Analyst: Who’s in trouble — and who’s in bigger trouble — at $20 oil

Houston’s energy companies are being rocked by plunging demand amid the COVID-19 pandemic on one side and supply shocks as OPEC countries gear up to produce more oil on the other.

But some subsectors are better off than others.

The top of that list right now would be oil and gas trading arms backed by physical assets, said Jamie Webster, senior director at the Boston Consulting Group’s Center for Energy Impact.

“This is the sort of volatility that they love,” Webster said. “They can trade around their physical assets, combining them with financial instruments to offset some of the losses from the upstream or downstream parts of the organization.”

Refineries have seen their margins crushed by the plunging demand for the products they produce, but the declining crude prices have given them some amount of breathing room, Webster said. That means that if something changes on the demand side and refineries can find buyers for their product, things could turn around for them fairly quickly, he said.

“They could end up having a fantastic second half of the year,” Webster said.

The oil field services sector, which was already in a tight spot due to tightening upstream capital expenditure budgets even before the rapid changes that came earlier this month, could have an especially tough time ahead. That’s particularly true of companies associated with exploration — seismic companies, for example, Webster said.

“What we saw in 2014, and I expect to see it now, is that you want to cut where you can, where you have degrees of freedom to move. You want to cut things like exploration, where they’re way out there, and you aren’t going to be getting volumes online any time soon,” Webster said.

Early analysis indicates that capital expenditures among upstream producers could end up cut by 40 percent of the initial guidance at the start of the year, Webster said.

West Texas Intermediate crude oil futures reached down into the mid- to low-$20s per barrel on March 18 and 19, following a rapid decline into the low $30s and high $20s in the week prior. Social distancing as a response to the pandemic and the OPEC activity are poised to create a supply and demand imbalance that would double the worst quarter in the post-2014 oil price downturn.


By Joshua Mann – Senior Reporter

Courtesy of Houston Business Journal


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Halliburton furloughs Houston employees; other energy cos. working from home

Some of the biggest energy companies in Houston are making changes to when and where some employees work amid the coronavirus pandemic and drop in oil prices.

Halliburton Co. (NYSE: HAL) will furlough about 3,500 Houston employees for 60 days, according to Reuters and other reports. Furloughed employees will alternate working one week and being off the next. They won’t be paid for the time off but will keep their benefits.

The furlough is intended to help the oil field services giant reduce costs as many oil companies cut spending after oil prices plunged down below $30 per barrel on March 9, when the first shots in an oil price fight between Saudi Arabia and Russia put downward pressure on the supply side. At the same time, the coronavirus pandemic has been creating concerns on the demand side of the market, cutting into consumption as consumers taper off air and road travel.

Separately, Kinder Morgan Inc. (NYSE: KMI) ordered employees nationwide to work from home this week in light of the pandemic, the Houston Chronicle reports. The midstream giant won’t reduce operations, but it is restricting employees’ travel and will reevaluate the telecommuting order on a week-by-week basis.

Canada-based midstream giant Enbridge Inc. (NYSE: ENB), which also has a significant presence in Houston, has also ordered employees to work from home, the Chronicle reports. The order affects employees company wide, except for field workers. Large group meetings are canceled, and business travel is limited.

All three companies made the Houston Business Journal’s 2019 Largest Houston-Area Energy Employers List, which published in October. Halliburton was No. 13 with 4,217 local, full-time employees, Kinder Morgan was No. 16 with 2,207, and Enbridge was No. 21 with 1,027


By Olivia Pulsinelli – Assistant Managing Editor

Courtesy of Houston Business Journal

Kinder Morgan on target for Texas pipeline construction

Houston-based Kinder Morgan Inc. (NYSE: KMI) has started construction on Permian Highway Pipeline, a long-haul natural gas pipeline from the Permian Basin to the Gulf Coast.

And despite a court case, the projected in-service date for the pipeline is still early 2021, said Dax Sanders, Kinder Morgan’s executive vice president and chief strategy officer. Sanders was speaking at Credit Suisse’s 25th Annual energy Summit on March 4.

The company had faced legal opposition when the city of Austin, city of San Marcos and others asked the U.S. District Court for the Western District of Texas to stop Kinder Morgan from moving forward on the project. Opponents said in their initial complaint filed with the court that the project threatened the habitat of endangered species, including the golden cheek warbler.

The plaintiffs asked the court to issue a temporary restraining order on the project, but the court declined to do so on Feb. 14, according to court documents.

That cleared the way for Kinder Morgan to begin construction. Sanders is confident the project will proceed as expected. The company had already pushed back the start date for the asset from the fourth quarter of 2020 as of its third-quarter conference call with investors in 2019.

Although the company is moving forward on Permian Highway, it still has not yet secured customers for another pipeline project — Permian Pass — and it won’t make a commitment to do so until it has contractual support, Sanders said.

