propane - for Petroleum News

Transcription

page Izzo says cost of bringing LNG to
4 Cook Inlet could kill spur line
Vol. 11, No. 53 • www.PetroleumNews.com
A weekly oil & gas newspaper based in Anchorage, Alaska
●
COURTESY NSSI
Coordinating North Slope science
Week of December 31, 2006 • $1.50
LAND & LEASING
DNR says no to Exxon
Rutherford: lessees had notice; ‘poor policy’ to certify nonexistent wells
By KRISTEN NELSON
Thomson unit in default for lack of an
approved plan of development.
The field’s owners, operator
he State of Alaska is continuing to
ExxonMobil Production, BP, Chevron
indicate it will kick start developand ConocoPhillips — along with a host
ment of the languishing Point
of smaller owners — have struggled to
Thomson field, with a denial of
find an economic way to develop the
reconsideration of the commissioner’s
high-pressure condensate field on the
decision issued Dec. 27 by acting
eastern edge of the state’s North Slope
Commissioner of Natural Resources MARTY RUTHERFORD lands. At one point the owners were
Marty Rutherford.
agreed on a gas cycling plan: oil would
For 30 years the poster child of failed attempts be produced from the condensate and the gas reby the state to get the owners to develop, the state injected. The recent brouhaha began when the
signaled the end of its patience in 2005 when Mark owners said gas cycling was not economic and that
Myers, former director of the Division of Oil and they would develop Point Thomson as part of
Gas, rejected a plan of development from operator
ExxonMobil Production and found the Point
see DNR page 15
Petroleum News
T
Following on the heels of the opening of tundra travel in the
coastal areas of state North Slope lands, the U.S. Bureau of Land
Management opened tundra travel in the NPR-A northeast planning area on Dec. 24. BLM had opened the NPR-A northwest
planning area on Dec. 13 — tundra travel stipulations for the
northwest planning area differ from those of the northeast planning area. BLM said that the required tundra travel conditions of
a 12-inch frost depth and an average snow depth of six inches in
northeast NPR-A have now been met.
“Therefore, tundra travel is open using low-ground-pressure
vehicles such as Rolligons, ARDCO, Trackmaster, Nodwell, or
similar types of vehicles as well as limited use of tractors
equipped with wide track for use in pulling trailers and sleighs,”
BLM said.
There’s no word yet on when state lands in the lower and
upper Brooks Range foothills will be opened. On Dec. 28, the
Alaska Department of Natural Resources confirmed both areas
remain closed due to insufficient frost and snow. The foothills
tundra opening requires nine inches of snow and a 23 degree
Fahrenheit soil temperature at a 30-centimeter depth.
—ALAN BAILEY
Mackenzie natural gas pipeline
project assailed from all sides
Proponents of the Mackenzie Gas Project have invested
about C$500 million in the venture so far, but a confluence of rising costs, weakening economics and aboriginal resistance that
has slowed down the regulatory process could still undo that
commitment, TransCanada Chief Executive Officer Hal Kvisle
has warned.
In a year-end interview he delivered one of the bleakest
assessments yet of the proposal to finally start shipping gas from
Canada’s Arctic region to southern markets.
see MAC GAS page 12
B R E A K I N G
N E W S
3 Trusts insist fight not over: Trust coalition entering federal
election arena, going directly to investors with C$10M campaign
5
Nuiqsut gas meters to be replaced: Conoco, North Slope
Borough, agree to install custody transfer units that meet AOGCC reqs
6 Failure to act could slow oil sands growth: Alberta utilities board calls for coordinated action plan to cushion impacts
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PIPELINES & DOWNSTREAM
TransCanada to TransBig?
Adds El Paso line, gas storage, solidifies N.A. ‘leading energy infrastructure’ role
By GARY PARK
El Paso unit ANR.
Operating largely through its master
limited partnership TC Pipelines,
TransCanada is picking up El Paso’s 50
percent stake in Great Lakes Gas
Transmission including 2,100 miles of
pipeline and 2.5 billion cubic feet per day
of storage.
TransCanada is already general partner
in Great Lakes and will take over the operator’s role from an El Paso-TransCanada
joint venture.
For Petroleum News
H
aving pulled off a long-rumored deal
by paying $3.4 billion, plus $670
million of assumed debt, for natural
gas pipeline and storage assets
owned by El Paso, TransCanada is making
no effort to hide its ambitions.
Hal Kvisle, chief executive officer of Hal Kvisle, CEO,
the Canadian energy powerhouse, said the TransCanada
acquisition solidifies his company’s role as
“the leading North American energy infrastructure”
company, making it the “dominant player” in conti- Company will have 40,000-mile network
nental gas transport.
Once the deal is concluded, TransCanada will
The purchase includes 10,500 miles of pipeline
see TRANSCANADA page 16
and 6.8 billion cubic feet per day of storage held by
●
NATURAL GAS
Propane demo in works
ANGDA: Proposal to truck 100 bpd from Prudhoe to Yukon River propane facility
By KRISTEN NELSON
Petroleum News
W
hile a gas pipeline from the
North Slope could directly
benefit communities along
the line such as Fairbanks —
or those in Southcentral via a spur
line — providing access to natural
gas for Alaska rural communities is a HAROLD HEINZE
challenge.
It’s a challenge the Alaska Natural Gas Pipeline
Authority has been looking at addressing with propane.
ANGDA Chief Executive Officer Harold Heinze told the
authority’s board Dec. 18 that if you compare piped gas to
propane, piped gas is more economic. “But in the case of
most of Alaska, we’re not going to have the opportunity for
see PROPANE page 14
JUDY PATRICK
Tundra travel opens in NE NPR-A
FORREST CRANE
Beth Lenart of the Alaska Department of Fish and Game and Ken
Taylor of NSSI collaring a young female musk ox as part of a study
to investigate the musk ox population decline. See story on page 7.
There are “tens of thousands” barrels per day
of propane re-injected at Prudhoe Bay.
2
PETROLEUM NEWS
contents
•
WEEK OF DECEMBER 31, 2006
Petroleum News A weekly oil & gas newspaper based in Anchorage, Alaska
ON THE COVER
11 U.S. weekly rig count rises by seven
DNR says no to Exxon
FINANCE & ECONOMY
Rutherford: lessees had notice of certified well
issue; “poor policy” to certify nonexistent
wells as capable of production
3
Going directly to investors in a C$10 million
campaign, coalition of energy trusts
is entering federal election arena
TransCanada to TransBig?
Adds El Paso line, gas storage, solidifies N.A.
“leading energy infrastructure” role
Propane demo in works
Energy trusts insist fight ‘not over’
GOVERNMENT
6
Failure to act could slow oil sands growth
Alberta Energy and Utilities Board calls for “coordinated
action plan” to cushion environmental,
infrastructure impacts of growth
ANGDA: Proposal to truck 100 bpd from
Prudhoe to Yukon River propane facility
Mackenzie project assailed from all sides
LAND & LEASING
Tundra travel opens in NE NPR-A
12 Potential Alaska state and federal oil and gas lease sales
ASSOCIATIONS
NATURAL GAS
10 Palmer vows to promote Alliance interests
4
LNG into Cook Inlet could kill spur line
EXPLORATION & PRODUCTION
5
Nuiqsut gas meters to be replaced
6
ConocoPhillips, North Slope Borough, agree
to install custody transfer meters that
meet AOGCC regulatory requirements
NWT, Yukon pay drilling price
5
7
Quoddy Bay project would be on Passamaquoddy
reservation; issue LNG tankers negotiating
passage off New Brunswick
NSSI: Coordinating North Slope science
New Alaska North Slope project database nearing
completion; GIS coordination depends
on funding from U.S. Congress
Maine-New Brunswick on collision course
11 Conoco advances on ultra low sulfur diesel for North Slope
11 Industry supports liquids pipeline from United States
WORKFORCE DEVELOPMENT
9
DEC report shows big issues looming
Alaska Department of Environmental Conservation
faces increasing costs, shrinking federal
funding; spill fund unsustainable
PETROLEUM NEWS
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•
F I N A N C E
3
&
E C O N O M Y
Energy trusts insist fight ‘not over’
Going directly to investors in a C$10 million campaign, coalition of energy trusts is entering federal election arena
By GARY PARK
For Petroleum News
C
anadian Finance Minister Jim
Flaherty issued an “end of story”
declaration Nov. 18.
Energy trust executives retaliated
with a vow to continue their fight, gambling C$10 million that they can yet win
the hearts and minds of Canadians and
force the federal government to revise its
plan to start taxing trusts in 2011.
In the process the trusts are taking the
unusual step, however much they deny it,
of entering the political arena as the federal political parties start grooming themselves for an election expected by spring
2007.
Operating through the Coalition of
Canadian Energy Trusts, which includes
31 royalty-generating trusts with a market
capitalization of C$100 billion, they are
pulling out all of the stops in a public campaign they plan to launch early in the New
Year.
Their resolve has been stiffened by
Flaherty’s refusal to offer any concessions
beyond the guidelines that allow trusts to
double in size during the transition period.
Government: decision
in country’s best interest
Flaherty infuriated some of the sector
leaders by telling lobbyists they are wasting their time pressing for an extension of
the 2011 deadline from four years to 10.
“I’ve been surprised that since Oct. 31
(when he announced an end to the trusts’
tax-free status) some people have entertained the notion that there might be any
extension whatsoever from four,” a bristling Flaherty told reporters in Vancouver.
“There will not be.”
He said business leaders have “uniformly” told him that the tax on trusts is a
necessary move.
To continue along the path of allowing
corporations to become trusts and shrink
revenue sources for various federal programs would turn Canada into a “couponclipping, passive economy. That’s just not
in the best interests of Canada,” he said.
Prime Minister Stephen Harper, in a
series of year-end interviews, said the trust
decision had been his toughest of 2006.
But he said that offering an energy
exemption at this stage would “turn into
exactly the problem we just got out of.”
Energy trust coalition: decision
not in country’s best interest
The energy trust coalition is just as certain that what the government has done is
not in Canada’s best interests.
When the battle resumes in January it
will have heavy political overtones.
