If approved by band members, the deal will transfer roughly $1 billion in cash to the Lax Kw’alaams band over 40 years, while the B.C. government is putting more than $100 million worth of Crown lands on the table. For the 3,600 members of the Lax Kw’alaams band, the package works out to a value of roughly $320,000 per person. The proposed pact hinges on federal environmental approval of the Petronas-led Pacific NorthWest LNG project, to be built on the traditional territory of the Lax Kw’alaams.
In British Columbia, most of the land base is still subject to Native claims, and recent court rulings have firmly established the existence of aboriginal title. Lax Kw’alaams members will vote in May on the offer from Pacific NorthWest LNG, TransCanada and the B.C. government. TransCanada’s pipeline would carry gas from northeastern British Columbia to Pacific NorthWest LNG’s planned export terminal. In addition to the cash and lands, the deal includes job training and employment, funding to pave a local road, and creating a fisheries compensation fund.
Chevron says no investment decision on B.C. LNG project in 2015
http://nwcoastenergynews.com/2015/05/01/7428/fid-kitimat-lng-2015-chevron-tells-investors/
(Northwest Coast Energy News; Kitimat, BC; May 1) - Chevron will not be making a final investment decision on the Kitimat LNG project in British Columbia in 2015, Pat Yarrington, the company’s vice president and chief financial officer, told the first-quarter earnings conference call May 1. All investment decisions for Chevron projects around the world, with one exception, are on hold for this year, Yarrington said.
“In terms of other FID projects, part of the reduction that we took in our capital spending from 2014 to 2015 really did relate to the pacing of other major capital projects,” she said. “Kitimat is a primary one there, we moved spending on that out considerably. We are only limiting our self to appraisal work and continuing to look at the design and the cost structure. “
Chevron’s new partner in Kitimat LNG is the Australia-based oil and gas company Woodside Petroleum, which purchased Apache’s half interest in Kitimat. The proposal started more than a decade ago as an LNG import terminal, but the plans switched to exports after the shale gas boom flooded the North American market with gas. The original owners left years ago, with Chevron buying into the export proposal in 2012.
LNG hopeful asks Texas county for 10-year, 100% property tax break
http://www.brownsvilleherald.com/premium/article_06c246f6-eede-11e4-ba1b-f7dc84862715.html
(The Brownsville Herald; Texas; April 29) - The Cameron County Commissioners Court has agreed to enter into contract negotiations with Houston-based Annova LNG over the company’s request for a 100-percent property tax abatement from the county as an economic development incentive to build a liquefied natural gas export terminal at the Port of Brownsville, Texas.
Annova LNG, owned by Chicago-based utility services holding company Exelon, is one of several companies that have proposed LNG export terminals on the Brownsville Ship Channel. The company claims that even with the tax abatement, construction and operation of its LNG plant would bring substantial economic benefit to the county in the form of jobs and investment. State law allows for tax abatements in economically challenged counties in order to spur economic development.
Annova said it plans to spend $2.9 billion over three or four years on construction of the LNG plant in three stages. The requested tax abatement would last for 10 years. County Judge Pete Sepulveda Jr. said commissioners haven’t crunched the numbers but will look closely at the long-term impact of the tax break before making a decision whether to grant it. “We’re not going to automatically give it to them,” he said. The Annova project is among multiple LNG export terminals proposed for the U.S. Gulf Coast.
North Dakota lowers oil tax rate in exchange for eliminating tax break
(Wall Street Journal; May 1) - North Dakota, the nation’s second-largest oil producer, is revamping the way it taxes the oil industry amid the recent slump in oil prices, aiming to tone down big fluctuations in tax revenue. Republican Gov. Jack Dalrymple on April 29 signed a tax-overhaul bill passed in the final days of the legislative session, as concern grew that the state could miss out further on oil-tax collections because of a provision that drops a tax rate to zero for most wells when prices stay below a certain threshold.
North Dakota’s tax system was designed more than two decades ago to give producers an incentive to keep pumping during low prices. But the shale oil boom of recent years means that a tax-lowering provision in the law opens up the state to big swings in revenue. Under the law, if oil remains below $55 a barrel for five months, the extraction-tax rate — one of two major taxes on production in the state — falls to zero from 6.5 percent for most oil. The zero rate hasn’t yet been triggered, but state officials forecast it could kick in next month, resulting in an estimated revenue drop of $75 million a month.
The tax overhaul passed in recent days would eliminate the rate reset. In exchange, lawmakers would drop the tax rate to 5 percent from 6.5 percent. Supporters say the bill tries to strike a balance, giving up potential revenue over the long term in exchange for eliminating sharp collection swings possible under the previous structure’s zero-percent rate. The North Dakota Petroleum Council said the new structure would provide the industry with a tax structure that is stable and more competitive.
Oregon LNG developer says local permit denial not a problem
(Platts; May 1) - Oregon LNG still plans to move ahead with its proposed $6.3 billion liquefied natural gas export facility in Warrenton, Ore., despite a state agency decision upholding a county denial of a land-use permit for a pipeline to deliver gas to the facility, CEO Peter Hansen said May 1. The Oregon Land Use Board decision would have no effect on the LNG project, he said, because the Federal Energy Regulatory Commission, not the state, will regulate the development.
