President Donald J. Trump issued an updated presidential permit for the proposed Keystone XL crude oil pipeline on Mar. 29. The move was seen as an attempt to jump-start the project’s construction after a federal judge in Montana blocked it in November and ordered further environmental reviews (OGJ Online, Nov. 9, 2018). US District Judge Brian Morris modified, but did not rescind, his order a few months later (OGJ Online, Feb. 18, 2019).
“This permit acknowledges the project’s importance to the White House once again, and the steps TransCanada Corp., the project’s sponsor, has taken over the years,” a Washington energy observer said. “But there is an injunction still in place which halts construction. The steps from here regarding that injunction depend on what steps the US Department of Justice and TransCanada want to take.”
Business and labor organizations welcomed the president’s action. “The Keystone XL pipeline is one of the most studied pieces of infrastructure in American history. Over the course of a decade, it has been through five environmental reviews on the main route and an additional two on an alternative route,” said Christopher Guith, acting president of the US Chamber of Commerce’s Global Energy Institute.
Noble Midstream announced it has secured a $200 million equity commitment (“Preferred Equity”) from Global Infrastructure Partners Capital Solutions Fund (“GIP”) to fund capital contributions to Dos Rios Crude Intermediate LLC, a newly-formed subsidiary holding Noble Midstream’s 30% equity interest in the EPIC Crude Pipeline.
The 30-inch EPIC Crude Pipeline is being designed with an initial capacity of 590 MBbl/d from the Permian Basin and Eagle Ford to the Gulf Coast. With the installation of additional pumps and storage, EPIC can increase the 30-inch capacity to approximately 900 MBbl/d. Interim service remains on track for startup in the third quarter of 2019 and permanent service is anticipated in January of 2020.
Commenting on the announcement, John Bookout, Chief Financial Officer, said, “We look forward to having GIP as our partner given their extensive energy investing track record and believe this transaction is a further endorsement of our investment in the EPIC Crude Pipeline. This Preferred Equity provides an attractive funding source for the Partnership, allowing us to maintain a prudent balance sheet without issuing common equity as the EPIC Crude Pipeline progresses. We are excited to capitalize on the growing demand for crude oil takeaway and export capability from the Permian Basin and look forward to adding a high-quality source of cash flow to our portfolio. The EPIC Crude Pipeline, together with our other recently announced joint ventures, is a crucial piece in building a leading Permian Basin midstream platform and delivering long-term value for our unitholders.”
Wood has been awarded a $34 million contract from RH energytrans LLC to construct 28 miles of new pipeline designed to carry natural gas from Pennsylvania to Ohio.
Awarded through a competitive tender process, Wood’s scope also includes the construction of the North Kingsville meter station in Ashtabula County, Ohio.
The project is underway and expected to be completed in Summer 2019.
The Risberg pipeline will connect to 32 miles of existing pipeline, originating in the area of Meadville, Penn., extending in a northwest direction and terminating at the North Kingsville meter station.
About 16 miles of new pipeline will be installed in Pennsylvania and 12 miles in Ohio.
A Minnesota regulator has confirmed its approval of Enbridge Inc’s Line 3 crude oil pipeline replacement, allowing the $7 billion project that will ship more barrels out of western Canada to move forward, the company said on Wednesday.
The Minnesota Public Utilities Commissioninitially approvedEnbridge’s plan to rebuild the aging 1,031-mile (1,660-km) pipeline that runs from Alberta to the U.S. state of Wisconsin in June, but that decision was challenged by Minnesota’s governor in February.
On Tuesday, the PUC denied all petitions asking for its decision to be reconsidered, according to minutes of the meeting. Minnesota PUC spokesman Dan Wolf said a formal order will be issued soon.
“The PUC confirmed its decision to approve the conditions placed on L3R’s (Line 3 Replacement) Certificate of Need – conditions meant to protect Minnesotans – allowing this critical energy infrastructure modernization project to move forward,” Enbridge said in a statement.
The decision clears a hurdle for the pipeline and is welcome news for Canadian oil producers struggling with congestion on export pipelines as crude production increases. The discount last year on Canadian heavy crude versus U.S. barrels widened to record levels, prompting the Alberta government to impose production curtailments to draw down crude storage inventories and help shore up prices.
In a blow to Alberta’s oil and gas sector, Line 3 hit a snag earlier this month when Enbridge said its replacement will bedelayed by almost a yearuntil the second half of 2020 while the project awaits state and federal permits.