The coalition points out that the bulk of
its millions of investors are in Ontario and
Canada, which represents a combined 60
percent of Canada’s population and are
thus the swing provinces in any election.
If the Harper administration is to form a
majority government it needs a decisive
victory over its three rival parties in the
heartland.
While coy about their tactics, coalition
leaders such as Gordon Kerr, chief executive officer of Enerplus Resource Fund,
told a conference call that when trust
investors start receiving the latest value of
their trust holdings in January they will see
clear proof of the “devastation created by
the government decision of Oct. 31 to end
the tax free status of trusts — they will feel
betrayed, as we do.”
Dielwart: changes could
erode retirement income
John Dielwart, chief executive officer
of ARC Energy Trust, said he is most
offended by the fact that Canadians are
“giving the government a free pass. We
want to put our case out there, if for nothing else than so it can be debated.”
He said the changes could erode retirement income for investors, produce higher
energy prices for consumers and have a
drastic impact on plans by some trusts to
deploy enhanced oil recovery technologies
to capture and store carbon dioxide.
“This is not just about taxes,” Dielwart
said. “It’s about the environment, personal
investments and Canada as an energy
leader.
“We believe that when Canadians learn
more about the issues that go beyond tax,
they will stand by our side.”
He said that once Flaherty tables legislation to implement the changes the bill
will face the parliamentary process, which
gives the coalition a chance to sway the
opposition parties.
If the legislation is defeated it could
trigger an early election.
Coalition plans to explain
role of trusts
Meanwhile, the coalition is rolling out
its heavy artillery to explain the role of
trusts in the oil and gas industry, accusing
the government of failing to understand
the sector’s importance to the Canadian
economy.
For openers, it has challenged government claims that energy trusts are a source
of lost tax revenues.
In a 100-page report, the coalition said
energy trusts pay more in taxes than conventional oil and gas companies that generate significant tax pools to pay for exploration and, as a result, end up paying little
in corporate taxes.
The report also said energy trusts have
paid more than C$35 billion to acquire
mature oil and gas assets over the past five
years and invested C$15 billion to develop
those properties that senior producers had
abandoned.
“We go back to those properties and we
squeeze them — we squeeze them hard,”
said Bill Andrew, chief executive officer of
Penn West Energy Trust.
Noting that trusts account for more than
one-fifth, or about 1 million barrels of oil
equivalent per day of Canada’s oil and gas
production, he warned that half of those
volumes could be lost if trusts were taxed
like regular companies, thus inhibiting
their ability to raise capital.
As well, the trusts repatriated C$10 billion worth of assets from foreign-controlled companies over the past 10 years,
many of which the coalition says are now
being aggressively optimized, while senior
producers have turned their attention to the
Alberta oil sands or outside Alberta altogether.
Coalition paper says chance could cost
10% of production
The coalition paper estimated that 30
percent of the tax revenue collected from
publicly traded oil and gas companies
came from the trust sector, which represented only 16 percent of the industry’s
total revenue.
It also pointed out that the 15 to 25 percent withholding taxes collected from foreign investors did not include any corresponding use of Canadian services or
infrastructure by those investors.
Should trust assets revert to foreign
ownership as a result of the tax changes,
the tax value would most likely leave
Canada in the form of deductible interest,
the coalition said.
The trust leaders said the net result
could be the loss of about 10 percent of
Canada’s oil and gas production, while as
much as 22 billion barrels of oil-in-place
(of which the U.S. experience shows 1530 percent could be recovered) that is a
candidate for enhanced oil recovery is at
risk.
Dielwart said EOR projects now being
developed by ARC and Penn West Energy
Trust that could remove 30,000 metric
tons per day of greenhouse gas emissions
through carbon sequestration are at risk
because the trusts will face higher costs of
capital if they rejoin the corporate ranks. ●
4
PETROLEUM NEWS
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N A T U R A L
•
G A S
LNG into Cook Inlet
could kill spur line
By KRISTEN NELSON
“Generally LNG delivered is going to be
at the same base price as utility prices in say
Chicago or something like that, so we would
be paying a relatively small premium (for
re-gasification) compared to Chicago,”
Heinze said, noting that for the eight or 10
years it would take to get a main line built
from the North Slope to connect with a spur
to Southcentral it might be worth it, as the
alternative would be converting furnaces to
diesel.
Petroleum News
T
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Industrials needed
Heinze has said industrial customers —
the current ones are the LNG plant and the
Agrium fertilizer plant — will be needed,
along with some gas going to Valdez, to support the cost of a spur line to Southcentral
Alaska (see story in Dec. 24 issue of
Petroleum News).
“I have continuously and will continue to
make the argument that while in the short
term it is difficult to understand our limited
gas resource in this area leaving the area, I
sure know that 10 years from now I’ve got
to have those people around or my bill to
heat my house is a lot bigger,” Heinze said.
Heinze told Sullivan it might be as much
as 75 cents per British thermal unit to regasify LNG at Kenai. That’s 75 cents in
addition to the delivered price.
And that delivered price would be comparable to Lower 48 prices.
RCA also a factor
JUDY PATRICK
he Alaska Natural Gas Development
Authority has had disquieting discussions about Cook Inlet natural gas supplies in the past and at a Dec. 18 board
meeting they got more unsettling news
about one possible stop-gap measure discussed in the past.
The subject was imported liquefied natural gas.
Board member Dan Sullivan, chair of the
Anchorage Assembly,
asked about the
export license for the
Kenai LNG plant,
which expires in 2009
if not renewed, and
about using the plant
to import LNG if that
export license is not
renewed.
ANGDA has been TONY IZZO
working on a spur line to bring gas into
Southcentral Alaska, but Sullivan said he
didn’t think customers cared where they got
their gas, as long as they got the cheapest gas
possible.
ANGDA Chief Executive Officer Harold
Heinze said as far as he knows
ConocoPhillips Alaska, operator of the LNG
plant, hasn’t made a business decision yet on
whether or not to apply for an extension of
the export license, but said he thinks the
company will have to show its hand sometime in the next quarter.
Tony Izzo, former president of Enstar
Natural Gas Co., the local gas distribution
company for Southcentral Alaska, said he
expects it would cost $300 million to convert the LNG facility to receive and re-gasify LNG.
That cost would go into the rates consumers pay, he said. And the Regulatory
Commission of Alaska would have to
approve that rate.
He said he doesn’t see imported LNG as
a short-term solution because of the costs to
convert the Kenai facility to receive and regasify LNG.
If the commitment was made to import
and re-gasify LNG and that $300 million
was spent, “It really does limit your ability
to then turn around two or three years later
and say let’s have a spur line,” Izzo said.
Consumers are going to pay 100 percent
of the spur line and if the cost for that line is
$1 billion, “that billion dollars and its debt
service” will be paid by consumers in their
gas bills.
If you had LNG going to Valdez, Izzo
said, you might cut that billion dollars in
half.
He said reliability is also “an important
component of service,” and asked if you
want all of your fuel on ships at sea. “It can
work; there are models around the globe that
show that can work. But for $200 million
more (than the $300 million — i.e. the half
a billion cost for a spur to Southcentral in
conjunction with a spur to Valdez), if you
tell me that I never have to worry about it
again because I’ll be connected by spur line,
one time payment,” that would be the way to
go, Izzo said.
Heinze said those are the kinds of realities that have made ANGDA “one of the
strongest advocates of encouraging exploration in Cook Inlet.” He said they are suggesting that the new administration look at
incentives for Cook Inlet exploration, so that
companies will look for and find new gas. ●
PETROLEUM NEWS
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•
N A T U R A L
5
G A S
Nuiqsut gas meters to be replaced
ConocoPhillips, North Slope Borough, agree to install custody transfer meters that meet AOGCC regulatory requirements
By KRISTEN NELSON
Petroleum News
T
he Alaska Oil and Gas Conservation Commission,
informed by ConocoPhillips Alaska at the end of
November that the company and the North Slope
Borough have agreed to install custody transfer
meters meeting petroleum measurement standards of the
American Petroleum Institute for the borough’s gas conditioning skid at Alpine, said Dec. 21 that it will review
ConocoPhillips’ plans for installation of the custody meters
before making a decision on the borough’s pending request
for a meter variance.
The borough and ConocoPhillips said at a Nov. 28 public hearing (see story in Dec. 3 issue of Petroleum News)
that the meters installed in the borough’s gas conditioning
skid at Alpine did not meet requirements in the commission’s regulations.
The borough said the design of its skid assumed custody
transfer and royalty measuring would be done upstream of
the Alpine conditioning facility. While the gas is provided
free of cost to Nuiqsut as a condition of the company having surface use of village lands for its facilities, royalties are
still paid and the State of Alaska (both the departments of
Natural Resources and Revenue commented on the proposal) was concerned about the accuracy of the meters for cal●
N A T U R A L
ConocoPhillips said it supports the borough’s
request for a variance, “but on a temporary
basis to cover the period between startup and
first shutdown.”
culation of the state’s royalties.
The borough is involved because it funded the gas
pipeline to the village.
David Hodges, the borough’s program manager for the
project, told the commission at the November hearing that
the difference in royalties as measured by the meters in the
skid and approved custody transfer meters would be in the
hundreds-of-dollars range per year, while replacing the
meters would cost $25,000 to $40,000 and — if the meters
were replaced now — could delay startup of gas until next
spring or summer. Nuiqsut, he told the commission, has
been waiting for gas for years.
Where meters will go subject
of engineering and design work
In its Nov. 30 letter to the commission, ConocoPhillips
said the borough and the company had further discussions
on the custody meters and agreed to the installation of custody transfer meters meeting the commission’s standards.
The company said the custody transfer meters would be
installed upstream of the borough’s gas conditioning skid or
at the outlet of the skid. “Additional engineering and design
work must be performed to determine which location will
work best,” the company said.
However, if startup of the Nuiqsut Natural Gas Pipeline
occurs before March 1, ConocoPhillips said it may not be
possible to install the new custody transfer meters prior to
start-up of the system. In that case the meters would be
installed during the first shutdown of the system, likely next
summer during the Alpine field’s annual maintenance turnaround.
ConocoPhillips said it supports the borough’s request for
a variance, “but on a temporary basis to cover the period
between startup and first shutdown.” It said the borough has
agreed to reimburse it for any additional royalty payments
resulting from meter uncertainty.
