Legislature(2011 - 2012)BUTROVICH 205
04/11/2012 07:00 AM House ENERGY
| Audio | Topic |
|---|---|
| Start | |
| Hearings Related to the Short and Long Term Stability and Reliability of Gas from the Cook Inlet Field | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON ENERGY
April 11, 2012
7:08 a.m.
MEMBERS PRESENT
Representative Neal Foster, Co-Chair
Representative Lance Pruitt, Co-Chair
Representative Bob Lynn
Representative Dan Saddler
Representative Pete Petersen
Representative Chris Tuck
MEMBERS ABSENT
Representative Kurt Olson
OTHER LEGISALATORS PRESENT
Representative Mike Chenault
Representative Kyle Johansen
Representative Bob Miller
Representative Charisse Millett
Representative Paul Seaton
COMMITTEE CALENDAR
HEARINGS RELATED TO THE SHORT- AND LONG-TERM STABILITY AND
RELIABILITY OF GAS FROM THE COOK INLET FIELD
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
PAUL DECKER, Petroleum Geologist
Resource Evaluation Section Manager
Division of Oil and Gas (DOG)
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation
entitled, "Cook Inlet Activity and Natural Gas Resource Update"
dated 4/10/12, and answered questions.
ROBERT (BOB) SWANSON, State Geologist and Director
Division of Geological & Geophysical Surveys (DGGS)
Department of Natural Resources (DNR)
Fairbanks, Alaska
POSITION STATEMENT: Participated in the PowerPoint presentation
entitled, "Cook Inlet Activity and Natural Gas Resource Update"
dated 4/10/12, and answered questions.
TOM WALSH, Managing Partner
Petrotechnical Resources of Alaska (PRA)
Anchorage, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation
entitled, "Cook Inlet Gas Supply Study Update" dated 4/10/12,
and answered questions.
ACTION NARRATIVE
7:08:06 AM
CO-CHAIR LANCE PRUITT called the House Special Committee on
Energy meeting to order at 7:08 a.m. Representatives Pruitt,
Foster, Tuck, Petersen, Saddler, and Lynn were present at the
call to order. Representatives Chenault, Johansen, Miller,
Millett, and Seaton were also present.
^HEARINGS RELATED TO THE SHORT AND LONG TERM STABILITY AND
RELIABILITY OF GAS FROM THE COOK INLET FIELD
HEARINGS RELATED TO THE SHORT AND LONG TERM STABILITY AND
RELIABILITY OF GAS FROM THE COOK INLET FIELD
7:08:57 AM
CO-CHAIR PRUITT announced that the only order of business would
be hearings related to the short and long term stability and
reliability of gas from the Cook Inlet field.
7:10:42 AM
PAUL DECKER, Petroleum Geologist, Resource Evaluation Section
Manager, Division of Oil and Gas (DOG), Department of Natural
Resources (DNR), provided a PowerPoint presentation entitled,
"Cook Inlet Activity and Natural Gas Resource Update" dated
4/10/12. He said the presentation would begin with the high
points of two natural gas studies conducted within the past two
years on Cook Inlet exploration activity. The first study was
completed in 2009, and took an engineering and geological
approach to determine how much gas remains in the 28 known and
producing gas fields in Cook Inlet. The emphasis of this study
was on reserves of potentially recoverable resource and examples
of undeveloped gas leads. The 2009 study did not attempt to
include an estimate of undiscovered gas resources in the basin.
The 2011 study covered the commerciality of developing the
reserves for market to meet the existing demand. This was done
by generating dozens of development scenarios using hard data
and Monte Carlo simulation to model the reserve resource's
commerciality and production outcomes.
7:14:40 AM
MR. DECKER displayed slide 3 entitled, "Cook Inlet Natural Gas
Reserves and Resources Hypothetical Production Forecast" which
was a forecast of different volumes of gas identified with
various types of geologic engineering analysis from 2010
forward. The most conservative forecast identified a volume of
863 billion cubic feet (bcf) remaining in existing wells
throughout the basin. Furthermore, a material balance analysis
revealed more reserves from remediated wells in the amount of
279 bcf throughout the basin. Additional volumes were from
reserves identified by geologists as the category of natural gas
volumes recoverable from reservoir sandstone layers that meet
all the criteria used to identify viable production (PAY
category). Other volumes were forecast by looking at well logs
from PAY category reserves, and from "less confident"
identification of PAY on the well logs, which is discounted at
50 percent risk. Finally, prospects from exploration leads were
included in the forecast.
7:17:59 AM
REPRESENTATIVE TUCK observed that all of the decline curves are
consistent.