“It (the PUC decision) is good news for Enbridge undoubtedly, but they still have the issue of local permits that are delayed,” Wood Mackenzie analyst Mark Oberstoetter said.
In its statement, Enbridge said it is hopeful the remaining permitting schedule stays on track.
Line 3, which began service in 1968, currently operates at half its capacity. Its replacement would allow it to return to approved capacity of 760,000 barrels per day.
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(Reuters) – New York energy company Consolidated Edison Inc said on Friday it still plans to impose a moratorium on new natural gas service in parts of Westchester County after March 15 despite a $250 million plan by the state to reduce energy usage.
“The moratorium will still go into effect after March 15,” Con Edison spokesman Allan Drury said, noting the company needs to stop hooking up new gas customers to avoid compromising gas system reliability because of limited space on existing interstate pipelines into the region. Westchester County is north of New York City.
New York State has blocked construction of new interstate pipelines for environmental reasons for years as Governor Andrew Cuomo and other state officials want utilities to focus more on renewable power sources and energy efficiency programs, instead of building more gas and other fossil fuel-fired power plants and infrastructure.
Consumers, however, want access to more gas to heat homes and businesses because it is cheaper and cleaner to burn than oil. This winter, U.S. Northeast households, on average, are expected to spend $723 to heat with gas and $1,646 with oil, according to federal estimates. Drury said Con Edison has received more than 1,300 applications for new gas hookups since notifying the state of the moratorium on Jan. 17, well above the number the company normally receives during a two-month period.
On Thursday, the state announced several steps totaling $250 million to reduce energy consumption and fund alternative energy programs. The state said the programs will “provide immediate relief to Westchester County businesses and residents affected by Con Edison announcement that it will put new applications for firm natural gas service on a waiting list beginning March 15.”
The programs, which are estimated to reduce energy consumption equivalent to the amount of gas needed to heat over 90,000 homes, include funding for clean energy alternatives like electric heat pumps and high-efficiency appliances.
The problem with those programs is they only reduce demand, not boost gas supplies.
To provide gas to more customers and maintain system reliability, Con Edison has said it needs more programs to reduce demand and more interstate pipelines and storage facilities. Several energy companies have tried for years to build gas pipelines from the Marcellus shale in Pennsylvania to New York, but regulators in Albany have denied some of those projects, like Williams Cos Inc’s long-delayed Constitution pipeline.
(Reporting by Scott DiSavino; Editing by Steve Orlofsky)
CALGARY—The National Energy Board has endorsed an expansion of the Trans Mountain pipeline following a reconsideration of its impact on marine life off the B.C. coast.
The energy regulator says an increase in tanker traffic resulting from the pipeline would hurt southern resident killer whales and increase greenhouse gas emissions.
But it says those consequences can be justified in light of what would be the pipeline’s benefits.
“While these effects weighed heavily in the NEB’s consideration of project-related marine shipping, the NEB recommends that the government of Canada find that they can be justified in the circumstances, in light of the considerable benefits of the project and measures to minimize the effects.”
The energy board says it will impose 156 conditions on the project if it is approved. It has also made 16 new recommendations to the federal government.
Among those recommendations are measures to offset increased underwater noise and the greater chance that a whale could be hit by a ship. They also include suggestions for better spill response and reducing emissions from tankers.
The board notes that the new recommendations deal with areas outside its jurisdiction, but within the purview of the federal government.
Reaction from environmental groups was swift.
Stand.earth, which had tried unsuccessfully to widen the scope of the board’s reconsideration, had said before the ruling that it expected the board to endorse the project again.
“Today’s recommendation is the direct result of the Prime Minister’s Office telling the NEB and federal bureaucrats to ‘get to yes’ on this project,” Tzeporah Berman, director of the Vancouver environmental group, said in a statement.
“Scientific evidence filed with the NEB clearly shows that there is not enough data to ensure the safety of the marine environment … and that the NEB failed to address the climate impacts of this project.
“The Trans Mountain pipeline is not in the public interest and will never be built.”
Alberta has been fighting hard for the Trans Mountain expansion so that the province could move more crude oil to ports and from there to lucrative overseas markets.
The energy board’s original approval of the project was set aside last summer by the Federal Court of Appeal, which said the regulator had not properly considered marine life.
The NEB’s report starts the clock on a 90-day period for the federal government to decide whether the project should proceed.
