no deal with siemens - petroleum news · 2019. 4. 12. · igu purchased pentex natural gas co.,...
TRANSCRIPT
The Explorers, an annual publication from Petroleum News
ExplorersThe
Oil & gas companies
investing in Alaska’s future
ExplorersOil & gas
companies investing in
Alaska’s future
Hilcorp aims for lower Cook Inletdrilling; inlet 3-D survey delayed
page7
l E X P L O R AT I O N & P R O D U C T I O N
l U T I L I T I E S
l P I P E L I N E S & D O W N S T R E A M
Vol. 24, No. 15 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of April 14, 2019 • $2.50
Final rate potential estimated at3,800 barrels per day for Pikka B
In an April 4 update, Oil Search said its first of two North
Slope wells and their sidetracks this winter was a resounding
success. The Pikka B/Pikka B ST1 appraisal well flowed at a
stabilized rate of 2,410 barrels of oil per day, its flow restrict-
ed by the capacity of the testing equipment. (In a presentation
on Feb. 18, Oil Search said the well “has intersected the thick-
est Nanushuk reservoir seen in the field,”)
The Pikka B ST1 was spud Jan. 23 at the southern end of
the Pikka unit, its target the Cretaceous Brookian Nanushuk
formation with the objective to assist defining potential
resource volumes and reservoir deliverability in the unit.
All coring, wireline and pressure data acquisition was com-
see PIKKA SUCCESS page 12
Jade gets final OK from state for Sourdough development plan
Jade Energy LLC received its final approval from the state
Division of Oil and Gas on April 4 for its Sourdough plan of
development in the Point Thomson unit where the Alaska-based
independent is scheduled to drill a well in early 2020.
Sourdough is an untapped oil discovery on state land next to
the border of the ANWR 1002 area, a narrow strip of coastline set
aside for potential development by Congress because of its
hydrocarbon-rich geology.
The Sourdough lease and its two mid-1990’s BP discovery
wells lie in the Eastern North Slope’s Point Thomson unit, or
PTU.
In November 2018, as part of a farm-out agreement, PTU
see JADE APPROVAL page 13
RCA moves toward electric systemprogress report to Legislature
The Regulatory Commission of Alaska is entering the clos-
ing stages of preparing a report to the state Legislature on the
status of achieving a more unified mode of operation for the
Alaska Railbelt electrical system. Following a directive from
the Legislature, in 2015 the commission issued recommenda-
tions for a more unified approach to the operation of the sys-
tem. The commission now wants to inform the Legislature of
what has happened in the past four years, potentially with sug-
gestions on what to do next.
The Railbelt system is owned and operated by six inde-
pendent utilities and the state. This balkanization of the sys-
tem leads to inefficiencies that cause the price of electricity to
see RCA REPORT page 10
Alberta ‘at the crossroads’; withdifferent strategies proposed
The people of Alberta have repeatedly been hearing over the
last month the message that seems to echo through election cam-
paigns everywhere.
Their province, they are told, is “at the crossroads.”
Only this time the dire time-worn message is on the mark.
After five years of experiencing an economic tailspin, dragged
down by the collapse of oil prices, their inability to gain access to
world prices in Asia and a pullback from Alberta’s lifeline oil
sands sector, they are faced with a debt that has soared from C$12
billion in 2015 to an estimated C$71 billion by the end of the cur-
rent fiscal year.
Accustomed to decades of leading Canada in every positive
category — employment, budget surpluses, capital investment,
see ALBERTA CROSSROADS page 15
Another CI oil field?Hilcorp looks to new development from North Cook Inlet Tyonek platform
By ALAN BAILEYPetroleum News
Hilcorp Alaska has prepared an initial develop-
ment plan for a known oil pool below the
North Cook Inlet gas field. Drilling of the first
development well from the offshore Tyonek plat-
form should happen in 2020, the company told
Alaska’s Division of Oil and Gas in the 2019 plan
of development for the North Cook Inlet unit.
The Tyonek platform currently supports pro-
duction from the gas field. Because the oil devel-
opment well will penetrate the top of the structure
of the Sterling and Beluga gas sands, the well will
also enable an evaluation of remaining dry gas
development in the unit, the company told the
division.
In the early 1990s ARCO discovered oil in a
major geologic anticline under the gas field. In
1998 Phillips Petroleum conducted some appraisal
drilling in the oil accumulation, termed Tyonek
Deep. Although the company applied for a right of
way for an oil pipeline from the Tyonek platform
to the west side of the Cook Inlet, in 1999 the com-
pany put the project on hold, saying that viability
required higher oil prices. At that stage the compa-
No deal with SiemensIGU board votes to terminate MOU for negotiations over potential LNG supply
By ALAN BAILEYPetroleum News
The board of the Interior Gas Utility has opted
to end negotiations with Siemens over a pos-
sible supply of liquefied natural gas that Siemens
had proposed for the Fairbanks utility. During its
April 9 meeting, the board passed a resolution by
five votes to two to cancel a memorandum of
understanding with Siemens, under which the
negotiations were taking place. Board members
Patrice Lee and Mary Norland voted against the
resolution.
As part of the Alaska Industrial Development
and Export Authority’s Interior Energy Project,
IGU purchased Pentex Natural Gas Co., including
its subsidiaries Fairbanks Natural Gas and the
Titan LNG plant near Point Mackenzie on Cook
Inlet. The consequence is the establishment of IGU
as a single, consolidated gas utility for the
Fairbanks region of the Alaska Interior. The con-
cept is to greatly expand the availability of natural
gas in the region, as an affordable means of heating
buildings, and to alleviate severe air pollution
New pipeline playerFirst Nations prepare possible bid for majority stake in Trans Mountain pipeline
By GARY PARKFor Petroleum News
Canadian First Nations have wasted no time
seizing on a federal government invitation for
indigenous communities to enter discussions and
possibly negotiations to take a 51 percent owner-
ship stake in the existing and expanded Trans
Mountain heavy crude pipeline.
No sooner had Finance Minister Bill Morneau
unveiled the principles for indigenous participa-
tion in the planned 890,000 barrels per day trans-
portation link from Alberta to the Pacific Coast
than a First Nations-led group declared its interest
in buying a 51 percent share.
All First Nations in British Columbia, Alberta
and Saskatchewan have been invited to join the
C$6.8 billion expansion, which would raise Trans
Mountain’s value to about C$13 billion.
The bid is being assembled by Delbert Wapass,
former chief of the Thunderchild First Nation in
Saskatchewan and current vice-chairman of the
Indian Resource Council, which looks for opportu-
see TYONEK PLATFORM page 14
see SIEMENS DEAL page 11
see PIPELINE PLAYER page 12
In preparation for reviving the oil fielddevelopment Hilcorp has now laid most ofa new subsea oil pipeline from the Tyonek
platform to the Inlet’s west side.
In October the IGU board agreed on theMOU with Siemens that would enable
confidential negotiations over thespecifics of the Siemens plan.
Despite the enlistment of leaders fromseveral leaders of oil and gas investmentsby indigenous communities, many First
Nations will not be swayed by theinitiative.
2 PETROLEUM NEWS • WEEK OF APRIL 14, 2019
GOVERNMENT
EXPLORATION & PRODUCTION
FINANCE & ECONOMY
LAND & LEASING
PIPELINES & DOWNSTREAM
7 Hilcorp aims to drill in lower Cook Inlet
11 NSIDC reports on winter sea ice conditions
2 EIA: March US crude at 12.1 million bpd
Short-term for April says Brent at $66 per barrel in March, up$2 from February, expected to average $65 in ’19, $62 in 2020
3 French appeals AOGCC decisions
Former chair argued scope of commission’s authority when he was on the commission; if appeal denied, Superior Court next step
ENVIRONMENT & SAFETY
EXPLORERS PREVIEW
Another CI oil field?Hilcorp looks to new development from Inlet Tyonek platform
No deal with Siemens IGU board votes to terminate MOU on potential LNG supply
New pipeline playerFirst Nations prepare possible bid for stake in Trans Mountain
ON THE COVER
Final rate potential estimated at3,800 barrels per day for Pikka B
Jade gets final OK from statefor Sourdough development planRCA moves toward electric systemprogress report to LegislatureAlberta ‘at the crossroads’; withdifferent strategies proposed
Petroleum News Alaska’s source for oil and gas newscontents
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EIA: March US crude at 12.1 million bpdShort-term for April says Brent at $66 per barrel in March, up $2 from February, expected to average $65 this year, $62 in 2020
By KRISTEN NELSONPetroleum News
U.S. crude oil production continues trending up, but
the Brent spot price is expected to average $65 per
barrel this year, down from $71 per barrel in 2018, the
U.S. Energy Information Administration said in its latest
Short-Term Energy Outlook, released April 9.
“In the April outlook, EIA increased its forecast for
U.S. crude oil production in 2019 and 2020 even after
lowering its forecast for Gulf of Mexico production,”
said EIA Administrator Dr. Linda Capuano. “Strong
growth out of Texas and New Mexico is largely behind
growing U.S. crude oil production, which continues to
be on pace to set new production records in three consec-
utive years.”
Commenting on the forecast for U.S. retail gasoline
prices, expected to “average $2.76 per gallon this sum-
mer, which is down from $2.85 per gallon in 2018,”
Capuano said, “The lower average
price in 2019 tracks with EIA’s
forecast for decreased crude oil
prices.”
PricesBrent averaged $66 per barrel in
March, EIA said, up $2 from
February, but for the first quarter of
the year Brent averaged $63 per
barrel, $4 per barrel lower than the
first quarter of 2018.