MR. DECKER advised the rate of decline is determined by the rate
of consumption. He pointed out that the graph shows the volumes
as sequential; however, production and exploration could occur
at the same time. Slide 4 entitled, "2011 DNR CI Gas Production
Cost Study" illustrated how commercial the projects were by the
sort of investment; for example, existing wells with no capital
investment should recover about 660 bcf, and compression
additions should recover about 288 bcf. Material balance and
geologic analyses were included in the new well development
estimate of resources of 638 bcf, and exploration leads were
estimated at resources in the amount of 248 bcf. Mr. Decker
noted that these figures are the "mean case," specifically
identified with concrete projects, before the completion of the
commercial analysis. Slide 5 entitled, "Summary and Conclusions
2011 DNR Study" indicated: The Cook Inlet basin is capable
given sufficient investment of continuing to supply the regional
natural gas needs until about 2018-2020 with attractive rates of
return. He opined this should spur investment, but the reason
exploration is not seen in Cook Inlet has to do with its unusual
gas market - which is not attached to the spot market - and
suffers from huge seasonal swings in demand.
7:21:51 AM
MR. DECKER displayed slide 6 entitled, "Illustrative South-
Central Alaska Daily Demand" which indicated the differences in
wintertime and summertime demand: Demand on a peak winter day
is nearly twice what it is on an average basis. He expressed
his belief that natural gas storage will play an increasing
important role in commercial deliverability and in spurring
investment in the basin. Slide 7 entitled, "Gas Storage Design
Rate & Capacity" indicated there are six approved gas storage
projects in the inlet; three are currently online, the largest
of which is the Marathon Kenai Field Pool 6 storage that has six
bcf of storage capacity and sixty million cubic feet per day
(MMcf/d) deliverability into the gas system. The CINGSA/SEMCO
Cannery Loop Sterling C sands is the biggest new project which
will add storage in the amount of 11 bcf of capacity and 150
MMcf/d of deliverability. He advised that adding storage and
deliverability is "a big step" in tempering the effect of the
seasonal swings by creating a year around market for gas. Slide
8 entitled, "Cook Inlet 2011 Lease Sale Results" described the
successful 2011 lease sale that sold over 100 tracts totaling
575,202 acres for over $11,000,000. Apache Alaska Corp. was the
largest bidder, investing $9,000,000. Slide 9 entitled, "Cook
Inlet Oil and Gas Activity 2012" indicated there are present
activities by companies such as Apache, Hilcorp, Furie,
Buccaneer, Nordaq Energy, Anchor Point Energy, Cook Inlet
Energy, CIRI, Linc Energy, and the expanded gas storage
facilities.
7:27:16 AM
MR. DECKER displayed slide 11 entitled, "Alaska Exploration
Wells Per Year 1960-2011" which indicated there was a lot of
activity in Cook Inlet in the 1960s; there was an increase in
drilling from 2002 to 2005; and there is an upswing now.
CO-CHAIR PRUITT asked what created the spike from 2002 to 2005.
7:28:12 AM
ROBERT (BOB) SWANSON, State Geologist and Director, Division of
Geological & Geophysical Surveys (DGGS), explained in the early
2000s a lot of wells were drilled on the Kenai Peninsula looking
at "bypassed pay" along the Kenai gas field, and offshore in a
structure near Nikiski.
MR. DECKER displayed slide 12 entitled, "Cook Inlet Development
Wells Per Year 1950-2011" which indicated many wells were
drilled in the late '60s. He opined the tapering-off of
development activity in the last few years is "not unlike we've
seen in the past, but I think it has to do with uncertainty as
to whether there is going to be additional capacity in the
market." Slide 13 entitled, "Oil and Gas Resources vs.
Reserves" explained the difference between resources and
reserves: Resource is undiscovered and technically recoverable
oil and gas estimated to exist in accumulations that have never
been found by drilling. In addition, if resource is found, it
can be produced using current technology. An unknown fraction
of this category is commercial thus it is also known as
prospective resource, because it does not occur in oil and gas
fields, but in prospects.
7:30:44 AM
REPRESENTATIVE PETERSEN asked whether tax incentives provided by
the state will encourage companies to look for prospective
resource.
MR. DECKER said yes, this is part of the reason the jack-up rig
was brought to Cook Inlet basin.
7:31:31 AM
REPRESENTATIVE TUCK understood that much of the Cook Inlet
exploration was for oil, and gas was a byproduct. Because the
new incentives from the state are now for gas, he asked how many
of the explorers listed on slide 9 have indicated interest in
the last five years.
MR. DECKER said most of them. Many independents have come into
the basin, and the role of the major producers in exploration
has decreased.