Officials in Natural Resources Minister Amarjeet Sohi’s office have said a final decision won’t be made until consultations with affected Indigenous groups are complete.
The consultations were also an issue the federal Appeal Court raised when it put a halt on the project. It said talks with First Nations in the area had been insufficient.
The regulator’s support does not guarantee restart of construction on the controversial pipeline. Sven Biggs, climate campaigner for Stand.earth, predicted before the ruling that there will be more lawsuits and delays resulting from the board’s support of the project. He also said there will be protests in the streets and along the pipeline route if Ottawa decides to go ahead
Vanessa Adams, spokeswoman for Sohi, wouldn’t comment on Thursday on whether a cabinet ruling could be delayed.
She said in an email the federal government wants to “achieve the required public trust” to help move resources to market by first addressing environmental, Indigenous and local concerns.
She said a 60-member consultation team in British Columbia and Alberta has met with more than 85 of 117 Indigenous groups that would be affected by a Trans Mountain expansion and more meetings are taking place daily.
ISLAMABAD (Reuters) – Pakistan plans to offers dozens of gasfield concessions in the coming year to fill in a fuel shortage, a senior official said, with Islamabad hoping a sharp drop in militant violence and changes to exploration policy will attract foreign investors. To encourage development, the government also plans to make its pipeline system more accessible and affordable.
“The entire mechanism of how the pipeline system is working today is being is being re-looked at, to make it more deregulated, make it more open access.”
Much of the mineral-rich South Asian nation remains unexplored despitegasdiscoveries dating back to the 1950s. Conventionalgasreserves are estimated at 20 Tcf, or 560 Bcm, and shalegasreserves, which are untouched, at more than 100 Tcf.
Italy’s ENI and U.S. oil major Exxon Mobil are jointly drilling forgasoffshore in Pakistan’s Arabian Sea, but many other Western companies have not returned after leaving more than a decade ago because of Islamist militant violence.
Nadeem Babar, head of Prime Minister Imran Khan’s Task Force on Energy Reforms, told Reuters the government was amending its naturalgasregulation and drawing up its first-ever shalegaspolicy, with licensing rounds to follow later this year.
The government hopes improving security in recent years and the country’s extensivepipelinenetwork will attract investors.
More than 30 onshoregasblocks have been identified and the government plans to auction a large chunk of them in one or two licensing rounds by the end of 2019, Babar said in his office in the capital Islamabad.
“I expect in the second half of this year we will be auctioning at least 10, if not 20 blocks for exploration.”
Pakistan’s domesticgasoutput has plateaued in the last five years, falling to 1.46 trillion cubic feet in 2017/18, from 1.51 Tcf in 2012-2013, according to an annual report from the Petroleum Ministry.
This has led to severegasshortages as Pakistan’s population, now at 208 million people, has risen sharply over the same period, driving fuel demand from industries and new power plants higher.
Gasdemand was estimated at 6.9 Bcf/d for 2017-18, according to Pakistan’s Oil &GasRegulatory Authority, nearly 3 Bcf more than daily output.
To help plug the deficit, Pakistan has built twoLNG import terminals, and demand is expected to hit 6.97 Bcf/d a day for 2018-19, and 7.06 Bcf/d in 2019-20.
But LNG is expensive, so Islamabad wants foreign companies to ramp up domestic exploration.
Babar said Pakistan was also drafting its first shalegaspolicy and it should be finished this year, with a licensing round in the first half of 2020.
One recent study by the U.S. Agency for International Development (USAID) put Pakistan’s shalegasreserves at more than 100 Tcf in the Lower Indus Region alone, enough to meet current demand for at least a few decades.
One of the keys to developing naturalgasproduction is to give investors affordable and reliable access to apipelinenetwork, Babar said, and such a plan is being drafted.
“The entire mechanism of how thepipelinesystem is working today is being is being re-looked at, to make it more deregulated, make it more open access,” Babar said.
Prolific Blocks and Good Data
Babar said the blocks for auction were “prolific and … (had) good data”, with interested companies including Saudi Arabia’s Aramco, Exxon Mobil and Russia’s Gazprom.
Only about 4 percent of Pakistan’s landmass has been explored, and the success rate, with one out of three wells making a find, is above the international average, he said.
Babar said at least three more offshore blocks have also been carved out near where Eni and Exxon are searching forgas.
“We will be auctioning those … probably next year.”