The Oregon Land Use Board of Appeals April 29 in a 38-page decision upheld Clatsop County's denial of a permit for construction of a 40-mile segment of an 87-mile gas pipeline that would run through the county. In April, FERC set a schedule for environmental review of Oregon LNG's proposal to build an LNG facility near the mouth of the Columbia River. The federal agency expects to issue its final environmental impact statement for the project — the LNG plant and the pipeline — in February 2016.
Hansen said the project sponsor has decided to ignore the actions of the county and state board, as they are irrelevant to the project’s outcome. "We have had this ongoing conflict with Clatsop County for years and we knew that they were not going to issue us a local permit, but we don't need a local permit. It's a FERC-jurisdiction pipeline and it's very clear that local governments do not have jurisdiction and the state is not allowed to give them jurisdiction," he said. "The county has adopted an anti-fossil fuel position.”
China the big question in global LNG demand growth
https://rbnenergy.com/a-whole-new-world-asian-lng-demand-and-north-american-gas-production
(RBN Energy; April 30) - The pace of liquefied natural gas demand growth in Asia will be a critical factor in determining how much natural gas North American producers export over the next 10 to 20 years. Last year's pause in Asian LNG demand growth — combined with a collapse in LNG prices — led many to wonder, where is all this heading, and what does it mean for gas producers and LNG exporters?
The vast majority of the world’s LNG demand growth is expected to occur in Asia, most of it in China and India and as a bunker fuel for ships, with demand growth in China the biggest wild card. And much of that will depend on how much natural gas China gets delivered by pipeline from nearby regions of mainland Asia. In 2014, China imported 19 million metric tons of LNG — the equivalent of about 2.4 billion cubic feet per day — ranking it third among Asian LNG importers behind Japan and South Korea.
China is expected to at least double — and perhaps triple or quadruple — LNG imports by the early 2020s, mostly to feed new gas-fired power plants and industrial growth. An important driver is the need to clean up air pollution, dirtied by coal-fired power plants. The question isn’t whether China’s demand for gas will grow substantially, it’s where the gas will come from. China hopes to develop more of its own gas reserves, and it has been reaching deals to import increasing volumes of gas via pipeline. That leaves LNG as the balancing source of supply — and as additional diversity of supply.
Gas-turbine modules built in Italy for Gorgon LNG
http://www.pddnet.com/news/2015/04/gas-turbine-generator-starts-one-worlds-largest-gas-projects
(Product Design & Development; April 30) - Five hundred years ago, Michelangelo fashioned David from Italian marble cut out of the mountains towering over the Tuscan town of Carrara. Today, the area is in the business of making Goliaths. Adjacent to Carrara are the towns Avenza and Massa, the home of two huge plants and testing fields where GE’s oil and gas business builds some of the world’s largest industrial equipment, including five gas-turbine generators for the Chevron-operated Gorgon LNG project in Australia, one of the world’s largest natural gas developments.
The first module just started generating electricity on Australia’s Barrow Island, as the project moves ever closer to producing LNG. Power from the GE modules will drive the compressors and refrigeration units that will liquefy natural gas coming from the sea floor. Each of the modules weighs as much as four double-decker Airbus jets. GE started shipping them from Italy to their new home more than 12,000 miles away three years ago. The $53 billion Gorgon project is expected to start shipping LNG in 2016.
The beating heart of each power module, which takes about a year to complete, is a massive gas turbine made at a GE plant in France. In total, the five gas-turbine generators will have a combined site rating of 584 megawatts of electricity to support the Gorgon LNG plant. Workers in Avenza applied six miles of structural welding to assemble the steel trusses that support each 2,300-ton module and hold the turbine in place, and also attached 12 miles of electric cable.
EIA reports on oil, gas and coal permanent funds in eight states
http://www.eia.gov/todayinenergy/detail.cfm?id=21032&src=email
(U.S. Energy Information Administration; April 30) – Several states set aside a portion of their revenue from non-renewable resources — coal, oil and natural gas production — for strategic or long-term use. Similar to an endowment, the states typically only spend the earnings and investment gains from these funds, according to a report by the U.S. Energy Information Administration. Expenditure of principal from the funds is usually prohibited unless authorized by legislative approval or constitutional amendments.
Eight states have such funds, primarily bankrolled by coal, oil or gas tax revenues. Many of the funds also include revenue from royalties and leases on public lands granted to states by the federal government at the time of statehood, such as school or university funds. For example, the Texas Permanent School Fund was established in 1854 to provide funding for public education. Today the $37 billion fund is predominantly dependent on revenue received from oil and gas development on state lands.
Alaska’s Permanent Fund, created in 1976, has a $52 billion balance that exceeds the balance of national funds of major oil and gas producers such as Venezuela, Mexico and Angola. Constitutional amendments in the 1970s created funds in New Mexico and Wyoming. Wyoming’s trust fund consists of all severance tax revenue derived from coal, oil, gas and other minerals. The fund’s income is annually distributed to support the state general fund. New Mexico's fund sets aside a portion of severance tax revenue to support the general fund, as well as public education and infrastructure development.