Despite lower Brent prices than last year at this time,
March prices were $9 per barrel higher than December,
“marking the largest December-to-March price increase
since December 2011 to March 2012,” EIA said.
Recent price drivers include increasing crude oil sup-
ply disruptions and voluntary reductions by members of
the Organization of the Petroleum Exporting Countries,
the agency said, noting that recent prolonged power out-
ages in Venezuela have “directly resulted in reduced
crude oil production and exports” from that country.
There have also been mixed economic indicator sig-
nals recently, “increasing uncertainty regarding the
future direction of oil prices.”
Brent is forecast to average $65 per barrel this year
and $62 in 2019, compared to a 2017 average of $71 per
barrel, with West Texas Intermediate expected to average
$8 lower than Brent in the first half of the year, with the
discount gradually falling to $4 per barrel in late 2019
and through 2020, the agency said.
US crudeEstimated U.S. crude oil production for March, 12.1
million barrels per day, is up 300,000 bpd from February.
EIA said it is forecasting that U.S. crude oil production
see EIA OUTLOOK page 4
LINDA CAPUANO
6 US drilling rig count gains 19 to 1,025
4 Kenai Pipe Line modifications proposed
6 CIRCAC has website, webinar on pipelines
6 State publishes notice for spring lease sales
10 AOGCC approves PBU injection commingling
By KRISTEN NELSONPetroleum News
When Hollis French was a commis-
sioner and chair of the Alaska Oil
and Gas Conservation Commission he
disagreed with the other two commission-
ers on the scope of the commission’s
authority.
In the findings of fact for a hearing on
whether the governor had grounds to dis-
miss French, the hearing officer noted
that French “was persistent and energetic
in pursuing his view that the jurisdiction
of the AOGCC was being interpreted
more narrowly than he believed that the
enabling statutes intended.” The hearing
officer said French attempted to secure a
written response from the Department of
Law “as to whether his legal reasoning
had merit, and conducted his own
research and issued writings of his own
supporting his point of view.”
French arranged a conference with the
Attorney General and other members of
the Department of Law to argue for his
point of view and wrote to then-Gov. Bill
Walker to state his position. The hearing
officer said the other two commissioners
wrote a rebuttal.
Gov. Mike Dunleavy ultimately
removed French for cause on Feb. 26
(see story in March 3 issue of Petroleum
News), citing causes other than French’s
disagreement with the other commis-
sioners on the commission’s scope of
authority.
Petitions for hearingsOn Feb. 28, French wrote to the com-
mission, requesting hearings on com-
plaints of waste, one concerning a fuel
gas leak from an 8-inch line in Cook Inlet
in 2017, the other concerning a gas leak
from a North Slope well, DS02-03B,
which also occurred in 2017. In both
cases, French requested that a hearing be
scheduled. “At the hearing, I will be urg-
ing the commission to take action upon
this complaint,” he said in both letters.
On March 1, the commission denied
both requests.
Cook Inlet fuel gasIn the case of the
fuel line gas leak in
Cook Inlet, the com-
mission said it
“investigated the
leak at the time it
occurred.” Initially
AOGCC believed
the source was
“upstream gas, i.e., gas which remained
an AOGCC-regulated resource and had
not been metered and severed from the
property.” Had that been the case, the
commission said in a March 20 ruling on
French’s petition, “the leak would have
constituted waste and AOGCC would
have instituted an enforcement action
against Hilcorp.”
The commission said its investigation
determined the leaking gas had been pur-
chased from a third-party provider and
was being shipped back to Platform A.
“The primary purpose behind the pro-
hibition against waste is to maximize
resource recovery,” the commission said,
and its regulatory authority “like every
other state’s oil and gas conservation reg-
ulatory authority,” is to regulate waste
upstream, before oil or gas is metered and
severed from the property, “in connection
with drilling, exploration, and production
activities. Neither AOGCC nor any of its
counterparts in other states has ever
attempted to extend its jurisdiction over
waste to gas which has been sold by a
vendor.”
In an April 8 appeal of the commis-
sion’s decision, French said the gas lost in
the inlet was a waste and said the com-
mission’s job was “to ‘protect the public
interest in Alaska’s valuable oil and gas
resources.’”
As for the commission’s position that
its authority ends once oil or gas is
metered, he said: “The law says that the
agency’s authority extends statewide.”
“If the Legislature had wanted the
agency’s jurisdiction to end at the meter,
it would have said so in a statute,” French
said, and went on to say that AOGCC’s
“interpretation of its own statute short-
changes the public, by cutting off the
agency’s power far short of what the
Legislature enacted.”
Prudhoe gas On French’s petition for a hearing on
gas from the DS02-03B well, the com-
mission denied the request for a hearing
and said: “The circumstances surround-
ing the release of gas from the DS02-03B
well are the subject of an on-going
AOGCC investigation. A hearing prior to
the conclusion of that investigation would
be premature.”
In his April 8 appeal, French argued
that the commission had a duty to hold a
hearing, citing Alaska statute, which says:
“On the filing of a petition concerning a
matter within the jurisdiction of the com-
mission under this chapter, the commis-
sion shall promptly fix a date for a hear-
ing, and shall cause notice of the hearing
to be given.”
He said “the agency claims to be
investigating the same incident” at the
DS02-03b, but said the commission
appeared to be referring to a docket on
the mechanical integrity of Prudhoe Bay
wells, and “seems to be implying that this
petition is repetitive of matters being con-
sidered in another docket.”
French asked to be notified of a hear-
ing on that well which concerns “wasted
gas.”
“Either way, under either docket, the
commission must schedule a hearing on
this incident of waste. Failing to do so
would be an abuse of the commission’s
discretion.”
The commission has 10 days to grant
or refuse the application for reconsidera-
tion. Failure to act is a denial. Appeal is to
the Alaska Superior Court. l
l G O V E R N M E N T
French appeals AOGCC decisionsFormer chair argued scope of commission’s authority when he was on the commission; if appeal denied, Superior Court next step
PETROLEUM NEWS • WEEK OF APRIL 14, 2019 3
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In an April 8 appeal of thecommission’s decision, French said
the gas lost in the inlet was awaste and said the commission’sjob was “to ‘protect the public
interest in Alaska’s valuable oiland gas resources.’”
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4 PETROLEUM NEWS • WEEK OF APRIL 14, 2019
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6180 Electron DriveAnchorage, AK 99518
will average 12.4 million bpd this year
and 13.1 million bpd in 2020, with
most of that production growth coming
from the Permian region of Texas and
New Mexico.
U.S. Lower 48 onshore crude pro-
duction is forecast to average 10.5 mil-
lion bpd in 2020, more than 200,000
bpd above its March forecast, EIA said.
“The higher crude oil production is
the result of both higher forecast prices
in 2019 that have a lagged effect on
production and of data updates that
increased drilling levels in the Permian
Basin,” the agency said.
Gulf of Mexico offshore crude pro-
duction is forecast to average 2.1 mil-
lion bpd in 2020, almost 200,000 bpd
below the March forecast. The net
effect of the changes is a forecast up
100,000 bpd from March.
Natural gasThe Henry Hub natural gas spot
price averaged $2.95 per million British
thermal units in March, up 26 cents
from February, as a result of colder-
than-normal temperatures across much
of the U.S., EIA said, which increased
the use of natural gas for space heating.
Henry Hub is projected to average
$2.82 per million Btu this year, down
33 cents from 2018; the forecasted
2020 price is $2.77.
Dry natural gas production is fore-
cast to average 91 billion cubic feet per
day this year, up 7.6 bcf from 2018, and
is forecast to continue to grow in 2020
to an average of 92.5 bcf per day.
Spot prices at the Waha Hub in West
Texas, near the Permian basin, where
transportation is constrained, averaged
73 cents per million Btu in March,
$2.22 lower than the average Henry
Hub price.
“Multiple force majeures have con-
strained pipeline capacity and reduced
westbound flows out of the Permian,
which has put downward pressure on
prices,” EIA said, noting that the Waha
Hub price turned negative the last week
of March, and fell to a record minus
$4.63 per million Btu on April 3.
“Negative prices indicate that some
producers are willing to pay someone to
take their natural gas to avoid the costs
or penalties of storing, shutting in, or
flaring their natural gas production or to
lose revenue by reducing their liquids
production,” the agency said.
Additional natural gas pipeline
capacity out of the Permian is expected
to come online later in 2019, EIA said,
which should stabilize Waha Hub
prices. l
continued from page 2
EIA OUTLOOK
l P I P E L I N E S & D O W N S T R E A M
Kenai Pipe Line modifications proposedBy KRISTEN NELSON
Petroleum News
Kenai Pipe Line Co. has applied to the
Regulatory Commission of Alaska for
permission to modify its existing facilities
to allow blocked crude operations, permit-
ting the company to segregate sweet and
sour crude to meet new low-sulfur marine
fuel standard taking effect next January.
KPL receives crude oil from four receipt
points — Swanson River Oil Pipeline inter-
connection, Middle Ground Shoals Pipeline
interconnection, KPL’s truck rack and
Kenai marine terminal. The crude is stored
for delivery to Tesoro Alaska Co. LLC’s
Kenai Refinery. All crude oil used at the
refinery comes through KPL facilities. KPL
provides crude to the refinery in amounts
and types that the refinery requested.
Both modification of existing facilities
and construction of new facilities would be
required.