Kinder Morgan produced $13.21 billion in 2019 revenue, which translated to a net income of $2.24 billion. The company employed 11,086 people full time at the start of 2020, up slightly from 11,012 a year prior, according to Kinder Morgan’s two most recent annual financial reports.


By Joshua Mann – Senior Reporter

Courtesy of Houston Business Journal

Offshore terminal planned with Phillips 66, ending dispute between Corpus, Trafigura

Houston-based Phillips 66 (NYSE: PSX) and Singapore-based Trafigura Group Pte. Ltd announced a joint venture Feb. 28 to build a terminal capable of loading very large crude carriers off the coast of Corpus Christi, Texas.

The two companies are awaiting permitting for the project, known as Bluewater Texas Terminal LLC, and plan to make a final investment decision later this year. Bluewater will consist of up to two single-point mooring buoys capable of loading VLCCs — massive oil tankers that can carry 2 million barrels per trip.

The project replaces a previous proposition by Trafigura to build a single mooring buoy under a venture called Texas Gulf Coast Terminals. On Feb. 28, Trafigura announced that it had withdrawn its application with United States Maritime Administration to permit that project, which would have been near the Padre Island National Seashore.

The Bluewater buoys will be placed 21 nautical miles, or 24 land miles, from the Port of Corpus Christi, according to the companies. It will sit farther out north to sea than the previously proposed Trafigura project.

The new location is one of the reasons that the Port of Corpus Christi is throwing its support behind the Bluewater project despite its objections to Trafigura’s discontinued Texas Gulf Coast terminal, port CEO Sean Strawbridge told the Business Journal. Sitting the buoys further offshore will help protect Corpus from emissions, he said.

The port was also happy with Phillips 66’s inclusion in the new project as the company has for decades run a similar crude terminal off the east coast of England.

“I’ve been there along with some board to see it and have them explain it to us,” Strawbridge said. “We got a better understanding and a higher level of comfort for what they are and how they’re operated speaks volumes to [Phillips’] ability to do this safely and responsibly.”

Although the terms of the contract are still being hammered out, Bluewater has agreed to lease land from the port to place a booster station for the offshore terminal, according to Strawbridge. That means money going back to the community, whereas the old Trafigura project wasn’t planning on leasing land on from the port.

The land being leased for the Bluewater booster station is on Harbor Island, the site of another proposed VLCC docking station.

Homeowners in Port Aransas have pushed back against construction on Harbor Island, which is separated from Port Aransas by the same waterway the port wants to dredge for the VLCC terminal.

By Jessica Corso – Reporter

Courtesy of Houston Business Journal


CenterPoint Energy makes another divestment deal for hundreds of millions of dollars

Houston-based CenterPoint Energy Inc. (NYSE: CNP) will sell its natural gas retail business to a private equity firm for about $400 million, according to a Feb. 24 press release.

Energy Capital Partners LLC is buying CenterPoint Energy Services Inc. in the deal, which is expected to close in the second quarter of 2020. CenterPoint plans to use the net proceeds to pay down debt. The deal comes just days after the departure of the company’s CEO and shortly after another multimillion-dollar divestment was announced.

New Jersey-based ECP has an office in Houston and specializes in energy infrastructure projects. Houston-based CES has about 300 employees. It provides natural gas sales, storage and supply plus other energy-related services to about 30,000 commercial and industrial customers, utilities and municipalities across more than 30 states, per the release.

As part of the deal, CES and Shell Energy North America (US) LP will enter into a long-term preferred supply agreement in which the latter company will provide gas supply and collateral support and receive equity warrants.

“The sale of our gas retail business further positions CenterPoint Energy to focus on the long-term performance of our core electric and natural gas utility businesses,” John W. Somerhalder II, interim president and CEO of CenterPoint Energy, said in the release. “At the same time, this sale will strengthen our balance sheet and improve our business risk profile.”

This is the first announcement CenterPoint has made with Somerhalder at the helm. Just days earlier, previous President and CEO Scott Prochazka abruptly departed after leading the company for six years. His departure came just days after the Texas Public Utility Commission approved a $13 million rate hike for CenterPoint. The company initially sought a $161 million increase.

“When (the CES deal is) combined with our recent agreement to sell Miller Pipeline and Minnesota Limited, two businesses that comprised our infrastructure services segment, we expect our utility earnings contribution to approach 90 percent over the next several years,” Somerhalder added.

Earlier this month, CenterPoint announced the deal to sell Miller Pipeline and Minnesota Limited to Atlanta-based PowerTeam Services LLC for $850 million. The subsidiaries — which CenterPoint acquired in its multibillion-dollar acquisition of Indiana-based Vectren Corp. — are natural gas distribution and transmission pipeline contractors that employ about 7,500 people combined.

