Pipeline News

Where does the world’s oil and natural gas come from?

Canada is a leading producer of oil and natural gas, and one of the few with strong environmental standards. 


Where does your oil and natural gas come from? And in a world where energy demand is increasing (an estimated 27 per cent by 2040), where oil demand will increase due to rising use of petrochemicals, and natural gas demand will increase as emerging economies seek to decrease greenhouse gas (GHG) emissions by displacing coal—shouldn’t that energy come from a nation like Canada?

Canada is one of the few top producers with an oil and gas industry open to investment (most are state-owned), with transparent reporting of environmental performance. We are a world-leader when it comes to our regulatory standards, environmental innovation and commitment to reducing GHGs.

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Con Edison Halts Gas Hookups, Citing Interstate Pipeline Constraints


(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.

Con Edison Halts Gas Hookups, Citing Interstate Pipeline Constraints

“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)

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NEB Gives Trans Mountain Pipeline Expansion Its Endorsement


February 22, 2019 Updated: February 22, 2019

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.”

NEB Gives Trans Mountain Pipeline Expansion Its Endorsement
Pipes are seen at the Kinder Morgan Trans Mountain facility in Edmonton, Alberta on April 6, 2017. (Jonathan Hayward/The Canadian Press)

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., 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.”

NEB Gives Trans Mountain Pipeline Expansion Its Endorsement
An oil tanker goes under the Lions Gate Bridge as it enters Vancouver Harbour on May 5, 2012. Now, 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 Canadian Press/Jonathan Hayward)

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.

Audrey Siegl of the Musqueam First Nation chants and beats a drum during a protest outside National Energy Board hearings on the proposed Trans Mountain pipeline expansion in Burnaby, B.C., on Jan. 19, 2016. (THE CANADIAN PRESS/Darryl Dyck)

The regulator’s support does not guarantee restart of construction on the controversial pipeline. Sven Biggs, climate campaigner for, 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.

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Pakistan to Open Gas Fields, Pipelines to Attract Foreign Investment


ISLAMABAD (Reuters) – Pakistan plans to offers dozens of gas field 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 despite gas discoveries dating back to the 1950s. Conventional gas reserves are estimated at 20 Tcf, or 560 Bcm, and shale gas reserves, which are untouched, at more than 100 Tcf.

Italy’s ENI and U.S. oil major Exxon Mobil are jointly drilling for gas offshore 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 natural gas regulation and drawing up its first-ever shale gas policy, with licensing rounds to follow later this year.

The government hopes improving security in recent years and the country’s extensive pipeline network will attract investors.

More than 30 onshore gas blocks 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 domestic gas output 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 severe gas shortages 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.

Gas demand was estimated at 6.9 Bcf/d for 2017-18, according to Pakistan’s Oil & Gas Regulatory 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 shale gas policy 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 shale gas reserves 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 natural gas production is to give investors affordable and reliable access to a pipeline network, Babar said, and such a plan is being drafted.

“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,” 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 for gas.

“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)

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Booming Permian Rewriting Rules For Global Oil Industry

Booming Permian Basin Rewriting Rules For Global Oil Industry

Dan Eberhart

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.

It’s time to reassess those assumptions.

Bullish projections this week from Exxon Mobil and Chevron on their separate operations in the Permian are rewriting the conventional wisdom about that basins potential.

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 cartel expects 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 the Saudi-led cartel to curtail production to 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.

The cartel is not alone in thinking that the dominance of American shale must have an expiration date. The International Energy Agency, the consumer watchdog for developed countries, also sees the market the same way. The IEA expects shale production to plateau in the mid-2020s, ultimately falling by 1.5 million barrels a day in the 2030s due to resource constraints.

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. The cartel 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 the data presented this week by 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 to increase 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.

Profit margins are even higher at Chevron, which owns most of its land outright and doesn’t have to pay landowners for drilling rights. “Shale returns are the highest in our portfolio,” said Chevron CEO Mike Wirth, adding they are “north of 30 percent at low oil prices.”