The existing lease automatic custody
transfer, or LACT, facilities would be mod-
ified “to facilitate block crude operations,”
allowing the refinery “to segregate and
process sweet and sour crude oil” to meet
new International Maritime Organization
standards.
The current limit for sulfur in fuel oil
used on ships is 3.5 percent mass by mass,
a standard met by the Kenai Refinery. The
new standard, however, is 0.5 percent mass
by mass, and “in order to effectively and
efficiently produce fuel oil that complies
with the new IMO standard, operations at
both KPL and the Refinery will require
changes,” KPL told RCA in an April 1 fil-
ing.
Services will remain the same, KPL
said, with the manner in which transporta-
tion is done changing.
“Instead of moving a continuous blend-
ed stream of oil as is presently being
accomplished, KPL will be able to provide
flow of crude oil of a specific type (sweet or
sour) as needed by the Refinery.”
The projected cost of the project, at a
plus-or-minus 30 percent estimate level, is
$5.25 million, KPL said.
KPL tankage to refineryThe company said all crude oil from
KPL tankage is transferred to the refinery
via the LACT unit.
Among changes, the project includes a
new booster pump to permit crude oil to
move directly from Tank 2402 to the LACT
unit, a process which currently requires the
crude to flow first through the Pump 2400
area. The existing LACT unit power sys-
tem, controllers and explosion-proof
starters will be removed and replaced with
a new motor control center, the company
said, housed in a new electrical module,
with a new power system.
A new system, provided by the refinery,
will allow refinery operators to control the
flow rate into the LACT unit building.
Changes to KPL, in conjunction with
changes at the refinery, will allow more
efficient and economic production of low
sulfur fuel oil, the company told RCA.
KPL said the proposed block crude oper-
ations “will facilitate the segregation and
processing of sweet and sour crude” to meet
the new IMO standards.
“Currently, fuel oil is effectively blended
together as refined,” KPL said, but the
change in IMO standards requires segrega-
tion of low sulfur oil to avoid contamination
— the blending of low and high sulfur fuel.
That blending, the company said, “would
make the fuel oil from the Refinery much
less valuable and marketable.” With the
proposed changes, the refinery “will be able
to produce runs of low sulfur fuel oil and
segregate it so as to make it more valuable
and marketable.”l
Changes to KPL, in conjunctionwith changes at the refinery, willallow more efficient and economicproduction of low sulfur fuel oil,
the company told RCA.
PETROLEUM NEWS • WEEK OF APRIL 14, 2019 5
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6 PETROLEUM NEWS • WEEK OF APRIL 14, 2019
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l L A N D & L E A S I N G
State publishes noticefor spring lease sales
By KRISTEN NELSONPetroleum News
The Alaska Department of Natural
Resources’ Division of Oil and Gas
has published a notice of sale for its spring
areawide oil and gas lease sales. Offerings
for the bid opening May 22 will be for
Cook Inlet Areawide 2019W and the
Alaska Peninsula Areawide 2019 compet-
itive oil and gas lease sales.
In-person bid submission will be May
20 from 9 a.m. to 4 p.m. in Suite 1100 of
the Atwood Building in Anchorage or by
mail to the division.
The public bid opening will be May 22
at 9 a.m. in Suite 102 of the Atwood
Building.
Complete sale details are available on
the division’s website http://dog.dnr.alas-
ka.gov/Services/BIFAndLeaseSale under
current lease sales.
There are no current leases in the
Alaska Peninsula areawide sale area,
which encompasses some 4 million gross
onshore acres and 1.75 million gross acres
of offshore state waters. There are 1,047
tracts offered in the sale, which is on the
north side of the Alaska Peninsula from
the Nushagak Peninsula in the north,
south and west to the vicinity of Cold Bay.
Division data show 213 active leases in
the Cook Inlet areawide sale area, which
encompasses some 4.2 million gross acres
divided into 815 tracts, consisting of state-
owned uplands generally south and west
of Houston and Wasilla in the Matanuska-
Susitna Borough, the Anchorage bowl, the
western shore of Cook Inlet from Beluga
River to Harriet Point, and tide and sub-
merged lands in upper Cook Inlet from
Knik Arm and Turnagain Arm south to
Anchor Point ant Tuxedni Bay.
Minimum bids are $5 per acre for the
Alaska Peninsula and $15 per acre for
Cook Inlet. Primary lease terms are 10
years for the Alaska Peninsula and eight
years for Cook Inlet, with a one-time
extension for the Cook Inlet leases under
certain conditions.
One of the tracts in the Cook Inlet sale,
Stump Lake Tract C1057, contains sur-
face improvements. The division said a
new lessee may enter into an agreement
for assumption of the assets, otherwise,
obligation to dismantle, remove and
restore those assets would remain with
previous lessees.
The royalty rate is 12.5 percent for
both lease areas.
Annual rental rates for the Alaska
Peninsula sale are $1 per acre for year
one; $1.50 per acre for year two; $2 per
acre for year three; $2.50 per acre for year
four; and $3 per acre for years five
through 10.
For Cook Inlet, the annual rental rate is
$5 per acre for years one through four and
$10 per acre for years five through eight. l
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EXPLORATION & PRODUCTIONUS drilling rig count gains 19 to 1,025
The number of rigs drilling for oil and natural gas in the U.S. increased by 19
the week ending April 5 to 1,025.
A year ago the count was 1,003 active rigs.
Houston oilfield services company Baker Hughes reported that 831 rigs target-
ed oil (up 15 from the previous week) and 194 targeted natural gas (up four).
The company said 70 of the U.S. holes were directional, 901 were horizontal
and 54 were vertical.
Among major oil and gas producing states, Texas, the most active state with 499
rigs, was up eight from the previous week.
West Virginia was up four rigs and New Mexico was up three.
Alaska and Colorado were each up two rigs.
North Dakota was up by one rig.
California, Louisiana and Wyoming were unchanged.
Oklahoma and Pennsylvania were each down by one rig.
Baker Hughes shows Alaska with eight active rigs, unchanged from a year ago.
The U.S. rig count peaked at 4,530 in 1981. It bottomed out in May 2016 at 404.
—PETROLEUM NEWS
CIRCAC has website, webinar on pipelinesThe Cook Inlet Regional Citizen’s Advisory Council is providing opportunities
for Cook Inlet citizens and stakeholders to ask questions and offer suggestions on the
safe operation of the pipeline infrastructure in Cook Inlet.
An online webinar is scheduled for April 25 and a public meeting for May 8.
“We’re pleased to have the opportunity to share information with citizens and
stakeholders about Cook Inlet’s critical pipeline infrastructure,” said Michael
Munger, CIRCAC executive director. “Delivering information to the public and
bringing their ideas or questions to the operating companies is an important part of
how we achieve our mission.” CIRCAC has developed a website to provide infor-
mation about Cook Inlet pipeline systems at www.cookinletpipelines.com.
The website provides an opportunity for feedback, as well links to a survey, to the
webinar and registration for the May 8 meeting.
The May 8 public meeting, also accessible online, will provide answers to ques-
tions and concerns raised at the April 11 webinar.
CIRCAC said the project is funded under a technical assistance grant from the
Pipeline and Hazardous Materials Safety Administration.
—PETROLEUM NEWS
PIPELINES & DOWNSTREAM
PETROLEUM NEWS • WEEK OF APRIL 14, 2019 7
By KAY CASHMANPetroleum News
Prior to the 2011 entry of Hilcorp Energy into Alaska,
the Cook Inlet basin’s onshore and offshore oil produc-
tion had declined to 8,900 barrels per day. At the same time,
natural gas reserves were projected to soon be insufficient
to meet continued local utility demand and aging platform
infrastructure was considered to be nearing its functional
end of life. Cook Inlet was consid-
ered a mature oil and gas province
that had reached peak oil production
in 1970 and peak natural gas produc-
tion in 1994.
Fortunately, the privately owned
Texas-based independent had a
strong track record of entering
mature hydrocarbon basins and mak-
ing the necessary investments to pro-
duce more oil and gas.
Initially, Hilcorp’s local sub-
sidiary, Hilcorp Alaska, accumulated a large portfolio of
legacy assets in the Cook Inlet region and on the North
Slope through separate deals with Marathon Oil Corp.,
Union Oil Company of California and BP Exploration
(Alaska) Inc.
Its focus on development for its first five years in Alaska,
Hilcorp only used exploration to expand operations within
existing units, particularly at the Ninilchik and Deep Creek
units on the Kenai Peninsula. Even a foray beyond unit
boundaries was closely tied to work at nearby units.
But the company took a somewhat more expansive
approach to its exploration activities in the Cook Inlet
region in 2017 by drilling 16 stratigraphic test wells at
three prospects in the southern Kenai Peninsula — Pearl,
Seaview and Deep Creek SW — during the latter half of
the year.
Possibilities for next five yearsIn April through October 2020, Hilcorp Alaska hopes to
drill two to four exploratory wells in the untapped federal
waters of lower Cook Inlet, pending the results of a 3-D
seismic survey 20 miles due west of Homer halfway
between Kachemak Bay in the lower Kenai Peninsula.
Potential Cook Inlet exploration and development plans
for the next five years from April 1, 2019, through April 1,
2024, are listed in an application Hilcorp filed with the
National Marine Fisheries Service for an incidental take
authorization (the non-lethal unintentional taking of small
numbers of marine mammals incidental to oil and gas
exploration, development, and production activities).
The earliest activities described are the 374 square-mile
lower Cook Inlet 3-D seismic survey in 2019, pending the
receipt of a Bureau of Ocean Energy Management permit.
