Legislature(2019 - 2020)ADAMS ROOM 519
02/27/2019 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| Presentation: Fall 2018 Production Forecast | |
| Presentation: Permitting Issues, & Status of Development on North Slope | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
HOUSE FINANCE COMMITTEE
February 27, 2019
1:34 p.m.
1:34:39 PM
CALL TO ORDER
Co-Chair Foster called the House Finance Committee meeting
to order at 1:34 p.m.
MEMBERS PRESENT
Representative Neal Foster, Co-Chair
Representative Tammie Wilson, Co-Chair
Representative Jennifer Johnston, Vice-Chair
Representative Dan Ortiz, Vice-Chair
Representative Ben Carpenter
Representative Andy Josephson
Representative Gary Knopp
Representative Bart LeBon
Representative Kelly Merrick
Representative Colleen Sullivan-Leonard
Representative Cathy Tilton
MEMBERS ABSENT
None
ALSO PRESENT
Maduabuchi Pascal Umekwe, Ph.D. and Commercial Analyst,
Division of Oil and Gas, Department of Natural Resources;
Sara Longan, Deputy Commissioner, Department of Natural
Resources.
SUMMARY
PRESENTATION: FALL 2018 PRODUCTION FORECAST
PRESENTATION: PERMITTING ISSUES, & STATUS OF DEVELOPMENT ON
NORTH SLOPE
Co-Chair Foster reviewed the meeting agenda.
^PRESENTATION: FALL 2018 PRODUCTION FORECAST
1:35:48 PM
MADUABUCHI PASCAL UMEKWE, PH.D. AND COMMERCIAL ANALYST,
DIVISION OF OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES
(DNR), introduced himself. He shared that he was trained as
a petroleum engineer and economist. He intended to talk
about the fall 2018 production forecast. He provided a
PowerPoint presentation titled "Fall 2018 Production
Forecast" dated February 27, 2019 (copy on file). He
relayed that the Division of Oil and Gas had been
conducting a production forecast for the state since the
fall of 2016. The primary objective was to support the
revenue projection work done by the Department of Revenue
(DOR). He noted that the information in the presentation
was a result of work done by a team of engineers with
support from the commissioner.
1:37:29 PM
Mr. Umekwe turned to slide 2 and addressed a presentation
outline. The first part of the presentation included a high
level overview touching on North Slope projects that had
impacted production in the past several fiscal years. The
section showed a comparison between actual production and
the division's forecast for the fall of 2018. He noted it
was a long-term 20-year outlook for production in Alaska.
The second part of the presentation addressed the approach
the division had taken to generate the forecast, including
some of the efforts taken to improve the near-term and
long-term results included in the presentation.
Mr. Umekwe moved to slide 3 and addressed a comparison
between actual production the fall 2018 production
forecast. Actual production was represented by the blue bar
and the forecast was represented by the red bar. He pointed
out that the information was from the month of July through
November. He noted that data outside those months would be
a slightly different comparison. He highlighted that the
forecast and actual numbers for the period shown were very
close. He highlighted that the period shown included summer
months that typically had lower production because the
operators did a lot of work in the summer and there were
inefficiencies in gas compression capabilities in the
different fields. The variance between the forecast versus
actual was about 15,000 barrels.
1:39:38 PM
Mr. Umekwe advanced to slide 4 and discussed the overall
perspective for the North Slope including some of the
projects that had impacted production in the past four
fiscal years. He pointed to a graph on the top right
showing that production had been flat for the past four
fiscal years. He pointed to a more detailed view showing
change across some fields during the past four years. In FY
15 through FY 17 there were two years of production growth,
primarily intensive work carried out by operators on the
different fields. Prudhoe Bay was the largest and had
numerous efficiency gains during the period. Additionally,
operators had conducted rig work and other work to keep
production healthy in the Prudhoe Bay field.
Mr. Umekwe highlighted the Kuparuk unit and detailed that
ConocoPhillips' work on the Sharks Tooth development and
1H-NEWS development was instrumental in maintaining steady
production growth. He reported that the CD5 development had
been beneficial for the Colville River and ConocoPhillips
was looking into doing a second expansion of the
development. He moved west to the Greater Mooses Tooth unit
(GMT1) and detailed that much work had gone into the
development that had its first production in the fall of
2018.
Mr. Umekwe discussed future projects (at the bottom of
slide 4) including the CD5 expansion, GMT2, and Hilcorp's
Milne Point Moose Pad. Farther out in the future, projects
that would impact the state's overall production would be
exciting discoveries like Pikka and Willow. He highlighted
that old discoveries like Liberty were now moving forward.
1:42:02 PM
Mr. Umekwe addressed the 20-year production outlook on
slide 5. The blue section of the graph represented legacy
production from Prudhoe Bay, Kuparuk, and some of the other
fields currently producing; the red portion represented
production expected to be online within FY 19; and the
brown portion showed production expected to be online after
FY 19. The chart showed that legacy production continued to
be the backbone of overall state production, especially in
the near-term. He noted that five to six years in the
future, projects expected to come online beyond FY 19 would
play an increasingly important role (e.g. Pikka, Willow,
and GMT2).
Vice-Chair Ortiz looked at slide 5 and surmised that even
with the future projects, the long-term future for
production was a gradual decline. He asked if all of the
potentially feasible future projects were reflected in the
tan area of the graph.
Mr. Umekwe replied that all of the projects that DNR
considered as discoveries where companies were moving
forward were included in the tan area of the graph. He
noted that the tan area represented the mean case and not
the best case scenario. There were outcomes where
production could be higher. He pointed out that subsequent
slides showed a range around the number. He confirmed that
the potentially feasible future projects were reflected in
the tan area of the graph. He explained that legacy fields
were still very important and as those naturally continued
to decline, the new production would be added on top. He
detailed that if production from legacy fields was 300,000
barrels, the new production would bring total production to
about 500,000 barrels (as shown on the graph).