The commission said Dec. 21 that because circumstances have changed since the hearing it wants to review
ConocoPhillips’ proposed installation plans for the custody
transfer meters before making a decision on the borough’s
request for a meter variance.
ConocoPhillips and the borough have until Jan. 16 to
submit proposed plans for installation of the meters and the
departments of Natural Resources and Revenue have until
Jan. 22 to respond to the proposed plans. ●
G A S
Maine-New Brunswick on collision course
Quoddy Bay project would be on Passamaquoddy reservation; issue LNG tankers negotiating passage off New Brunswick
By GARY PARK
For Petroleum News
P
lans for two liquefied natural gas
terminals in Maine have entered the
regulatory process, setting the stage
for a showdown with opponents in
Canada.
Quoddy Bay LNG, an independent
Oklahoma-based energy company, made
its filing with the U.S. Federal Energy
Regulatory Commission in midDecember one year after initiating a prefiling process.
It plans to build and operate a 2 billion
cubic feet per day LNG import and
regasification
facility
at
the
Passamaquoddy Indian tribe’s reservation
in Maine’s Washington County, along
with a storage facility and 36 mile
pipeline to deliver natural gas from the
terminal to the Maritimes & Northeast
Pipeline.
The timetable calls for construction to
start within 12 months and the terminal to
start operations in 2011.
Downeast LNG came hard on Quoddy
Bay’s heels, filing for U.S. regulatory
approval on Dec. 22 to build a $500 million, 500 million cubic feet per day terminal.
Quoddy Bay President Donald Smith
said his project has reached an “important
milestone and is significantly closer to
providing the Northeast with environmentally clean natural gas.”
Shipping passage an issue
But it is another environmental issue
that has the project headed for a showdown that could reach the highest levels
of the U.S. and Canadian governments.
The New Brunswick and Canadian
governments have registered their concerns over the prospect of LNG tankers
negotiating a confined passage off New
Brunswick, the only access available to
Maine ports.
The clash has already ended in a diplo-
The New Brunswick and Canadian governments have registered their
concerns over the prospect of LNG tankers negotiating a confined
passage off New Brunswick, the only access available to Maine ports.
The clash has already ended in a diplomatic stalemate over who controls
navigation rights through Head Harbor passage between the Bay of
Fundy and Passamaquoddy Bay.
matic stalemate over who controls navigation rights through Head Harbor passage between the Bay of Fundy and
Passamaquoddy Bay.
Washington insists the passage is an
international waterway; Canada disputes
that claim, arguing the passage flows
through a channel created by Canadian
islands.
The U.S. has countered by contending
that even if the channel is an internal
waterway U.S. ships have right of passage under the International Law of the
Sea Treaty.
Canadian Prime Minister Stephen
Harper has joined the dispute, vowing to
take the fight to international courts if
necessary.
Downeast President Dean Girgis, a
former consultant for the World Bank on
LNG projects, said New Brunswick is
driven by its desire to fend off competitors to the Irving Oil-Repsol LNG plant
under construction in the province and
designed to ship gas into the U.S.
Northeast.
He told the Globe and Mail that elected officials and residents of Maine see
the disagreement as “purely an attempt
by the New Brunswick government to
protect the Irving turf.”
Turf issue vs. safety concerns
But federal politicians in both
see COLLISION page 6
6
PETROLEUM NEWS
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NWT, Yukon pay drilling price
Canada’s northern regions took one of the heaviest blows from the downturn in
drilling in 2006 when well completions for the first 11 months dropped 5 percent from
2005 to 21,334.
With the proposed natural gas pipelines from the Mackenzie Delta and North Slope
in a state of uncertainty, the Northwest Territories and the Yukon both paid a price.
The NWT logged three exploration and three development wells, just half of last
year’s total, while the Yukon was the only Canadian region to have no wells after completing two in the January-November period of 2005. Alberta recorded an 8.3 percent
decline to 16,010 reflecting the drop in shallow gas and coalbed methane drilling.
The only upside was a solid gain in deeper wells, with 800 wells reaching depths
of 10,000 feet and greater, a gain of 23 percent from 2005. Of the 254 rigs capable of
handling those targets, the utilization rate for the 11 months was 69 percent, compared
with 41 percent and 55 percent for the two shallowest formations.
Saskatchewan showed a solid increase of 3.7 percent to 3,543 well completions,
while British Columbia was up 1.5 percent to 1,273 wells and Manitoba surged by
almost 86 percent to 459 wells.
Bolstered by strong commodity prices, oil drilling was up 20 percent to 4,999
wells, including 792 completions in November — 365 in Saskatchewan, its best performance in two decades, and 354 in Alberta. Despite the volatility in gas prices, gas
wells still accounted for almost 13,800 completions, or close to 70 percent of the total.
The early statistics for the full year point to an average rig utilization of 63 percent
or 509 rigs, down from 71 percent in 2005 when 527 rigs of a smaller fleet were
active. The inactive rig count was 293, the highest in four years. Investment dealer
Peters & Co. forecast that drilling activity is unlikely to rebound until mid-January.
It is targeting a first-quarter utilization rate of 60-65 percent (or 510 to 533 rigs),
compared with the blistering 90 percent (688 rigs) in the same period of 2006.
—GARY PARK
•
G O V E R N M E N T
Failure to act could
slow oil sands growth
Alberta Energy and Utilities Board calls for ‘coordinated action
plan’ to cushion environmental, infrastructure impacts of growth
By GARY PARK
For Petroleum News
A
lberta’s energy regulator has taken
another chance to hammer home its
message to governments that unless
action is taken to handle oil sands
growth development could be in trouble.
For the second time in two months, the
Alberta Energy and Utilities Board called
for “sustainable long-term solutions” to
cushion the impact on the environment
and community infrastructure in giving
conditional approval to a C$12.8 billion
expansion of Shell Canada’s Athabasca
project.
A 124-page decision called for priority
attention to the “need for a coordinated
action plan and for accountabilities within that plan to assure the public that concrete action is being taken.”
Similar concerns were raised by the
board in November when it approved a
C$7 billion addition to Suncor Energy’s
operation.
At that time, the regulator said there
was only a “short window of opportunity” to provide the roads, health care, education and other infrastructure to accommodate rapid growth in the Fort
McMurray region and prepare for a possible C$120 billion of projects over the
next decade.
Stelmach puts services
at top of agenda
The message has apparently been
heard by the new Alberta government of
Premier Ed Stelmach, who put the provision of services at the top of the agenda
for his cabinet after his predecessor Ralph
Klein publicly admitted his administration had no plan to handle the frantic rate
of expansion.
The board, as part of a joint review
continued from page 5
COLLISION
Harper’s current Conservative government and the previous Liberal administration say that New Brunswick is driven
by the same safety concerns that have
blocked progress on other LNG projects
in the U.S.
Conservative Member of Parliament
Greg Thompson, a member of the federal cabinet, said the Head Harbor passage
is rated the most difficult to navigate on
the East Coast of Canada because it is
narrow, littered with rock outcrops and is
subject to fast-moving currents and
tides.
The tides are reflected in the Bay of
Fundy, which is believed to have the
with the Canadian government, said that
if public infrastructure investments are
“not made in parallel with continued oil
sands development, socio-economic
issues will become a critical part of the
decision-making regarding oil sands
applications.”
But the review panel rejected attempts
to stall project approvals for Athabasca
until services were in place to handle
industry and population growth.
Conditions imposed
However, the regulators imposed an
unusually long list of conditions.
It made 13 recommendations to the
Canadian government dealing with water
quantity, water quality and fish habitat
and the need for coordinated measures to
ensure the Wood Buffalo region of northeastern Alberta was able to service the
anticipated level of growth.
There were 21 recommendations to the
Alberta government urging coordinated
action by all levels of government to
ensure Wood Buffalo could service the
anticipated level of growth.
In the process, the panel turned down a
request by Albian Sands Energy, the
Athabasca partnership, to relocate a road
within the Athabasca River valley, to
build a 200-foot-wide pipeline corridor
and to build a 100-foot-wide corridor for
a power grid connection.
It was not convinced that the applicant
had shown the relocation of the highway
would maintain the Athabasca River’s
watershed, wildlife, recreation, ecological and traditional values.
Shell Canada still hopes to start work
early in 2007 on the expansion, which is
designed to boost production by 65 percent to 250,000 barrels per day and lay
the groundwork for its eventual goal of
500,000 bpd. ●
greatest difference between high and low
tides of any place in the world.
Thompson said Canada is not fundamentally opposed to LNG facilities that
serve U.S. markets, noting that there has
been support for other projects in New
Brunswick, Nova Scotia and Quebec.
The two projects also face a challenge
on their home front.
The Save Passamaquoddy Bay 3National Alliance believes neither has a
“chance of actually succeeding,” according to spokesman Bob Godfrey, who sent
an e-mail to the Bangor Daily News.
“Both have insurmountable obstacles,” he said.
The main State Planning Office has
also filed a motion to intervene, although
it is not necessarily opposed to the projects. ●
PETROLEUM NEWS
●
•
7
E X P L O R A T I O N
&
P R O D U C T I O N
NSSI: Coordinating North Slope science
New Alaska North Slope project database nearing completion; GIS coordination depends on funding from Congress
COURTESY NSSI
By ALAN BAILEY
Petroleum News
I
t’s been little more than a year since the
U.S. Energy Policy Act formalized the
existence of the North Slope Science
Initiative, an inter-agency effort to provide a consistent approach to high-caliber
science across the North Slope. And since
then NSSI has been moving ahead with its
role of facilitating a more coordinated
approach to scientific research in the region,
and acting as a clearinghouse for North
Slope scientific knowledge.
Ken Taylor, NSSI executive director,
explained to Petroleum News that NSSI
evolved from a research and monitoring
team established in 1998 to address environmental issues in northeast National
Petroleum Reserve-Alaska, as part of the
opening of that part of NPR-A for oil and
gas leasing. A recognition that a set of similar issues applied to more than just NPR-A
led to an interest in expanding the research
and monitoring area to encompass the
whole North Slope and adjacent offshore
regions.