Seismic will be followed by outer continental shelf geohaz-
ard and geotechnical surveys in the fall of 2019 or the
spring of 2020, with the surveys site specific, determined by
the number of potential exploratory drill sites in an area,
and covering less than one lease block in a day.
Also slated to occur is the Iniskin Peninsula exploration
and development program in both 2019 and 2020, from
April through October, and in 2020 a Trading Bay area geo-
hazard survey, followed by the possible drilling of Trading
Bay area exploratory wells.
In 2020 and 2021, Hilcorp’s list of planned activities
also includes a 2-D seismic survey in the marine, intertidal
and onshore area on the eastern side of Cook Inlet from
Anchor Point to Kasilof, with an area of interest some five
miles on each side of the coastline.
Hilcorp says the methods for acquiring the seismic will
be similar to those employed by Apache Alaska Corp. in
l E X P L O R E R S P R E V I E W
Hilcorp aims to drill in lower Cook InletDespite delay in 3-D seismic survey to late August, lower CI, Iniskin Peninsula and Trading Bay exploration programs on track
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companies investing in
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May 25, 2019
see EXPLORERS PREVIEW page 8
8 PETROLEUM NEWS • WEEK OF APRIL 14, 2019
2011 and 2012, noting a single vessel can
acquire a 2-D source line in some one to
two hours, with only a single line acquired
in a day, allowing for node deployments and
retrievals and intertidal and land zone shot
hole drilling. There are up to 10 source lines
and the entire operation is estimated to take
30 days to complete, allowing for weather
and equipment contingencies.
3-D survey over 8 OCS blocksThe 3-D seismic survey tentatively
planned for May and June 2019 but in early
April was postponed by Hilcorp per an
email to Petroleum News that says “our
team has made the decision to delay the sur-
vey until after the height of fishing and
tourist season.” The survey will be over
eight of the 14 OCS lease blocks Hilcorp
holds in lower Cook Inlet, including blocks
6357, 6405, 6406, 6407, 6455, 6456, 6457
and 6458. The new scheduling by the com-
pany suggests surveying will start in late
August 2019.
In the application, Hilcorp says it will
possibly drill wells to depths of 7,000 to
16,000 feet, depending on the well, each of
which will likely take 40-60 days to drill
and up to 10-21 days of well testing. If two
wells are drilled, it will take some 80-120
days to complete the full program; if four
wells are drilled, 160-240 days.
Hilcorp was the only bidder in BOEM’s
2017 OCS Cook Inlet lease sale, taking
tracts in federal waters off Ninilchik and
Anchor Point, a three-tract block southwest
of Anchor Point, and a block of eight tracts
farther south and in the middle of the inlet.
In December 2017, Hilcorp applied to
BOEM to collect airborne gravity and mag-
netic data in lower Cook Inlet over an area
which generally overlaps the federal OCS
waters of BOEM’s lower Cook Inlet plan-
ning area, including aerial gravity and mag-
netic survey of all 14 lease blocks Hilcorp
acquired in the 2017 sale.
Hilcorp also planned to have the surveys
run over the Iniskin Peninsula. Fixed-wing
aircraft were to be used offshore and rotor-
wing aircraft onshore, with data collection
expected to take two to three weeks. BOEM
says the company notified it on Aug. 17,
2018, that the surveys had been completed.
On March 15, 2019, in Kenai, Mike
Dunn, Hilcorp’s development manager, said
the lower Cook Inlet 3-D survey timelines
had slipped from mid-April to May 3 (and
since slipped again) because of the federal
government shutdown at the end of 2018,
but the company still expected to get the
survey completed in the shorter timeline.
“If all were to go perfect, we’ll be run-
ning about three lines per day; there’s about
90 lines; we should be able to finish in 35
days,” he says. “We’ve got some contin-
gency, there will be some tangles, but the
tides are not quite as bad down here as they
are in the upper Cook Inlet.”
With anticipated contingencies the entire
shoot is likely to take 40 or 45 days, he said.
Possible new platforms, partnerHilcorp will not use either of the jack-up
rigs currently positioned in Cook Inlet
should it proceed with exploratory drilling.
“The deepest water in that area is about
280 feet; you get to the edges, I want to say
it’s at least 180 to 190 feet of water,” Dunn
says. “A 300-foot jack-up rig will be able to
drill the wells.”
Both the Spartan 151 and the Randolph
Yost jack-up rigs — now in Cook Inlet —
are limited to a maximum water depth of
150 feet.
The cost of mobilizing a 300-foot jack-
up rig to Alaska will raise the bar in terms of
the quality of the targets the company must
have to justify exploration drilling in the
survey area.
“This whole program, including getting
the permits, and shooting the seismic, is
about $15 million,” Dunn says. “Hilcorp is
paying 100 percent of that and we hope to
get some partners to help us drill some wells
if we do identify some prospects.
“If we make some discoveries, we will
do an environmental impact statement and
hopefully set a couple of platforms,” he
says.
Iniskin Peninsula programHilcorp says it began baseline explorato-
ry data collection in 2013 for proposed
land-based oil and gas exploration and
development on the Iniskin Peninsula near
Chinitna Bay some 60 miles west of Homer
on the west side of Cook Inlet in the Fitz
Creek drainage. The 2-D program was pro-
posed over 41 miles between Chinitna Bay
and Iniskin Bay.
The lower Cook Inlet and the Iniskin
Peninsula area have known oil potential but
as yet no commercial discoveries — the
region has an active petroleum system,
including excellent oil source rocks, but has
been only very sparsely explored.
New project infrastructure proposed by
Hilcorp for the Iniskin project includes
material sites, a 4.3-mile access road, pre-
fabricated bridges to cross four streams, an
air strip, barge landing/staging areas, fuel
storage facilities, water wells and extraction
sites, an intertidal causeway, a camp/staging
area and a drill pad, with construction antic-
ipated to start in 2020.
Hilcorp says initial delivery will be by
low-draft tug and barge vessels with barge
landing/staging areas at Camp Point and
Fitz Creek to be used for storage and stock-
piling of supplies, equipment and fuel.
An intertidal rock causeway is proposed
adjacent to the Fitz Creek staging area to
improve accessibility of the barge landing.
The causeway will extend seaward from the
high tide line some 1,200 feet to a landing
area 150 feet wide. Rock fill will be sourced
from the Gaikema material site.
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continued from page 7
EXPLORERS PREVIEW
Seaview 8 drill rig and pad.
ALA
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see EXPLORERS PREVIEW page 9
PETROLEUM NEWS • WEEK OF APRIL 14, 2019 9
“The causeway will enable more consis-
tent use of the Fitz Creek staging area to
receive freight and fuel with fewer limita-
tions due to short high tide windows and
result in less dependency on the Camp Point
staging area,” Hilcorp said in the applica-
tion, and will also enable quicker response
to emergency incidents and reduce the risk
associated with materials logistics and fuel
deliveries.
When the causeway is no longer needed
for the project, rock fill will be removed,
allowing wave actions and currents to natu-
ral fill and cover the disturbed area.
“The project camp site is located along
the historic road alignment at a location
where bedrock can be quarried and the pad
developed by cutting to grade and utilizing
excavated rock for fill,” the company said.
Seaview explorationIn fall 2018, Hilcorp received approval
from the state of Alaska for a plan of oper-
ations for a two-well exploratory program
at its new Seaview pad near Anchor River
in the upper Cook Inlet basin, just onshore
from the Cosmopolitan unit. The company
drilled seven shallow stratigraphic tests in
the undeveloped area in 2017.
The Seaview pad is on a private parcel
off the Old Sterling Highway.
The two new exploration wells were to
be the Seaview No. 8 and Seaview No. 9
wells within ADL 392667.
Alaska Oil and Gas Conservation
Commission records show the well was
completed on Dec. 16, 2018, to a true ver-
tical depth of 10,148 feet and a measured
depth of 10,500 feet. The agency later
reported testing had been completed.
There was no word as of April 5, 2019
on the results.
According to fall 2018 state docu-
ments, both Seaview wells were to be
drilled directionally to measured depths of
around 10,000 feet. The No. 8 well was to
test oil and gas prospects, while the No. 9
well would target gas.
The division says the first 5,500 feet of
the Seaview 8 will be perforated to evalu-
ate gas zones, while the bottom-hole loca-
tion will extend beyond ADL 392667 to
explore for oil on fee simple land.
There are three separate stages for each
well, beginning with the directional
drilling and insertion of surface casing
through subsurface of potential hydrocar-
bon-bearing zones within the Lower
Sterling and Beluga formations, with well
evaluation including downhole instrumen-
tation. Well control equipment and casing
was to isolate gas-bearing zones.
In stage two the well will be deepened
beyond the state lease with a lateral hori-
zontal evaluating the Lower Tyonek,
Hemlock and deeper formations on fee
simple lands.
The third stage will involve evaluating
potential hydrocarbon reservoirs by perfo-
rating and flow-back testing, following
which the well may be temporarily
secured or formally suspended while data
is evaluated.
Deep oil at North Cook InletHilcorp did not plan any exploration or
delineation activities at its North Cook
Inlet unit in its plan of development that
went through May 2019; nor did it have
any planned in the next plan submitted
April 1, 2018.
The company is redeveloping the unit,
which it acquired from ConocoPhillips in
late 2016 and got permission from the
state to extend an existing plan of devel-
opment to June 2018.
A plan of development filed in April
2018 represents the first full plan from
Hilcorp since it took
over the unit and
takes a measured
approach to activi-
ties at North Cook
Inlet.
