Cook
Inlet oil and gas proves boon to Southcentral Alaska
Suzanna Caldwell April 21, 2014 http://www.alaskadispatch.com
The Tyonek offshore oil platform in Cook Inlet on Nov. 1, 2012. Cook Inlet
oil and gas provides numerous benefits to the Southcentral Alaska economy,
according to a new report from Northern Economics.
The natural gas of Cook Inlet does a lot
for the hundreds of thousands of Alaskans who live in Southcentral. It heats
their homes, cooks their food, powers the lights and recharges cell phones.
The gas is so prevalent that those residents utilize it almost every minute
of their lives, and that's been the status quo for at least two generations,
according to JR Wilcox, co-founder and CEO of Cook Inlet Energy and chairman
of the Cook Inlet Subcommittee for the Anchorage Chamber of Commerce.
"The only time Cook Inlet gas doesn't support me is when I'm
in my car," he said, acknowledging that even then, the inlet still produces
oil that maybe -- in a less-than-direct way -- powers his drive to work.
Alaska Legislature should ignore Kelly's coal plant and focus
on Cook Inlet gas
Lawmakers approve refinery subsidy plan, excluding Agrium
Wilcox presented the Northern Economics study "The Importance
of Cook Inlet Oil and Gas to Southcentral Alaska," in an Anchorage Chamber
of Commerce luncheon Monday. The study examines the economic impact of Cook
Inlet natural gas in Alaska.
It's a relevant topic, especially as production has ebbed and
flowed throughout the years. Most recently, production seemed to be declining
-- and sharply. Despite incentives, production is nowhere near what it was
a decade ago. Starting in the 1990s and through 2005, Cook Inlet annually
produced more than 200 billion cubic feet of gas a year. But in 2007, things
started to slip. Aging wells meant less production, ultimately leading to
closures of the Agrium fertilizer plant and the eventual mothballing of
the ConocoPhillips LNG liquefaction plant, both located in Nikiski on the
Kenai Peninsula.
So what to do to keep people on the ground interested in the
role Cook Inlet natural gas plays in their lives? Let them know the importance
of the resource, according to Wilcox.
"(The study) is useful to (Chamber of Commerce) members in the
case of what happens if Cook Inlet can't keep up," Wilcox said.
It's another phase in the up-and-down history of natural gas
in Southcentral Alaska. Two years ago utilities and lawmakers warned that
unless there was a turnaround, residents in Alaska's largest population center
would find themselves left out in the cold, literally, with gas supply unable
to meet demand.
But earlier this year, Conoco reapplied for its LNG export permit,
and local utilities announced they had shored up natural gas contracts up
through 2018, signaling a resurgence in the region.
ConocoPhillips will resume exports of liquefied natural gas
from the Kenai Peninsula after the Department of Energy granted the company
export permission for two years. The announcement on Monday comes after
local utilities announced that their natural gas needs were met through
2018, and after the state in September asked Conoco to renew those exports
from its liquefied natural gas facility in Nikiski. The resumed exports
will open market opportunities for excess quantities of natural gas, ConocoPhillips
said in a statement. The state has offered incentives to boost natural gas
production in Cook Inlet, but the gains so far have been somewhat modest,
meeting needs in Anchorage for a just a handful of years. However, state
officials pressed for the renewed exports to foster continued investment
in Cook Inlet by oil and gas companies that will need new markets if production
continues to increase. The Energy Department’s approval will allow exports
to both free-trade and non-free-trade countries. Conoco will be able to
export about 40 billion cubic feet of liquefied natural gas during the two-year
period. How much is that? By comparison, Enstar's 136,000 customers -- from
the Matanuska Valley to Anchorage the Homer -- use about 33 billion cubic
feet of natural gas a year. Conoco’s LNG facility operated for decades, shipping
LNG overseas to Asian markets, until it was mothballed in 2012 because of
limited gas availability in Cook Inlet. At its peak, the facility produced
64 billion cubic feet a year.
That, along with economic incentives from the state legislature
and the construction of CINGSA, short for Cook Inlet Natural Gas Storage,
Alaska -- a facility designed to hold 17 billion cubic feet of natural gas
-- have shored up supplies, at least for the time being. Though Enstar,
the regional natural gas utility, has expressed concerns about deliverability,
gas supply contracts have been negotiated and suppliers insist they will
be able to meet demands.
But beyond the give and take of utilities, and the basic needs
they provide, Wilcox suggests it goes deeper than that. Specifically, he
noted the economic benefits Southcentral receives because of low energy prices.
The study quantifies exactly how much that is, with up to $350 million coming
to Southcentral Alaska directly from jobs related to oil and gas.
That doesn't take into account all the "stuff" Cook Inlet jobs
pay for -- aka, the industrial output. The study said that in 2011 the economic
output on Kenai Peninsula Borough from oil and gas production was $2.8 billion.
Most of that came from the Tesoro refinery, mostly refining crude from outside
of Cook Inlet. Increases in oil production could mean fewer imports and
big gains for the refinery.
It even suggests that regardless of how much natural gas is
being extracted from Cook Inlet, even if it declines to the point where
alternative fuel sources need to be considered, Alaskans should stick to
natural gas.
Even if it was imported, natural gas would still be significantly
cheaper than propane or fuel oil to heat Alaskans' homes, the study says.
Importing natural gas would run about $12 per thousand cubic feet -- about
double what those customers pay now. If Southcentral Alaskans were forced
to use propane, the cost for the average homeowner would skyrocket -- an
estimated $7,053 a year for heat, instead of about $1,386 a year currently.
Fuel oil -- already a primary heat source for many communities in Alaska
that don't have natural gas -- would run about $4,385 a year.
Plus, Wilcox noted, that doesn't even take into account the
costs people would incur in having to install new heaters and boilers for
their homes for those other types of fuel.
Ultimately, Wilcox believes there is hope in Cook Inlet. The
study notes that the amount of recoverable oil and gas in the inlet -- 600
million barrels and 19 trillion cubic feet, respectively -- are worth, at
today's prices, $173 billion.
And while there will always be the back and forth, for the most
part, there's plenty of reason to be optimistic about the future, he said.
"This is a very serious issue, but let's not panic," he said.
"Let's quantify it."
|
Top 5 metals stories this year
By Greta Bourke - Monday, April 21, 2014
The most popular metals stories so far this year have been mainly focused
on price drivers and forecasts, with interest divided between the base metals
complex and gold.