In 2003 a group of interagency staff
began to design a working model for NSSI
and an NSSI oversight group was formed.
The oversight group consists of executive
leadership from the various federal, state
and municipal government agencies
involved in the North Slope. Arctic Slope
Regional Corp. is also represented.
The Bureau of Land Management contracted the design of a Web portal for the
initiative. The Altarum Institute carried out
an information needs assessment and the
Argonne National Labs prepared a draft science plan. And in 2004 members of the
NSSI group conducted workshops in
Anchorage, Fairbanks and Barrow to assess
the information needs of people with an
interest in the environmental science of the
North Slope.
Charter in 2004
The oversight group adopted an NSSI
charter in 2004 and in 2005 the U.S.
Congress formally recognized NSSI in the
Energy Policy Act. Taylor was appointed as
Beth Lenart of the Alaska Department of Fish and Game and Ken Taylor of NSSI collaring a
young female musk ox as part of a study to investigate the musk ox population decline.
executive director in 2005. In 2006 the secretary of the Interior appointed a science
and technical group, consisting of a multidisciplinary team of scientists who can provide technical advice to the oversight group.
So far, NSSI funding has come from the
government agencies involved in the oversight group.
“For the last two years most of the member agencies have pitched in a small portion
of the cost,” Taylor said. “BLM has covered
the brunt of the cost of what we’ve done to
date.”
President Bush’s 2007 budget includes
specific funding for NSSI but Congress has
not yet approved that budget, Taylor said.
Information needs identified from NSSI
workshops in 2004 drive some of the organization’s priorities. People attending those
workshops requested information about
what North Slope science is being done,
who is doing it and where it is being done,
Taylor said. People also wanted access to
scientific study results through a single
point of contact. And there was a strong
desire for a single geographic information
system (or GIS) to retrieve and display
mapped data about the North Slope.
“I think we count about 75 (geographic
information systems) right now,” Taylor
said.
For 2006 the oversight group also set
NSSI objectives to identify and prioritize
scientific information needs, and to coordinate scientific activities, to minimize duplication of effort.
Research priorities
So what are some of the scientific
research areas that NSSI is monitoring?
The impact of the oil and gas industry on
caribou sits high on the list of priority areas
and for the past few years NSSI has been
funding a study entitled “The Effects of
Oilfield Infrastructure on Caribou
Demography,
Distribution
and
Movements,” Taylor said.
Taylor said that the caribou calving
grounds have changed a little more in developed areas of the slope than in undeveloped
areas.
“The concern is that as these calving
areas move more and more towards the
foothills will predation increase?” Taylor
said. “… We are having a caribou workshop
scheduled for Feb. 21 and 22 in Fairbanks
to look at how the caribou herds are monitored, what research is going on related to
oil and gas development, what data gaps
might exist, look at all of the various stipulations.”
Taylor said that the conference will
assess the extent to which current permit
stipulations are science based and what
additional science might be needed in specifying stipulations.
Other wildlife research topics monitored
by NSSI include the disturbance of nesting
and molting waterfowl.
Water is also a major North Slope issue,
with relatively little hydrologic information
available. There are only three river water
gauging stations on the entire North Slope,
an area roughly the size of Utah, Taylor
said. Increasing the amount of data available would, for example, improve the accuracy with which flood predictions can be
made.
see NSSI page 8
8
PETROLEUM NEWS
ARCTIC POWER
NSSI
“So we’ve found funding to establish
four additional gauges in NPR-A,” Taylor
said.
Ongoing NSSI projects include the trial
use of robotic equipment for water quality
testing on the North Slope. That type of
equipment could greatly help in collecting
the baseline environmental data that are
essential to an understanding of industry
impacts.
Assessing the impact of the North Slope oil infrastructure on caribou is a priority research
topic for NSSI
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Water withdrawals
During the winter exploration season
companies draw water from lakes for ice
road construction. Although there are regulated limits on how much water can be withdrawn, NSSI would like to understand more
about the impact of water withdrawals.
“We have a limit on how much can be
pumped but until recently there hasn’t been
much science behind that limit,” Taylor
said. “We just know we’ve been doing it for
years — it seems to be working and the fish
are surviving, but it may be having some
other effects that we don’t know.”
NSSI is also interested in the issue of
where fish on the North Slope go during the
winter freeze up. Apparently artesian water
is common under the North Slope and some
fish winter at places where that artesian
water upwells in rivers.
Culverts used for stream crossings present another issue.
“It’s difficult to build a culvert battery
that’s (drill) rig capable but doesn’t cause
sedimentation scouring and allows the passage of fish,” Taylor said.
Taylor said that the Alaska Department
of Natural Resources has been monitoring
the condition of culverts on the North Slope
and has also been investigating new culvert
battery designs for possible use on the
slope.
The potential impact of oil spills is also a
major environmental concern, but NSSI has
not focused on that issue because several
government agencies are already doing so,
Taylor said.
Community impacts
The effect of the oil and gas infrastructure on traditional subsistence use areas of
the North Slope forms a topic of significant
concern. And, curiously, the impact of scientific research itself on the North Slope
communities is becoming an issue.
“One of our challenges is going to be
•
how do we keep the research community
from overwhelming the communities,”
Taylor said. “… That’s a real problem …
when you look at any development up there
and the requirements for scientific research
and monitoring that are placed on that
development. That equates to lots of helicopter flights, lots of fixed-wing flights,
people on the ground. It’s not insignificant.”
Offshore, Taylor sees a role for NSSI in
facilitating the use of vessel capacity for scientific research — vessel usage typically
adds major expense to offshore research.
“One of the critical pieces for offshore
research that’s missing on the North Slope
is vessel time and most of the vessels that
will be out there will be industry vessels,”
Taylor said. “I just think there’s a lot of
opportunity with all the work that’s going
on out there to collect some good science at
the same time.”
Projects database and GIS
Meantime, NSSI is forging ahead with a
key strategy of making scientific information more available to people.
A spreadsheet-based database with
information about science projects carried
out on the North Slope region is now available online at the NSSI Web site.
NSSI is in the final stages of converting
its database to work with projects database
software developed by the North Pacific
Research Board. The result will be a database with a slick user interface and greatly
improve search capabilities.
“This provides the first two things that
people want — who’s doing what and
where, and access to their information in
one place for current work,” Taylor said.
“That will be very useful I think in putting
together the environmental documents for
various agencies.”
Another NSSI objective, the development of a consolidated GIS for the North
Slope, will require substantial funding and
will depend on approval of NSSI funds in
the federal budget. The concept is to make
as much North Slope mapped data as possible accessible through a single computer
interface.
“We’ve been working with the
Geographic Information Network of Alaska
(or GINA) at the University of Alaska
Fairbanks to develop a system that could be
easily used by anyone who wants all of the
various GIS data layers,” Taylor said. Each
data layer would contain a specific type of
data, such as lands records, topographic
information or vegetation information.
NSSI has assembled an inventory of all
of the data layers that are potentially available from various government agencies.
Under the NSSI concept, each agency
would continue to maintain its data layers
but would make those layers available to the
GINA system.
“In order to make this work effectively
those (individual agency data layers) would
be invisibly linked to the GIS system, so
that when you were retrieving data from
GIS you would think that it was all residing
in that one place,” Taylor said.
A meeting of the NSSI science technical
group in 2006 also made recommendations
for including remote sensing data in the GIS
system. And Taylor thinks that GIS data
about the artesian water under the North
Slope would also be of considerable practical value — hitting pressurized artesian
water when, for example, placing pipeline
support members could wreak havoc with a
project, he said.
NSSI is also investigating the inclusion
of the North Slope residents’traditional ecological knowledge and cultural data into the
GIS data sets. Traditional and local knowledge forms part of the required environmental analysis under the National
Environmental Policy Act but this informasee NSSI page 9
PETROLEUM NEWS
●
•
9
W O R K F O R C E
D E V E L O P M E N T
DEC report shows big issues looming
Alaska Department of Environmental Conservation faces increasing costs, shrinking federal funding; spill fund unsustainable
THE ASSOCIATED PRESS
S
tate environmental regulators are facing increasing
costs and shrinking federal funding and a fund set
up to help prevent oil spills could be unsustainable
by 2009, according to a report by a transition team
for Gov. Sarah Palin.
The report notes areas within the Alaska Department
of Environmental Conservation needing immediate
attention as well as long-term
trends. It says, for example,
that 40 percent of the department’s employees will be
up for retirement in the
next five years.
The report was compiled by a team of 10 volunteers after a review of transition documents from former
Gov. Frank Murkowski and meetings
with department heads.
“They hit most things on the nose,” said Deputy
Commissioner Dan Easton, who served under
Murkowski and stayed on under Palin.
According to the report, the DEC sometimes is
“unable to fully engage its mission” because of a lack of
qualified personnel. To attract and keep necessary personnel, the department must offer competitive wages and
NSSI
tion is difficult to collect as part of a scientific study, Taylor said.
Continuing role
By providing access to comprehensive
research information Taylor sees initiatives
such as the projects database and the GIS
system bringing significant benefit to people doing North Slope environmental
assessments and other studies. And the
availability of good information should
feed through to better research and analysis.
“This information should help provide
some of the answers and hopefully will
result in better decisions,” Taylor said.
Taylor also sees the importance of the
NSSI facilitating role.
“I think the role of NSSI is really … to
help facilitate various issues by bringing
people together from the different agencies,
industry or academia that are knowledgeable,” Taylor said. “… There’s so much to
be gained by looking past your front door
to see what your neighbor’s doing.” ●
The DEC sometimes is “unable to fully engage
its mission” because of a lack of qualified
personnel. To attract and keep necessary
personnel, the department must offer
competitive wages and benefits.
—transition team report on DEC for Gov. Sarah Palin
benefits, the report says.
Federal funding agencies won’t
over overhead due to retirement benefits
Declining federal funding, which accounts for about a
third of department funding, will have a “significant”
impact on the department’s ability to do its job, the
report says. The reductions would have the greatest
impact on the divisions of water and environmental
health.
According to the report, federal funding agencies
refuse to accept the higher overhead costs the department needs to cover retirement benefits.