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.

And it’s not just Exxon and Chevron, Royal Dutch Shell and BP are also building prominent positions in the Permian. The superior scale and integrated-asset portfolios of the majors make them well situated to handle shale’s challenges, including pipeline constraints, surplus production of associated natural gas, and workforce shortages.

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.

What’s a realistic forecast for U.S. production? Rystad Energy is probably on point with its prediction that U.S. liquids production will surpass 24 million barrels a day in the next six years at an average U.S. benchmark price of $58 a barrel. But the more interesting question is what happens if U.S. output continues to rise beyond 2025.

Source article: FORBES

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ExxonMobil Ups Permian Output Target to 1 Million Barrels per Day by 2024


ExxonMobil said Tuesday it has revised its Permian Basin growth plans to produce more than 1 million BOE/d by as early as 2024 – an increase that is driving significant pipeline and infrastructure development.

The Irving, Texas-based oil giant’s new target represents a significant boost in size and speed over plans set only a year ago, when it announced a goal of tripling total daily Permian production to more than 600,000 BOE/d by 2025.

ExxonMobil Ups Permian Output Target to 1 Million Barrels per Day by 2024

Exxon then said it would support its increased production by investing more than $2 billion in terminal and transportation expansion, including pipeline construction from the Permian Basin to the Gulf Coast.  The company formed a joint venture with Plains All American Pipeline last year to build a 1 MMbd pipeline to refineries in Baytown and, this January, said it would nearly double the capacity of its 365,000 bpd Beaumont refinery.

“We’re increasingly confident about our Permian growth strategy due to our unique development plans,” said Neil Chapman, ExxonMobil senior vice president. “We will leverage our large, contiguous acreage position, our improved understanding of the resource and the full range of ExxonMobil’s capabilities in executing major projects.”

The size of the company’s resource base in the Permian is approximately 10 billion oil-equivalent barrels and is likely to grow further as analysis and development activities continue.

Exxon said its anticipated increase in production will be supported by further evaluation of its Delaware Basin’s increased resource size, infrastructure development plans, and secured capacity to transport oil and gas to ExxonMobil’s Gulf Coast refineries and petrochemical operations through the Wink-to-Webster, Permian Highway and Double E pipelines.

ExxonMobil is actively building infrastructure to support volume growth. Plans include construction at 30 sites to enhance oil and gas processing, water handling and ensure takeaway capacity from the basin. Construction activities include central delivery facilities designed to handle up to 600,000 barrels of oil and 1 billion cubic feet of gas per day and enhanced water-handling capacity through 350 miles of already-constructed pipeline.

“These investments support growth plans and ensure that as production levels continue to rise, we are well positioned in processing and transportation capacity,” Chapman said.

Exxon’s investments in the Permian Basin are expected to produce double-digit returns, it said, even at low oil prices. At a $35 per barrel oil price, for example, Permian production will have an average return of more than 10 percent, the company said.

“Our plans are attractive at a range of prices and we expect them to drive more value as we continue to lower our development and production costs,” Chapman said.

ExxonMobil remains one of the most active operators in the Permian Basin and has 48 drilling rigs currently in operation and plans to increase its rig count to approximately 55 by the end of the year.

Increased use of technology, including enhanced subsurface characterization, subsurface modeling and advanced data analytics to support optimization and automation, will help the company reduce costs, improve its development plan and increase resource recovery, Exxon said. – P&GJ

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“Most sweeping oil and gas reforms” in Colorado history proposed by state legislators

Heated Debate Over “Most Sweeping Oil & Gas Reforms” in Colorado’s History


Tyler Silvy of the Greeley Tribune

Republicans and industry groups are urging Democratic lawmakers in Colorado to wait just a minute when it comes to a newly introduced, sweeping oil and gas regulations bill scheduled for a hearing Tuesday.