The most read story focused on the impact of lower Chinese demand growth
and rising supply in the industrial metals complex this year. The lift in
Chinese demand seen in 2H13 will not be sustained as the country seeks to
restructure its economic growth away from investment and production towards
consumption and services, leading to less commodity intensive growth.
At the same time, mine supply is coming on line, particularly in copper
and iron ore, which is expected to put further pressure on prices. Copper
has been trading around US$3/lb since March 12, while iron ore prices saw
the second largest one-day decline on record in early March due to increased
supply and a demand slowdown.
In March, Nomura's decision to raise its 2014 gold price forecast to US$1,335/oz
was the second most read story this year. Nomura followed UBS and RBC Capital
Markets, both of which raised their gold price forecasts in the third month.
UBS sees gold averaging US$1,300/oz this year while RBC set an average of
US$1,400/oz.
Gold averaged US$1,411/oz last year, putting an end to 12 years of consecutive
price growth and is expected to average US$1,219/oz this year, according
to the median forecast of 28 analysts in the London Bullion Market Association's
precious metals forecast for 2014.
Back in the base metals complex, a story about the aluminum
market turning a corner captured readers' attention early this year. After
years of being in surplus, aluminum could finally see a deficit this year,
Barclays Capital said. The global market balance will shift into a 275,000t
deficit this year for the first time since 2006-07 thanks to production cuts,
according to the bank. In mid-2013, Barclays had been forecasting a 1.2Mt
surplus.
Barclays is forecasting an average aluminum price of US$1,838/t in 2014.
It is back to gold again for the fourth most read story, after the yellow
metal rallied to three-month highs in February. The rally, which was driven
by short covering and Chinese demand, will be short-lived, Barclays said
at the time.
"Gold needs investor sentiment to turn decisively positive to extend recent
gains, although ETP outflows have stabilized, gross longs also need to gain
traction," the bank said.
Just a little over a month later, Barclays raised its 2014 average gold
price forecast to US$1,250/oz from the previous US$1,205/oz to account for
the yellow metal's strong performance earlier this year.
More recently, Brazilian steelmaker Gerdau's (NYSE: GGB) offer of 41.5mn
euros (US$57mn) to acquire French specialty steels producer Ascometal was
on readers' radars.
Ascometal's installed steel capacity is 920,000t/y in three plants and
the company started a judicial recovery process, or type of bankruptcy protection,
in March. Gerdau expects the transaction to close by the end of Q2.
The acquisition is part of Gerdau's plan to expand its presence in the
global automotive industry as a supplier of specialty long steels. |
ENI Interested In Floating Gas
Liquefaction Plant
MAPUTO, April 16 (BERNAMA-NNN-AIM)
Italian energy company ENI is considering building a floating liquefied
natural gas (FLNG) facility off the coast of the northern Mozambican province
of Cabo Delgado where it is the operator of the Rovuma Basin Offshore Area
Four, where huge deposits of natural gas have been discovered.
The adjacent block, Offshore Area One, is operated by United States
oil and gas company Anadarko, which has also discovered vast quantities
of gas, presumably all part of the same field. The total known reserves
in the Rovuma Basin are estimated at 180 trillion cubic feet of gas.
It had been thought that ENI and Anadarko would join
forces to set up a single liquefaction plant onshore in the district of Palma
and a site for such a plant had been identified, and meetings held with
villagers who would have to be resettled. On Tuesday, however,
ENI published in the Mozambican media a "Public Announcement for Expression
of Interest" in a floating gas liquefaction facility. The announcement asks
companies which can build such a plant to express their interest, after which
they will receive a potential "Invitation to Tender" package from ENI.
ENI is interested in "Front End Engineering Design (FEED) for a
floating LNG facility, and possible future phases of detailed engineering,
procurement, construction, installation, commissioning, and of operation
and maintenance services".
The proposed floating LNG plant would be moored off the coast of
Palma district. In the ENI proposal, it would "receive, process
up to liquefaction and store liquefied natural gas produced from sub-sea
wells, and subsequently offload it onto LNG carriers for export".
The plant would be "a turret-moored double-hulled floating facility type",
said ENI, which stresses that as yet there is no tender, but only an expression
of interest. Companies wishing to participate are told to submit all the
relevant documentation to ENI by May 5.
Currently there is no floating LNG facility anywhere in the world,
although the Malaysian oil and gas corporation, Petronas, expects to have
one completed and operating off the eastern Malaysian State of Sarawak
in 2015. In 2011, Royal Dutch Shell announced that it would
build such a floating factory 200 kilometres off the shore of Western Australia,
which it hoped would be in operation by 2017.
A floating LNG platform might have both economic and environmental
advantages.
It could prove cheaper to pump the gas to a floating facility than
to an on-shore factory. With no pipelines onshore, and no need for dredging,
and new port facilities, the environmental impact of gas liquefaction might
be reduced.
However, there are enormous technical challenges involved in building
huge structures at sea which can withstand major storms. The northern Mozambique
Channel is frequently hit by cyclones.
|
DOE lets ConocoPhillips
Alaska resume LNG sales to non-FTA countries
WASHINGTON, DC, Apr. 15 By Nick Snow OGJ Washington Editor
The US Department of Energy approved a ConocoPhillips Co. subsidiary’s
request to resume exports of LNG to countries not having a free-trade agreement
with the US from the company’s Kenai facility in Alaska in an Apr. 14 order.
ConocoPhillips’s authorization for such LNG exports from the site expired
on Mar. 31, it noted.
Exports of as much as 40 bcf of gas equivalent would be authorized for
2 years, DOE’s Fossil Energy Office said in the order. The overseas sales
would provide additional demand for Cook Inlet gas, which is otherwise not
needed in the state, ConocoPhillips Alaska Natural Gas Corp. (CPANG) said
in its application. It included a Sept. 5 letter from Alaska’s Department
of Natural Resources supporting this point.
A Feb. 19 DOE order authorizes LNG sales from CPANG’s Kenai Peninsula
installation to countries that have an FTA agreement with the US, ConocoPhillips
noted. Those sales would be part of the 40-bcf limit, it said.
Alaska’s two US senators applauded DOE’s action. “I’m glad ConocoPhillips
will be able to add to Alaska’s 40-year history of supplying natural gas
to Japan,” said Lisa Murkowski (R), the Energy and Natural Resources Committee’s
ranking minority member.