In light of shrinking federal support and the need for
competitive wages, the report says, “the potential for
dramatically increased fees is imminent.”
Easton said such challenges as the retirement obligation and the aging workforce, are not unique to the
Department of Environmental Conservation.
Fund issues specific to DEC
Specific to the department, however, is the Oil and
Hazardous Substance Release Prevention and Response
Fund, which is funded by a surcharge on oil production
and divided into accounts for spill prevention and emergency response. Despite a recent increase to the surcharge for spill prevention, the department expects
expenses to top revenues by fiscal year 2009, the report
says.
Needing immediate attention, according to the report,
is the cruise ship tax passed in August. Besides imposing
a $50 head tax on each cruise ship passenger, the new
law calls for the department to place an “ocean ranger”
on all large cruise vessels starting next summer.
Ocean rangers will be certified marine engineers who
are also knowledgeable of state wastewater discharge
programs, public health and sanitation.
“It’s kind of this multicolored person that you’re not
going to find,” said Charlie Boddy, one of two transition
team leaders for the department.
The report estimates that implementing the new law
will lead to a shortfall of at least $2 million. It recommends that the department work with state lawmakers,
industry representatives and the ballot measure sponsors
to find a solution. ●
10
●
PETROLEUM NEWS
•
A S S O C I A T I O N S
Palmer vows to promote Alliance interests
Natural gas pipeline development, oil exploration and production are top Alaska trade association leader’s priorities for 2007
By ROSE RAGSDALE
For Petroleum News
J
im Palmer, president of the Alaska
Support Industry Alliance, says he has
a few simple goals for his term as
leader of the state’s largest oil industry
support group.
“My plans are to support and promote
development in the state, particularly oil
and gas activities and mineral development,” Palmer said in a Dec. 7 interview.
In addition, the
Alliance supports its
membership, which
comprises 400 or so
companies
along
with individuals who
support the petroleum and minerals
mining industry as
opposed to the producers themselves, JIM PALMER
he said.
The major issue confronting the oil and
gas support industry in Alaska is obtaining
a pipeline to bring Alaska’s large gas
resources to market, according to Palmer.
“A gas transportation system would
open up a huge area for economic development in Alaska,” he said. “More gas
exploration activity, increased state revenues, potentially other industries spinning off because of access to a supply of
natural gas, and, hopefully, lower energy
costs here in the state would follow a gas
line’s development.”
The one advantage sometimes not spoken about is that once you have a gas
transportation
system,
The more we can explore
Coming soon the better. But we also
added Palmer, people will
actually go out and look
must remember that once
for and find much more
you find something, it
gas.
must be developed and
“It means an increase
produced. Ensuring and
in business and job opporenhancing the ability to
tunities. I think that the big
develop discoveries is critprize is the business and
ical, and whatever we can
job opportunities for
do to expedite responsible
Alaska businesses and
development should be
workers,” he said.
done.
“Secondly, we need to
“Personally, I think the
ensure that the oil sector
regulatory
reforms the
The Meet Alaska magazine
grows,” Palmer said. “If
Murkowski administration
will be available at the
2007 Meet Alaska conferyou look at oil production
put into place were benefience in Anchorage on Jan.
right now, it’s down below
cial. Certainly, many of us
19. This article is a reprint
a million barrels a day. We
believe the state permitting
from that magazine, which
was produced by
have two segments — the
and regulatory framework
Petroleum News under
base production, as I call
is functioning better now
contract with The Alliance.
it, Prudhoe Bay and
than it was in the past. I
Kuparuk. These fields
hope the new governor
must remain strong. At the
doesn’t change it so
same time, I believe we must encourage resource development becomes more difas much as we can the new producers, ficult again,” Palmer said. “Obviously, the
new explorers and new players that are tax debate last year was long and tedious.
coming to Alaska. These would include I certainly believe, and I think the Alliance
Pioneer Resources, which we are real does too, that since we’ve been through
excited about. With their Oooguruk proj- that debate, let’s see how this tax law
ect, they’ll be the first non-major to oper- works before making any additional
ate on the slope.”
changes. Let’s move on.”
As for the Alaska service sector, it is
Support for more exploration
always changing, according to Palmer.
“That’s just the nature of the competiThe Alliance also wants to encourage
tive
marketplace”.
more exploration.
“I understand that this year will be a
The more players, the better
fairly robust one for exploration on the
North Slope,” Palmer said. “That’s good.
Looking back 20 years, the early ‘80s
Register today at www.alaskaalliance.com
brought an oil boom to Alaska. Toward
the end of that decade, the state entered a
recession or depression, he recalled. In
the early 1990s, the industry went into a
phase of forming alliances to cut costs
and improve performance.
This effort yielded mixed results.
Some companies benefited, others did
not. Since then, many players and contractors downsized or left the state, while
others have expanded, Palmer observed.
The Alaska oil patch has changed from
this period.
“I think the producers, the explorers
and the people in the oil patch are always
looking for better ways of doing business.
The more players you have the better the
marketplace works.
“And the increased activity, hopefully,
will allow greater opportunities in the
market and greater success for Alaska
businesses and Alaska-based businesses.
And that is who makes up the Alliance
membership,” he added.
Palmer said the Alliance is ready and
willing to work with the Palin administration in whatever way it can to benefit the
state.
“Regardless of whom we voted for in
the general election, I think almost all
Alaskans are hoping our new governor
will do well and succeed, certainly in the
gas negotiations but in other areas as
well,” he said. “We’re all optimists at this
point, and we are supporting her and her
administration’s efforts regardless of
political persuasions. Hopefully, things
will go very well.” ●
PETROLEUM NEWS
●
•
11
P I P E L I N E S
&
D O W N S T R E A M
Conoco advances on
ultra low sulfur diesel
for Alaska North Slope
By ALAN BAILEY
Petroleum News
W
ith the clock ticking on the U.S.
Environmental
Protection
Agency’s mandated introduction
of ultra low sulfur diesel fuel,
ConocoPhillips has submitted permit
applications for the construction of an
ultra low sulfur diesel production facility
in the Kuparuk River unit on Alaska’s
North Slope. The new facility will produce diesel fuel for all of the industrial
operations on the North Slope and may
also produce fuel for North Slope communities.
EPA requires diesel powered vehicles
operating on the U.S. road system to transition in 2007 to low sulfur fuel containing 500 parts per million of sulfur and
then to fully convert to the use of 15 parts
per million ultra low sulfur diesel by
2010.
But EPA, recognizing the unique
issues situation in Alaska, granted rural
Alaska (those areas off the road and ferry
system) an exemption from the requirement to switch to low sulfur diesel in
2007. One key issue in Alaska is, for
example, the need for Arctic grade diesel
fuel that will not gel in frigid winter temperatures.
This need for ultra low sulfur Arctic
grade diesel poses issues for the North
Slope oil industry — currently the industry uses Arctic grade diesel refined in two
small-scale refineries known as topping
plants in the Prudhoe Bay and Kuparuk
oil fields.
Special North Slope deal
In June 2005 BP Exploration and
ConocoPhillips signed an agreement with
the State of Alaska for the transition to
ultra low sulfur diesel on the North Slope.
Under that agreement, the whole of the
North Slope, north of Atigun Pass in the
Brooks Range, is classified as rural,
under the terms of the EPA Alaska
exemption. In return for this flexibility in
interpreting the federal rules, the oil companies agreed to transition to the on-site
manufacture of ultra low sulfur diesel by
2008, two years ahead of the EPA mandated timeframe. Additionally, the companies agreed that after the transition all
North Slope diesel equipment would use
the new fuel, regardless of whether that
equipment was subject to EPA ultra low
sulfur diesel rules. And the producers
agreed to also require contractors to use
ultra low diesel and would sell excess
ultra low sulfur fuel to the North Slope
communities.
Construction plans
The oil companies plan to meet their
commitments by using the ultra low sulfur diesel facility that ConocoPhillips
proposes to build.
“ConocoPhillips has determined the
most economical and environmentally
safe method to comply with the regulation is to produce ULSD on the North
Slope,” the company said in its plan of
operation for a proposed ultra low diesel
facility. “Other alternatives investigated
were: importing from Alaska or Canada;
using gas-to-liquids fuel; and using compressed natural gas.”
ConocoPhillips is locating its new
ultra low sulfur diesel facility at the
Kuparuk field Central Processing Facility
3; the facility will strip sulfur from diesel
fuel produced by the existing North Slope
topping plants. The topping plan at
Kuparuk’s CPF 1 will form the main
diesel fuel source, with the untreated fuel
passing through a new pipeline between
the two central processing facility locations. The Prudhoe Bay topping plant will
produce additional diesel fuel for delivery
by truck for the new facility when fuel
demand is high.
Ultra low diesel fuel from the new
facility will pass through another new
pipeline to new diesel storage and distribution facilities at CPF 1.
The new sulfur-removal facility will
use hydrogen in a catalytic reaction that
will convert sulfur in the fuel to hydrogen
sulfide. A catalytic oxygenation process
will then convert the hydrogen sulfide to
solid sulfur. The sulfur will be formed
into cakes that can be ground and injected into an appropriate disposal well in the
Prudhoe Bay field.
Electrolysis of seawater
Hydrogen for the facility will come
from the electrolysis of seawater diverted
from CPF 1’s waterflood system, powered by two 3-kilovolt transformers connected to CPF 3’s electrical power system. Because the process requires pure
water, a reverse osmosis plant will filter
see DIESEL page 12
U.S. weekly rig count rises by seven
The number of rigs actively exploring for oil and natural gas in the United States
rose by seven the week ending Dec. 22 to 1,723.
Of the rigs running nationwide, 1,438 were exploring for natural gas and 279 for
oil, Houston-based Baker Hughes Inc. reported Dec. 22. Six were listed as miscellaneous.
A year ago, the rig count stood at 1,475.
Baker Hughes has tracked rig counts since 1944. The tally peaked at 4,530 in
1981, during the height of the oil boom. The industry posted several record lows in
1999, bottoming out at 488.
Of the major oil- and gas-producing states, Louisiana gained five rigs, Colorado
four, Oklahoma three and Texas one. Wyoming and New Mexico each declined by
three and Alaska was down one. California was unchanged.