The company
launched a “compre-
hensive field study”
to evaluate the
remaining potential
of the Beluga and Sterling sands and to
determine the need for future wells, side-
tracks and perforations.
The most exciting exploration news in
the plan: Hilcorp says it intends to study
the potential of developing deep oil
prospects at North Cook Inlet known as
Tyonek Deep or Sunfish, which lie under
the natural gas accumulation.
Over the years previous operators and
farm-in partners have considered a similar
venture, but Hilcorp went one step further
by installing an eight-inch diameter sub-
sea oil pipeline to the Tyonek platform,
the production platform for the North
Cook Inlet gas field, as part of its efforts to
extend natural gas transmission across
Cook Inlet. The new line enables the
movement of oil west to east under Cook
Inlet.
Hilcorp says the pipeline will not be
used unless it makes an oil development
decision. Laying of the oil line at the same
time as the gas line presumably saves sig-
nificant cost relative to laying the oil line
separately.
In January 1999, having drilled three
wells into the Tyonek Deep oil pool,
ConocoPhillips pulled the plug on the
project, saying that the project was not
viable — oil prices were around $10 per
barrel at the time.
In its April 1, 2019, plan submittal
Hilcorp says the “initial development plan
for the deep oil prospect has been com-
pleted. Drilling of the first development
well is expected in the 2020 timeframe.
This oil development well will be drilled
through the top of the Sterling and Beluga
gas sands’ structure and so will allow for
evaluation of the remaining dry gas devel-
opment potential.”
Dominant CI producerHilcorp is the dominant on and off-
shore oil and gas producer in the Cook
Inlet basin, as of Jan. 1, 2019, operating
about 19 fields and units — a number that
seems to fluctuate each year due to acqui-
sitions, consolidations and terminations.
On the west side of Cook Inlet, Hilcorp
operates the Ivan River, Lewis River,
Pretty Creek and Beluga River units.
Offshore, the company operates the
North Cook Inlet unit (actually in middle
Cook Inlet), the Granite Point unit, the
Middle Ground Shoal unit, the Trading
Bay unit, and the North Trading Bay unit
(middle Cook Inlet) and associated
McArthur River field.
On the southern Kenai Peninsula,
Hilcorp operates the Ninilchik, Deep
Creek and Nikolaevsk units. In the north-
ern Kenai Peninsula, the company oper-
ates the Birch Hill unit, the Swanson
River unit, the Beaver Creek unit, the
Sterling unit, the Kenai unit and the
Cannery Loop unit.
Active North Slope producerOn the North Slope, Hilcorp holds four
primary properties, the Milne Point unit,
the Endicott field at the Duck Island unit,
the Northstar unit and the Liberty project
which unlike the other three is not current-
ly producing but it is gaining momentum
again after several years of delays under
its former operator, BP, Hilcorp’s partner
in the development.
Hilcorp expects Liberty to come online
between 10,000 and 15,000 barrels per
day, peaking at 60,000 to 70,000 bpd with-
in two years. The company also expects
the field to produce as much as 120 mil-
lion cubic feet of natural gas per day.
When actual construction will begin was
not known as of April 1, 2019.
Although Hilcorp is a strong produc-
er and a very active developer on the
North Slope, it has not been an active
explorer.
Hilcorp was the third largest oil pro-
ducer in Alaska in 2018, behind
ConocoPhillips and BP. l
continued from page 8
EXPLORERS PREVIEW
MIKE DUNN
10 PETROLEUM NEWS • WEEK OF APRIL 14, 2019
229-6000
EXPLORATION & PRODUCTIONAOGCC approves PBU injection commingling
The Alaska Oil and Gas Conservation Commission has approved applications by
Prudhoe Bay unit operator BP Exploration (Alaska) for downhole commingling of
injection between the Prudhoe, Aurora and Borealis oil pools, subject to applications
by BP for each well prior to the commingled injection.
Aurora and Borealis are oil pools in the Kuparuk formation which overlie the
Prudhoe oil pool, the commission said in April 3 decisions. Aurora is present in the
drill site S area of the Prudhoe Bay unit. Borealis is present in the drill site L, V and
Z areas of the unit.
Both the Aurora and Borealis oil pools are authorized for lean and miscible gas
injection as well as water injection for enhanced recovery purposes, the commission
said. Commingled injection between the Aurora and Prudhoe oil pools is already
authorized in wells PBU S-09 and PBU S-31A; there is currently no commingled
injection between the Borealis and Prudhoe oil pools.
Lean and miscible gas used for injection in the three pools is sourced from the PBU
Central Gas Facility and Central Compression Plant, and services drill sites L, S and
V. The commission said the gas available for injection is the same for both the
Prudhoe oil pool and the Kuparuk formation pools, Aurora and Borealis.
The commission said several Prudhoe oil pool wells penetrate the Aurora oil pool
“in a location that could be advantageous for providing enhanced recovery injection
operations for that pool. Some of these locations have insufficient reserves to justify
a standalone injection well, so commingling injection with the POP provides an
opportunity to enhance recovery that otherwise would not be available.”
The commission said the same thing about the Borealis oil pool — several Prudhoe
wells penetrate the Borealis “in a location that could be advantageous for providing
enhanced recovery injection operations for that pool,” and some of the locations “have
insufficient reserves to justify a standalone injection well.”
—KRISTEN NELSON
be higher than might otherwise be the
case.
During an April 10 public meeting the
commissioners reflected on the status of
the unification efforts, and on plans for
what happens next.
Key functionsThere are four key functions that are
needed to achieve greater unification: the
mandating of a single set of reliability stan-
dards; the implementation of a transmission
company to operate the electrical transmis-
sion system; the implementation of merit
ordered economic dispatch for generating
facilities; and the implementation of an
electric reliability organization or system
operator, to oversee the system and enforce
the reliability standards.
Economic dispatch involves a protocol
whereby continuous use is made of the
most efficient available power generation
units.
Commissioner Robert Pickett said that
there has been progress in unifying and
mandating reliability standards for the sys-
tem. This progress includes a proposal to
institute the Railbelt Reliability Council, a
form of electric reliability organization.
Proposed statutory languageThe commission is uncertain whether it
would have legal jurisdiction over the RRC
under the terms of current state statutes and
has suggested statutory language that
would clarify the situation. The statute
changes would also give the commission
clear authority over the approval of the con-
struction and siting of major additions to
the electrical system, such as new, major
generation facilities. The changes would
also give the commission approval authori-
ty over regional planning for the system.
The utilities have commented on the
statutory language, making observations
on the technicalities of the proposed statu-
tory changes. In general, the utilities have
questioned the immediate need for the
changes and have expressed concern that
the requirement to have the Legislature
pass new statutes could significantly delay
the formation of the RRC. During the
April 10 meeting Tony Izzo, CEO of
Matanuska Electric Association, reiterated
this concern about potential delays in the
process, while also commenting that he
supports the concept of legislation that
would give the commission the required
statutory authority over the RRC. Mark
Johnson, speaking for the Arctic Railbelt
Cooperative Transmission and Electric
Co., a group of four of the utilities, said
that the ARCTEC members substantially
agree with Izzo’s views.
Less progress in other areasThere has been much less progress on
aspects of the unification efforts beyond the
reliability standards and RRC initiative,
Pickett said. For example, although a newly
formed transmission company involving
several of the utilities has applied to the
commission for a certificate, this company
does not directly commit some of the major
owners of transmission assets, he said.
The commissioners expressed particular
frustration at what they see as a lack of
progress towards the implementation of
economic dispatch. Chugach Electric
Association, Municipal Light & Power, and
Matanuska Electric Association had
formed an agreement to implement eco-
nomic dispatch across their service areas in
Southcentral Alaska. But in 2018 the utili-
ties announced an indefinite hold on this
initiative because of the need to first deal
with the proposed purchase of ML&P by
Chugach Electric.
Commissioner Antony Scott comment-
ed that the time is approaching for policy
makers to play a role in dealing with the sit-
uation. And commission Chair Stephen
McAlpine said that, with four years being
an adequate time frame for finding volun-
tary solutions, some legislative action is
needed.
Next stepsPickett commented that the plan at this
stage is to present to the Legislature an
account of what has happened to date, per-
haps sketching out a way forward from this
point. There is a need to build on what has
been achieved so far. Progress is being
made on reliability standards and that will
continue — the commission anticipates
opening a regulatory docket on the stan-
dards. Pickett also said that he has spoken
to the governor’s chief of staff, the speaker
of the House and the president of the
Senate.
The plan now is to vote on the various
elements of the report to the Legislature
during the next RCA public meeting. In
general, the commissioners concurred with
Pickett’s approach.
—ALAN BAILEY
continued from page 1
RCA REPORTThe commission is uncertainwhether it would have legal
jurisdiction over the RRC underthe terms of current state statutes
and has suggested statutorylanguage that would clarify the
situation.
PETROLEUM NEWS • WEEK OF APRIL 14, 2019 11
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ENVIRONMENT & SAFETY
NSIDC reports on winter sea ice conditionsOverall, air temperatures were at or slightly above average over much of the
Arctic Ocean during the past winter, with only the southern Beaufort Sea being
especially warm, the National Snow and Ice Data Center has reported in its com-
mentary on the background to this year’s sea ice maximum extent. As previously
reported in Petroleum News the NSIDC has said that this year’s maximum extent
occurred on March 13 and tied for the seventh lowest on record.
This winter’s ice conditions continue a multiyear trend of a loss of maximum
extent at an average rate of 2.7 percent per decade.