1:45:37 PM
Vice-Chair Ortiz referenced Mr. Umekwe's earlier statement
that production was typically less in the summer months. He
noted that it was not possible to use ice roads as much
along with other factors. He wondered whether climate
change would mean there would be less and less productive
time periods for Prudhoe Bay due to the gradual increase in
temperature.
Mr. Umekwe answered that the reason production declined in
the summer was for two key reasons. First, at the time it
was most convenient and safest to work. He detailed that if
work that may have been done in the winter was scheduled
for the summer to increase safety, production took a hit.
For some of the wells that were aging and needed artificial
methods to continue production - one of the main methods
used on the North Slope was gas lift. He elaborated that
the ability to compress gas to move gas to the fields
declined in the summer period. As a result, the production
from the wells was reduced.
1:48:00 PM
Mr. Umekwe advanced to slide 7 and spoke to fall 2018
forecast objectives. The primary objective for every
forecast was to support the work DOR did to generate state
revenue projections. The goal was to improve the long-term
accuracy of the forecast. For every field, the division
aimed to ensure its assumptions were tuned based on the
best available information it could get from the operators.
Also, the division was working to improve its forecast for
the near-term to ensure the state was working off of the
best possible information.
Co-Chair Wilson asked about the distinction between near-
term and long-term.
Mr. Umekwe answered that the near-term represented the
current fiscal year (FY 19). Key drivers for variation
within that period would be changes in the way the
operators worked with or handled a field and the schedule
and work a company intended within that fiscal year. The
division tried to ensure it captured the production impacts
that some of the activities would have.
Mr. Umekwe moved to slide 8 and highlighted the three
production categories that enabled the division to handle
the timing aspect and risks involved in projects. The first
category was currently producing/legacy fields. The second
category was fields expected to yield production within the
current fiscal year. The third category was fields expected
to generate production beyond the current fiscal year.
1:51:00 PM
Mr. Umekwe advanced to slide 9 titled "Production
Categories: Addressing Uncertainty." He discussed that most
legacy fields had long production histories (some had been
producing for decades); therefore, engineers within the
Division of Oil and Gas had a good understanding of how the
fields had behaved in the past. The division stayed abreast
on whatever was happening in a field as part of its day-to-
day work managing production from the fields. The knowledge
was used to generate forecasts for the fields. He reported
that what the legacy fields would generate in the future
was still slightly uncertain; the division tried to hone
its certainty in generating the outlook for a field like
Prudhoe or Kuparuk.
Mr. Umekwe addressed the projects under development
category, which included projects that were expected to be
done within the current fiscal year (FY 19). There was more
uncertainty with the category because it pertained to wells
that had not yet been drilled; there were times the wells
underperformed or overperformed operators' expectations.
The third production category included projects expected to
yield production beyond the current fiscal year (e.g.
Pikka, Willow, GMT2). There was much more uncertainty when
generating a forecast for projects under evaluation.
Mr. Umekwe highlighted the financial risk and economic
thresholds the projects would have to meet in order to be
sanctioned. Other uncertainties included the chance of the
project occurring in the 10-year forecast window. For
example, the Liberty project had been known about for the
past decade or so, but for one reason or another the
project had not been moved forward in the past. He
explained that those were the kinds of things the division
considered when looking at any new project discovered
throughout the state. Additionally, there was uncertainty
around timing - the start of sustained production. He noted
that producers often moved the start date for a project
based on logistical, seasonal, or other reasons. He added
that there were times where projects had come online sooner
than anticipated. There was also uncertainty around project
performance - a well could overperform or underperform
expectations. The division considered the three areas of
risk for a project.
Mr. Umekwe explained that in most cases the division
discounted the peak rates provided by operators because it
was trying to ensure that the state planned its short and
long-term future based on the best information available.
1:55:05 PM
Mr. Umekwe turned to slide 10 and discussed continued focus
on both sort-term and long-term forecast accuracy. He
stated that a secondary goal the division aimed to achieve
with the forecast was to give the state the clearest near-
term and long-term production outlook. The idea was to
ensure the forecast continued to serve multiple purposes
including state budgeting and revenue projections.
Mr. Umekwe discussed near-term focus on slide 11. The
division tried to be mindful of the schedule of work the
operators had planned for the near-term. For example,
perhaps the operators were planning work in the summer that
would have a major impact on production.
Mr. Umekwe moved to a chart titled "Near-Term Focus: North
Slope" on slide 12. The dots on the chart represented
actual production and the dashed lines represented the high
and low side of future production outcomes. The black line
represented the mean case. He detailed that based on the
division's work in the spring of 2018, its forecast aligned
well with actual production. He pointed out that the black
line and two broken lines represented the division's
forecast for the fall of 2018; some of the points were
right on target and in some cases actual production came in
a bit higher or lower than the projection.
Co-Chair Wilson referenced Mr. Umekwe's earlier example
about summer maintenance impacting production. She asked if
more shutdowns for maintenance were anticipated in the
coming year.
Mr. Umekwe replied that the data the division had received
from operators did not show a significantly different scale
of maintenance or shutdowns in the coming season than had
occurred in the past. He highlighted that the preceding
year the Colville River unit had major maintenance that
happened every five years; the unit was expected to run at
full capacity for the coming year.
1:58:43 PM
Mr. Umekwe moved to slide 13 and spoke about a realistic
long-term projection. He explained that instead of taking a
blanket assumption on every field, the division got the
best idea of what operators expected for production for the
different fields. The division applied industry techniques
including the decline curve analysis to project production
for the various fields. Instead of generating one
production outcome for a given field, the division tried to
acknowledge the production uncertainties that could impact
even legacy fields. The technique was applied to generate
several possible outcomes for every field; the outcomes
were combined to come up with the best estimate for a
field. The purpose of the method was to ensure the division
generated a long-term projection that considered the best
available information operators could provide.