REPRESENTATIVE TUCK then asked whether the legacy companies are
no longer interested in exploration because they seek oil and
not gas.
MR. DECKER advised that Cook Inlet, when compared with other
areas of the world, does not have a sufficient rate of return to
hold the focus of large companies.
MR. DECKER returned to slide 13, saying that proved reserves are
oil and gas which by analysis of geological data and engineering
can be estimated with reasonable certainty to be economically
producible, sometimes with a 90 percent certainty.
CO-CHAIR PRUITT observed "economic" means many different things.
MR. DECKER agreed; however, proved reserves are those that
"producers want ... out of the ground," and developed reserves
are one step higher in that they are proved reserves that can be
expected to be recovered through existing wells without
significant new investment. Slide 14 entitled, "Reserves and
Resources Terminology" indicated the steps from undiscovered
prospective resources to discovered commercial reserves,
beginning with seismic data that identifies a prospective
resource. After identification, the land is acquired, and
drilling begins. If - as in 10-20 percent of the time - the
drilled well makes a discovery, the resource becomes a
contingent resource; one that is known, but the commercial value
is unknown. After additional drilling, the project is refined,
modeled, and sanctioned with cost analysis, environmental,
permitting, and investor approval, and the resource is elevated
to the category of reserves. Finally, after development, the
category becomes proven and developed reserves.
7:35:36 AM
MR. SWANSON directed attention to the U. S. Geological Survey
(USGS) estimates of technically recoverable resources in the
basin. The USGS has been working with the state for five years
to understand the geology in the basin and perform its analysis.
He explained the statistics of gas exploration in the basin
through time:
· 85 percent was discovered in the '60s during oil
exploration until Prudhoe Bay was discovered and attention
was turned north.
· Only structural traps were being prospected and drilled as
the quality of the seismic at that time was poor, but
prospects now are "difficult to miss" with present
technology.
· Nearly one in ten fields is greater than 2 trillion cubic
feet (tcf) of gas.
· Four of the largest fields have 86 percent of the current
known reserves.
· Field-size distribution lacks the size of discoveries
between 300 bcf and 1.3 tcf.
MR. SWANSON displayed slide 16 entitled, "Cook Inlet Resource
Potential USGS Resource Assessment 2011" and explained the work
done by USGS was identifying the undiscovered technically
recoverable oil and gas that does not have an economic filter,
meaning that the USGS estimates include resource that may not be
produced economically. A portion of the resource may be
produced, and the estimates are referred to in "an arithmetic
mean of a distribution." Mr. Swanson stressed that the range of
possibilities is important; in fact, USGS is changing how it
reports estimates and is now including the range of
possibilities. In the Cook Inlet basin, USGS estimated an
arithmetic mean of probabilistic distribution of about 600
million barrels of oil located in two assessment units: 372
million barrels in the tertiary sandstone play, from which all
of the current oil production comes; and 227 million barrels in
the Mesozoic sandstone play, which is a deeper part of the
section. For gas, USGS assessed two conventional units: 12.2
tcf in the tertiary sandstone play, from which all of the
current gas production comes; 1.5 tcf in Mesozoic sandstone; and
two unconventional units: 0.6 tcf in the Mesozoic tight
sandstone play; and 4.7 tcf in the tertiary coalbed play.
7:41:44 AM
MR. SWANSON displayed slide 17 entitled, "USGS Assessment of
Cook Inlet Undiscovered Technically Recoverable Resources" and
pointed out the mean for undiscovered resources of gas in
tertiary sandstone was 11,992 bcf of gas; however, there is a
wide range between the low and high estimates of 2.8 tcf and
24.4 tcf, which suggests that these estimates are based on
limited information. Importantly, when the range of estimates
is narrow around the mean that suggests there is a tremendous
amount of information from 3-D seismic data and many wells. He
cautioned that when looking at the estimate currently getting a
lot of attention - total undiscovered gas resources of 19,037
bcf - one must understand that there are many assessment units
contributing to that number, and pay attention to the wide range
around the mean.
CO-CHAIR PRUITT clarified that recoverable is different from
economical, in that the mean might be 19 tcf, but the total may
be only a portion of that.
MR. SWANSON indicated yes, this estimate represents the
potentially technically recoverable resource and not what will
be found, what is economic, or what is accessible.
REPRESENTATIVE PETERSEN surmised there is a 95 percent chance
that there is 2.8 tcf of gas, and at the current rate of
consumption that supply would last close to 30 years.