But bill sponsor and Senate Majority Leader Steve Fenberg is calling the industry and Republican handwringing nothing more than a political stunt.

Senate Bill 19-181 was introduced about 5 p.m. Friday, a day after a joint news conference involving sponsors Fenberg, D-Boulder; Speaker of the House K.C. Becker, D-Boulder; and Gov. Jared Polis, among others.

The bill would make a variety of changes to oil and gas law in Colorado, including the following:

  • It would change the mission of the Colorado Oil and Gas Conservation Commission from one of fostering oil and gas development to one of regulating the industry. It also changes the makeup of the COGCC board.
  • It would provide explicit local control on oil and gas development, opening the door for local government-instituted bans or moratoriums, which have previously been tied up in court battles because the industry has been considered one of state interest.
  • It would change the way forced or statutory pooling works, requiring a higher threshold of obtained mineral rights before companies can force pool other mineral rights owners in an area.

The bill is set for a hearing at 2 p.m. Tuesday in the Colorado Senate, and in news releases sent Sunday afternoon, the Colorado Oil and Gas Association, the Colorado Petroleum Council and the Colorado Republican Party all shared the same basic message: “This is going too darn fast.”

“We’re asking that Senate President Garcia and others allow for a transparent stakeholder process that includes impacted Coloradans, including local governments, environmental interests, regulators, and industry,” CPC Executive Director Tracee Bentley and COGA President Dan Haley said in a joint news release Sunday.

Colorado Republicans echoed those sentiments, albeit with a more political edge when addressing the schedule for the bill.

“This wasn’t a mistake — it’s a planned attempt to get this bill through the legislature as quickly as possible and prevent working Coloradans from speaking up,” Colorado Republican Committee Chairman Jeff Hays said in the release.

Fenberg didn’t laugh, but he did say it was funny that industry groups were putting on such a public show, as they were all involved in the process, and nothing in the bill should come as a surprise to them.

Fenberg said he has met with anybody who requested a meeting, including COGA, the American Petroleum Institute, Noble Energy, Anadarko and Extraction, among many others.

“We didn’t write this bill in a black box,” Fenberg said. “We solicited and received input from all stakeholders.”

In a follow-up statement sent to The Tribune on Sunday night, Bentley acknowledged that industry groups met with Democratic leadership and offered potential solutions. But she called the process highly unusual.

“We were promised a true stakeholder process where we could see a draft and have the opportunity to comment,” Bentley said. “That did not happen.”

Fenberg has an idea as to why industry groups and Republicans are railing against the process, saying it’s more about stalling than anything.

“They want to delay the bill to spend money on lobbying and putting up TV ads to try to kill the bill,” Fenberg said. “They have very expensive lawyers who either submitted language (for the bill) or are reading the bill. They don’t need more time to understand it; they need more time for politics.”

Bill sponsors have already taken their lumps from Weld County Republicans, including Weld County Commissioner Chairwoman Barbara Kirkmeyer, who railed against the “Boulder legislators” ramming through legislation without bothering to consult with Weld, the largest oil and gas producing county in the state.

Fenberg said sponsors met with Colorado Counties Incorporated, of which Weld County is a part, and with the Colorado Municipal League.

Sen. John Cooke, R-Greeley, said Democrats were “playing games.”

“And unfortunately, they’re playing games with people’s livelihoods,” Cooke said.

John Cooke

Like the others, Cooke said Democratic leadership should have a more robust stakeholder process, and said it was happening too quickly. For context, he pointed to a transportation bill he introduced in the first week of the session that still hasn’t been scheduled for a hearing.

When asked about the average wait time for a hearing for a bill introduced by the majority party, Cooke said it’s a minimum of two weeks.

Fenberg said there have been other bills this session that have reached a first committee hearing just as quickly as SB 19-181.

Further, Fenberg said this is the first of six proposed committee hearings — three in the Senate and three in the House. When it comes to feedback, Fenberg said, there’s plenty of time.