Mr. Umekwe turned to a chart slide 14 that compared the
long-term projections of the operators with long-term
projections generated by the Division of Oil and Gas (2020
through 2028). The high side of DNR's forecast was shown in
red and the low side was shown in tan. The blue bars showed
an aggregate of the operators' outlook. The chart showed
that overall, the operators' outlook fell within the range
DNR provided to DOR for its revenue projections.
2:00:50 PM
Mr. Umekwe advanced to slide 15 and addressed the level of
uncertainty for the three production categories. Once the
information was combined, the division came up with a
forecast that had the potential to be significantly
different from the mean projection. The slide included a
chart showing the production forecast range from 2014 to
2028. The black line showed historical production and the
blue line going into the future represented the mean case.
He drew attention to the bars indicating that production
could be anywhere within the range shown [the chart
indicated an increasing uncertainty (wider range) in the
longer-term forecast]. He explained that if everything
aligned well, there could be a situation where production
significantly exceeded the mean line up to 700,000 barrels
per day.
Mr. Umekwe showed a map of projects under evaluation
(medium and long-term) that DNR had considered in its
forecast (slide 16). He pointed out that most of the
projects were located within the central area of the North
Slope (some were located to the far west such as Liberty
and some were south). The yellow section of the map showed
federal government interest lands. The blue section showed
mostly state land and the pink reflected Native land. He
highlighted that GMT1, GMT2, and Willow fell within the
federal section on the map. He noted that most of the other
fields he had discussed, including Pikka, fell within the
state-owned land.
2:03:07 PM
Mr. Umekwe showed a "North Slope Oil Production" chart on
slide 17. The chart depicted a portfolio-scale rollup of
all of the risks DNR applied to the projects. He pointed
out that at the peak, the projects could yield 200,000
barrels of oil per day. He noted that as time went on, DNR
would continue to update the information as it received
more information from operators about changes in scope and
start times. He reiterated his earlier remarks that the new
production would all be layered on top of a declining base
of legacy production. For that reason, the 200,000 barrels
were not being added to the current 500,000-plus barrels.
2:04:13 PM
Vice-Chair Johnston asked for verification that forecasting
had been brought in-house three years back. Mr. Umekwe
replied it had been in the fall of 2016.
Vice-Chair Johnston asked for verification that the
forecast work currently done by the Division of Oil and Gas
had been contracted out as well.
Mr. Umekwe replied affirmatively.
Vice-Chair Johnston asked if there was a comparison between
the in-house projections and the contractor projections.
Mr. Umekwe answered that DNR had the information and had
done some analysis in the past. He offered to update the
information and make it available.
2:05:08 PM
Vice-Chair Ortiz asked how much price variability impacted
a company's willingness or unwillingness to increase
production.
Mr. Umekwe answered that the impact of price on production
depended on numerous factors. For example, normally
companies evaluated projects based on an update in their
price outlook. While the state's oil price forecast may
serve as a good medium for companies to talk to each other,
the companies had internal price outlooks. He explained
that in most cases the state new when changes occurred,
based on activities and other factors in the news; however,
companies may have a different timeline - perhaps they
needed to see oil prices significantly down for a long
period of time prior to updating the outlook on different
projects. He explained that it depended on the company. He
furthered that some companies may hedge a series of
production. Once the price of crude was hedged, based on
the contract the company had with a buyer, it made
momentary changes in oil pricing material to the specific
company. He summarized that it depended on the company and
their own internal assessments, but overall if oil prices
were projected to be low or high, companies updated the
outlook for their projects.
Vice-Chair Ortiz returned to the production range chart on
slide 15. He considered the best case scenario showing
700,000 barrels of oil per day in 2028. He asked how much
price would play in contributing to the best case outcome
shown on the slide.
Mr. Umekwe answered that he did not have an exact number.
He explained that the forecast generated by DNR was based
the price projection for the state provided by DOR. The
price projection had a range around it and DNR's projection
was directly tied to the range in the state's outlook for
oil prices.
^PRESENTATION: PERMITTING ISSUES, & STATUS OF DEVELOPMENT
ON NORTH SLOPE
2:08:44 PM
SARA LONGAN, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, provided a PowerPoint presentation titled
"Alaska Department of Natural Resources: Oil and Gas
Outlook and Permitting" dated February 27, 2019 (copy on
file). She intended to provide additional information on an
oil and gas outlook and share updates on the status of the
department's oil and gas permitting programs. She began on
slide 2 and addressed the state's land base and ownership:
Land Base
â?¢ 586,412 sq. miles?more than twice the size of
Texas
• Larger than all but 18 sovereign nations
• More coastline than all other 49 states combined
• More than 3 million lakes; half of world's
glaciers
• Approximately 40% of the nation's freshwater
supply
Land Ownership
• Federal Land: more than 200 million acres
• State Land: Approx. 100 million acres of uplands,
60 million acres of tidelands, shore lands, and
submerged lands, and 40,000 miles of coastline
• Native Corporation Land: 44 million acres
Ms. Longan advanced to slide 3 and provided a basic, high-
level overview of the business conducted by DNR:
• Secure lands and access from federal government
• Identify minerals and oil and gas prospectivity
via interest findings
• Lease lands for exploration and development
• Permit programs to ensure conservation of
resources and protection of state's lands and
interests
• Manage production units and mines to protect
state's royalty interests
• Approve and monitor reclamation and closure
operation
Ms. Longan noted that the department's business was
continuous and often cyclical. She highlighted that in
addition to Alaska's large size, it had world class
resources. She shared that IHS Markit recently classified
Alaska's North Slope basin as a super-basin. She discussed
oil and gas resource potential on slide 4:
North Slope
• More undiscovered, potentially recoverable oil
than any other Arctic nation
o OIL: Est. 40 billion barrels of conventional
oil
o GAS: Est. over 200 trillion cubic feet of
conventional natural gas
• Untapped unconventional resource potential,
including tens of billions of barrels of heavy
oil, shale oil, and viscous oil, and hundreds of
trillions of cubic feet of shale gas, tight gas,
and gas hydrates
Cook Inlet
• Significant undiscovered resources remain
o 19 trillion cubic feet of natural gas
o 600 million barrels of oil
o 46 million barrels of natural gas liquids
Compared to most basins, Alaska is relatively
underexplored, with 500 exploration wells on the North
Slope, compared to Wyoming's 19,000.