MR. SWANSON agreed. He turned attention to the amount of work
put into the assessment, noting USGS performs analyses on many
basins around the world. For example, assessment input is
garnered from fields, seismic, the study of geologic features
such as rocky outcrops and reservoir distributions, detailed
rock analysis, and stratigraphic understanding. After the data
is compiled, USGS compares the petroleum system models to a
global database of known basins. Slide 19 entitled, "Log Normal
Distribution of Gas Accumulation Size" was an example of the
distribution of field sizes in the model, thus revealing how
many fields of what size make up the total resource base.
7:47:26 AM
MR. SWANSON, in response to Representative Saddler, explained
that continuous oil and gas resources such as shale gas and oil
plays and coalbed methane are often seen in the Lower 48;
instead of migrating into a reservoir, the hydrocarbon is in
place where it was generated. He returned attention to slide
19, saying a key part of the study is the size of the field
which is compared to known basins. Most of the fields globally
are small; however, in Alaska - on the North Slope and in Cook
Inlet - the fields are huge. Slide 20 entitled, "New Gas from
New Exploration Play Types" pictured oil and gas trapping
structures: anticline, normal fault, stratigraphic, and thrust
fault. Mr. Swanson advised that the more complicated structures
in Cook Inlet such as normal fault, stratigraphic, and thrust
fault, have not been explored for gas. Slide 21 entitled,
"'New' Gas in Existing Fields" illustrated discontinuous sands
that have not been tapped by the existing wells, such as those
found at the Beluga River gas field. Slide 22 was seismic data
from the northwest side of the basin which showed a very large
structure approximately two and one-half miles deep. Large
structures like this were easily found in the '60s, but the very
subtle plays in the footwalls of the folds of the large
structures have not been explored because of the expense.
7:52:21 AM
MR. SWANSON further explained what is unexplored in the basin
are the plays that are stratigraphically-controlled sand bodies
not found in a large structure. Their existence is detected by
USGS from seismic lines, features, and signs in the layers of
rock. Another very important part of the story is exploration
maturity. Slide 25 was a depiction of the exploration activity
in Wyoming compared to that of Prudhoe Bay. Wyoming has 70,000
exploration wells, Prudhoe Bay has 500, and Cook Inlet has 350;
thus the level of exploration in Alaska is miniscule compared
with other resource-rich areas. The tight level of exploration
that is seen in Wyoming resulted in a dramatic increase in its
proved reserves and additional gas produced from
"unconventional" continuous-type resources such as sands and
coalbed methane. Mr. Swanson stressed the key issue: To get to
a proven reserve requires significant investment to advance from
identified prospective resources. Hurdles to this process are:
the market; whether there is more than one commodity such as oil
and gas; and surface access to land. Slide 29 illustrated the
ownership of the land in the basin by several entities, and
closures due to Beluga habitat protection.
7:55:49 AM
CO-CHAIR PRUITT agreed that land ownership in the basin adds
complexity to exploration.
MR. SWANSON returned to the subject of field sizes. Slide 31
listed the field sizes for 22 units in Cook Inlet, ranging from
6 bcf to 2,425 bcf. A chart of Estimated Ultimate Recovery
(EUR) Field Size Distribution illustrated that fields which fall
between a range of 301-400 bcf and 1,100-1,200 bcf in size have
not yet been identified in Cook Inlet. In fact, USGS exactly
predicted a field size of 35 bcf as the most common occurrence,
and the chances of finding huge fields of 2-3 tcf are slim. Mr.
Swanson then turned to the price of natural gas by state. Slide
34 entitled, "2007 Average Gas Price to American Consumer"
showed that Alaska paid the lowest price for natural gas
nationwide in 2007 - Alaska consumers have been paying the
cheapest price for natural gas for the last 30 years - but this
changed when shale gas became available. During the period from
2007 to 2010, shale gas production tripled, imports were reduced
by 11 percent, and the use of shale gas increased from 5 percent
to 20 percent of the total volume used in the Lower 48.
Recently, the Henry hub price for natural gas was $2, and the
price now paid by Alaskans is similar to what is paid in the
Lower 48. In conclusion, he agreed with others that even though
understanding resources in the basin is complex, there is a lot
of undiscovered gas in the Cook Inlet basin; however, to access
gas will take a tremendous amount of work and economics will
come into play. He noted the next state lease sale is scheduled
for May, 2012.
7:59:41 AM
REPRESENTATIVE PETERSEN asked whether increasing demand and the
market by building a gas pipeline to Fairbanks and the refinery
at North Pole, would make a positive difference in the amount of
exploration.
MR. SWANSON suggested anytime there is an increase in demand and
a constant market, there will most likely be an increase in
exploration, but he could not say for sure.
REPRESENTATIVE PETERSEN recalled previous testimony that the
size and age of Cook Inlet should have led to two or three times
more drilling and, if so, more gas would have been produced.
