with a flat 25% tax rate

To make the production tax slightly progressive, the

35% tax / $5 credit structure was added in committee

At expected prices (then about $100 / bbl), going from

25% / $0 to 35% / $5 was revenue neutral

Yet the NOL rate was also increased to 35%.

This, we believe, was unnecessary and distorting

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Net Operating Loss Reform

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Potential NOL Carry-Forward Liability

Oil and Gas Tax Credit Fund: Budgeted vs. Actual vs. Statutory Tax Credit Fund Transfer Cap

(Beginning with the first budget cycle after the passage of ACES in November 2007)

Credit Claims and Carried-Forward Lability for FY17 and Beyond Include Program Changes Made in HB247

Fiscal Year Original Appropriation ($million) Actual Claimed Credits ($million) Actual Production Tax ($million) Plus Credits Against Liab ($million) AS 43.55.011 Revenue ($million) Oil Price Per Spring 16 Forecast Credit Cap per AS 43.55.028(c) End Year Fund Balance Non- Cashable Carried- Forward Liability Total Credit Oblig Actual FY09 not to exceed $175 $193 $3,101 $334 $3,435 $85.73 $343 $150 $0.0 n/a FY10 unspec ** $250 $2,861 $412 $3,273 $65.70 $327 $228 $0.0 n/a FY11

est. $180

$450 $4,543 $361 $4,904 $73.32 $490 $268 $0.0 n/a FY12

est. $400

$353 $6,137 $363 $6,500 $94.70 $650 $565 $0.0 n/a FY13

est. $400

$369 $4,043 $550 $4,593 $110.44 $459 $655 $0.0 n/a FY14

est. $400

$593 $2,589 $919 $3,508 $109.61 $351 $413 $0.0 n/a FY15

est. $450

$628 $363 $664 $1,027 $95.24 $103 ($112) $0.0 ($112) FY16

est. $700

$500 $144 $70 $214 $39.99 $32 ($580) ($357) ($937) Forecasted FY16

est. $700

$500 $144 $70 $214 $39.99 $500 $0 ($357) ($357) FY17 $460 $760 $59 $135 $194 $38.89 $30 ($730) ($605) ($1,335) FY18 n/a $445 $16 $205 $221 $43.79 $33 ($1,142) ($715) ($1,857) FY19 n/a $285 $11 $250 $261 $48.89 $39 ($1,388) ($690) ($2,078) FY20 n/a $190 $13 $305 $318 $54.48 $48 ($1,530) ($515) ($2,045) FY21 n/a $150 $33 $325 $358 $60.29 $36 ($1,644) ($245) ($1,889) FY22 n/a $150 $110 $275 $385 $61.64 $39 ($1,756) ($130) ($1,886) FY23 n/a $150 $217 $205 $422 $63.05 $42 ($1,864) ($50) ($1,914) FY24 n/a $150 $212 $170 $382 $64.45 $38 ($1,975) $0 ($1,975) FY25 n/a $150 $275 $95 $370 $65.90 $37 ($2,088) $0 ($2,088)

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2. Minimum tax increased to 5% when the price of oil

is greater than $55 / bbl

3. “Migrating Credits” fix preventing per-barrel credits

from being used in a different month than when they were earned (volatility protection)

4. Gross Value at the Points of Production can’t go

below zero for a lease or property

5. Interest Rate on delinquent taxes- clean up zero

rate after three years, and apply to all taxes

6. Release seismic / geophysical data in less than

10 years if the lease for which the data was acquired is terminated

Other Features of HB/SB 5005

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Governor’s Fiscal Plan

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Governor’s Fiscal Plan

The governor’s 2016 Fiscal Plan proposal was based on a four-pronged approach

1. Continued budget cuts and government

efficiencies

2. Use of our savings in a structured, sustainable

manner

3. Balanced set of taxes that would impact

individuals and industry equitably

4. Reform of oil and gas taxes and tax credits

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General Fund Budget over Time

Adjusted for inflation and population, the current budget is lower than most years during the post-pipeline boom

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$0 $200 $400 $600 $800 $1,000 $1,200 $1,400

General Fund Operating Budget Detail (FY16)

$0 $200 $400 $600 $800 $1,000 $1,200 $1,400

Education & Early Development Payments & Obligations Health and Social Services

Top Three Unrestricted General Funds Spending Categories Total $3.4 billion

($ Millions)

K-12 Formula Oil Tax Credits Retirement Debt Medicaid and Formula

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Governor’s Fiscal Plan for 2017

The 2017 Fiscal Plan is likely to be similar, however:

1. Approaching place of diminishing returns with

many agencies; capital budget

2. One year delay impacts some of the calculation

in how we’d use Permanent Fund earnings

3. Burden on Revenue and other departments

trying to move a dozen different bills

4. Much of the tax credit reform was

accomplished last session

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Governor’s Fiscal Plan for 2017

Much more pressure to get it done this year:

1. Recognition that we’re less likely to see a rapid

return to high oil prices

2. Even with tax credit veto, it would take $102 oil

to balance the budget this year

3. At current rate of draw, CBR will run out of

funds at the end of FY2018

4. If that happens, we have to actually balance the

budget with revenues and the Permanent Fund. That could mean much higher taxes than we’re currently proposing, plus loss of the dividend.

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30 $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000

$3.4 Billion Annual Deficit Permanent Fund at Risk Short-Term Savings Gone by 2021 Existing Revenue Dividends End by 2020

Governor’s Fiscal Plan for 2017

“Status Quo” presented at beginning of 2016 session

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Governor’s Fiscal Plan for 2017

So how does this work in practice?

FY17 Deficit is $3.2 billion based on $40 oil
Assume moderate continuing cuts, but more

spending to draw down the tax credit obligation. So a FY18 starting point deficit is still about $3.2 billion based on $43 oil

Pass the fiscal plan:
Permanent Fund Protection Act would produce a

stable $1,000 dividend indefinitely and provide $1.8 to $2.0 billion to the general fund (more in later years)

Moderate suite of revenue measures, similar to last

year’s proposals, could raise $600-$800 million

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Governor’s Fiscal Plan for 2017

So how does this work in practice? (cont’d)

So that reduces the deficit to $400-$800 million
What it really does is moves the break even

point down. So the budget now balances at $55-$65 oil

(Among other things, this takes pressure off the
il industry to cover everything)
And let’s accept that we’re not going to be able

to balance the budget at $40 oil without unacceptable levels of service cuts and extremely high taxes

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Comparable Tax Burden

Black bar is $700 million in new and increased taxes (we’d still be 2nd lowest in the country) Source: Gunnar Knapp, ISER

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Comparable Tax Burden

41 states with a true income tax

2016 proposal

was $200 million

Lowest (Arizona)

would equal about $350 million for Alaska

Highest (New

York) would equal $1.8 billion

Source: Tax Foundation

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Governor’s Fiscal Plan for 2017

Balancing the budget for $60 oil requires retaining adequate savings for $40 oil

This means leaving +/- $2 billion in the CBR to

cover the difference in low price years

And that means fixing the problem before the

end of FY2018

Otherwise all bets are off and the revenue “ask”

would have to move up a whole other level

Also, inevitably that would mean a more

aggressive look at resource taxation

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Thank You!

Contact Information

Ken Alper Director, Tax Division Department of Revenue Ken.Alper@Alaska.gov (907) 465-8221