Ms. Longan advanced to the oil and gas outlook on slide 5.
She reported that the 2018 fall lease sale brought the 3rd
highest number of winning bids since 1998. A map on the
slide showed the North Slope and leases purchased (in
green) in the 2018 sale. The sale included over $29 million
in total bonus bids, the highest bid per acre was $586, and
over 243 acres were leased. The blue portion of the map
displayed the state acreage already under lease on the
North Slope.
2:13:30 PM
Ms. Longan discussed royalty rates on a state map on slide
7. She began with state lands in the middle of the map
where the royalty rates were 12.5 percent or 16.67 percent
and the state received 83 to 100 percent of the royalties.
The Natural Petroleum Reserve-Alaska (NPRA) on the left of
the map had royalty rates of 12.5 percent or 16.67 percent.
The state received 50 percent of those royalties, which
were managed by the Department of Commerce, Community and
Economic Development (DCCED) and made available to the
communities within the NPR-A through DCCED's impact
mitigation grant fund. She noted an error on the slide and
reiterated that 50 percent of the state royalties went
through the state mitigation fund.
Ms. Longan reviewed the Alaska National Wildlife Refuge
(ANWR) coastal plain on the right of the map where the
royalty rate was 16.67 percent and the state received 50
percent of the royalties. She finished with offshore
developments and reported that from zero to three nautical
miles the state received 100 percent of the royalties at a
rate of 16.67 percent. At a distance of three to six miles,
the state received a royalty rate of 20 percent.
2:15:01 PM
Representative Knopp referenced the information on slide 4
specifying that Alaska had 500 exploration wells compared
to Wyoming's 19,000. He asked if the data pertained to
initial discovery wells. He remarked there were many more
wells as far as production injection.
Ms. Longan replied that she would follow up with the
information.
Mr. Umekwe answered that the 500 wells were designated as
exploration wells and drilled for the purpose of finding
the resource. In some cases, the well would be repurposed
as a development well.
Mr. Umekwe advanced to slide 8 and explained a graph
reflecting a 20-year production outlook for the North
Slope. Legacy fields were represented in blue and
production anticipated to come online in FY 19 or later was
shown in orange. The graph broke out the Pikka and Willow
projects separately in gray and yellow respectively.
Mr. Umekwe advanced to a map on slide 9 that Willow and
Pikka developments. He shared that the next couple of
slides showed the different revenue outcomes as a result of
the different project locations.
2:17:25 PM
Mr. Umekwe turned to slide 10 and addressed the Willow
development (representing a success case). The slide
addressed revenue the state was anticipating from the
Willow development. He detailed that generally the state
experts on production taxes were housed within DOR, but he
would speak briefly to the issue. The first chart on the
top right represented the revenues the project would
generate for the state at a flat price of $60 per barrel.
He noted that the figures would be slightly different with
inflation. He detailed there was a slight impact on the
state in terms of reduced corporate income taxes as the
company spent money to get the project online.
Mr. Umekwe moved to the chart on the lower right of slide
10 showing revenues the project would generate for the
state at a flat price of $75 per barrel. He explained that
in the initial years as a company spent money to get the
project online, because taxes were estimated at the total
North Slope level all costs and revenues generated from
assets or developments for the entire North Slope were part
of the assessment conducted by companies. In the absence of
a project like Willow, the initial spending incurred by a
company would be part of the overall spending it was
assessed on. He explained it was the reason there was more
spending with the project and consequently, the company
paid slightly lower taxes. However, going into the future,
the development yielded more revenues for the state.
2:20:04 PM
Mr. Umekwe moved to slide 11 and addressed the Pikka
development (representing a success case). The slide gave
an example of a project carried out by a company without
existing tax liability. He drew attention to two bar charts
on the right side of the slide and noted that the blue
portion of the bars representing royalties to the state had
not been present in the previous slide for Willow. He
explained that the project was located on state lands, the
operator would pay royalties to the state as well as
production taxes.
Mr. Umekwe elaborated that the first chart on the top right
[of slide 11] represented the revenues the project would
generate for the state at a flat price of $60 per barrel.
He detailed that while the company was spending to get the
project online, the expenditure was not shown because the
company was experiencing a loss at the time (there was
spending, but no production). Once production began in
2024, some of the losses the company accumulated would help
the company reduce its production tax liability for the
initial years; after those ran out, the company would start
paying more production taxes. He noted that at the flat $60
price, the company was a minimum taxpayer.
Mr. Umekwe explained that three things could happen for a
company developing resources on the North Slope: 1) if
assets were in production, there could be a situation where
the company was producing oil, but it was spending much
more than it was producing; 2) if the company was slightly
profitable, it would be a minimum taxpayer because the
state's tax system allowed the state to get some revenue if
the gross tax was higher than the net tax; 3) in a
situation where the net tax was higher than the minimum tax
and the companies would pay the net tax.