MR. SWANSON observed that by 1968, 8.2 tcf of gas had been
discovered in Cook Inlet, but there was no market. Afterward,
the market was developed by the Agrium Inc., fertilizer plant,
liquefied natural gas (LNG) exports, and local demand, but
exploration efforts were turned to oil.
8:03:16 AM
REPRESENTATIVE SADDLER asked whether Cook Inlet basin is unique
in the world.
MR. SWANSON advised Cook Inlet basin is not unique, but is not
common either. It is a forearc basin, which means it is in
front of the volcanic arc and contains volcanic detritus. What
is relatively unusual is its thickness, which is all nonmarine.
8:04:08 AM
The committee took an at-ease from 8:04 a.m. to 8:06 a.m.
8:06:30 AM
TOM WALSH, Managing Partner, Petrotechnical Resources of Alaska
(PRA), stated PRA is an oil and gas consulting firm in Anchorage
which was commissioned in 2009 by ENSTAR, Chugach Electric, and
Anchorage Municipal Light & Power (ML&P), to study the remaining
Cook Inlet gas supply in existing fields. The purpose of the
study was to determine when there would be a shortfall in the
supply of gas. The study allowed the utilities to better
understand: the impact and drivers of drilling/development; the
results of an impending report by DNR; and when another source
of gas would be needed. In 2012, PRA updated the supply study.
Mr. Walsh returned to the 2009 study, and gave the reasons that
utilities care about gas supply: ENSTAR is 100 percent reliant
upon Cook Inlet gas for its consumption, which was 32.5 bcf in
2009; Chugach Electric is 90 percent reliant upon Cook Inlet gas
for its consumption, which was 26 bcf in 2009; and ML&P is 88
percent reliant upon Cook Inlet gas for its consumption, which
was 10.8 bcf in 2009. The total 2009 consumption by Cook Inlet
utilities was approximately 90 bcf of gas.
8:10:03 AM
REPRESENTATIVE TUCK recalled in 2010 Cook Inlet exploration was
incentivized by legislation, and pointed out that gas storage is
now available. He asked whether the utilities' concern dates
back to 2009, or is present today.
MR. WALSH advised the 2012 update was to the forecast; however,
the concern from 2009 remains today. Although there is gas
storage in the basin operated by the producers, and gas is
flowing into the reservoir, the issue is not resolved in the
long-term.
CO-CHAIR PRUITT clarified that gas is flowing into the
reservoir, but the system is not fully online.
MR. WALSH presented slide 4 entitled, "Cook Inlet Fields" which
was a map showing 2011 gas production. Major producers were:
Beluga River Unit, 27 percent; Trading Bay Unit (TBU), 21
percent; North Cook Inlet (No. CI), 13 percent; Ninilchik, 11
percent; Kenai Unit, 11 percent; and others, 15 percent. He
stated the study concentrated on producing assets - their
current production and history - in order to forecast their
future production. Slide 5 entitled, "2009 Combined Utility Met
and Unmet Gas Demand" illustrated the growing uncontracted
demand beginning in 2011, and increasing through 2019. Mr.
Walsh said this projection of "giant" unmet demand is a driver
for Cook Inlet gas development. Slide 6 entitled, "Annual
Supply - DNR 2009 Report" showed the historical gas production
from 1995 to 2010, which serviced not only local electrical
usage and heating demand, but also supplied exported LNG and the
Agrium plant. The PRA study primarily looked at the decline
curve analysis provided by DNR, focusing on the existing fields
and what the existing fields are producing. Exploration
potential or other future activities on the horizon were not
considered.
8:14:24 AM
MR. WALSH stated the objectives of the study:
· Review DNA reserve analysis: DNR conducted a comprehensive
geologic study, looking at the potential of what might
exist in the basin; however, PRA was looking at very short-
term supply options which could be brought online from
existing assets. The utility companies also asked PRA to
review and provide prospective to DNR's analysis.
· Review the deliverability of Cook Inlet gas wells drilled
from 2001-2009: PRA looked at how rapidly the wells have
declined to create a forecast for future production. The
consideration of well history is a standard means of
determining future production.
· Forecast deliverability of existing and future gas wells:
From the aforementioned review, PRA forecast the existing
well-set, what the wells could produce in the future, and
what could be recovered from drilling additional wells.
· Analyze timing required for delivery of non-Cook Inlet gas
sources: Bringing gas to Cook Inlet basin in order for the
utilities to continue to operate revolves around importing
LNG or obtaining gas from the North Slope.
8:16:02 AM
REPRESENTATIVE TUCK asked whether PRA's analysis shows how much
gas is available for consumers in Alaska, now that the Agrium
plant is no longer in operation and LNG is no longer exported.