“DOE’s announcement also highlights the growth that’s occurring in Cook
Inlet, where there is now ample gas supply to both meet local needs and
help out our friends overseas,” she observed.
“This is great news for the cradle of Alaska’s oil and gas
industry on the Kenai Peninsula,” said Mark Begich (D). “With plenty of
gas available to meet local needs through at least 2018, we’re seeing the
kind of job growth responsible oil and gas development can provide.”
He said he urged DOE to process the ConocoPhillips application to ship
LNG to non-FTA countries outside the queue the department established for
other LNG export applications. Only six applications in that group have
been approved as being in the national interest, and at least 24 more remain,
Begich said.
The company plans to operate the liquefaction plant seasonally, during
summer when regional gas demand is low, the senator indicated.
ConocoPhillips separately said it is committed to meeting its local
gas supply contracts and to diverting gas from the LNG facility to address
local supply issues if needed. It previously said it would seek a new export
authorization if local Cook Inlet area gas needs were met and there was
sufficient gas available for export.
It said that during 2013, local utilities executed agreements securing
their gas supplies through at least the first quarter of 2018. “The Cook
Inlet area gas supply forecast has increased, which is a positive development
for local utilities,” ConocoPhillips said. “LNG exports will provide a market
opportunity for Cook Inlet gas production in excess of local market demand.”
|
Stabilis Encana and
a venture with Flint Hills Resources
lngglobal.com 14 April 2014 05:14
Encana to sell US LNG assets to Stabilis Energy
Stabilis Energy has announced they have signed
a definitive agreement to purchase substantially all of the U.S. based
assets of Encana Natural Gas Inc. Encana Natural Gas Inc. is based in Denver,
Colorado and is a distributor of liquefied natural gas used in high horsepower
engine operators in the oilfield, mining, rail, marine, over the road transportation,
and industrial sectors. Encana Natural Gas Inc. is a subsidiary
of Encana Corporation. The transaction is scheduled to close on April 30,
2014. Terms of the transaction were not disclosed.
Stabilis noted in addition to adding the staff of Encana
Natural Gas, Stabilis has also agreed to purchase its fleet of cryogenic
assets including storage and regasification trailers, mobile fueling units,
and other related equipment. Stabilis will fulfill all of the existing customer
obligations including its existing contracts, subject to customer consent
of Encana Natural Gas.
"We are proud to announce the addition of Encana Natural
Gas Inc.'s people, assets, and customer relationships to Stabilis Energy,"
said Casey Crenshaw, President and CEO of Stabilis Energy. "ENGI has a world-class
staff that will help us reach our goal of being the leading provider of
LNG fuel solutions to high horsepower operators in North America. They possess
deep sector expertise and strong customer relationships that we believe
will make Stabilis Energy an LNG industry leader across multiple geographies
and end markets."
In October of 2013 Stabilis announced they had formed a
venture with Flint Hills Resources, LLC to build up to five LNG liquefiers
serving oilfield fuel consumers. The new venture plans to open its first
LNG production facility in January 2015 in George West, Texas. The
facility will produce LNG for high horsepower oilfield fuel applications
throughout the Eagle Ford Shale. Planned production capacity is 100,000
gallons per day.
In January of this year Stabilis announced
they had hired former Clean Energy Fuels employee Koby Knight as Vice
President of Liquefied Natural Gas Plant Construction and New Market Development.
Knight is responsible for the construction of Stabilis' LNG production
facilities, including the facility currently under construction in George
West, TX, and for developing new business opportunities in off road natural
gas fuel end markets.
|
ISO LNG Shipment to Hawaii
Provided by Clean Energy Fuels
10 April 2014
Clean Energy Fuels Corp. announced today that it has supplied Hawaii
Gas with the first shipment of liquefied natural gas in Hawaii state history.
Hawaii Gas recently received approval from the Hawaii Public Utility Commission
to land containerized LNG for use as a back-up fuel source for its Oahu
synthetic natural gas plant. Clean Energy’s initial delivery totaled approximately
7,100 LNG gallons.
The LNG was loaded into an ISO container at Clean Energy’s liquefaction
plant in Boron, California, transported to the Port of Los Angeles and
then shipped to Honolulu, Hawaii, where it was re-gasified and injected
into Hawaii Gas’s utility distribution pipeline.
“Natural gas has again proven its versatility by meeting the fueling
needs of Hawaii Gas in an economically and environmentally-friendly manner,”
said Brian Powers, vice president of LNG production at Clean Energy. “Hawaii
Gas has shown leadership in its multi-year commitment to bring the benefits
of natural gas to the ratepayers of Hawaii.”
Hawaii Gas is working in partnership with stakeholders throughout
the state to utilize LNG as a less expensive and cleaner burning fuel
for utility and commercial power generation as well as for ground and
marine transportation.
“These initial shipments of LNG represent an important step in support
of Hawaii’s clean energy future,” said Alicia Moy, Chief Executive Officer
of Hawaii Gas. “Bringing LNG in ISO containers allows us to diversify our
existing fuel supply. As we bring in larger quantities of LNG, we believe
we can meet the needs of the people and businesses of Hawaii by lowering
their cost of energy with a lower-carbon fuel.”
|
Westport LNG tender cars EMD
CN CAT
Written by Kevin Smith railwayage.com April 11, 2014
Vancouver, British Columbia-based Westport Innovations, has delivered
the first of four liquefied natural gas (LNG) tenders ordered by Canadian
National (CN) to Electro-Motive Diesel (EMD, which is developing a pilot
low-pressure LNG diesel dual-fuel locomotive for the Class I railroad.
For the project EMD is retrofitting SD70ACe and SD70M-2 3.2MW locomotives,
which meet US EPA Tier III emission standards, and will utilize parent
company Caterpillar's Dynamic Gas Blending technology. A 45,500 liter ISO
LNG tank, which is 12.2m-long and is fitted to a 48ft intermodal well wagon,
will hold the LNG, which will be vaporized in the tender, avoiding the need
for the cryogenic liquid to be carried across a coupler.
The ISO LNG tender can fuel either a single or dual locomotive formation
and offer comparable power ratings and range to diesel-powered locomotives.
Brian Dracup, Wesport's senior director of rail, says this particular LNG
project will have a 60%-to-80% LNG use rate, and has the advantage of
converting to 100% diesel if required.