To address security concerns, Babar said a military or a paramilitary unit will be created to guard companies that are exploring in the riskier parts of Pakistan, with the companies paying the costs.
“A mechanism like what was done in CPEC will be developed,” Babar said, referring to a 15,000-strong army division set up to safeguard Beijing-funded infrastructure projects in the China-Pakistan Economic Corridor (CPEC).
Pakistan also plans to introduce measures that ensure auction rights are unaffected by government or policy changes, to give investors greater regulatory certainty.
(Reporting by Drazen Jorgic; Editing by Henning Gloystein and Tom Hogue)
Conventional wisdom used to be that as the major integrated oil companies acquired smaller independents, production growth in the Permian Basin would slow. The same wisdom held that regardless which companies were operating in the Permian and other shale plays, domestic U.S. production would peak in the mid-2020s and then begin to decline.
If what the major integrated companies are saying about the Permian is true, it presents serious questions for global oil markets, particularly for the cartel otherwise known as OPEC. It’s also represents a challenge to future projects in the deep-water offshore, oil sands, the Arctic and other higher-cost basins.
Let’s start with OPEC where the impact could be most damaging. The cartelexpects shale growth to “slow significantly” after 2023, causing U.S. output to peak at 14.3 million barrels a day by 2028. OPEC then expects U.S. production to fall to an average of 12.1 million barrels a day by 2040.
That’s a convenient outlook if you’re a member of OPEC. In recent years, U.S. shale has single-handedly been meeting increases in global oil demand, forcing theSaudi-led cartel to curtail productionto avoid a price collapse. No doubt the members of OPEC, along with co-conspirator Russia, would prefer to see U.S. production reversed sooner rather than later.
After 2025, the “baton gradually passes to OPEC to meet continued – albeit slowing – growth in global oil demand,” according to the most recent IEA long-term outlook.
If this scenario doesn’t materialize, OPEC will have some tough decisions to make, including whether to challenge shale to another price war. Thecartel lost the last time it took on shale in 2014. And it started subsidizing U.S. production in late 2016 when it agreed to the production curbs that remain in place today.
Unless OPEC and Russia are prepared to live with the supply cut arrangement indefinitely, the cartel may need to throw down the gauntlet… again. That’s because thedata presented this weekby Exxon and Chevron, now two of the most significant players in the Permian, paints an extremely rosy picture for the future of the basin, even under lower oil price scenarios.
The two majors are expected to produce close to 2 million barrels of oil equivalent a day combined from the Permian by the mid-2020s, effectively tripling their 2018 output. Chevron plans toincrease production to 600,000 barrels a day by 2020, reaching 900,000 barrels a day by 2023. Exxon, meanwhile, expects its Permian production to hit 1 million barrels a day by 2024.
Perhaps more importantly, the Permian has proven to be among the most profitable assets in the companies’ global portfolios.
Exxon analysts say the company’s wells in the Permian are capable of delivering returns of more than 10 percent at an oil price as low as $35 a barrel.
Neither company expects growth to ebb in midterm. “This doesn’t end where our charts end, not even close,” said Wirth, adding that Chevron is not yet recovering “high single-digits” percentages of the hydrocarbon locked in its shale rocks. “If we left 90 percent of the oil and gas behind, it would be a first time in our history.”
Comments like that should serve as a wake-up call to global oil markets. The Permian is not only driving growth for the two companies – Exxon produces a whopping 4 million barrels of oil equivalent every day – it’s also proving to be among their most profitable and robust sources of free-cash flow.
There have always been doubts about shale’s capacity to generate cash. In the early days of the shale boom when swashbuckling independents dominated the plays, growth was the name of the game.
Those days came to an end with the price collapse in 2014, which put investors’ focus back on financial performance and cleaning up messy balance sheets. The current trend of major oil companies expanding and consolidating their shale assets represents the sector’s “third act.” Producers are moving into harvest mode, having already optimized the efficiency of their operations.
The other advantage the majors hold is the financial resources to invest in pipelines and other midstream infrastructure, as well as new refining and petrochemical capacity to process the surplus of light, sweet crude and associated gas that shale basins generate.
The potential effect of all this on the future investment strategies of the global oil industry should not be underestimated.
If the majors can maintain a low-breakeven cost in the Permian while boosting output, OPEC will need to recalculate but so will other investors in conventional “long-cycle” projects that require longer development times and higher oil prices to be profitable. Deep-water and oil sands operators are hereby put on notice: compete with shale on cost or else.