MR. WALSH said yes, that is reflected in the decline of the
demand curve shown during the 2012-2013 timeframe. He continued
to slide 9 entitled, "Study Methodology" which indicated the
following:
· Field-level decline curve analysis: PRA looked at Alaska
Oil and Gas Conservation Commission (AOGCC) records of
production for gas fields which show what the fields have
produced on an annual basis, and from that projected
production and the remaining reserves for those fields.
· Individual well decline curve analysis on the five largest
fields: Studied to get a better feel for what could be
expected from new wells.
· New well initial production (IP) decline through time: PRA
looked at the decline curve analysis from individual wells
and predicted what new wells would contribute to future
production based on the acceleration of production from
existing assets.
· Calculate activity required to meet future demand: Sought
to determine the number of wells needed to be drilled every
year to continue to operate utilities.
· Plan of Development (POD) review: Studied the plan for
each field that deals with what development might occur to
ascertain what operators might be doing in the next year.
· Analysis of business drivers: Searched for what is driving
the producers to drill more wells and spend more money in
Cook Inlet basin.
8:20:32 AM
MR. WALSH displayed slide 10 entitled, "Cook Inlet Drilling
Results" and explained that the drilling results were split
into two periods to show whether there were changes in the
amount of gas discovered per well. From 2001-2009, 128 gas
wells were drilled and 105 were completed, of which initial
production was an average of 3.6 MMcf/d per well. From 2007-
2009, 34 wells were drilled and all were completed, and the
average production was 3.1 MMcf/d per well. This is significant
because as wells are drilled in a mature basin, less gas is
expected from each well, and the level of decline is factored
into the analysis.
REPRESENTATIVE PETERSEN surmised the areas where the new jack-up
rigs are drilling are areas where there is no current
production, thus would not be subject to the decline curve.
MR. WALSH said correct, successful exploration by the jack-up
rigs was not involved in this analysis.
REPRESENTATIVE TUCK referred to slide 10 and asked whether the
wells depicted there are new wells drilled into existing fields,
or wells drilled beyond existing fields.
MR. WALSH responded that these are new wells into existing,
producing fields. Some also represent production from intervals
that were not producing before, and some may intersect layers of
sediment that have not been produced, which would be virgin
pressures. However, most are infield wells drilled into
producing zones.
REPRESENTATIVE TUCK referred to slide 4, and asked whether the
existing fields are all attributed to the five major producers,
or whether the 15 percent produced by other companies is also
represented.
8:24:32 AM
MR. WALSH said the reported activity does include the 15 percent
of production by other companies. Slide 11 entitled, "Cook
Inlet Gas Development" illustrated the expected downward trend
in the number of cubic feet of gas produced by each well during
the 2001-2009 time period. Slide 12 entitled, "Cook Inlet Gas
Production Forecast from Decline Curve Analysis, PRA and DNR
2009 Studies" compared the results of the DNR and PRA studies.
Generally, forecasts from both studies are close; in fact, PRA
agrees with DNR in terms of what is expected to be produced from
existing assets. He said there were no discrepancies between
the studies and both found that - according to the 2009 data -
supply problems will arrive by 2013. The PRA study concluded
that significant new activity is required to keep production at
a level that will support the utilities in the future. Slide 14
entitled, "Annual Supply and Demand" indicated that the demand
forecast is about 90 bcf per year, and the supply forecast drops
below the demand forecast during 2013, which is the date the
utilities needed to know. The drop in the demand forecast from
2009 to 2011 is due to a reduction in LNG exports and the
closure of the Agrium plant, which, in turn, were due to the
disappearance of excess gas supply. Mr. Walsh pointed out the
Southcentral market for gas is too small to interest companies
such as ConocoPhillips, Marathon, and Chevron. The two drivers
for this commodity are cost and the size of the market, and
creating a larger market will attract interest.
8:30:37 AM
CO-CHAIR PRUITT asked for the potential effects of the loss of
the export market on exploration and production.
MR. WALSH advised that in the past the LNG export served as gas
storage, in terms of keeping gas wells flowing during low demand
from Southcentral. The export of LNG is a great anchor tenant,
and he opined the export of LNG may happen again in the future
if exploration is successful and gas can be stored during the
summer.
REPRESENTATIVE TUCK observed there will always be a field
consistently in decline. He asked how many wells have been
discovered from 2009-2012.
MR. WALSH said that information will follow.
REPRESENTATIVE TUCK heard previous testimony in 2009 from
Armstrong Oil Company that Cook Inlet fields are typical to
other fields, and that new wells will produce more gas. Since
the state has taken action to incentivize the exploration for
gas, he inquired as to whether there will be a proliferation of
drilling, as in Wyoming.