Dracup says that adopting LNG could offer
Class I's a 30%-to-50%, fuel savings per locomotive, or roughly $250,000
to $450,00 per year, based on average fuel consumption of 1.14 million gallons
per year.
LaGrange, Ill.-based EMD is expected to carry out stationary
testing of the LNG-powered locomotive during the next few months ahead
of CN's pilot line testing program, which is due to begin this summer.
Westport Innovations will deliver the three remaining LNG tenders by the
end of the second quarter.
The low-pressure project is a companion project to the
application of Westport's high-pressure direct injection (HPDI) technology
to a SD70M-2 locomotive, which is supported by the Sustainable Development
Technology Canada, a Canadian government-backed initiative which aims to
commercialize emerging clean technologies. This scheme is again being developed
in partnership with EMD and CN along with Gaz Métro Transport Metro
Solutions (GMTS) and aims to provide a 95%-5% LNG:diesel fuel ratio.
Dracup likens the adoption of LNG to the conversion from
steam to diesel locomotives in the 1960s, a view shared by leaders in
the North American railway industry, including BNSF President Matt Rose.
Dracup expects the market for LNG tenders and locomotives to remain small
scale in 2014-15 as initial pilot projects take place, but for these pilots
to expand to orders for 25-to-100 units in 2016, and larger orders for
100-to-300 tenders or more in 2018.
He adds that in his opinion, due to the structure of a
market in which only seven Class 1s now operate compared with over 100
during the steam era, that the widespread adoption of LNG could happen
much faster than the 20 years it took for a complete switch from steam
to diesel.
But Dracup does not expect HPDI locomotives to be commercially
available until at least 2018. He says that due to the average life of
locomotives, retrofits to existing units will be more common initially before
the adoption of locomotives built specifically for LNG utilization.
"Dual fuel technology is the right technology in the beginning,"
Dracup says. "It is an interim technology designed to familiarize the Class
1 railroads with the new fuel to provide peace of mind before the major
investment that will initiate the complete switch over. The risk-free demonstrations
with dual-fuel locomotives that we are seeing now are intended for the
railroads to get comfortable with natural gas, and to develop the infrastructure
to accommodate it. When they have reached this point we will then be ready
to enter with the HPDI technology."
EMD is a subsidiary of Progress Rail Services.
|
Sage Midstream to build
propane butane export terminal in Washington
04.10.2014 www.hydrocarbonprocessing.com
The company will construct a unit-train-accessible rail
unloading facility, storage tanks, and ship loading area with the capability
to load marine vessels with up to a capacity of 550,000 bbl.
Sage Midstream has launched a project to build a world-class propane
and butane export terminal at the Port of Longview in Washington, the
company announced on Thursday. The project will take place through Sage's
subsidiary Haven Energy Terminals.
Haven Energy plans to construct a unit -train-accessible rail unloading
facility, storage tanks, and ship loading area at the port with the capability
to load marine vessels with up to a capacity of 550,000 bbl.
The terminal will have a capacity of 47,000 bpd and is expected to
be operational by the fourth quarter of 2016. "Haven Energy will provide
the growing North American propane and butane supplies a direct route
to the highest growth demand market for these products in Asia and in
other Pacific destinations," said Greg Bowles, president of Sage and Haven
Energy.
"The terminal will be strategically located at the intersection of
Class 1 mainline rail and a deep-water draft port on the West Coast to
ensure these products unparalleled access to our terminal and ultimately
to the waterborne markets," he added.
Sage commissioned ECONorthwest, an economic consulting firm, to conduct
an independent economic study of the Haven Energy project. During the construction
period, the project is expected to create over 2,000 construction jobs
with over $135 million in payroll and benefits, while generating over $17
million in state and local tax revenue.
Once operational, the project is expected to create between 100 and
125 permanent direct and indirect jobs and generate over $80 million in
local and state tax revenue in the first 20 years.
Haven Energy said it will also invest in safety features at the terminal,
including the first full-containment propane and butane storage tanks
to be constructed in the US.
"The economic benefits to the local community and an unsurpassed
investment in safety will make this project the gold standard of propane
and butane export terminals in the US," said Bowles.
|
LNG run trucks costs that
are higher than expected
By Julie Gordon VANCOUVER Wed Apr 9, 2014 2:32pm IST Reuters
Just over a year ago, Canadian trucking firm Bison Transport took
a bet on a potentially game changing technology, buying 15 big rigs powered
by liquefied natural gas. The privately-held company was attracted
by the promise of a cheap and abundant fuel source and lower greenhouse
gas emissions. If all went well, it would be the first step toward converting
more of its 1,250-strong fleet to a type of fuel that costs about $1.50
less per equivalent gallon than diesel.
After 14 months on the road, though, the Winnipeg-based company
has found that the reality - at least initially - is less rosy. The savings
on fuel have been offset by other costs that are much higher than expected.
Bison is not alone. There are already signs that broader adoption
is falling short of initial expectations, particularly in off-road sectors
like locomotives and mining vehicles.
While the lack of fueling infrastructure remains the largest hurdle,
other operational teething pains are now tempering some of the growth
in LNG use that was expected to further reduce oil demand in North America,
as well as carbon emissions, according to interviews with industry experts
and officials from five transport companies.
Bison had anticipated that LNG, which generates fewer miles per
unit than diesel, to be 10 percent less efficient; instead, the drop
was closer to 18 percent. Maintenance costs were about double that of
a diesel tractor, more than budgeted. While Bison is not considering
abandoning its investment, it now expects to take at least four years
to break-even on the rigs - which cost roughly $75,000 more than standard
engines - rather than the two-year pay-off it had hoped for.
"We just wanted to be clear that when you first look at LNG, it
can look like there's a potential windfall for carriers, and the reality
is not that," said Lionel Johnston, corporate marketing manager with
Bison, a top Canadian carrier known for its large, modern trucks that
haul two trailers. The longer pay-off "doesn't mean it's a bad investment,
but it was definitely not as good as we were hoping," he said.
To be sure, it takes time for both technicians and drivers to adjust
to new equipment, impacting early costs, and technical glitches are not
uncommon with new technologies.
Still, Royal Dutch Shell last month surprised the LNG industry when
it scrapped a small-scale liquefaction unit it was building at its Jumping
Pound complex near Calgary.