“That’s the purpose of committee hearings,” Fenberg said. “There will be amendments. There’s input — public input, people who support it, people who oppose it, people who think the bill doesn’t go far enough, people who think the bill goes too far.”

Cooke is also the assistant minority leader in the Colorado Senate, and as such he and Minority Leader Sen. Chris Holbert, R-Douglas County, meet with Senate President Leroy Garcia and Senate Majority Leader Fenberg every Monday.

Cooke said Republicans on Monday will ask Democrats to delay the hearing for SB 181, but he’s not optimistic.

“We’re going to ask, but they’ll probably say no,” Cooke said.

— Tyler Silvy is a content manager for The Greeley Tribune. Reach him at Connect with him at or @TylerSilvy on Twitter.

Rally For Colorado Energy! Click Here!!!

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Williams & Targa Resources NGL Pipeline

Williams and Targa to Construct Nearly 300 Mile of NGL Pipe in New $600 Million Investment

Williams and Targa Resources Corp. have announced that they will be working on a new NGL pipeline. The agreement will have the project link the Conway, Kansas, and Mont Belviue, Texas NGL markets.

The 188 mile Bluestem Pipeline will be built by Williams from its fractionator in Conway, Kansas and the terminus of Overland Pass Pipeline to an interconnect with Targa’s Grand Prix NGL Pipeline in Kingfisher County, Oklahoma.

Targa will be responsible for construction a 110 mile extension of Grand Prix which will connect southern Oklahoma and the Sooner Trend oilfield, the Anadarko basin, as well as Canadian and Kingfisher counties in Central Oklahoma where it will finally connect with Williams’ new Bluestem Pipeline.

“Expanding our NGL pipeline business to interconnect with Targa’s strategically-positioned Grand Prix Pipeline will provide Williams and our customers with access to Mont Belvieu while opening up additional markets for Conway,” said Alan Armstrong, President and Chief Executive Officer of Williams.

 “The further expansion of our Grand Prix NGL Pipeline into the STACK is an attractive extension of a highly strategic asset for Targa and will direct significant incremental NGLs over the long-term from Williams and other third parties to Grand Prix and to our downstream assets in Mont Belvieu and Galena Park,” said Joe Bob Perkins, Chief Executive Officer of Targa.

An expected investment of $350 million to $400 million will be made by Williams in these NGL logistics projects, and an expected cost of $200 million will be made by Targa’s Grand Prix extension, which will have an initial capacity of approximately 120,000 bpd.

For both the Grand Prix extension and the new Bluestem Pipeline, the target in-service date set is first quarter of 2021, according to Targa and Williams.

Williams also plans to expand the DJ Lateral of the Overland Pass Pipeline and make improvements at its Conway NGL Storage facility, as part of this project.

World Pipelines

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Court Rejects Dominion Energy’s Request for New Atlantic Coast Pipeline Hearing


RICHMOND, Va. (AP) — A federal appeals court on Monday denied a request to reconsider a ruling throwing out a permit for the Atlantic Coast Pipeline to cross two national forests, including parts of the Appalachian Trail.

The 4th U.S. Circuit Court of Appeals rejected a request from lead pipeline developer Dominion Energy and the U.S. Forest Service to hold a full-court rehearing.

In December, a three-judge panel of the 4th Circuit sharply criticized the Forest Service, saying the agency lacked authority to authorize the pipeline’s crossing of the trail.

The panel also said the agency “abdicated its responsibility to preserve national forest resources” when it approved the pipeline crossing the George Washington and Monongahela National Forests, and a right-of-way across the Appalachian Trial.

The ruling came in a lawsuit filed by the Southern Environmental Law Center on behalf of the Sierra Club, Virginia Wilderness Committee and other environmental groups.

Representatives for Dominion Energy and the Forest Service declined immediate comment Monday.

The 605-mile (974-kilometer) natural gas pipeline would originate in West Virginia and run through parts of North Carolina and Virginia.