However, this winter’s weather conditions actually led to a near average ice
extent for much of the winter over much of the Arctic. There were none of the
short-term heat waves that have characterized recent winters. But substantial ice
loss in February and early March in the Bering Sea led to near ice-free conditions
in that region. Ice began to build again in the Bering towards the middle of March
but melted sharply during the last week of the month, the NSIDC reported.
A multiyear trend towards later sea ice formation and an earlier spring melt is
reducing the time period during which snow can accumulate on the sea ice — the
amount of snow on the ice influences rates of winter ice growth, the development
of melt ponds in the summer, and the amount of melt water entering the upper
ocean. Snow on the ice also effects the amount of sunlight able to penetrate the
ice, and hence has biological impacts, the NSIDC said.
—ALAN BAILEY
resulting from the widespread use of
wood burning stoves.
LNG optionsThe base plan for the Interior Energy
Project involves the construction of
expanded LNG storage facilities in
Fairbanks along with a two-stage expan-
sion of the Titan LNG plant. However,
Siemens and Knikatnu, the Native village
corporation for Knik and Wasilla, have
proposed the construction of a new LNG
plant on a spur of the Alaska Railroad, on
Native land near the city of Houston.
LNG would be shipped to Fairbanks by
railroad. The concept would involve
Siemens financing the plant construction
and ultimately supplying LNG to
Fairbanks at some workable price. The
company had been negotiating a possible
gas supply from Cook Inlet for the plant.
Siemens would construct the plant using a
standard modular design that could be
expanded as needed.
The Titan plant, on the other hand,
would continue to be owned by IGU. The
utility would manage the plant expansion
and would fund the expansion project pri-
marily through bonding. The utility would
recover the expansion costs through the
rates that it charges for gas supplies in
Fairbanks.
Based on potential gas uptake rates by
Fairbanks consumers, as assessed by an
external consultant, and on estimated
costs for expanding LNG supplies, IGU
has an expectation that the project will
prove viable. However, the utility has
been considering both potential means of
increasing the LNG supply: the Titan
expansion and the Siemens proposal. The
utility had hoped to reach a point where
both options were sufficiently well
defined to do a side-by-side comparison
of their relative economics.
Siemens MOUIn October the IGU board agreed on
the MOU with Siemens that would enable
confidential negotiations over the
specifics of the Siemens plan. The first
stage of the negotiations would lead to a
term sheet for the LNG supply. The term
sheet would enable Siemens to finalize the
design of the required LNG facilities, thus
enabling the company to make a firm
price offer to IGU for the LNG.
However, no term sheet has been
agreed thus far. Because of the confiden-
tial nature of the negotiations, there is no
public information regarding whatever
issues have arisen in the discussions
between IGU and Siemens. It appears
from comments made during the April 9
board meeting, that negotiations had run
aground, with contention over the scope
of the Siemens system, issues such as
accountability for some of the project
risks, and questions regarding the poten-
tial gas supply for the Siemens plant. IGU
General Manager Dan Britton commented
that the utility’s counsel, Robin Brenna,
had sent a confidential memo to the board,
outlining the issues that the IGU team
viewed as unresolvable through future
negotiations.
Board member viewsLee and Norland, in opposing the ter-
mination of the MOU, commented that
they did not feel that they had enough spe-
cific information about the nature of the
areas of disagreement between IGU and
Siemens. Norland commented that she
had heard different versions of what had
happened and that there is a need to clari-
fy exactly what Siemens thinks about the
project. Lee said that she thinks that there
are differences between Siemens’ and
IGU’s views of the negotiations.
Other board members expressed views
that the negotiations had reached an
impasse, with reasons that had been thor-
oughly discussed. Board member Gary
Wilken said that he respects the profes-
sional views of Britton and Brenna in rec-
ommending an end to negotiations.
Meanwhile, at the beginning of
February the IGU board commissioned
Braemar Technical Services to proceed
with the front-end engineering and design
for the expansion of the Titan LNG plant.
The FEED project, expected to complete
by early November, will pin down a budg-
et and plan for the expansion project.l
continued from page 1
SIEMENS DEAL
TMI?l E X P L O R A T I O N & P R O D U C T I O N
l U T I L I T I E S
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MOST LIKELY.To subscribe call: 907-522-9469Or visit: PetroleumNews.com
TMI?sees plenty of work for interim
T I O N & P R O D U C T I O NE X P L O R Al
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Giessel has ambitious plansQ&A:page
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Lee and Norland, in opposing thetermination of the MOU,
commented that they did not feelthat they had enough specific
information about the nature ofthe areas of disagreementbetween IGU and Siemens.
12 PETROLEUM NEWS • WEEK OF APRIL 14, 2019
nities to link up with projects.
Project ReconciliationCalled Project Reconciliation, the group has assembled
a team of indigenous and non-indigenous executives with
experience in oil and gas, capital markets, business devel-
opment and indigenous relations, Wapass said.
He said the objective is to gather support from major
Canadian banks to lead a syndicated debt issue to finance
the takeover of Trans Mountain and a share of the expan-
sion costs.
The secured debt would cover long-term shipping con-
tracts that oil producers have signed with Trans Mountain,
as well as guarantees that governments have offered to
pay construction costs (Alberta has committed up to C$2
billion for any cost overruns), thus eliminating the need
for taxpayer subsidies or upfront payments by indigenous
communities, the project said.
Wapass told the Globe and Mail that his group is aware
that the Canadian government bought Trans Mountain last
year from Kinder Morgan for C$4.5 billion, with the
understanding — as confirmed by Morneau — that the
asset would eventually be put back in private hands.
He said the proposal is at a “very advanced” stage,
although Morneau said the sale of the pipeline depends on
when the venture is “de-risked,” which in turn can’t be
resolved until consultations with indigenous groups are
completed.
Meaningful economic participationMorneau told reporters in Calgary that indigenous
ownership can only proceed if the communities would
have “meaningful economic participation,” if a deal could
proceed in the spirit of reconciliation and if the resulting
entity worked for the benefit of all Canadians on a com-
mercial basis.
Project Reconciliation has taken its lead from a 2017
deal that resulted in Alberta’s Miskew Cree and the Fort
McKay First Nation buying 49 percent of a Suncor
Energy oil sands storage tank for C$503 million — a
transaction that was financed through a high-yield bond
issued to more than a dozen investors.
Despite the enlistment of leaders from several leaders
of oil and gas investments by indigenous communities,
many First Nations will not be swayed by the initiative.
Grand Chief Stewart Phillip of the Union of British
Columbia Indian Chiefs said he did not care who owned
or held a stake in the pipeline.
He said the project is detrimental to the Pacific marine
ecosystem and poses a threat to killer whales and wild
salmon.
Wapass countered that Trans Mountain represents an
opportunity for indigenous people to realize that the envi-
ronment and the economy don’t have to be at logger-
heads.
Naomi Sayers, an indigenous lawyer in the energy sec-
tor, wrote in the Globe and Mail that she is “inspired by
the possibilities,” noting that the project could see five
indigenous groups making a bid.
“I am excited to see indigenous stakeholders taking
their seat at the table instead of waiting to be invited,”
she wrote. l
continued from page 1
PIPELINE PLAYER
pleted and on March 5, a well test com-
menced in the 71-degree angle wellbore
over a single stage stimulation in the
Nanushuk reservoir. The flow test includ-
ed cleanup, low flow rate and pressure
build-up periods, prior to the final flow,
with the test concluded on March 19.
The final flow test was conducted
over a two-hour period with a flowing
bottom hole pressure of 1,270 psi and
flowing well head pressure of 240 psi on
natural flow with no artificial lift. Based
on the productivity index calculated dur-
ing the final flow test, the well flow rate
potential is estimated at approximately
3,800 bpd at a flowing well head pres-
sure of 50 psi.
The objective of the second well, the
Pikka C/Pikka C ST1, in the central part
of the unit was to reduce uncertainty on
well deliverability and test the northern
extent of the Nanushuk reservoir trend.
During March, logging-while-drilling
data was successfully acquired over
Pikka C ST1. A flow test program began
on March 14, which included testing of
six stimulation stages within the 3,800-
foot-long horizontal section.
Mechanical problems with the test
equipment delayed starting of the test
and down-hole blockages restricted flow
rates and the ability to clean the well out
properly. Despite the down-hole restric-
tions, stabilized rates of more than 860
bpd were established at 800 psi flowing
bottom-hole pressure, with higher peak
rates recorded during unloading the well.
In addition, modeling of the geological
properties recorded in the well indicate
the potential for much higher flow rates
than observed. While unlikely to be
indicative of the full potential of the
well, the test data, combined with the
comprehensive data suite acquired, will
be fully evaluated and integrated into the
forward planning ahead of the FEED
decision for the first Pikka unit develop-
ment project.
Oil Search has previously said it
expects a FEED, or front-end engineer-
ing and design, commitment for the
Pikka project by mid-2019, subject to
appraisal and an Environmental Impact
Statement, or EIS, Record of Decision
from the U.S. Army Corps of Engineers.
Demobilization of the Doyon Arctic
Fox and Nabors 105E rigs and personnel
on the wells was expected to be complet-
ed by mid-April.