"This additional demand has not developed in line with market expectations,"
said Shell spokeswoman Destin Singleton. The company also paused work
on two other plants, in Ontario and in Louisiana, but Singleton said those
projects may resume due to better opportunities for LNG-powered marine
vessels.
A BRIDGE TO RENEWABLE
Operators of commercial trucking fleets have been eyeing natural
gas as a potential fuel since the shale boom sent prices plunging. Gas
burns cleaner than diesel and is produced domestically, thus insulating
supplies from global political events that can drive up petroleum prices.
Thus far it's been compressed natural gas (CNG), rather than its
frozen cousin, LNG, that has captured more of the market.
With cheaper fuel and a more established infrastructure, CNG vehicles
now make up a large portion of smaller truck fleets for companies like
garbage collector Waste Management and United Parcel Service's (UPS) local
delivery. They are ideal in urban or short-haul operations.
North America's CNG infrastructure is also more developed, with
681 public stations across the United States, according to the U.S. Department
of Energy. By comparison, there are 52 public LNG stations, with another
37 planned, the data shows.
And CNG is cheaper than LNG at about $2 less per equivalent gallon
than diesel, providing hefty savings in vehicles that use 40,000 gallons
of fuel or more each year.
But LNG is ideal for large highway tractors that haul heavy loads.
Its energy density is greater than CNG, which means its fuel tank is smaller
and lighter, leaving more room for cargo.
Support is still building despite some setbacks. For example, UPS
has started deploying its new fleet of 1,100 heavy-haul LNG trucks, which
have a 600 mile range. However long-haul applications raise other
problems, say industry insiders. Drivers can only be on the road for so
many hours, and the trucks are restricted to routes where there are existing
fueling stations.
Heavy-duty fleet operators are "recognizing it's not going to be
a universal fit and in some cases there might be parts of the operation
where natural gas just isn't going to work," said Erik Neandross, chief
executive of Gladstein, Neandross & Associates, a clean transportation
consulting firm. Indeed, the viability of natural gas as a diesel
alternative depends on many factors, in particular whether a fleet burns
enough fuel to justify the additional cost of buying LNG rigs.
LEARNING CURVE
Bison's rough first year experience was familiar to other early
adopters in the trucking sector, they said. Early costs are often higher-than-expected,
as truck service and maintenance shops need to be retrofitted for the
natural gas technology and technicians need time to get comfortable with
the new equipment. In Bison's case it did not convert its shop for
the trial, so maintenance was done externally, leading to higher labor charges.
Many of the trucks also had fickle fuel sensors, gauges and software, which
had to be addressed by suppliers.
Other companies Reuters spoke with also ran into technical issues.
One, Quebec-based Robert Transport, was forced to install solar
panels on truck roofs to power energy-intensive methane detectors.
Raven Transport, a beverage hauler based in Florida, said its first
rigs stalled on the road and had to be towed after the LNG tanks were
filled at the wrong pressure.
Westport Innovations, a leading natural gas engine designer behind
many models now on the road, says that it can take time to work out the
bugs for first-generation technology.
"There have been challenges with reliability or just with performance
not as expected," said Karen Hamberg, vice president of strategy at Westport.
"So those things are being addressed and as we see new products being
launched, there will be higher levels of reliability with those new products."
The Vancouver-based company is working on its second-generation
heavy-haul offering, the HPDI 2.0, which it says will deliver breakthrough
performance and fuel economy, making it competitive with current high
performance diesel-fueled engines.
Back on the road, industry experts say once equipment and use practices
are modified, maintenance costs should be close to in-line with diesel,
no more than 1 to 2 cents more per mile - or up to $2,000 for a 100,000-mile
per year vehicle. "When you're saving in the order of magnitude
of $25,000 on fuel and paying $1,500 more in maintenance, that's obviously
a fair trade off," said Neandross.
UPS was the only company that Reuters spoke with that said its LNG
maintenance costs were currently even with diesel, though trucking companies
that have made the switch say that as they gain experience, reliability
goes up and costs come down.
PREACHING THE GOSPEL
Fueling infrastructure remains a critical issue.
"It's like the chicken and egg, if you don't have fuel stations,
then people won't buy trucks, and if people don't buy trucks, then you
don't get infrastructure," said Yves Maurais, engineering manager for Robert
Transport, which runs its 125 LNG trucks between Quebec City and Windsor,
Ontario.
Despite the hurdles, many early-adopters remain strong supporters
of natural gas for transport.
"Natural gas is good for the environment, and it's good for this
country to reduce its dependence on foreign oil from our enemies," said
Phil Crofts, director of marketing for Dillon Transport, an Illinois-based
firm with 25 LNG and 150 CNG tractors. "So we are disciples and we are
spreading the gospel."
(Additional reporting by Edward McAllister in New York; editing
by Jonathan Leff and Martin Howell)
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Liquefied natural gas arrives
in Honolulu
Apr 07, 2014 8:05 PM CDT By Chris Tanaka HONOLULU
(HawaiiNewsNow) -
Hawaii Gas' first shipment of liquefied natural gas, or LNG, has
arrived. While the contents of the 10,000 gallon tank meet approximately
1/8th of the daily output, the implications are far greater.
"This is just a stepping stone for what we hope to be a larger
activity as we move forward" said Kevin Nishimura, Director of Strategic
Initiatives for Hawaii Gas. "To do any more than this we need
to go back and seek commission approval, which we'll do I hope during
2014…about how we might scale this project up, and then start to have
a significant impact on the cost of energy in Hawaii" added Joe Boivin,
Senior Vice President of Business Development and Corporate Affairs for
Hawaii Gas.
There have been concerns that terrorists may weaponize the gas.
The Institute for the Analysis of Global Security has produced a lengthy
report about the transport and storage of LNG.
"There is a very robust set of policies, procedures and regulations
that anyone shipping LNG has to be in compliance with" said Boivin of
the security policies.
Hawaii Gas' facility is within a secure area. It has multiple high
fences, security personnel in the area as well as a 24-hour security
guard stationed just feet from the tank. There are also video monitoring
cameras as well.
"The industry is fairly mature, that is, been operating for over
40 years and shipping LNG by container vessel. It's a very safe industry,
has an impeccable track record" Boivin said.
The turnaround time for each tank is approximately three to four
weeks.
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Niobrara shale oil saves US
West refiners from dwindling supply
Gary Willingham Noble senior vice president of US onshore
04.04.2014 by LYNN DOAN and ELIOT CAROOM Bloomberg
Companies from Noble Energy to Whiting Petroleum are ramping
up output in the Niobrara shale oil play near the Rocky Mountains that
may help save US West Coast refiners from dwindling supplies in their
own region.