After the ruling in December, Dominion Energy spokesman Aaron Ruby said the court’s ruling was “at odds” with the U.S. Department of the Interior, the U.S. Department of Agriculture, National Park Service and U.S. Forest Service.

“All of these agencies agree that the Forest Service has the full legal authority to approve the Atlantic Coast Pipeline’s crossing of the Appalachian Trail,” Ruby said.

In a joint statement, the Southern Environmental Law Center and the Sierra Club said the 4th Circuit’s denial of a new hearing “sends the Atlantic Coast Pipeline back to the drawing board.”

The groups said they believe it is impossible to build the pipeline “without causing massive landslides and threatening the Appalachian Trail and our clean water.”

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Bakken Shale: North Dakota’s Oil & Gas Growth Engine


By Richard Nemec, Contributing Editor, PG&J

In mid-December with dwindling shopping days left before the holidays, North Dakota’s chief oil and natural gas regulator Lynn Helms was in a festive mood, reporting on his webinar for news media another set of new monthly production records in the Bakken Shale play. 

In fact, for several years now, Helms has been holding these monthly press soirees because of continued robust growth in North Dakota’s portion of the Williston Basin. For this sparsely populated, resource-and grain-rich part of America, Helms is a bit of a rock star overseeing a golden cash cow for the governor and state legislature.

North Dakota Bakken Footprint
Source Map: Courtesy of Hess

Helms is known for keeping close tabs on the sector as part of his position as head of the Department of Mineral Resources, which includes an oil and gas division, a role he has played in the state for nearly two decades. He saw the economic tidal wave known as the Bakken coming before it hit nearly 10 years ago. It has catapulted North Dakota to the No. 2 oil-producing state behind Texas, eclipsing historically oil-rich states such as Alaska and California.

Speaking almost casually, Helms in December was reporting the latest full monthly statistics covering October, and in that pre-winter time producers stepped on the accelerator ramping up oil production by 30,000 bpd, or 2.4%, and gas production jumped up, too, although not as much as oil, at 35 MMcf/d or 1.4%.

“Interestingly, we’re starting to see the gas-to-oil ratio coming into alignment,” he told reporters back then.

While Helms’ mood generally was upbeat in keeping with the pre-holiday production levels, he acknowledged that global prices and the latest corrective measures taken by OPEC and Russia were presenting mixed signals. He, therefore, was looking for Bakken producers to slow things down the first four or five months in 2019. 

“OPEC’s announced 2 MMbpd cut should begin to rebalance the market,” Helms told the webinar audience. “There are a lot of mixed signals and the bulls and bears will duke it out in the global oil markets.” 

Other, smaller but key entities, such as the Canadian province of Alberta (350,000 bpd cut) were also pursuing cutbacks in production at year-end 2018.

At about the same time at year-end 2018, one of the major Bakken operators, Hess Corp. and its CEO John Hess were touting the prospects for more cost-savings and expanded margins in 2019 and beyond, supported by an overall U.S. capital budget of nearly $2 billion for the new year. Hess intends to increase to six rigs in the Bakken, producing 135,000-145,000 boe/d.

In the Bakken, Hess plans to “complete the transition to higher intensity ‘plug-and-perf [perforation]’ completions in 2019, generating a significant uplift in net present value and initial production rates while also increasing the estimated ultimate recovery of oil and natural gas,” according to COO Greg Hill.

As the Hess’ were outlining their plans, Housley Carr, the respected energy analyst with RBN Energy LLC, published a commentary on his blog noting that while crude oil and natural gas production in the Bakken are at all-time highs, there is still bad news in that “for the past few months, the volumes of Bakken gas being flared are also at record levels, and producers as a whole have been exceeding the state of North Dakota’s goal” on the percentage of gas not captured, processed and piped away. 