—THE ASSOCIATED PRESS
Industry supports liquids pipeline from U.S.
Enbridge has received a green light to proceed with regulatory applications for its
proposed $1.3 billion Southern Lights condensate pipeline from the Chicago area to
Western Canada where the liquids are needed to facilitate transportation of heavy crude
from the oil sands.
The Canadian pipeline company assured itself of industry support from the
Canadian Association of Petroleum Producers by agreeing to step up development of
a $400 million light crude export line from Cromer, Manitoba to Clearbrook, Minn., to
ease bottlenecking on Enbridge’s existing network and add 45,000 barrels per day of
capacity to an existing line by late 2008.
That will precede the reversal of a 909 mile pipeline from Clearbrook to Edmonton,
Alberta, to open the way for 180,000 bpd of diluent to start flowing in 2010.
Regulatory approval is still needed in the U.S. and Canada for the diluent line which
Enbridge said is vital to support a tripling of Alberta oil sands production by 2015.
Without the Southern Lights project, Alberta faces a critical domestic shortage of
“adequate supplies of reasonably priced diluent,” although those liquids are relatively
plentiful in the U.S. Midwest and the Pacific basin.
Enbridge is still hopeful it will complete a 150,000 bpd pipeline to carry Pacific
region diluent from Kitimat, British Columbia, to Edmonton, although that project is
tied to its proposed Gateway project to ship 400,000 bpd from the oil sands to Asia and
California.
Because negotiations with Chinese refineries have bogged down, Enbridge has indicated that Gateway’s original start-up date of 2010 will be delayed to 2012 and possibly 2014.
For economic reasons, Enbridge prefers to build the two pipelines simultaneously,
but Chief Executive Officer Pat Daniel said recently a decision could be made in
the “next few months” to decouple the projects and build the diluent line sooner.
—GARY PARK
12
PETROLEUM NEWS
LAND & LEASING
MAC GAS
Potential Alaska state and federal oil and
gas lease sales
Agency
Sale and Area
Proposed Date
DNR
Alaska Peninsula Areawide
Feb. 28, 2007
DNR
North Slope Foothills Areawide
Feb. 28, 2007
MMS
Sale 202 Beaufort Sea
DNR
Cook Inlet Areawide
May 23, 2007
DNR
Beaufort Sea Areawide
October 2007
March 28, 2007
DNR
North Slope Areawide
MMS
Chukchi Sea
October 2007
BLM
NE NPR-A
BLM
NW NPR-A
DNR
February 2008
DNR
February 2008
DNR
Cook Inlet Areawide
DNR
DNR
DNR
February 2009
DNR
February 2009
DNR
Cook Inlet Areawide
DNR
October 2009
DNR
October 2009
MMS
2009
MMS
Sale 211 Cook Inlet
2009
DNR
February 2010
DNR
February 2010
DNR
Cook Inlet Areawide
DNR
October 2010
DNR
October 2010
MMS
Sale 212 Chukchi Sea
2010
MMS
2011
MMS
Sale 219 Cook Inlet
2011
MMS
Sale 221 Chukchi Sea
2012
November 2007
2007
2007
May 2008
October 2008
October 2008
May 2009
May 2010
Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, manages leasing in the National Petroleum Reserve-Alaska; DNR, Alaska Department of
Natural Resources, Division of Oil and Gas, manages state oil and gas lease sales onshore
and in state waters; MHT, Alaska Mental Health Trust Land Office, manages sales on trust
lands; MMS, U.S. Department of the Interior’s Minerals Management Service, Alaska
region outer continental shelf office, manages sales in federal waters offshore Alaska.
This week’s lease sale chart
sponsored by:
PGS Onshore, Inc.
“At some point, the Mackenzie project
gets just too complicated and it’s not worth
the grief to go ahead and do it,” he told the
Financial Post.
Kvisle said the issue Canada has to
resolve is figuring out a way to prevent the
project from “getting mired down and
bogged down in government policy and
other social issues.”
The National Energy Board wrapped up
almost a year of hearings in mid-December,
but parallel hearings by a Joint Review
Panel on environmental and socio-economic matters have become entangled in a land
claim by the Dene Tha First Nation of
Alberta, while the Deh Cho First Nations
are in the midst of tense negotiations with
the Canadian government over a land
claims settlement.
As well, there are unresolved concerns
in Northwest Territories aboriginal communities that are supporters of the project.
Meanwhile, the Mackenzie partners led
by Imperial Oil are updating their budget
which was last estimated at C$7.5 billion,
but has since been hit with inflation that is
expected to see the numbers climb well
above C$9 billion when they are disclosed
early in 2007.
TransCanada entered the project in mid2003 when it provided an C$80 million
loan to the Aboriginal Pipeline Group to
cover one-third of preliminary engineering
and environmental studies.
DIESEL
the salts from the seawater. The new
diesel storage and distribution facilities
at CPF 1 will require the addition of
new pumps, a 5,000-barrel surge tank
and a new truck loading rack to an
existing diesel distribution facility.
The two pipelines that transfer
untreated fuel to the sulfur-removal
facility and back from that facility to
the storage and distribution facility will
be 3 inches in diameter and run parallel
to each other alongside the seawater
pipeline that passes between CPF 3 and
CPF 1.
Pipeline construction will occur in
the winter of the first half of 2008 and
•
Kvisle said the issue Canada has to
resolve is figuring out a way to
prevent the project from “getting
mired down and bogged down in
government policy and other social
issues.”
If APG is able to arrange gas volumes
from independent producers it is eligible to
take a one-third ownership stake in the
Mackenzie pipeline.
The deal sets TransCanada up as the
leading contender to carry gas from the
Mackenzie Delta to northern Alberta, where
it would be expected to enter
TransCanada’s pipeline network.
In addition, TransCanada has an option
to buy 5 percent of the project and acquire
up to 50 percent of any portions offered for
sale by the four gas-producing partners –
Imperial (almost 70 percent owned by
ExxonMobil), ExxonMobil Canada, Shell
Canada and ConocoPhillips Canada.
Kvisle said his company has been working with the partnership to use new pipeline
construction technologies, such as welding
practices TransCanada has tested with BP,
to reduce overall costs by eliminating
pricey safety testing methods.
He indicated that avoiding hydrostatic
testing could trim C$100 million from the
budget.
But Kvisle made no effort to disguise his
concern about the complexity of the
Mackenzie project from a technical, regulatory, political and social standpoint.
—GARY PARK
The new (Kuparuk) facility will
produce diesel fuel for all of the
industrial operations on the
North Slope and may also
produce fuel for North Slope
communities.
will require an ice road.
ConocoPhillips expects to start offsite module construction and some onsite facility work in 2007. The sulfurremoval plant modules, electrical
transformers and new surge tank will
arrive by sealift in August 2008. Other
equipment will be trucked to the North
Slope in March 2008, and the new
facility should go into operation in
December 2008. ●
•
13
Companies involved in Alaska and northern
Canada’s oil and gas industry
ADVERTISER
PAGE AD APPEARS
A
Ace Transport
Acuren USA (formerly Canspec Group)
Aeromed
ACS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Agrium. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Air Liquide
Air Logistics of Alaska
Alaska Air Cargo
Alaska Anvil
Alaska Coverall
Alaska Dreams
Alaska Frontier Constructors
Alaska Interstate Construction
Alaska Marine Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Alaska Railroad Corp.
Alaska Rubber & Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Alaska Steel Co.
Alaska Telecom
Alaska Tent & Tarp
Alaska Textiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Alaska West Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Alliance, The . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
American Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Arctic Controls
Arctic Foundations
Arctic Slope Telephone Assoc. Co-op.
Arctic Structures
Arctic Wire Rope & Supply
ASRC Energy Services
Engineering & Technology
Operations & Maintenance
Pipeline Power & Communications
Regulatory and Technical Services
Avalon Development
B-F
Badger Productions
Baker Hughes
Bombay Deluxe Restaurant
Bond, Stephens & Johnson
Broadway Signs
Brooks Range Supply
Capital Office Systems
Carlile Transportation Services
Chiulista Camp Services
Computing Alternatives
CN Aquatrain
Coldwell Bankers
Colville
CONAM Construction
ConocoPhillips Alaska
Construction Machinery Industrial
Contract Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Coremongers
Crowley Alaska
Cruz Construction
Dowland-Bach Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Doyon Drilling
Doyon LTD
Doyon Universal Services
Egli Air Haul
Engineered Fire and Safety
ENSR Alaska
Epoch Well Services
ESS Support Services Worldwide
Evergreen Helicopters of Alaska
Fairweather Companies, The . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Flint Hills Resources
Flowline Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Friends of Pets
Frontier Flying Service
G-M
Grainger Industrial Supply
Great Northern Engineering
Great Northwest
Hawk Consultants
H.C. Price
Hilton Anchorage
Holaday-Parks
Horizon Well Logging
Hotel Captain Cook
Hunter 3-D
ADVERTISER
Business Spotlight
PAGE AD APPEARS
Industrial Project Services
Inspirations
Jackovich Industrial & Construction Supply
Judy Patrick Photography
Kenai Aviation
Kenworth Alaska
Kuukpik Arctic Catering
Kuukpik/Veritas
Kuukpik - LCMF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Last Frontier Air Ventures
Lounsbury & Associates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Lynden Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Lynden Air Freight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Lynden Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Lynden International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Lynden Logistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Lynden Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Mapmakers of Alaska
Marathon Oil
Marketing Solutions
Mayflower Catering
MI Swaco
MWH
MRO Sales
N-P
Nabors Alaska Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
NANA/Colt Engineering
Natco Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Nature Conservancy, The
NEI Fluid Technology
NMS Employee Leasing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Nordic Calista
North Slope Telecom
Northern Air Cargo
Northern Transportation Co.
Northland Wood Products
Northwest Technical Services
Offshore Divers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Oilfield Improvements
Oilfield Transport
P.A. Lawrence
Pacific Power Products
PDC Harris Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Peak Oilfield Service Co.