The formation spread across parts of Colorado, Kansas, Nebraska
and Wyoming is estimated to hold as much as 2 billion bbl of oil, Energy
Information Administration data show. Niobrara’s oil and lease condensate
output will reach a record 304,434 bpd this month, the agency said.
The Rocky Mountains play may be a godsend for Western refiners
because its crude closely matches the characteristics of oil from the
region’s largest domestic supplier, Alaska’s North Slope, where output
has declined every year since 2002. A slide in Alaska and California oil
production has forced West Coast refiners to increasingly rely on foreign
imports and oil shipped by rail from other states.
“We’ve had a number of shipments move by rail, but I don’t
think any of it has gone to the West Coast yet,” Gary Willingham, Noble’s
senior vice president of US onshore, said in Denver during conference
on Bakken and Niobrara crudes. “It’s certainly part of our plan to have
that flexibility. We want it to go where the demand is and where the
best price is.”
The posted price for oil from the Denver-Julesburg Basin, where
the Niobrara is located, rose 75 cents to $84.05/bbl on Thursday, according
to the marketing division of Plains All American Pipeline. Meanwhile,
Alaska North Slope oil rose $1.27 to $107.46/bbl.
Match for West
Noble, the largest producer in the Niobrara, expects its output
from the basin to surpass 100,000 equivalent bpd this year and reach
250,000 by 2018, Willingham said at Hart Energy’s 2014 DUG Bakken and
Niobrara conference. Whiting has three rigs running in its Redtail prospect
there and plans to add a fourth in August.
Oil from the Niobrara matches the medium crude Alaska North
Slope so well that it may be “demanded by folks on the West Coast,”
said Mark Smith, vice president of development, supply and logistics
for Tesoro, the largest refiner in the West.
Wyoming, home to the Guernsey oil-pipeline hub, issued permits
last year allowing projects with collectively more than 459,000 bpd of
crude trans-loading capacity. It has approved permits for two more sites
this year with as much as 146,000 bpd in capacity.
Musket Corp. runs an oil-by-rail terminal in Windsor, Colorado,
that began loading unit-trains at the beginning of this year. The White
Cliffs pipeline that carries oil from the basin to Cushing, Oklahoma,
is scheduled to double capacity to 150,000 bpd this year.
Colorado to California
California, home to two-thirds of the West Coast’s refining
capacity, received 55,025 bbl of oil by rail from Colorado in December,
the most ever for that month, and took in a record 87,951 bbl from the
state in May 2013. Colorado oil production reached a record 206,000 bpd
in October.
While companies including Noble and Whiting are accelerating
drilling in the Niobrara, Continental Resources decided to allocate spending
elsewhere this year, said John Kilgallon, the company’s vice president
of investor relations. “There has been some success by some operators
there, but we’re not one of them,” Kilgallon said by telephone March 28.
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Five Cat Engines to Power
World’s First LNG-Hybrid Barge
marine.cat.com Posted by Eric Haun Tuesday, April 01, 2014
Caterpillar Marine announced the first shipment of Cat 3500
series marine gas engines from its Lafayette, Indiana manufacturing
facility. Five Cat G3516 marine engines were selected to power the Becker
Marine Systems subsidiary, Hybrid Port Energy, LNG-Hybrid Barge, the
world’s first LNG-powered barge in the Port of Hamburg. The LNG-Hybrid
barge will provide clean and efficient shore power to cold ironing cruise
ships and serve as a backup power provider for the local Hamburg electric
power and heat grid.
The G3516 is a spark-ignited, gas engine specially designed
to operate in commercial vessel applications. The solution is compliant
with the strict Marine Classification Societies requirements, SOLAS
and is certified by Bureau Veritas. The gas fuelled units will be capable
of providing up to 7.75 MW of electric power. Cat dealer Zeppelin Power
Systems led sales efforts on the project and will continue to support
packaging and installation of the Cat power solutions.
“We are working very closely with the technical team from Zeppelin
and Bureau Veritas to provide a customer solution which is not only
safe and environmental friendly, but also very economical in regards
to the lowest cost of operation,” Chris Chenette, Caterpillar Large
Power System marine product value manager, stated. “The G3516 marine
engines represent a pinnacle in efficiency and peak performance, with
the capability to handle the dynamic load profiles in typical vessel operations.”
The base engine is the field-proven, land-based Cat G3516C
Island Mode genset engine which is known for its best-in-class transient
response. The G3516C is a vee-16 configuration, providing 1,550 ekW
at 1,500 rpm. The fuel system is an inlet fumigated low pressure gas
system. It is able to run at 100% power with gas qualities down to Methane
Nr 70. The electronics and control system provide the reliability and
safety that marine customers demand. Additionally, the first generator
set packages recently completed and successfully passed the Bureau Veritas
witness testing at the Zeppelin Power Systems facility in Achim, Germany.
Chenette added, “For this particular project, some changes to the engine
were required in order to meet the strict marine classification society
standards; however we were able to leverage many of the approved solutions
from our current Cat 3500 type approved marine diesel engine.”
“As the world leader in providing gas engine technology,
Caterpillar has made a strong commitment to support the growing demand
for LNG-fuelled solutions in the global marine industry. The Cat G3516C
is just one product in our comprehensive LNG initiative,” Jason Spear,
Caterpillar Marine product definition engineer said. “We’re pleased
to be able to leverage our deep expertise to engineer marine gas engines
and deliver high-performing, value-add solutions to our diverse marine
customers with varying operational needs.”
Spear continued, “As part of our tactical new product introductions,
we are bringing high speed dual fuel solutions to the market for customers
who require the flexibility to operate on diesel in the event natural
gas bunkers are not available. Our Cat LNG engines are a perfect complement
to the recently-introduced MaK dual fuel engines in the 34 and 46 cm
bore class. Moving into the future Caterpillar Marine will be able to
offer a complete line of propulsion and auxiliary engines with configurations
capable of using dual fuel or 100% natural gas.”
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LNG Powered Escort Tugs
Tuesday, April 01, 2014 30 March 2014 Diesel & Gas Turbine
Worldwide
Norway continues to be playground for gas-fueled offshore support
vessel; sister vessel to begin service in spring
Norwegian
shipping company Bukset og Berging said its escort tug MIT Borgøy
is the world’s first tug to be fueled by liquid natural gas (LNG).