Explorers are canceling offshore drilling contracts
(Wall Street Journal; April 28) - Offshore drillers are bracing for a wave of contract cancellations as energy companies try to cut their costs to cope with low oil prices. Big oil and gas companies lease drilling rigs and crews, often for years at a time and at a cost of up to $400,000 a day. The industry has long considered these leases basically unbreakable. But now several drilling companies have reported that some clients are trying to get out of leasing deals — and analysts say a flood may follow.
“We expect additional contract cancellations,” said Angie Sedita, an analyst at the investment bank UBS. “Offshore rigs could be offered for free and most oil companies would still not want to drill.” Analysts are likely to be pressing offshore specialists on their contracts as they report first-quarter earnings. In the past, energy companies’ worries about their ability to hire rigs in the future kept them from backing out of leases, analysts said. But that has changed now that global oil prices have fallen.
BP said April 28 that it was paying $375 million to cancel contracts for two deep-water rigs in the Gulf of Mexico. Diamond Offshore Drilling, basedin Houston, has been preparing for the termination of six of its rig contracts — four with Mexico’s Petróleos Mexicanos, one with Brazil’s Petróleo Brasileiro and one with U.K.-based Dana Petroleum. Jackson Sandeen, an analyst for Wood Mackenzie, said cancellations are surprising. “This is something new,” he said. “It’s abnormal … cutting these contracts.”
TransCanada has to wait for South Dakota to re-certify Keystone line
(Financial Post; Canada; April 29) - TransCanada was expecting that South Dakota’s re-certification of the Keystone XL pipeline would be a routine procedure to determine that the project was still relevant. After all, the permit for construction of the 310-mile portion of the Alberta-to-Nebraska pipeline traversing South Dakota had sailed through the state regulator’s desk five years ago without much opposition.
But the process has dragged on for more than eight months, as environmental, Native American and citizen groups opposed to the pipeline attempt to delay the process. The South Dakota Public Utilities Commission set July 27 for a hearing on the re-certification process, which will see as many as 40 interveners, most of them environmental groups. “Normally, we issue a siting permit and construction begins,” Chairman Chris Nelson said. “Coming back four years later is not really something we have dealt with before.”
The commission had initially authorized the Alberta-to-Nebraska crude oil line in June 2010, but state rules dictate permits must be re-authorized if construction has not begun within four years of their issuance. The $10 billion project has been under review by the U.S. State Department for the past six years. The unprecedented legal wrangles are now routine for TransCanada. “Whether or not we are surprised that this hearing has taken a life of its own — the answer is no,” TransCanada spokesman Mark Cooper said.
U.S. regulators issue new rules for oil-by-rail
(Wall Street Journal; May 2) - U.S. transportation regulators May 1 issued tough new rules for railroads hauling crude oil and ethanol that will require trains to be equipped with expensive new brake systems. The regulations also require that sturdier tank cars be built for hauling oil, ethanol and other flammable liquids, and prescribes upgrades for an estimated 154,500 tank cars already carrying flammables.
Trains carrying large amounts of oil will be restricted to 30 miles per hour if they don’t have electronic brakes installed by 2021. In addition, trains with either a block of 20 or more cars or a total of 35 or more cars of flammable liquid will be required to use a second locomotive to help with braking. The rules, unveiled in a joint announcement by U.S. and Canadian officials, were tougher than expected. The electronically controlled pneumatic brakes deploy faster than the air brakes now used on freight trains.
Railroads maintain that installing the brakes on existing railcars and locomotives would be prohibitively expensive and take years to fully implement. The cost of installation on an existing railcar is estimated at $8,000 to $10,000, according to industry consultants. The decade-long phase-in for upgrading tank cars already in service is double the time originally suggested by U.S. regulators. Several fiery crashes of crude-oil trains have ratcheted up pressure on government officials to reduce the risks posed by dozens of crude-oil trains a day traveling through metropolitan areas on their way to refineries.
Qatar now collects 90% of boil-off gas in LNG ship loading
(Gulf Times; April 29) – The $1 billion Jetty Boil-Off Gas Recovery (JBOG) Project in Ras Laffan, Qatar, was inaugurated April 28. “The JBOG facility will recover the gas flared during liquefied natural gas loading at the six LNG berths in Ras Laffan Port,” said Saad Sherida al-Kaabi, CEO of Qatar Petroleum. Al-Kaabi, who is also Qatargas chairman, said the project is part of the common facilities at Ras Laffan, operated by Qatargas.
As of April 2015, Qatargas had recovered jetty boil-off gas from 500 ships since the JBOG facilities started up in October 2014. The project salvages gas normally lost and burned off in a flare. Officials said it will result in a 90 percent reduction in flaring at the Ras Laffan port in northern Qatar, the largest LNG export terminal in the world.
Instead of the wasted gas being flared, JBOG collects the fuel and transports it to a facility where it is compressed to be ready for use again either as LNG or fuel gas.