Mr. Umekwe moved to the chart on the lower right of slide
11 showing revenues the project would generate for the
state at a flat price of $75 per barrel. He noted that
revenue take for the state was much higher under the
scenario. He highlighted that it was still the case that in
initial years the company was spending without production,
which would allow the company to use some of its losses to
reduce the production tax liability in the future. Overall,
the project would yield between $8 billion and $13 billion
for the state (he noted a typo on the slide in the revenue
figures listed on the slide).
2:23:42 PM
Mr. Umekwe turned to slide 12 and reviewed a royalty
analysis broken out by different areas of the state. He
pointed to the royalty rate of 16.67 percent in the first
row of the first column related to a project in the NPR-A.
He explained that nothing went to the state's General Fund;
whatever the state received from resources on federal land,
50 percent went to the impact mitigation fund and whatever
was spent on grants and projects would be available to the
state. The green portion of the table showed production
from state land. He reported that the state received 100
percent of the royalties generated from that production.
The state received a share of the royalties generated on
lands that were jointly owned by the state and Native
lands. He noted that the state received 83 percent of two-
thirds of the production from Pikka. Offshore, the state
received 100 percent of the royalty between zero to three
nautical miles; the state royalty was 27 percent from three
to six nautical miles. In ANWR the state received 50
percent of the royalties.
2:25:30 PM
Representative Josephson asked why some royalty rates were
12.5 percent and others were 16.67 percent.
Mr. Umekwe replied that when lease sales were organized,
terms and conditions were set and included things like
royalty rates, minimum bids, and net profit shares in some
cases as had been done in the past. When the leases were
issued, 12.5 percent and 16.67 percent had been rates set
by the state. He believed there was a statutory minimum of
12.5 percent.
Representative Josephson thought it had to do with
challenged fields, but he was trying to understand why they
were seeing more fields with a royalty rate of 16.67
percent.
Mr. Umekwe answered that one of the internal analyses the
Division of Oil and Gas had done in the past was to look at
the general area of the North Slope. He agreed there were
areas that DNR considered to be more prospective, where the
general rule of thumb was to set the royalty rate at 16.67
percent. He explained that areas that were far from
infrastructure and had no evidence of successful commercial
development would be offered at the lower royalty rate.
Representative Josephson believed there had been a 12.5
percent used in 1968 or 1969 when oil development began in
Alaska. He believed those rates were binding unless
revisited through mutual agreement of both parties. He
asked if the state's royalty rate was competitive with
rates in other states (setting aside the difficulty of
exploring in Alaska).
2:28:34 PM
Mr. Umekwe answered that he knew of areas in the Lower 48
such as Texas, where royalty rates were 20 percent or more.
He pointed out that all of those areas were privately owned
so it was possible for a private landowner to negotiate
whatever royalty rates they could. Additionally, the scope,
scale, and spending of those projects were different. All
of those items were considered in a transaction before
operators had access to acreage.
Representative LeBon pointed to the Willow project on NPR-A
land [slide 12] with an Alaska Native royalty of zero
percent and a federal royalty of 50 percent. He asked what
the mitigation impact fund royalty is and who received it.
Mr. Umekwe deferred the question to Ms. Longan.
Ms. Longan replied that the program was administered by
DCCED. She shared that 50 percent of the NPR-A royalties
were received by the state and were administered by through
DCCED's impact grant program. There was legislation that
dictated how the funds were utilized. The first use of the
royalties went to communities within the NPR-A who could
apply through the DCCED grant program for qualified
projects to help offset the impacts of development. She
elaborated that if those funds were not used, the remaining
funds went to the school trust and elsewhere. She offered
to provide general information from DCCED on the mitigation
program.
Representative LeBon asked if the money remained within the
state. Ms. Longan replied in the affirmative.
2:31:08 PM
Ms. Longan advanced to slide 14 and addressed the status of
development:
• 2019 is expected to be the highest year in the last
20 years for exploration and production rig
activity.
• Pikka, Mustang, and Placer finds demonstrate great
potential.
• New data suggests enormous potential in Nanushuk and
Torok formations.
• Legacy fields including Prudhoe and Kuparuk have
exceeded internal expectations through infield work.
• Smaller companies, like Caelus, BlueCrest &
Armstrong, are engaging in exploration plans that
will help maximize TAPS throughput into the future.
• New players, like Oil Search, indicate industry
acknowledgment of large, viable fields that were
unknown.
• Continuous work with North Slope communities,
presidential administration, and Congressional
delegation on Arctic energy policy and decision
making that support responsible development (ANWR
Coastal Plain, OCS, NPR-A)
Ms. Longan elaborated on the second to last point and noted
that new players, like Oil Search, indicated industry
acknowledgement of large, viable fields that were
previously unknown or were not totally understood.
2:32:41 PM
Representative Sullivan-Leonard considered the great
potential with Pikka, Mustang, and other North Slope
fields. She found it very encouraging. She asked how much
oil they were expecting from new exploration. She
referenced the graphs showing a gradual decline in
production.
Ms. Longan answered that the production outlook ranges
provided by Mr. Umekwe had been determined by the
department and showed what types of production would be
going into the Trans-Alaska Pipeline System (TAPS).
Representative Sullivan-Leonard spoke to the decline. She
stated the decline was not with the new companies coming
onboard and putting oil into TAPS. She asked the decline
pertained to the other companies.
Ms. Longan answered that the projects the division used to
analyze what the production outlook may be based on its
assumptions and taking multiple factors into consideration,
there was always the opportunity for new companies to
acquire leases. She agreed, that once new companies entered
into exploration to understand resource potential, DNR did
not know what the future held. When new players came to
Alaska to lease lands and perform exploration activities
where there were discoveries and resource potential
elsewhere, it would help increase the TAPS throughput and
would slightly change the production outlook presented by
Mr. Umekwe.