The tug was designed by the company’s in-house team, assisted by Marine
Design AS in Norway, and will be operated by Gassco for Statoil at the
KArsto terminal.
It is
the first of two tugs developed by Sanmar’s shipyard in Istanbul for
the Norwegian shipping company —the MIT Borgøy completed its
sea trials successfully and began its maiden voyage in January; and the
second Bukser og Berging tug is planned to sail in mid-April.
The
gas engines, propulsion package and LNG system have been delivered
by Rolls-Royce. Two Rolls-Royce Bergen C26:33L6PG main engines each
supply 1705 kW of power at 1000 r/min. Rolls-Royce said this engine type
is the only engine in the market built for operation on 100% gas fuel
only. The engines are equipped with exhaust silencers with spark arrestors,
and cooling is achieved by plate-type heat exchangers.
Rolls-Royce
also provided two U535 CP azimuth thrusters with four-blade controllable
pitch propellers, each with a diameter of 3000 nun and made from cunial,
a high-strength, corrosion-resistant alloy of copper, nickel and aluminium.
The bow thrusters are Schottel SPJ 82 all-direction thrusters capable
of providing 333 kW.
Additionally,
two diesel fuel generation sets per vessel have been delivered by
the Danish company Nordhavn. The engines are Scania Diesel GAS1 12-07-10-60G
engines, each producing 240 kW at 400 V, 50 Hz.
The
use of LNG eliminates sulfur emissions, bringing particulate matter
(PM) emissions down to almost zero, the company said. The discharge of
CO2 and NOx is reduced by 26% and 80 to 90%, respectively.
The new hull
and propulsion system of the tug will achieve up to 20% higher thrust
efficiency compared to standard designs, Rolls-Royce said.
The vessel
offers a bollard pull of 68 tonnes with a maximum service speed of 13.5
knots.
Rolls-Royce
said an increased availability of LNG and growing public awareness
of the gas fuel is driving its use for a variety of vessels, particularly
gas driven tug boats.
Rolls-Royce
has closed contracts with the Turkish Sanmar Shipyard for the supply
of azimuth thrusters for another 12 new tug boats for various shipping
companies. To date, the Sanmar Shipyard has built 50 tugs equipped with
Rolls-Royce thrusters.
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CAT
new MaK M 34 DF
October 2014 for the New M 32 C-Based MaK M 34 DF
Caterpillar is introducing a new dual fuel natural gas-diesel
engine for marine applications. The new MaK M 34 DF has the same onboard
footprint as the existing M 32 C diesel engine series, and as such is
suitable for a wide range of vessels, from large fishing craft to cargo
ships.
Caterpillar's new MaK M 34 DF natural gas-diesel dual fuel
engine – Initial deliveries are expected in October 2014.
The M 34 DF dual fuel engine has a power rating of 500 kilowatts
per cylinder at 720 and 750 rpm in diesel and gas modes, Caterpillar
says. It will be capable of running on natural gas as an alternative
to marine diesel oil or large and complex scrubber installations for ECA
– Emission Control Area – operations.
The Parsian Shila (Astilleros Armon, Spain) is powered by Cat’s
M 32 C diesel, the basis for the new M 34 DF natural gas-diesel dual
fuel engine.
The M 34 DF will provide full flexibility for vessels operating
in regulated and/or lesser regulated areas without major changes to
the engine room or exhaust gas system, Cat says, “supporting the ease
and simplicity of engine installation and certification.
“Although designed for unlimited operation on LNG, marine
diesel oil and heavy fuel oil,” the manufacturer adds, “the M 46 DF
will reach industry- leading efficiency in gas mode.”
‘Industry-Leading Thermal Efficiency’
“It was important for us that M 34 DF and M 32 C share
the same footprint features, and the same system interfaces,” MaK product
definition manager Detlef Kirste says in the M 34 DF announcement. The
engine “was designed to provide operators with industry-leading thermal
efficiency for lowest total cost of operation,” he said.
“The engine offers optimized load response and load stability
in addition to numerous support features, such as remote monitoring
and engine system diagnostics, helping engine operators with their daily
service and maintenance work. Our target was to keep the typical MaK
marine engine attributes like reliability, safety and efficiency while
striving for an engine design that is easy to service and maintain.”
Trials in Germany, Sales Through MaK
The M 34 DF has a bore of 340 millimeters and stroke of 460,
and “was designed to be the preferred choice for gas electrical and
mechanical propulsion applications notably in the offshore and cargo
segments.
“The engine design features new real-time combustion
monitoring, Flexible Camshaft Technology functionality as well as
a lower valve train and several innovative monitoring and component
solutions to ensure maximum safety during operation.”
The new engine will go through customer acceptance tests and
classification approvals in Rostock, Germany and will be sold through
Caterpillar’s MaK dealer network.
Source: Caterpillar Marine with HHP Insight follow-up
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LNG ISOs replace Propane
FortisBC studies switching Revelstoke from propane to LNG
by Aaron Orlando - Revelstoke Times Review posted
Mar 26, 2014
The company that operates the underground gas pipeline network
in Revelstoke is studying the possibility of switching from propane
to natural gas. FortisBC spokesperson Michael Allison confirmed
the utility is in the very early stages of studying the business case
for the switchover.
Currently, FortisBC uses a bank of large propane storage tanks
located in the industrial park on Powerhouse Road to feed an underground
network that was installed just over 20 years ago. (Fortis didn’t
have the exact date.) The propane is shipped in by rail, and
the tanks are refilled via a rail spur line that runs behind the Powerhouse
Road property.
Spokesperson Michael Allison explained the reason FortisBC
is considering the switch is cost. “We would be exploring this
to save customers money,” Allison said. Propane prices are rising,
and long-term forecasts call for increased prices for the gas, which
is a by-product of oil refining. Natural gas prices are trending
in the opposite direction. “We do see a long-term continued decrease in
natural gas prices,” Allison said.
So, is FortisBC building a 100-odd kilometre pipeline from
the nearest distribution point in Salmon Arm? No, Allison said: “That
is not economically feasible.”
He said FortisBC had looked into the pipeline, but it wasn’t
considering it due to cost.