—KAY CASHMAN
continued from page 1
PIKKA SUCCESS
PETROLEUM NEWS • WEEK OF APRIL 14, 2019 13
Oil Patch Bits
ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS
Companies involved in Alaska’s oil and gas industry
All of the companies listed above advertise on a regular basis with Petroleum News
AABR Inc.Acuren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Afognak Leasing LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Airgas, an Air Liquide companyAK Lofts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Alaska Energy Services, LLCAlaska DreamsAlaska Frac Consulting LLCAlaska Frontier Constructors (AFC)Alaska Marine LinesAlaska MaterialsAlaska RailroadAlaska Rubber & Rigging Supply Inc.Alaska Steel Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Alaska Tent & TarpAlaska TextilesAlaska West ExpressAlpha Seismic CompressorsAmerican Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Arctic ControlsARCTOS Alaska, Division of NORTECH . . . . . . . . . . . . . . . . .14ArmstrongASRC Energy ServicesAT&T . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16Avalon DevelopmentAviator Hotel
B-FBaker Hughes, a GE companyBombay DeluxeBPBrandSafway ServicesBrooks Range SupplyCalista Corp.
CarlileChosen ConstructionColville Inc.Computing AlternativesCONAM ConstructionCruz Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Denali Universal Services (DUS)Doyon AnvilDoyon AssociatedDoyon DrillingDoyon, Limitedexp Energy ServicesF. R. Bell & Associates, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . .4FairweatherFlowline AlaskaFluorFugro
G-MG COMMGeotempsGMW Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Greer Tank & WeldingGuess & Rudd, PCICE Services, Inc.Inspirations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Judy Patrick Photography . . . . . . . . . . . . . . . . . . . . . . . . . .15Little Red Services, Inc. (LRS)Lounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMapmakers of Alaska
Maritime HelicoptersMotion & Flow Control Products
N-PNabors Alaska Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Nalco ChampionNANA WorleyParsons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Nature Conservancy, The . . . . . . . . . . . . . . . . . . . . . . . . . . . .5NEI Fluid TechnologyNordic CalistaNorth Slope TelecomNorthern Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11Northern SolutionsNRC AlaskaOil SearchPacific Power Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9PENCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Petroleum Equipment & Services, Inc.PRA (Petrotechnical Resources of Alaska) . . . . . . . . . . . . . . .2Price Gregory International
Q-ZRaven Alaska – Jon AdlerResource Development CouncilSAExplorationSecurity AviationSourdough Express . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Strategic Action AssociatesSummit ESP, A Halliburton Service . . . . . . . . . . . . . . . . . . . .6Tanks-A-Lot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6The Local PagesTOTE – Totem Ocean Trailer ExpressVolant ProductsWeston Solutions
Lynden companies bring Ted Stevens statue to AlaskaLynden said March 29 that a life-size
bronze statue of the late Alaska Senator TedStevens was unveiled Feb. 23 at theAnchorage airport that bears his name. WithLynden’s long relationship with the senator, itwas only fitting that Lynden companiesdonate the transportation of the statue toAnchorage where it is now gracing the air-port. Lynden assisted with customs for ship-ment of materials from China and shippedmaterials from Los Angeles to Alaska for thebackground of the statue.
Alaska Marine Lines picked up the clay form from the artist Joan Bugbee Jackson inCordova, Alaska, for transport to Seattle. From Seattle, Alaska Marine Lines delivered the formto a foundry in Oregon for bronzing. Lynden Transport handled the final leg back to Anchorageand stored the statue until the installation and final unveiling ceremony at the Ted StevensAnchorage Airport.
Karina Waller of the Ted Stevens Foundation thanked Jim Jansen and Lynden for their sup-port at the unveiling. “This is such a wonderful tribute to the Senator who truly loved Alaskansand shaped our state,” said Jeanine St. John, vice president, Lynden Logistics.
Fluor’s Prevost named nation’s top Craft InstructorFluor Corp. announced April 1 that Clemon Prevost was named the 2019 Craft Instructor of
the Year by Associated Builders andContractors. Prevost is the electrical tradeinstructor at Fluor’s U.S. Gulf Coast CraftTraining Center in Pasadena, Texas. He wasrecognized during the Careers in Constructionceremony at the ABC Convention in LongBeach, California last week.
“Clemon has a passion for developingtomorrow’s workforce, and the heart he hasfor his students is evident in everything he does,” said Mark Landry, executive vice presidentand chief human resources officer for Fluor. “From instructing students through technical simu-lations and competitions to mentoring them on employability skills, Clemon prepares them forsuccess.”
A journeyman in the electrical and instrumentation fields and an NCCER-certified instruc-tor, Prevost has more than 42 years of experience in the electrical industry. Since 2015, he hasled the electrical program at Fluor’s U.S. Gulf Coast Craft Training Center. With Fluor, he hassafely delivered more than 300,000 hours of craft training with 169 graduates in the electricalprogram. He is active in his community, mentoring others to help them prepare for careers inthe construction industry.
The Craft Instructor of the Year award is presented annually by ABC to an instructor whopossesses outstanding creativity, a positive attitude and the ability to transfer knowledgethrough communications skills and innovative teaching to promote lifelong learning.
Editor’s note: Some of these news items will appear in the next Arctic Oil & GasDirectory, a full color magazine that serves as a marketing tool for Petroleum News’ con-tracted advertisers. The next edition will be released in September.
CO
URT
ESY
LYN
DEN
CO
URT
ESY
FLU
OR
operator ExxonMobil assigned a 63 percent working inter-
est in ADL 343112’s Tract 32 to Jade, retaining a 2 percent
overriding royalty.
This most southeasterly PTU lease is estimated to hold
100 million barrels of recoverable oil, per a 1997 BP press
release.
Jade’s members and managers are Anchorage-based
Erik Opstad and Castle Rock, Colorado-based Greg Vigil,
who each own 50 percent of the company.
The first proposed Sourdough plan of development for
PTU Area F was submitted Dec. 21, 2018, by Jade to the
division. Then-division Director Chantal Walsh formally
told the unit working interest owners — ExxonMobil, BP,
ConocoPhillips, Colt and, most recently, Jade — in a Dec.
27 letter that although the plan “as submitted” was incom-
plete, that fact “in no way triggers the release of Area F
acreage.” Dec. 21, she noted, “remains the date of submit-
tal” for purposes of the Point Thomson Unit Settlement
Agreement with the state, which dates back to March 29,
2012.
In other words, the Dec. 21, 2018, submittal satisfied the
requirement that a POD be submitted for Area F before
year-end 2018, per the unit’s settlement agreement, even
though the submittal was deemed incomplete.
Jade submitted an amended plan of development, or
POD, on Jan. 24, 2019, which the division deemed com-
plete on Feb. 4, 2019. Jade provided a technical presenta-
tion on the POD on March 4, 2019, and submitted amended
versions of both the public and confidential portions of the
POD on March 19 and March 29, 2019, respectively.
An April 4, 2019, decision signed by James Beckham,
acting division director, approved the 2019 Area F POD and
its early 2020 well.
Based on analysis of the appraisal well data, Beckham
said, Jade “will move forward accordingly with additional
development at Area F and adjoining areas in the 2020–
2021 winter drilling season. Current plans include drilling
an additional lateral into the Brookian reservoir and produc-
tion testing. The need for additional delineation wells and
the overall economic feasibility of a field development pro-
gram at Area F will be considered following the 2020–2021
season.”
—KAY CASHMAN
continued from page 1
JADE APPROVALBased on analysis of the appraisal well data,
Beckham said, Jade “will move forwardaccordingly with additional development at
Area F and adjoining areas in the 2020–2021winter drilling season.
ny said that it had tested two wells in the
oil pool and run completion tubing in a
third well, with the wells being ready for
production. But the development never
proceeded.
New oil lineIn preparation for reviving the oil field
development Hilcorp has now laid most of
a new subsea oil pipeline from the Tyonek
platform to the Inlet’s west side. The com-
pany has been installing the line in con-
junction with a major Cook Inlet pipeline
reconfiguration, conducted in 2018. The
reconfiguration project involved convert-
ing one of the twin subsea Cook Inlet Gas
Gathering System pipelines from the car-
riage of gas to the carriage of oil. To main-
tain adequate gas transportation capacity
across the inlet, Hilcorp laid a new subsea
gas pipeline from the Tyonek platform to
the west side of the inlet — that new
pipeline ties up with the existing gas
pipeline from the platform to the inlet’s
east side.
Hilcorp’s plan of development says
that all but 400 feet of the oil line from the
platform were laid in 2018, with weather
and pulling constraints preventing com-
pletion of the pipe laying operation.
Hilcorp told the division that it anticipates
completing the laying of the line in May
of this year.
The company is also in the process of
replacing the crew quarters on the Tyonek
platform, and plans to upgrade the cranes
and the helideck, and to remove drilling
and mud pits.
Meanwhile production from the North
Cook Inlet gas field continues. Hilcorp’s
plan of development indicates that in 2018
the field produced 6.2 billion cubic feet of
gas. That compares with 7.1 billion cubic
feet in 2017.
Hilcorp has also filed new plans of
development for the Granite Point, Middle
Ground Shoal, Trading Bay and North
Trading Bay units.
The Granite Point unitAccording to the new plan for the
Granite Point unit, during calendar year
2018 Hilcorp produced 611,000 barrels of
oil and 447 million cubic feet of gas from
the Granite Point platform; 307,000 bar-
rels of oil and 277 million cubic feet of gas
from the Anna platform; and 108,000 bar-
rels of oil and 279 million cubic feet of gas
from the Bruce platform. That amounted
to a total of about 1 million barrels of oil
and about 1 billion cubic feet of gas from
the unit, a significant uptick from the pro-
duction of 879,000 barrels of oil and 752
million cubic feet of gas in 2017.