“At the end of 2018, state regulators stood by their flaring goals, but in an effort to ease the squeeze, they gave producers a lot more flexibility in what gas is counted – and not counted – when the flaring calculations are made,” Carr added in his blog:

“North Dakota crude production grew by 39% between January 2017 and September 2018 to an even 1.3 million bpd, according to the North Dakota Industrial Commission’s (NDIC) most recent numbers, and gas production was up an astonishing 62% over the same period, to about 2.53 Bcf/d. Those gains have put enormous pressure on the play’s infrastructure, and – of most interest to us in today’s blog – made it impossible for the state to meet its goals for reducing the percentage of produced gas that is flared.” 

In early 2019, the three-member NDIC headed by the governor that oversees oil and gas regulation expects to receive a recommendation from the state’s Energy and Environmental Research Center (EERC) at the University of North Dakota on adopting gas storage programs to soak up for future use some of the gas volumes now being burned off.

Justin Kringstad, the numbers-crunching engineer who heads the North Dakota Pipeline Authority, was talking bullishly at year-end 2018 about the production prospects for oil and gas in the Bakken, underscoring this with indications that even the relatively small volumes from the Bakken in eastern Montana have been inching upward. And drilling activity was increased in the far western portions of North Dakota, near the Montana border. Where in mid-year there were zero rigs, Montana counted four rigs working at the end of 2018, Kringstad said.

“If you look across all fronts – oil, natural gas, natural gas liquids – every single area is going to have new pipeline investment in order to keep up with production,” Kringstad said. “There is not one segment of the industry right now that is prepared for long-term growth. The companies working these areas are busy in the boardrooms trying to figure out how many expanding existing systems are needed and how many are designed for open markets. So, for natural gas and all the fuels, there will be more infrastructures built.”

Besides regional production, Kringstad tracks rail and pipeline transportation, and for oil, the destinations of the cargo – West, East and Gulf Coasts. He also follows the changing spread between Brent (North Sea) and West Texas Intermediate (WTI) prices. If the difference is at least $5/bbl, rail is the favored transportation choice. At the end of 2018 with the Brent-WTI spread between $9 and $10, nearly three-quarters of the Bakken oil production was moving via pipeline with 16% going by rail, according to Kringstad.

While Kringstad and many other ongoing observer/participants in the Bakken dissect projections for a basin that some think contains billions of barrels of oil, they also pay attention to several other elements, including price, flaring of associated gas, workforce challenges and advances in technology and innovative processes. 

Counties and subdivisions within the overall Williston Basin, which sprawls into neighboring states and across the international border into Canada, also need to be accounted for. Kringstad has tracked nine different ranges of break-even prices for Bakken production within the overall basin, ranging from as low as $26-$30/bbl up to highs of $58-$73/bbl.

Noting the global price decline at the end of 2018, John Harju, vice president for strategic partnerships at the university-based EERC, said he sees overall Bakken production continuing to move upward, but with the caveat that price is most likely to be the limiting factor – not resource base or technology – but the global commodity prices.

“I don’t think we have seen a dramatic pullback by our producers yet [in North Dakota], but it is always something to worry about,” Harju said. “Price is the big factor that we’re going to be challenged with. Our governor established 2 million bpd as a goal he has challenged the state to get to, and I don’t think that is a ceiling, it is an attainable goal, and like all of these things, everything is dependent on pricing.”

In its last quarterly conference call in 2018, the leading Bakken producer, Tulsa-based Continental Resources Corp., reported record third quarter production of 167,643 boe/d, with 42 completions averaging 2,013 boe/d. The company founded and still headed by billionaire CEO Harold Hamm had all of its top-10 initial production wells for a 30-day period in the past 12 months; they ranged in 30-day volumes from 2,603 boe/d to 1,784 boe/d.

Ron Ness, president of the North Dakota Petroleum Council (NDPC), notes that Kringstad’s estimates indicate the state is halfway to reaching a projected peak natural gas production volume of 5 Bcf/d. 