2:34:51 PM
Ms. Longan moved to a map on slide 15 showing the status of
development. She noted the busy nature of the map and
stated it was indicative of the significant activity taking
place across the North Slope by multiple applicants and
companies. She detailed that the information was routinely
updated by the Division of Oil and Gas and was available on
the department's website. She briefly highlighted two maps
on slide 16 that were routinely updated by the department.
Ms. Longan addressed updates on the permitting process and
status and how DNR was engaged in oil and gas permitting
activities. She began with a description of the basic
anatomy of a large-scale development project on slide 18.
She noted that DNR's priority continued to be to manage its
permit programs as efficiently as possible to shorten the
time necessary from appraisal to development. She reviewed
slide 18:
• Statewide or regional impact - infrastructure
development, economic growth opportunities
• Generally [companies] require long term leases or
dedicated legal access such as easements in order to
obtain project financing
• Lease/Unit Plan of Operations or Plan of Development
• Shorter term land use permits are necessary for
construction
• Material sales for development
• Water Authorizations for development and operations
Ms. Longan shared that there were other departments with
jurisdiction over the permitting of oil and gas projects.
She planned to describe how DNR was interacting in the
processes, supporting other departments as they processed
permits for oil and gas activities.
2:37:08 PM
Ms. Longan shared an example of a success story on slide
19. She detailed that over the past few years the Division
of Oil and Gas had been working to increase permit
efficiencies. She pointed to a bar chart and highlighted
that in 2013 it had taken an average of 180 days for the
division to process permits. Over time, gains had been made
and in 2018 it took approximately 30 days to process the
permits. The division had achieved the accomplishment by
automating and modernizing its systems (e.g. electronic
applications). The division maintained a continuous
feedback loop with applicants to understand where things
were going well and identify future efficiencies. The
department recognized that incomplete applications could
cause delays; therefore, the division was proactively
working with applicants to ensure they understood permit
requirements. Additionally, updated guidance documents were
available online. There was currently no permit backlog.
Ms. Longan reported there had been some structural changes
at the department with the goal of maximizing the use of
its time and gaining efficiencies. The department had moved
the previously autonomous State Pipeline Coordinator's
Section underneath the Division of Oil and Gas. The change
had been made to increase efficiencies and made sharing
knowledge and working towards similar goals and timelines
more cohesive between the groups.
2:39:06 PM
Ms. Longan advanced to slide 20 and reported that DNR had
learned the importance of doing business efficiently in
order to handle the routine and daily workload.
Additionally, it was important to be flexible, nimble, and
ready for an uptick in activity. Over the past two years,
there had been more federal activities across the North
Slope than in the past. She reviewed reasons for the change
on slide 20:
Tax Act Coastal Plain Activity
• BLM to administer an oil and gas leasing program in
the Coastal Plain of ANWR
• Section 200001 PL 115-97 requires at least 2 lease
sales to be held by 2024
• Each sale must offer 400,000 acres of highest
hydrocarbon potential, up to 2,000 surfaces acres of
Federal land to support production and support
facilities
• SOA Royalty 50%
NPR-A Activity
• Oil and Gas Leasing
• CPAI continued progress
• CD-5 production
• GMT-1 began production October 2018
• GMT-2 & Willow Development
• SOA Royalty 50% through NPR-A Impact Mitigation Grant
Program
SOA authorizes water withdrawal, fish habitat permits
for activities on federal lands SOA consultation,
shares expertise on tundra travel, air quality,
reclamation, etc.
Ms. Longan elaborated that under NPR-A there had not been
as much of an uptick in activity over the past two years;
it was more of a progression of accomplishments and
activities over the last several years. She reported that
ConocoPhillips continued to have great success and had
reached significant milestones including production from
the CD5 project. She added that production from the GMT1
project was the first production from a federal lease
within the NPR-A. She shared that the state had authorities
that were triggered on the activities taking place on
federally managed leases. For example, DNR was authorizing
water withdrawals; the Department of Fish and Game was
processing and approving fish habitat permits; and the
Department of Environmental Conservation maintained
authorities over air quality, water quality, and solid
waste management. She informed the committee that as the
federal agencies were busier responding to an uptick in
activity, the state was busier managing the workload.
2:41:22 PM
Representative Josephson had always been curious about the
rejection of a permit application. He wondered if the
reason the legislature did not hear much about it was
because in order to proceed there would have to be some
mitigation or adjustment. For example, he assumed that if
someone did not obtain a fish habitat permit, they would
not merely stop because it meant the project would die. He
thought perhaps someone would come to DNR to do a
workaround of some sort. He asked for an explanation of
something that had been rejected and then accepted.
Ms. Longan replied that the scenario described by
Representative Josephson was fairly common throughout the
state's permitting process. She believed the reason people
did not commonly hear about permits being rejected was
because the process was iterative. She used Representative
Josephson's example of a fish habitat permit and detailed
that often times permit applications may not be suitable or
fish biologists and experts may have an alternative project
configuration or plan to help and support the project
applicant to make adjustments, which may have less impacts
on anadromous fish. There were numerous examples and most
often, permit applications as received were optimized and
improved over time, which was the reason there was such a
high success rate in permit approvals.
2:43:25 PM
Ms. Longan turned to slide 21 and described the complex
federal processes including the length of time it took to
obtain an oil and gas permit. She hoped to adequately
explain the reason the length of time to obtain an oil and
gas permit depended. She relayed that the timeline for
state permit agencies was almost always driven by a major
federal authorization and action. The left arrow on the
slide described the various stages of the National
Environmental Policy Act (NEPA), which was required for
almost all proposed oil and gas activities. The longer
process could require an environmental impact statement
(EIS) and there was a different process called an
environmental assessment (EA).