Penco
Petroleum Equipment & Services. . . . . . . . . . . . . . . . . . . . . . . 3
Petrotechnical Resources of Alaska. . . . . . . . . . . . . . . . . . . . 15
PGS Onshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
ProComm Alaska
Prudhoe Bay Shop & Storage
PTI Group
Q-Z
QUADCO
Rain for Rent. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Residential Mortgage
Salt + Light Creative
Schlumberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Seekins Ford
Spenard Builders Supply
STEELFAB
3M Alaska
Tire Distribution Systems (TDS) . . . . . . . . . . . . . . . . . . . . . . . . 4
Total Safety U.S. Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
TOTE
Totem Equipment & Supply . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Tubular Solutions Alaska
UAA Department of Engineering
Udelhoven Oilfield Systems Services . . . . . . . . . . . . . . . . . . . 3
Unique Machine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Unitech
Univar USA
Usibelli
U.S. Bearings and Drives
VECO
Welding Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
WesternGeco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Xtel International
XTO Energy
All of the companies listed above advertise on a regular basis
with Petroleum News
SUSAN CRANE
PETROLEUM NEWS
Sam Egli, Director of Operations
and Chief Pilot
Egli Air Haul
Inc. (EAH)
Egli Air Haul began operating in
1979 in Utah and moved to Bristol Bay,
Alaska in 1982. Since then EAH’s operation has expanded to six planes,
including a Bell 206B Jet Ranger helicopter. Services include air taxi, aerial
survey, tours, sport fishing and hunting,
search and rescue, aerial photography
and mail (even hauling Eskimo pies to
Eskimos, says Sam Egli). With the helicopter, EAH supports heli-fishing, heliskiing, movie filming, sling-loads and
aerial game management.
Sam Egli’s hobbies are flying and
photography, although he’s been
known to liven standby time strumming his banjo or guitar. Two of Sam
and Glenda’s children live in Idaho, and
the third is a mill operator and soon-tobe helicopter pilot living in Fairbanks.
The company supports no less than
12 civic organizations.
14
PROPANE
a piped gas supply.”
If you could reach Alaska coastal and
river communities with propane — in addition to those you could reach with a pipeline
— “you in essence touch 99 percent of the
population of Alaska,” he said.
“We’ve now made them part and parcel
of the North Slope energy issues.”
A lot is known about the cost of pipeline
transportation and the cost of extracting
propane from gas.
“What we don’t know about is how, in a
rural setting, we’re going to move the
propane around,” specifically on the Yukon
and Kuskokwim rivers, Heinze said.
He described a demonstration project
that would get the authority a piece of information it doesn’t now have — the cost of
providing propane to small rural communities on Alaska’s major river systems.
Yukon River propane plant
The long-term goal would be propane
extraction from a line moving gas to market
from the North Slope.
A mixture of propane and some ethane
and butane could be separated as a liquid
from a small side stream of the pipeline gas
using a small gas plant, Heinze said in a
paper describing the project. The cost
would be modest, he said, and residue gas
would be returned to the line.
The transportation cost for the gas would
PETROLEUM NEWS
be low since the Yukon River is close to
Prudhoe Bay — and “transportation cost is
the dominant part of gas value,” he said,
estimating that the Yukon River location
would yield a 30 to 50 percent discount.
Because rural Alaska now uses diesel, an
oil-based and more expensive fuel, gasbased fuel — traditionally lower priced than
oil — could provide a “significant opportunity for a new base energy price in rural
Interior Alaska.”
What rural Interior Alaska faces now, he
said, is a combination of high oil prices,
“long tenuous transportation systems —
basically you’re hauling it up from the
mouth (of the rivers) and then you’re making deliveries to … communities that are
not very big.” Add annual storage costs to
that and the economics are not good, he
said.
The propane would not replace diesel for
all purposes: power plants may run on
diesel. “On the other hand, why are you
using diesel or electricity to heat hot water?
That’s a natural task for propane,” Heinze
said.
PND Inc. Consulting Engineers completed a feasibility study on propane distribution in coastal Alaska for the authority in
August 2005. The report, available on the
authority’s
Web
site
(www.angda.state.ak.us/), focused on logistics, required infrastructure and economics
of propane distribution in coastal Alaska.
The study found that the most efficient
method of distributing significant amounts
of propane in rural Alaska would be through
the expanded use of ISO propane containers.
Heinze said the PND study also found
that “in almost every case (the report looked
at eight communities around Alaska) … it
was a better fuel for cooking and hot water
heating, but not necessarily for home heating and certainly not for electricity.”
100 barrels per day for test
Heinze said the demonstration project
would truck 100 barrels per day of propane
from an existing Prudhoe Bay facility side
stream to a wholesale propane facility at the
Yukon River highway crossing point, which
would also have “a multi-capability loading
system at the river level.” There are “tens of
thousands” of barrels per day of propane reinjected at Prudhoe Bay, he said, but if 100
bpd of propane could not be obtained from
Prudhoe facilities, the North Pole Flint Hills
refinery may be an alternate source of
propane.
Heinze said when he talked to BP about
the idea he wanted to get it on the table. “All
I asked them to do was to think about it, in
consultation with field operating people”
who know the places where propane is fractionated, and “whether there were any side
streams we could get to without creating
major havoc or expense.”
He said he doesn’t want to have to construct a facility to get at the propane for this
test. “Technically what I’m arguing is in the
course of working with the gas and making
miscible injectant and doing a number of
different tasks, you end up with fractionated
streams, one of which has got to look like
the kind of propane I want. And just find it,
drill a hole, put the valve in, and I’ll leave
you alone,” he said.
Flint Hills is a fall back. “The front end
of a refinery generally pops a little bit of
propane out.”
Heinze said he didn’t know the exact situation at the Flint Hills refinery, “but 100
barrels a day out of that refinery might be
doable,” although 100 bpd might also be a
large part of the propane Flint Hills gets,
while on the North Slope 50,000 to 60,000
bpd of propane is re-injected daily, so “asking for 100 barrels, this is not a big deal,” he
said.
About 1/20th of what would be
required for entire state
The 100 bpd of propane would be about
a tenth of what would be required on the
Yukon-Kuskokwim river system in the
longer term, and maybe one-twentieth of
what would be required in the state.
•
“The stakes we’re playing for are probably in the range of 5,000 to 10,000 barrels a
day of propane statewide, so this is in that
sense quite a small experiment,” Heinze
said.
The experiment is designed “to tell us
about the one thing we just don’t know
much about: What does it cost to reach the
smaller communities with propane?”
We know what it costs to move propane
on the highway system and can get a handle
on barging to communities, he said.
“The thing we don’t know anything
about is how to reach hundreds of small villages up and down the Yukon River. And …
what are they going to do with it, how are
they going to distribute it in their communities and how much does all that cost?”
Heinze said.
A few communities would be selected
for the demonstration project and propane
would be tested for a range of conversions
from fuel oil (water heating and home heating) and reduction in electrical power
demand (cooking, water heating and light).
Among the variables tested would be
alternative local storage facilities, local distribution systems and appliance design, he
said.
ANGDA would look for test sponsor
Heinze told the board that he doesn’t
envision ANGDA paying for the project,
although it could provide a little seed
money “to just advance the definition of the
project” and try to get it started. He said it
would require $10 million to $15 million
over several years to test, analyze and evaluate the feasibility and economic potential
of a river-based propane distribution system.
Costs would include: subsidizing
propane pricing at the Yukon to make it
equivalent to costs when the main gas line
feeds a small plant at the river; loans or
grants to communities for propane transportation and storage facilities; loans or
grants to participating consumers for home
storage, piping, appliance conversion and
new appliance purchase; and loans, grants
or guarantees to participating distribution
businesses.
Heinze said Nels Anderson, appointed
by Gov. Frank Murkowski as Alaska energy
advisor, has reviewed the project and
“strongly embraced” it. The Denali
Commission was interested in the proposal
as part of its ongoing federal investment in
rural energy.
He said he presented the proposal to BP
— operator of the Prudhoe Bay field — and
asked the company about the availability of
a facility connection for propane loading to
trucks and also presented it to the
Association of Alaska Native Corporations
Presidents and CEOs.
All interested parties would be involved
Heinze said he wants to meet with all
interested parties and also thinks an informational hearing before the Alaska
Legislature during this session “is essential
if a program is to get under way in the summer of 2007.”
“I have every reason to believe that both
rural legislators, the Native corporations
and a number of the regional community
organizations involved on the YukonKuskokwim will really like this idea. They
are caught in a horrible squeeze right now
of the high fuel prices, very little relief
potentially in sight and difficult logistical
issues. … This is at least something that …
offers hope,” he said.
Board Vice-Chairman Scott Heyworth
said Heinze pitched the idea to Gov. Sarah
Palin in early December and Heyworth
thought the governor was interested.
Heinze said the idea didn’t get thrown
out of the room in the meeting with the govsee PROPANE page 16
PETROLEUM NEWS
•
15
DNR
North Slope gas commercialization.
POD rejected
It was at this point that Myers rejected
a proposed plan of development and
declared the unit in default.
But a change in leadership at the
Department of Natural Resources in the
fall of 2005, and continuing negotiations
over a gas pipeline fiscal contract between
the administration of former Gov. Frank
Murkowski and the major North Slope gas
holders, BP, ConocoPhillips and
ExxonMobil, led to extensions of the
appeal from Myers’ decision by a new
DNR commissioner, Mike Menge.
The inability of the administration to
get legislative approval for the contract,
and Murkowski’s defeat in the primary,
finally triggered Menge’s Nov. 27 decision terminated the unit.
ExxonMobil and ConocoPhillips
requested reconsideration of the unit termination, and a finding by Menge on
wells certified capable of production in
the unit by previous directors of the
Division of Oil and Gas. Menge said that
because these were exploration wells
which had been plugged and abandoned
they were not capable of production.
Wells certified capable of production are
the basis for holding leases, although the
state requires plans for those leases — or
in this case, for the unit of which the leases are a part.
Reconsideration request denied
Rutherford denied requests for reconsideration of the Nov. 27 decision by
Menge terminating the Point Thomson
unit and affirmed the decision “in all
respects.”
“The facts clearly uphold Mike
Menge’s decision to terminate the Point
Thomson unit agreement,” Rutherford
said in a statement. “I agree that
ExxonMobil has not met its obligations,
and I must deny them the relief they
sought in their reconsideration request.”