“That would tell us we have a lot of work yet to do, and as oil/gas ratios decline, productivity increases,” Ness said. “There is a lot of continued investment that is going to be required. A lot depends on what happens with tertiary recovery. Can we re-inject gas effectively and that becomes a quasi-production storage enhancer?  We know we have a lot more gas to come and a lot more infrastructure is needed. Hopefully it won’t require another $18 billion, but it seems like we’re going to need twice the gas processing capacity we have today if we’re going to get to 5 Bcf/d.”

With the prospect for a doubling of gas production in the years ahead, the issue of flaring becomes an ongoing challenge for the state and industry. As RBN Energy’s Carr recently noted “producers in western North Dakota have been struggling with gas capture and flaring issues for the better part of the last decade. Back in 2011 and again in 2014, as much as 37% of the produced gas was being flared due to a lack of processing and takeaway capacity.” It has been less than 20% in recent years, but it is still a major concern.

Under the new federal Bureau of Land Management (BLM) approach, the state will not be concerned with Native American reservation trust land wells and gas capture on the Fort Berthold Reservation in the Bakken. North Dakota will monitor the capture statistics on the non-trust lands. 

“BLM is very much dedicated to delegating gas capture to the states,” Helms said. “We are meeting with them weekly with the goal of having a memorandum agreement in place by the first of February 2019. It will control the data transfer and establish how the state NDIC will notify the BLM.” Separately, the BLM and the tribes are working on an agreement for trust lands with the early February goal, too. 

Whether they make that or not, the state will press on regarding the non-trust lands on the reservation, Helms said.  “The huge BLM change for us is to delegate waste prevention to the states [federal fee lands] and tribes [on trust lands]. The BLM change is being challenged by environmental groups in California and New Mexico; but it nevertheless was effective in late November.”

Executives at one of the Bakken’s leading producers, Denver-based Whiting Petroleum Corp. in the last quarter of 2018 were telling Wall Street analysts that the company has a very high gas capture rate still, so it is somewhat apart from other operators. 

“Many operators are in a different situation,” said Whiting CEO Brad Holly on an earnings conference call in late October. “We have been aware of the tightening gas situation for some time now, and we have been planning to put various strategies in place, so Whiting is well positioned.”

Flaring is the major challenge for operators and stakeholders alike in the Bakken, according to the EERC’s Harju, who is part of a team recommendation set for early 2019 on gas storage as a mitigating approach. He said that despite the hard work by his researchers and the industry, flaring volumes in 2018 were on the rise again.

“We’re just finishing up a study for the Industrial Commission to evaluate gas storage as an option to help mitigate flaring,” said Harju, adding that the advent of EOR is another possible outlet to attack flaring. “It would target either productive or nonproductive formations for the storage.

“One of our big challenges was not only the gas side of the equation, but also the export side. So, there is need for a lot of new pipelines, and NGLs are the really big challenge. The EERC has been working on the use of ethane and rich gas in general as a working fluid for EOR,” said Harju, noting the research center has a small pilot project ongoing in this regard with Liberty Resources. “If we’re able to get that to work in a meaningful way, that could be extremely helpful in terms of creating some substantial utilization, especially for the NGLs.”

Harju said in surveying the major Bakken producers in 2018, EOR came up as a leading area for research, and he calls it a “focal point” of the EERC research these days.

The petroleum council’s Ness equates flaring and related challenges to everything in the Bakken becoming what he calls “under-sized” going into 2019. But this also is creating opportunities and incentives for new investment, he thinks. Flaring will be a continuous challenge, he said because of infrastructure needs, market structure impacts, and “lots of other things.” Some of the other issues involve workforce needs for able-bodied workers with the right skill sets.

“What has happened is the production increases have been so phenomenal that the wells are so much more productive than they were a year ago,” said Ness, noting he is unsure how many billions of dollars more are needed in new investment. “So, everything again is under-sized, but it is a good opportunity, so where there is this type of incentive, there will be investment.”