Ms. Longan continued that over the past year NEPA had been
working well in Alaska - oil and gas permits were typically
going through a three-year NEPA timeline. There were other
examples where things where things were delayed for various
reasons and NEPA's process took five or more years. She
reported that federal leadership was requiring federal
agencies to conduct EIS, the NEPA review, in a one-month
timeframe, while maintaining robust public and stakeholder
outreach. Federal agencies were requiring and had issued
four major projects including a Donlin [mine] project and
GMT2 in a joint record of decision (JROD). She detailed it
involved multiple federal decisions for a single project,
which were combined and issued within a joint record of
decision. She stated it was very important; it should and
probably had translated into minimized risk to the project
applicant (lessening the chance of conflicting federal
agency decisions).
Ms. Longan moved to the second arrow from the left on slide
21 showing examples of a major federal authorities and
required review processes that typically happened
concurrently throughout the NEPA process. She noted there
were dozens of examples that were not included. She
highlighted the Army Corps of Engineers 404 wetlands permit
required under the Clean Water Act anytime fill was placed
in U.S. waters. She shared that the state was known for its
robust, multi-layered permitting system.
Ms. Longan intended to highlight the DNR permit process and
the process in several other state agencies. Some permits
(e.g. the 404 permit) were associated with requiring longer
lead times. For example, the State Historical Preservation
Office (SHPO) was responsible for conduction the Section
106 review for proposed projects, which was important to
understand and minimize risk or any impact to cultural and
historical resources. She explained it was a good example
of where a state had authority to administer the Section
106 process, but it also had to comply with federal
statutes and regulatory guidelines. She elucidated that
when a state permitting program had the federal compliance
piece, it increased the level of complexity and in some
cases required more time for departments to collaborate and
coordinate with their federal counterparts.
2:47:43 PM
Ms. Longan continued addressing slide 21. She shared that
because DNR recognized that Section 106 was so important to
the overall timeline for large projects, it had made
another structural change for the specific review for large
projects. The department had moved the work into an office
to ensure the SHPO review process was close to leadership
to provide support throughout the operation. She
underscored that DNR were not experts at what other state
departments were doing for oil and gas permits. She shared
that DEC's air quality permit could be associated with
longer lead times. She explained that DEC had authority to
administer its air quality permit program and
authorizations thereunder, but they were also required to
comply with federal statute and regulatory guidelines under
the Clean Air Act. She relayed that data was essential to
inform DEC of how to issue air permits; data collection
could typically take one year or longer.
Ms. Longan shared that permit agencies recognized where
review processes may be complex; therefore, they were
working hard from a leadership and staff level to
communicate consistently between DNR, DEC, and DFG to
proactively troubleshoot any problems.
Ms. Longan relayed that while NEPA and federal and state
authorizations were concurrently moving forward, the
project applicant had to work with the local borough and
municipalities to secure borough, city, and tribal village
plans.
Representative Josephson shared that his office had learned
that the draft EIS for the Donlin Mine had a comment period
of about seven months. The Army Corps of Engineers was
offering a 90-day public comment period for the proposed
Pebble Mine project. He highlighted that the state's
delegation including Senator Lisa Murkowski and Senator Dan
Sullivan had stated that the 90-day period was too short.
He noted that Bristol Bay Native Association, Bristol Bay
Native Corporation, and Bristol Bay Economic Development
Corporation had asked for a longer comment period. He asked
why the Army Corp had limited the comment period to 90 days
and why it had denied requests to lengthen the timeline. He
wondered why the agency gave seven months for Donlin and
only three months for Pebble.
Ms. Longan did not know the answer but wanted to try to
help. She reminded the committee that federal government
(Army Corps of Engineers) had decided on the length of the
public comment period for the proposed Pebble project. She
noted that federal agencies typically made determinations
based on how robust and successful the stakeholder
engagement process was throughout the review period from
the point where land was released and when exploration took
place in advance of a project approval for oil and gas and
mining projects. She explained that if the lead federal
agency deemed there was sufficient information and the
process had been robust enough, it was factored into the
decision to extend or not.
Representative Josephson stated that one of the major mines
that most Alaskans had heard less about was the Donlin
project. He shared that earlier in the day he had met with
four residents of the Lower Kuskokwim district who claimed
the current administration was not being cooperative in
terms of government to government relations. He noted the
reference to tribal village plan on slide 21. He relayed
that the Lower Kuskokwim residents wanted some assurance
their concerns about subsistence issues and related matters
were heard.
2:53:19 PM
Ms. Longan addressed the reference to a tribal village plan
on slide 21 and explained that securing the plan was the
responsibility of the project applicant. She noted that she
was not an expert in the terminology referenced by
Representative Josephson because there was no requirement
for the State of Alaska to offer the formal government to
government consultation required by federal law; however,
DNR and the state maintained a broader public comment
opportunity and stakeholder outreach and engagement. She
noted it was an important responsibility of the
department's and the process was iterative. Often members
of the public or people living in rural communities
throughout Alaska and perhaps those impacted by the
proposed Donlin project, learned more about a project over
time due to its complexity. She would share an example of
how the department tried to break the process down to make
sure the affected stakeholders and public were keeping
track and able to voice their concerns to DNR. She stated
that the process was ongoing.
Co-Chair Wilson asked if there was any point in the process
where the state was more stringent than the federal
government.
Ms. Longan answered in the affirmative. She detailed there
was a lot of discretionary approval in many of the state
authorizations where the state followed very prescriptive
regulation. Alternatively, she used the fish habitat
example and relayed that if there was something in a
proposed action or project that needed to be modified, the
state could be more prescriptive by catching that and
wanting to work towards solutions. She did not know the
specific regulations where the state was more prescriptive
than the federal government. The state routinely examined
the issue and made changes to its regulatory programs to
make them more or less restrictive. The state also worked
for consistencies - if the state regulations required one
thing and the federal government required something
completely different, it was an iterative process where the
state tried to be as consistent as possible.