MR. WALSH answered that the major difference between Cook Inlet
gas and Wyoming gas is Wyoming's direct link to market via
pipelines; however, now there is too much gas for the market in
the Lower 48. Alaska's market is limited, and completely
disassociated with the Lower 48 market; in fact, the PRA study
revealed that a small market prevents large companies from
exploring and developing gas. The state's incentives for
exploration and production have brought jack-up rigs to Cook
Inlet, but the big issue is the market. Slide 15 entitled,
"Scenario in 2009 Study" indicated that if the current trends in
drilling success rates continue, an estimated 185 new wells must
be drilled between now and 2020 to meet the demand of the
utilities. Slide 16 entitled, "Cook Inlet Supply and Demand PRA
Forecast December 2009" indicated if there is development and
185 wells are drilled, the demand curve will be met to 2020.
Slide 17 entitled, "185 Wells Completed 2012 to 2019 Meet Demand
Through 2020" illustrated that no wells were completed in 2010
and 2011, thus an average number of 13.6 wells per year must be
drilled in the subsequent years. Mr. Walsh estimated the cost
of drilling and development to meet demand in the coming decade
is $1.9 billion $2.8 billion. Moreover, higher production costs
will lead to higher local prices for natural gas. The 2009
study also found that near-term drilling must be successful or
gas resources from outside the Cook Inlet could be required as
early as 2013; in fact, the only viable option is importing LNG.
He stressed that this is the bottom line - there is no other
means; however, the need to import LNG could be temporary
because the USGS and DNR have established that gas is available
in Cook Inlet. Slide 20 entitled, "2009 Summary" illustrated
the gap between the supply and demand, based on the decline
curve analysis by DNR and PRA.
8:42:28 AM
CO-CHAIR PRUITT clarified that the estimated cost of $1.9
billion to $2.8 billion in investment is only to meet the supply
of the Southcentral utilities, and does not include supplying
gas for LNG exports, Fairbanks, or Donlin Creek.
MR. WALSH said correct. Slide 22 began the 2012 update by PRA,
which was tasked by Cook Inlet utilities to look at the results
from the drilling campaign of the last three years and repeat
its forecast. The update found that due to drilling activity
and compression additions since 2009, the predicted shortfall
from existing fields has changed from 2013 to 2014. Slide 23
entitled, "Forecast Changes since 2009 Study" illustrated two
graphs that showed a slight increase in the supply forecast due
to investment in drilling activity and the added compression,
and a slight decrease in the demand forecast until Donlin Creek
comes online in 2019. Slide 24 entitled, "Changes in Supply
Forecast" showed the material increases in the supply forecast
were due to performance in wells mainly in the Beluga River,
Trading Bay, and Ninilchik Units where a total of eight new
wells have been drilled and compression has been added to bring
gas to pipeline pressure. Slide 25 entitled, "2009-2011
Drilling Activity and Production Adds" indicated that between
11/09 and 10/10 five new completions added 18.5 MMcf/d to
production, and between 11/10 and 10/11 six new completions
added 9.9 MMcf/d to production. Mr. Walsh concluded that
production from significant new wells pushed out the shortfall
to 2014. Turning to changes in the forecasted demand, he said
PRA expects reductions after the three or four final cargoes of
LNG in 2012, and because of a new, more efficient Chugach
Electric Association, Inc., (CEA) plant. Additional demand will
be for Homer Electric Association, Inc. (HEA), Matanuska
Electric Association (MEA), field fuel and flare, and the Donlin
Creek startup in 2019. Thus a shortfall of 7.3 bcf per year is
now predicted to occur in 2014. Slide 28 entitled,
"Sensitivity: Current Fields plus 3-4 New wells per year going
forward" indicated that even with three to four new wells
drilled each year in the next seven years - resulting in ten
MMcf/d of gas - there would still be a shortfall in 2014.
However, six to eight new wells per year pushes the shortfall
out to 2015.
8:48:54 AM
CO-CHAIR PRUITT questioned whether storage, although helpful
during periods of peak demand, will help meet the annual demand
of gas.
MR. WALSH explained the study "assumed perfect storage" which
means the study looks at annual averages of production, not peak
periods. As a matter of fact, Southcentral has come close to
not meeting peak demand already.
REPRESENTATIVE PETERSEN has heard that 10 to 12 new wells will
be drilled this year with more expected. He projected this
would push the shortfall to 2018.
MR. WALSH acknowledged that there is significant activity in the
basin; however, exploration activity is too far in the future to
boost production immediately. In the long-term, a multi-tcf
find would flood the market and exports would have to be
reopened. The study seeks development aspects in existing
assets.