ConocoPhillips and ExxonMobil
requested reversal of the finding that the
Point Thomson unit contains no wells certified as capable of producing in paying
quantities and reversal of the decision to
terminate the unit.
The companies also claimed they did
not receive fair notice that certified well
status was an issue and contended that the
department refused to allow them to
review its files.
On the certified well issue, Rutherford
said lessees had notice of the certified well
issue and said both ExxonMobil and the
Exxon sues state in Superior Court
As expected, Exxon Mobil Corp. is suing the Alaska Department of Natural
Resources over the department’s decision to terminate the Point Thomson unit.
Exxon’s Dec. 22 appeal in Alaska Superior Court, 3AN-06-13751, asks for
reversal of all respects of the commissioner’s Nov. 27 decision, “or in the alternative to remand the matter to the commissioner with instructions to make a new and
different decision.”
In its statement of points on appeal, ExxonMobil, the Point Thomson unit operator, said it intends to rely on a number of points.
The company said the commissioner erred in disapproving the plan of development and in affirming the director’s decision, and called the decisions “an abuse
of discretion … entirely unsupported by the evidence in the record.”
The company said the correct legal standard for a unit operator is the reasonable prudent operator, “which means the exercise of reasonable diligence to develop the hydrocarbon resources, giving consideration to the interests of both the
working interest owners … and the mineral owner” without requiring the working
interest owners “to follow a course that would not be economic for them.”
The company said the commissioner considered only the interests of the state
and failed to consider the interests of the working interest owners.
Alaska Gasline Port Authority cited the
issue in appeal paperwork.
“Lessees do not on reconsideration
challenge the grounds for unit termination” in the Nov. 27 decision, which were
“unwillingness to commit to put the unit
into production” and failure to submit an
appropriate plan of development.
“Instead, the focus of reconsideration is
the collateral finding that the PTU does
not contain wells certified as capable of
producing in paying quantities.”
Rutherford: certification of wells
that don’t exist ‘poor policy’
On the contention “that the certified well
finding is bad policy because it will generate uncertainty in the oil and gas industry,”
Rutherford said the decision was about the
Point Thomson unit, not about leases and
not about any other unit.
“Certification of a well that does not
exist as capable of producing in paying
quantities is poor policy,” Rutherford said.
“DNR does not need to certify a non-existent well in order to extend the term of a
lease. There are other much more appropriate ways to extend the term of a lease. The
other leases and units that lessees are concerned about will be administered based on
the facts applicable to them, and not the
facts applicable to the PTU.”
Rutherford said that the department does
not contest that the commissioner’s decision
reverses’ longstanding decisions by directors of the Division of Oil and Gas certifying plugged and abandoned wells. But, she
said, the DNR commissioner “has the ultimate authority to set DNR policy,” this is
the first time the well certification issue has
reached the commissioner’s office and the
commission “has the responsibility to correct poor policy. Certification of a non-exis-
tent well is poor policy not just because the
well cannot be ordered into production but
because it sends the wrong message to state
oil and gas lessees.” The lessees “interpret
the certification of a well as an indefinite
extension of the lease upon which it was
drilled. This is not an appropriate policy,”
Rutherford said.
“The agreements, regulations and
statutes provide for lease extension where a
lessee makes appropriate commitment to
explore, produce or other wise develop oil
and gas leases.”
On a claim that they were denied access
to department files, Rutherford said that on
the afternoon of Sept. 14 an ExxonMobil
representative requested to review 105 files
the following morning. On Sept. 15 the
department sent the company a letter asking
for the document request in writing;
ExxonMobil did not respond. “Lessees’
assertion is not supported by the facts,” she
said.
Grounds for unit termination
Rutherford discussed two grounds for
DNR to terminate the unit.
“Certification of a well that does
not exist as capable of producing
in paying quantities is poor policy.
DNR does not need to certify a
non-existent well in order to
extend the term of a lease. There
are other much more appropriate
ways to extend the term of a
lease.” —Marty Rutherford, acting
DNR commissioner
“DNR is entitled to terminate the unit
because the purpose of forming a unit is to
effect production,” she said, and while
Point Thomson has been known for more
than 30 years “to contain massive hydrocarbon reserves” it has never been put into
production and the lessees “unequivocally
state that they still cannot find a way to put
the unit into production.”
“Units are not formed for the purpose
of simply holding properties until such
time as the lessees think production will
be profitable enough to commence. On
these facts, when the lessees say they cannot put the unit into production, DNR can
terminate the unit as a matter of law.”
The second primary ground for unit
termination is the failure to submit an
acceptable plan of development,
Rutherford said. The director’s Oct. 27,
2005, decision put the lessees on notice
that the 22nd plan of development was
unacceptable and they had nearly a year to
submit an acceptable plan “that committed
to put the unit into production. Instead
they submitted a revised 22nd POD which
suffered from the same defects as the original 22nd POD,” Rutherford said, noting
that the reasons the plan was not acceptable were discussed in the director’s decision.
The department said the Point
Thomson unit covered 45 leases on
approximately 106,000 acres of state land
just west of ANWR. It holds an estimated
300 million barrels of oil and natural gas
condensates and 8 trillion to 9 trillion
cubic feet of natural gas. ●
16
PETROLEUM NEWS
TRANSCANADA
have a pipeline network covering almost
40,000 miles, offering its customers “unparalleled connections from traditional and
emerging supply basins to growing North
American markets” by covering the region
from the Texas Panhandle and Louisiana
coast to Michigan, while Great Lakes ties
Western Canada in with the same Upper
Midwest U.S. markets, Kvisle said.
He described the acquisition as a
“unique opportunity to invest in regulated
natural gas pipeline and storage assets that
are a strong fit with our existing North
American footprint.”
“These are high-quality assets that will
strengthen our position as a leader in the
North American gas transmission business
and deliver significant value to our shareholders.”
In addition, Kvisle said, the El Paso
assets will complement TransCanada’s
expanding portfolio of energy infrastructure assets that include power generation
holdings that range from a wind farm in
Quebec to a 47 percent holding in
Ontario’s Bruce nuclear power facility.
The company is also involved in two
proposed liquefied natural gas projects,
one in Quebec and the other off Rhode
Island.
Kvisle was enticed by the ANR holdings because of the volumes of LNG coming into the Gulf Coast and the natural gas
crossing the Rockies.
For El Paso, the restructuring is a
chance to use $3.3 billion of after-tax proceeds to slash its debt of $14.5 billion in
hopes of regaining an investment-grade
rating.
El Paso Chief Executive Officer Doug
Foshee described the sale as a “transformational event” that will allow his company to preserve its earnings outlook as
North America’s largest interstate gas
pipeline franchise, with about 43,000
miles of pipelines.
It will remain the dominant supplier to
the U.S. West and East coasts via four
pipeline systems.
TransCanada will have close to 12% of
North American gas storage
TransCanada said the deal will grow its
gas storage capacity to 360 billion cubic
feet, or close to 12 percent of the North
American market, with the prospect of
adding 100 billion cubic feet through
expansions.
“We would see growth of that storage
business or optimization of the operation
of it as the big value-driver for us,” Kvisle
said.
“In North America less and less gas is
flowing to industrial demand, which typically operates on a 24/7 basis, and more
and more is flowing to power generation,
which operates a little more sporadically
depending on demand for power and that’s
a real upside with our ability to meet that
kind of evolving market in the Great lakes
region.”
The Reason for Our Success
Nabors Alaska Drilling recognizes that our employees are
an important reason for our success.
Thanks to their commitment to safety,operational excellence
and the environment, we continue to be the premier drilling
contractor in Alaska today.
•
He was not troubled by the addition of
cross-border pipeline capacity at a time
analysts are warning of a decline in the gas
volumes that will be available for export
from Western Canada.
“We see things flat to slightly declining,
but the amount of the decline is relatively
modest,” he said.
Gas storage used by
producers to get best price
Given the wild fluctuations in gas
prices over the last 18 months, producers
are turning to storage to hold gas off the
market until prices climb.
TransCanada, operating like a broker,
collects a fee for gas in storage and is
counting on those fees rising as it adds to
storage.
Russ
Girling,
president
of
TransCanada’s pipeline business, said storage capacity is becoming increasingly
valuable in North America in response to
widening summer-winter natural gas price
differentials.
TransCanada, which has been on a
growth path since 1999, was helped in the
deal by the Canadian government’s plan to
start taxing income trusts.
Since the trust decision Oct. 31,
investors have turned to companies such as
TransCanada, which pays a large dividend,
and have helped push the company’s share
value up by about 10 percent over the past
two months.
William Lacey, a FirstEnergy Capital
analyst, told the Globe and Mail that
TransCanada’s access to capital has benefited from a “flight” by investors to bluechip companies. ●
PROPANE
ernor and he thinks the idea “will receive a
very favorable hearing from the
Legislature” and that there are “several
major grantors of money” who would be
interested in the project.
ANGDA wouldn’t run program
Marvin Rogers, Toolpusher
nabors.com
He said he does not envision ANGDA
running this program, although it would
remain involved, and might consider
investment in key wholesale and transportation facilities.
Heinze reminded the board that in one
of the propane studies ANGDA did, “we hit
upon this idea of having transportation and
storage vessels that were tanks that were
the same size, shape, form basically as ISO
containers, the inter-modal type containers
that you find all over Alaska, scattered
everywhere.”
The idea is that the tanks would go full
to the community and be exchanged for the
empties that would be taken away and
refilled.
And those ISO containers could be
made in Alaska, “anyplace that has a fabrication yard, even a small fabrication yard”
because “it’s not high-pressure welding, it’s
very low-pressure, steel-plate welding,” he
said.
With a standardized design and fittings
“you could make them all over Alaska” and
there could be interest-free loans to start
that business in the communities that make
them.
Board Chairman Andy Warwick asked
what it would take to kick the program off.
Heinze said it would take getting the
interested parties together to hammer out
the details so you can go after the needed
money.
If people are really interested, “I have
reason to believe there’s people out there
that will take this idea and move it forward.
I think we’ve got to go find them,” Heinze
said. ●

propane - for Petroleum News

Transcription

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