Whistler switched from propane to natural gas in 2009, after
upgrades to the Sea-to-Sky Highway for the 2010 Olympics made piggybacking
a new pipeline from the Lower Mainland economically viable, Allison
said. What FortisBC is studying is bringing in a relatively new
system to Revelstoke – likely the first of its kind in B.C. if it were
to proceed. The gas utility is proposing using rail-based “isotainers”
filled with liquified natural gas – known as LNG – to feed the gas network.
LNG is natural gas that has been processed, cooled and condensed into
a super-cold liquid state. The tanks would be brought to the existing
facility, feeding the network from there. The tanks are a cylinder that
is contained by a reinforced steel frame. This story was initiated
when the Times Review called FortisBC, after hearing about a possible study.
Allison emphasized the study is in really early stages, and the conversion
is far from certain.
When Whistler switched over to natural gas in 2009, they reduced
gas-related emissions by 15 per cent and gas costs were reduced by
20 per cent at the time. Allison said the current cost reduction is
higher and forecast to increase because the price of the two different
types of gasses are heading in opposite directions. However, it’s
not possible to calculate potential savings in Revelstoke because an apples-to-apples
comparison isn’t available. Whistler is on the gas pipeline network,
which is governed by a complex regulatory framework. The proposed, relatively
new LNG technology for Revelstoke will have different costs, and will
also have to gain approvals through regulators, such as the B.C. Utilities
Commission – which approves a final price.
Until that study is done, any potential cost benefit is unknown;
Allison restated that FortisBC is exploring the plan to see if they
can save customers money.
If the switch is made, customers will need to convert their
appliances to adjust to the change. FortisBC is responsible for the
gas line up to and including the meter, but it would be the residents’
responsibility to deal with an appropriate contractor for anything inside
their property.
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East Kalimantan, Indonesia
CBM Asia
CBM Asia reported plan for commercializing its 705 Bcf resource
at Kutai West PSC
VANCOUVER -- CBM Asia reported plans for the Kutai West PSC development.
CBM Asia’s primary goal for 2014 is to commercialize the Kutai West
Production Sharing Contract (PSC) in East Kalimantan, Indonesia, located
near the Bontang LNG export facility. Achieving early-stage commercial
production will help unlock the value of this asset, which is situated
close to high-priced Asian gas markets.
CBM Asia holds an 18% working interest in the Kutai West PSC,
representing 705 Bcf of recoverable prospective resources net to CBM
Asia from the total 3.9 Tcf estimated by an independent audit conducted
in 2013 by Netherland, Sewell & Associates. Kutai West is regarded
as one of the best and commercially most advanced of the more than 50
awarded CBM blocks in Indonesia.
Kutai West is adjacent to the Sanga-Sanga PSC, where VICO (BP
and partners) is commercially producing and selling CBM for power generation
and gas to the nearby Bontang LNG facility. As VICO notes: “This is the
first time in Indonesia that any CBM facilities have produced and sold
gas and represents a major milestone in the exploration of CBM potential.”
Kutai West will produce from the same coal seams as at Sanga-Sanga.
To date, the company and its partners have drilled four CBM test wells
on the block, verifying thick coal seams (average 105 ft) with high gas
content (average 300 ft3/ton; dry, ash-free basis) and gas saturation
(close to 100%), as well as 5-mD permeability. The KWCBM-01 well is currently
being dewatered, venting produced gas from the flare stack, which is a key
first step towards larger scale production.
Management’s main focus this year is to initiate commercial gas
production at Kutai West with a 5-well pilot, followed by a larger commercial
scale 25-well development (total 30 wells). To this end CBM has reached
consensus with its partners to sell the produced gas to locally installed
gas engine power generation units selling power into the PLN grid and
later to feed gas into the gas-short Bontang LNG export network. Anticipated
gas prices are $8/Mcf or higher. Bontang exports LNG to Japan and other
Asian rim importers, which are critically short of natural gas.
Under Phase 1 four new CBM wells will be drilled near the existing
KW-CBM01, forming an effective dewatering pilot on tight 40-acre spacing
to accelerate gas production and demonstrate commerciality. Produced
gas estimated at 2.0-2.5 MMcfd (gross) would be sold to a power station
developer/operator and PLN for on-site power generation at about $8/Mcf.
The government of Indonesia strongly supports such commercialization prior
to formal Plan of Development (POD) approval. Total capex for Phase 1 is
estimated at $7.16 mn, comprising four wells at $1.46 mn/well cost (drilling
& completion, water management, and surface facilities) plus $1.32
mn in engineering and overhead costs. An additional $200,000 would be required
for field operating expenses during the first year. CBM Asia’s share of
the Phase 1 costs is estimated at $2.15 mn.
The 10-MW power station would employ an array of 1-to5-MW reciprocating
engines; hundreds of such installations already are in operation throughout
Indonesia.The power station would be independently owned and operated,
with no capital required from CBM Asia. Drilling and completing the wells
would require about two months, plus an additional four months to install
and commission the power plant. An updated engineering audit would be conducted
to certify proved and probable reserves, with an excellent chance of
qualifying the project for low-cost Phase 2 project financing.
Following success in Phase 1 and the approval of the Phase 2
POD, CBM Asia and its partners would utilize two rigs to drill an additional
25 wells (30 total) over a 7-month period. The increased production initially
would supply the power station. Pending successful conclusion of a sales
agreement, a 12-in., 20-km pipeline would be constructed to the Badak compressor
station by a third party under BOO basis and funded via an estimated $0.50/Mcf
transport tariff. Total capex for phase 2 is estimated at $36.3 mn with
CBM Asia’s share of costs estimated at $8.0 mn. Production estimated at
12.5 MMcfd (gross) would be sold into the Bontang LNG export network at
approximately $8/Mcf or more. Note that Bontang is the world’s second
largest LNG plant (22.5 mtpa), shipping primarily to Japan, but local
conventional gas supplies are in decline and the facility is currently
operating at less than 60% of capacity.
“The Kutai West and Sekayu PSC’s both have substantial engineered
resources for commercialization, but Kutai West is most viable for near-term
commercial development” noted President and CEO Charles Bloomquist. “We
are focusing our efforts on achieving commercial production and gas
sales at the block as soon as possible, likely before the end of 2014.
We estimate that with completion of the Phase 2 development CBM Asia
will be operational cash flow positive. Jointly with its partners the
company has developed a technical plan and budget for the Kutai West
commercial development and will post details in a new presentation on
its website in the coming days.”
04/07/2014
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