CO-CHAIR PRUITT expressed his belief that the state's incentives
are to benefit assets outside of known areas and that have not
been previously explored.
8:53:04 AM
MR. WALSH said correct. In the short term, those activities are
beyond consideration by this report in that they will not help
the utilities in the next two to three years. Slide 30
entitled, "Summary of CI Shortfall Cases" indicated that
continuing with present production will result in a shortfall of
7.3 bcf per year beginning in 2014; adding 10 MMcf/d from new
wells will result in a shortfall of 1.0 bcf per year beginning
in 2014; adding an annual average of 20 MMcf/d from new wells
will result in a shortfall of 1.6 bcf per day beginning in 2015.
Mr. Walsh concluded that absent major new discoveries that can
be brought online in one to two years, the current pace of
development will mean a shortfall in Cook Inlet supply to meet
demand in 2014 or 2015.
CO-CHAIR PRUITT inferred that even with major successful new
finds, there will be a shortfall.
MR. WALSH said yes.
REPRESENTATIVE TUCK restated that the 185 wells referred to in
slide 15, and the production by the five majors in Mr. Walsh's
conclusion are in known fields, and are not new exploration,
thus are known. He returned attention to slide 6 and asked
whether the green tranche identified as "Geologic Analysis, PAY
Category Reserves" represents reserves from known fields.
MR. WALSH affirmed Representative Tuck's first statement. In
further response to Representative Tuck, he clarified that the
PRA study more closely aligns with the orange tranche,
identified as "Material Balance Analysis Reserves" representing
existing, producing assets. The DNR study indicated that the
reserves represented by the green tranche could be brought on in
existing assets, but PRA disagreed. However, he pointed out
that the operating companies have aggressively pursued all
opportunities to produce more gas from their existing assets.
CO-CHAIR PRUITT observed the green tranche is the difference
between the opinions of geologists and engineers.
MR. WALSH, speaking as a geophysicist, opined that there is more
gas in Cook Inlet but it may not be economical or online in time
to meet demand.
REPRESENTATIVE TUCK restated that the reserves in the green
tranche are known fields, and should be started with first.
REPRESENTATIVE SADDLER asked how to characterize the economic
impetus for more drilling in Cook Inlet, considering the current
relatively low prices for gas.
MR. WALSH said the study indicated that one of the business
drivers is the cost of the commodity, and suggested that
Southcentral's distinct, local, and small market must find
another way to attract companies. Higher prices for gas will
incentivize more development, but it is hard to use the export
of LNG to grow the market if there is no gas. Also, the recent
changes in the operators of Cook Inlet assets are a factor.
REPRESENTATIVE SADDLER asked whether the large demand for
manpower and equipment elsewhere will affect the quality and
rate of production by the companies in Cook Inlet.
MR. WALSH agreed that there has been a draw by the Lower 48 on
manpower and talent out of the state. However, this key factor
was not addressed in the study. In further response to
Representative Saddler, he said he was unable to assume whether
this factor would affect either way the rates of success or
effective, efficient drilling production by the companies.
REPRESENTATIVE PETERSEN directed attention to slide 5, and asked
whether the contracts currently approved and under consideration
by the Regulatory Commission of Alaska (RCA) are represented.
MR. WALSH said no.
REPRESENTATIVE PETERSEN recalled recent legislation granted 70
percent credits for the reimbursement of drilling costs, and
assumed that more companies will show an interest in exploring
Cook Inlet.
MR. WALSH related two companies are bringing in jack-up rigs,
and expressed his surprise that there was not more immediate
activity in response to the incentives.
9:04:32 AM
CO-CHAIR PRUITT referenced the cost of the investment needed to
continue the gas supply and asked whether the cost of gas will
stay the same for Southcentral consumers.
MR. WALSH advised gas commodity prices will definitely go up.
He suggested that consumers "benchmark" against the costs of
other realistic opportunities to bring gas to Cook Inlet, such
as a pipeline from the North Slope, or LNG imports. These
options will cost "significantly higher than what we are paying
for natural gas right now." However, the knowledge that higher
prices are coming will incentivize Cook Inlet exploration and
development because companies will not be competing against "$2
gas in the Lower 48."
9:06:28 AM
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Energy meeting was adjourned at 9:06 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Presentation - PRA CI Gas Study Alaska House Special Comm on Energy 4-11-12.pdf |
HENE 4/11/2012 7:00:00 AM |
|
| Presentation - House Energy 2012_DNR_DGGS_DOG.pdf |
HENE 4/11/2012 7:00:00 AM |