Ness’s passion these days focuses on what the industry’s future will look like in terms of work force and its ability to keep stretching out to new frontiers in terms of technology and innovation. Ultimately, this is where the rubber meets the road for operators in North Dakota. And like the petroleum sector nationwide, there is a concern about where the next generation of workers will come from as the level of sophistication in jobs across the board is rising. Being located out of the mainstream of the nation’s oil patch and population, North Dakota feels this more acutely, according to stakeholders like Ness.

Ness said as long as there are other active oil and gas plays across the nation, North Dakota will always have a struggle for work force. As the state’s economy expands, the oil and gas sector is just one opportunity for new graduates and a 750,000 population cannot support all the workforce needs, he notes, adding that oil and gas workers generally come from the Upper Midwest (Minnesota, Wisconsin and Montana), Oregon, Wyoming and Texas.

“I think that is going to continue to be a challenge here,” said Ness, adding that current governor, Doug Burgum, has made oil and gas workforce issues one of his primary focal points. “We’ve got a lot of new students coming out of our schools, and we have to make sure that we create the opportunities for them, and the awareness of the jobs and the skilled training needed.”

One push back North Dakota has begun to enjoy against its relative geographic and demographic remoteness is that the Bakken has brought it worldwide recognition to a certain extent. Its operational and technological successes have caused energy practitioners around the world to take note, Ness said.

“I absolutely continue to be amazed at the advances in technology – not just the production side, but also on the environmental footprint,” he said. 

Global interest includes the state’s use of unmanned aircraft (drones); remediation and reclamation practices; automation of well sites, and more, Ness thinks. 

“It’s pretty enlightening, becoming the high-tech oilfield, there is no doubt,” said Ness. “North Dakota is really the official test site in the United States for drones right now. Drone activity here is very high.” 

He said their use includes monitoring pipelines, monitoring facilities, reviewing reclamation sites and looking at easements. 

From the EERC’s perspective, Harju said he is not that close to the work force issue, but he has seen a decline in engineering enrollments at the university, and at the same time he sees no lessening of advances in innovation and technology that will allow the oil and gas sector to do more each year without a huge increase in work force. The companies he works will are still “prudent, technologically oriented, agile and they have ‘continuous improvement’ cultures,” he said.

Noting that research assignments with the industry have never been as robust, Harju said when a group of operators in 2016 asked what the one area they needed to focus on was, he told them to “learn how to make money on $30/bbl oil,” and he thinks they took the advice to heart. “EERC research programs have grown through the latest price depression [2014-17], so these guys invested in research and the results are the successes we see today,” he said.

Harju sees more advances coming in the Bakken in terms of well completions, long 2- and 3-mile laterals, and re-fracturing work. 

“There are a lot of older style hydraulic fracturing jobs that are being redone to bring a modern completion approach to them,” he said. “How you go about re-fracturing is absolutely ripe for innovation. Technology now evolves at a much faster pace, so I think we’re going to see a lot more in machine learning and artificial intelligence, so better understanding well completions is going to be a critical element.”

Helms’ ending to his December production webinar was the same upbeat stuff that Bakken followers are used to – record oil, gas production, and steady gas capture with much lower oil prices that so far had not translated into a drop-in rig count. “It has translated into more uncompleted wells and other items, so stay tuned,” the always positive Helms acknowledged.

At the outset of the new year, Helms focus had shifted to the EERC’s expected report on produced gas storage, for which he and the DMR engineers had been meeting with the research center.

Eyeing 2018 now in the rearview mirror, Helms called the EETC’s work “a very important report,” adding, “if the Industrial Commission goes along with the recommendations, North Dakota will be the first state to utilize this technology.” 

In response to a reporter’s question, Helms said a lot of the operators who have missed gas capture targets in recent months are claiming force majeure or capacity constraints as his DMR department has been deluged with year-end notifications in this regard.

A sign of the times, perhaps, but it is not likely to dampen the enthusiasm of the Bakken faithful. P&GJ

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