During the period of the last plan of
development for the unit, starting on July
1, 2018, the company installed a water
injection pump in one well, and conducted
a subsea sonar survey of all pipelines
associated with the platforms. The sonar
surveying also monitored the M/V
Monarch, which sank at the platform in
2009. In addition, Hilcorp conducted
acoustic monitoring of the natural vibra-
tions of the three offshore platforms and
completed inspection and repairs on some
platform leg welds.
Hilcorp told the division that it contin-
ues to evaluate further development
drilling in the unit, including the possibil-
ity of drilling multilateral, sidetrack wells
from existing well bores. For the coming
plan period, running from July 1, 2019,
through June 30, 2020, the company antic-
ipates drilling two sidetracks.
Middle Ground Shoal unitIn 2018 Hilcorp produced 520,000 bar-
rels of oil and 111 million cubic feet of gas
from the Middle Ground shoal unit. That
compares with 308,649 barrels of oil and
83 million cubic feet of gas in 2017.
Production in 2017 was impacted by a
field shutdown as a consequence of a leak
in the subsea pipeline that delivers fuel
gas to the offshore platforms.
Since July 2018 Hilcorp has conducted
well workover operations in the field, con-
verting an injection well to a producer;
perforating five wells; and performing
coiled tubing cleanouts on two wells. The
company also inspected some locations on
a gas pipeline, conducted sonar surveys on
all subsea pipelines and reconfigured the
subsea gas pipeline manifold on one plat-
form.
The field currently has two active plat-
forms, Platform A and Platform C, while
two other platforms, the Baker and Dillon
platforms, are currently dormant.
In anticipation of the potential future
reactivation of the Baker and Dillon plat-
forms, and to address issues relating to the
inspection of the field’s subsea gas
pipeline, Hilcorp plans to install two sub-
sea power cables to these platforms from
platforms A and C, possibly during the
summer of 2020. Reactivation of the dor-
mant platforms would entail major
upgrades to the platform facilities, Hilcorp
told the division.
Hilcorp continues to evaluate the eco-
nomics of reactivating drilling rigs on the
A and C platforms. Potential drilling oper-
ations would include updating the well
completions, adding perforations, clean-
ing out wells and repairing damaged
wells. There are also some potential new
drilling prospects — the company is in the
process of interpreting new and
reprocessed seismic data, to better delin-
eate the structure of the field, and hence
identify possible drilling targets. Drilling
possibilities include infill drilling and
step-out exploration tests, the company
told the division.
In terms of continuing maintenance,
Hilcorp plans to complete diver inspec-
tions of some subsea components of
Platform A, and of the subsea gas pipeline.
Trading Bay unitIn the Trading Bay unit the McArthur
River field produced 1.7 million barrels of
oil and 9.7 million cubic of gas in 2018.
That oil production was virtually the same
as production in 2017, while gas produc-
tion increased from 7.2 million cubic feet.
Since July 1, 2018, Hilcorp has completed
two new wells in the field and has started
but not completed a third well. The com-
pany conducted workovers on four wells
on the Grayling and Steelhead platforms.
The company also converted one well to
gas lift and reperforated another well.
Hilcorp plans to continue to evaluate
new rig workover opportunities in the
field while also identifying new subsur-
face possibilities.
The Trading Bay field, the other field
in the unit, produced 595,000 barrels of oil
and 1.3 billion cubic feet of natural gas in
2018. That compares with 675,000 barrels
of oil and 1.1 billion cubic feet of gas in
2017. Since July 1, 2018, Hilcorp has
been conducting workover operations on
two wells and anticipates workover of a
third well shortly.
The company is working on a study of
the field, to identify rig workovers, side-
track drilling, waterflood optimization and
other activities that may bolster field pro-
duction.
North Trading Bay unitHilcorp continues to anticipate restart-
ing production from the North Trading
Bay unit, using a sidetrack well drilled
from the Monopod platform that supports
the adjacent Trading Bay unit. North
Trading Bay used to produce from the
Spark and Spurr platforms, but oil produc-
tion ceased in 1991 and gas production in
2005. The two platforms have been main-
tained in lighthouse mode since then —
Hilcorp has in the past indicated that
restarting these platforms would not be
viable.
The company told the division that, fol-
lowing some additional seismic evalua-
tion, it now anticipates starting a sidetrack
from the A-10RD well in May of this year.
If this sidetrack proves successful, Hilcorp
anticipates applying for a unit expansion,
to include newly producing acreage. l
14 PETROLEUM NEWS • WEEK OF APRIL 14, 2019
COMPANIES
38 yearsBUILDING ALASKAF O R M O R E T H A N
Experts in Resource Development and Heavy Civil Construction
Cruz Construction | Alaska Interstate Construction
-
continued from page 1
TYONEK PLATFORM
CO
URT
ESY
HIL
CO
RP
The Tyonek Platform
Hilcorp has also filed new plans ofdevelopment for the Granite Point,
Middle Ground Shoal, TradingBay and North Trading Bay units.
Hilcorp’s plan of development saysthat all but 400 feet of the oil line
from the platform were laid in2018, with weather and pulling
constraints preventing completionof the pipe laying operation.
Hilcorp told the division that itanticipates completing the laying
of the line in May of this year.
PETROLEUM NEWS • WEEK OF APRIL 14, 2019 15
WHATEVER
WHENEVER
WHEREVER
judypatrickphotography.comCreative photography for the oil & gas industry.
907. 258.4704
export returns, population growth —
Alberta is turning into the national basket
case.
The jobless rate is now 6.9 percent —
7.7 percent in Calgary — with an estimated
172,000 Albertans out of work in a popula-
tion of 4.3 million, with unknown thou-
sands more having given up trying to find
work.
Four political partiesThe leaders of the four Alberta political
parties all claim to have the answer, as they
did four years ago when the Conservative
Party was resoundingly defeated, ending 44
years in power.
Then Premier Jim Prentice guaranteed
his overthrow when he was asked to explain
Alberta’s abrupt fiscal turnaround.
“In terms of who is responsible, we all
need to look in the mirror, right? Basically,
all of us have had the best of everything and
have not had to pay for what it costs,” he
said.
Albertans were not ready for that dose of
truth, but their response was stunning. They
did the unthinkable and turned the levers of
power over to the socialist New Democratic
Party under Rachel Notley.
Meanwhile, the Conservatives under-
went a top-to-bottom overhaul, remerging
as the United Conservative Party and chose
Jason Kenney, a former federal cabinet min-
ister, as their leader.
Two leading contendersThe two leading contenders to form the
next government share a common view that
Alberta desperately needs to find a way out
of its economic plight, but that’s where
agreement ends.
Approaching voting day on April 16,
Kenney, despite worries that he will slash
social programs and government union con-
tracts, has opened up a gulf in the polls over
Notley, reaching 19 percentage points at
one stage, though that margin has started to
shrink.
What is beyond question is that Alberta
really is “at the crossroads.”
Kenney has based his campaign on a slo-
gan of “jobs, the economy and pipelines,”
while Notley is pinning her hopes on offer-
ing “leadership you can trust.”
One of the few topics they agree on is the
need for new crude pipelines out of Alberta,
though Kenney accuses Notley of failing to
make any headway, despite what he calls
her “alliance” with Canada’s Prime
Minister Justin Trudeau.
Notley retaliates by taking credit for the
Trudeau government’s decision to buy the
Trans Mountain pipeline for C$4.5 billion
and committing itself to spending another
C$9 billion on expanding the export link to
Asia to 890,000 barrels per day from
300,000 bpd.
Kenney has a wide-ranging platform to
jumpstart the upstream sector, vowing to
accelerate by 50 percent to a maximum 180
days the time needed for regulatory
approvals of new wells and enshrining the
same royalty rate in perpetuity.
“Tens of billions of dollars of investment
have fled Alberta’s oil and gas sector,” he
said. “That money has not left the industry,
it has left Alberta ...”
One goal ‘fair price’ for gasKenney said that, if elected, he would
work with stakeholders to get “a fair
price” for Alberta natural gas producers
he estimates are selling their output at dis-
counts up to 70 percent. In addition, he
promises support for LNG infrastructure
to Pacific Coast export terminals.
Kenney also vows a “fight-back strate-
gy” against opponents of the oil and gas
sector, accusing them of feeding off
money from U.S.-based foundations.
On his hit list are promises to termi-
nate Notley’s plan to spend C$3.7 billion
to lease 4,400 rail cars to move an extra
120,000 bpd out of Alberta in hopes of
generating C$2.2 billion in royalties and
other revenues along with scrapping the
Notley government’s pledge to raise a
carbon tax from C$30 a metric ton to
C$50 and to cap all oil sands greenhouse
gas emissions.
That would put Kenney on a collision
course with Trudeau’s carbon tax that has
started at C$20 a metric ton and aims at
C$50 by 2022 and has already set up a
legal showdown with Saskatchewan,
Manitoba, Ontario and New Brunswick.
The NDP energy plan is based on a
more interventionist approach, taking
special aim at the downstream sector by
doubling to C$7 billion government
incentives for petrochemical facilities,
refining, partial upgrading of oil sands
bitumen and natural gas infrastructures.
Notley claims that would create
70,000 jobs over the next decade and trig-
ger C$75 billion of investment.
—GARY PARK
continued from page 1
ALBERTA CROSSROADSOne of the few topics they agree onis the need for new crude pipelines
out of Alberta, though Kenneyaccuses Notley of failing to make
any headway, despite what he callsher “alliance” with Canada’s Prime
Minister Justin Trudeau.
16 PETROLEUM NEWS • WEEK OF APRIL 14, 2019
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