2:55:55 PM
Co-Chair Wilson asked whether it added more time to get
permits through.
Ms. Longan replied in the negative. She detailed that
changes to a regulation could not and should not impact a
project application that had already been submitted. She
had not witnessed a time where a change had added a permit
delay.
Co-Chair Wilson thanked the department for its increased
efficiency and recalled that in the past the permit process
had been far behind. She was thankful that the items were
not all happening separately.
Representative LeBon believed the EIS likely touched almost
every permit. He wondered if it was usually the lead for
the project. He asked if many permits waited for the final
EIS before getting into their process. He noted that slide
21 gave the impression that everything was taking place
concurrently, but he did not believe that to be the case.
Ms. Longan agreed. She emphasized that the state could not
issue permits until the EIS process was complete. She
explained that the process configuration changed through
the EIS process. The configuration would be optimized and
modified to reduce environmental impacts. The state was
educating itself and working with the public and project
applicant to understand what the NEPA looked like. She
would describe the specific actions momentarily. She stated
it was imperative, because if the department waited for the
EIS to go on for a year without knowing much about it, it
started virtually from scratch when it worked to review the
state permits. The state was coordinating to make the
process as concurrent as possible, but the state would
typically not issue its major permits until the completion
of NEPA and the EIS.
2:58:44 PM
Representative Carpenter lauded the department for
eliminating the permit backlog. He wondered where the
department recommended that a new company hoping to invest
in Alaska begin in the process.
Ms. Longan replied that the question pertained to her next
slide. She had some success stories to share and a well-
executed process in Alaska. She turned to slide 22 and
shared that it was important for DNR to operate
efficiently, but it was also important to understand the
need to strike a healthy balance - that no matter how
efficient DNR was operating, it was still working to issue
science informed decisions that took public and stakeholder
input into consideration, ultimately to enable DNR to issue
defensible permit decisions. One of the greatest tools DNR
had seen utilized by the public and private sector for over
20 years was the Office of Project Management and
Permitting (OPMP). She detailed that OPMP was established
in the 1990s with the advent of the Fort Knox Mine. They
had recognized there was major federal jurisdiction, that
there would be numerous state permits required, and it
would make sense to have a structure in place for the
federal, state, and local governments to be able to
coordinate and operate things as concurrent as possible.
Ms. Longan detailed that OPMP was located in the DNR
commissioner's office, which was unique nationwide. She
believed the state was well ahead of the times. She
explained that it had been a voluntary coordination
services - the office was run almost exclusively off of
reimbursable services. She shared that OPMP was offering
industry a one-stop permit coordination approach to
minimize the regulatory risk of things not running
concurrently or off the tracks. The office was working
daily to ensure the process was fair, predictable, and on
time.
Representative Carpenter clarified that his previous
question was based on comments and discussions in the
legislature and his past experience in the military dealing
with governments and tribal governments outside of Alaska.
He observed that the Tribal Village Plan was one of many
items in the process [slide 21]. He stated that because all
emergencies were local, all development was also local. He
asked if the state was recommending that companies start at
the local level to gain buy in from the local community
before starting the federal or state process.
Ms. Longan replied in the affirmative. The local
governments had to wait for NEPA to finish in order to
issue permits. The companies with sights on doing business
in Alaska were sophisticated and knew the process; if they
did not know, they were reminded by DNR and most likely
legislators of the importance of getting boots on the
ground and working with local governments and stakeholders
to understand how they wanted to be incorporated into the
process. She was proud of DNR's leadership over many years.
She explained that in order for the state to help aid
communication, the project applicant needed to communicate
with local residents and the boroughs, and the state needed
to maintain effective communication as well.
Ms. Longan continued that due to high activity on the North
Slope and elsewhere in the state, DNR had a longstanding
memorandum of understanding (MOU) with the mayor of the
North Slope Borough. She was pleased to report that new DNR
leadership was working on updating the MOU. The work
required teams to work at the commissioner to mayor level,
there were quarterly leadership meetings, and staff spoke
monthly or on an as needed basis to ensure they were
sharing what they were hearing from applicants. The
department was also encouraging the private sector to
maintain good communication at the local and state level.
Vice-Chair Johnston referenced Ms. Longan's discussion of
changes made in Section 106. She asked if Section 106 had
been brought into "this" [OPMP] office.
Ms. Longan replied in the affirmative.
3:04:18 PM
Ms. Longan relayed that the next several slides [slides 23
through 25] to highlight the complexity of the process. The
slides also addressed where to start. She explained that
OPMP maintained coordination protocol that allowed DNR to
communicate with all branches of government so the private
sector and public could understand who they need to
contact. Slide 23 included a list of the various state
departments that were often involved with reviewing oil and
gas permits. She noted there were numerous departments with
multiple divisions underneath; the same was true for
federal counterparts [slide 24].
Ms. Longan turned to a state agency coordination bubble
chart on slide 25. The slide was intended show that OPMP
was a first line of contact to direct people to the
appropriate agency. The office also communicated with
counterparts throughout federal, state, and local
government. She stressed that the coordination effort
provided by OPMP was a value added tool that made the
complex permitting framework a bit easier to understand.
She concluded the presentation on slide 26 with a list of
department staff who had contributed to the presentation.
She thanked the committee for its time.
Co-Chair Foster thanked the presenters and reviewed the
schedule for the following day.
ADJOURNMENT
3:06:58 PM
The meeting was adjourned at 3:06 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HFIN - OG Production fcst 2-27-19.pdf |
HFIN 2/27/2019 1:30:00 PM |
HFIN DNR Production Forecast |
| HFIN - OG Permitting 2-27-19.pdf |
HFIN 2/27/2019 1:30:00 PM |
HFIN DNR Permitting |