When the Vectren deal was announced in April 2018, it was valued at roughly $5.98 billion plus the assumption of Vectren’s debt, which was expected to be about $2.5 billion. Upon closing the deal in February 2019, CenterPoint had assets totaling $29 billion, an enterprise value of $27 billion and approximately 14,000 employees. The company now has nearly $35 billion in assets, and it serves customers in nearly 40 states.

CenterPoint Energy is represented in the CES sale by Goldman Sachs & Co. LLC as exclusive financial adviser and Akin Gump Strauss Hauer & Feld LLP as legal counsel. Latham & Watkins LLP is serving as legal counsel to Energy Capital Partners, and BNP Paribas is providing a committed borrowing base facility.


By Olivia Pulsinelli – Assistant Managing Editor

Courtesy of Houston Business Journal

Houston LNG co. to sell South Texas pipeline project to Enbridge

Houston-based NextDecade Corp. (Nasdaq: NEXT) has reached a deal to sell its Rio Bravo Pipeline Company LLC to Canada-based midstream giant Enbridge Inc. (NYSE: ENB) for up to $25 million in cash.

The proposed Rio Bravo Pipeline would transport 4.5 billion cubic feet per day of natural gas from the Agua Dulce area to NextDecade’s proposed Rio Grande LNG export facility in Brownsville, Texas. In September 2019, the companies announced a memorandum of understanding to jointly pursue the development of the Rio Bravo Pipeline and other natural gas pipelines.

Now, Enbridge has agreed to own 100 percent of the pipeline company and assume all responsibility for the development, financing, construction, and operations of the Rio Bravo Pipeline. Enbridge will pay NextDecade $15 million when the deal closes and the rest when NextDecade makes a final investment decision on its Rio Grande LNG export facility. The deal is expected to close in the first quarter of 2020, and NextDecade anticipates making a final investment decision in 2020.

NextDecade will retain its rights to transport natural gas on the Rio Bravo Pipeline for at least 20 years to supply its Rio Grande LNG facility.

“This agreement with Enbridge further enhances our commitment to our global LNG customers, natural gas suppliers and other stakeholders to deliver our Rio Grande LNG project on time and on budget,” Matt Schatzman, NextDecade’s chairman and CEO, said in a press release. “As one of North America’s leading energy infrastructure companies, Enbridge brings extensive natural gas pipeline experience to execute the Rio Bravo Pipeline, and we are delighted to have them involved in supporting the delivery of our Rio Grande LNG project.”

The 27 million-tons-per-annum Rio Grande LNG terminal is expected to include gas treatment, liquefaction, and other supporting facilities and infrastructure. The terminal and its associated Rio Bravo Pipeline could amount to more than $15 billion of investment in Cameron County and are expected to create more than 5,000 jobs, according to an earlier press release.


By Olivia Pulsinelli – Assistant Managing Editor

Courtesy of Houston Business Journal

BP’s U.S. shale division on track to hit $1B in cash

U.S. shale oil company BPX Energy will be generating $1 billion in annual cash flow next year for its parent company, BP Group PLC, and it easily surpassed the $90 million synergies expected after its $10.3 billion acquisition of Texas oil field assets.

BP (NYSE: BP) outlined the 2019 results of BPX Energy as part of London-based energy giant’s 2019 fourth-quarter earnings call Feb. 4.

BPX Energy is the Denver-based division overseeing onshore, continental U.S. oil and gas exploration and production. It was created with BP’s acquisition of mining giant BHP Billiton’s oil and gas division, a deal which closed in late 2018 and was the largest acquisition by BP in 20 years.

The division was able to find $240 million in savings from the newly bought Texas assets, some of it from reducing productions by 10 percent, the company said. The savings should swell to $400 million by the end of this year, helping BPX Energy hit its lofty free-cash flow projections, said Brian Gilvary, CFO of BP.

“The synergy number is significantly higher than what we first set,” he said. “Everything we see gives us absolute confidence in that $1 billion.”

BPX Energy employs about 200 people in Denver and hundreds more people in Houston, Oklahoma City and across the regions where it operates wells.

Before the Denver division was created, BP’s onshore business in the continental U.S. had focused on natural gas production, and it has operated for years in the San Juan Basin area of southwest Colorado and in southern Wyoming.

The acquisition from BHP Billiton bought it 500,000 acres of oil and gas assets in Texas’ Permian Basin, Haynesville and Eagle Ford oil fields.

It shifted focus in the U.S. away from natural gas to unconventional crude oil and associated liquids.

On Feb. 4, the company said it has scaled down work in the Haynesville oil fields in Texas to focus solely on the Permian and Eagle Ford areas.

BPX Energy produced an average of 124,000 barrels of crude oil and natural gas liquids per day in 2019, more than double the crude oil and liquids production it notched in 2018 before the BHP Billiton acquisition.

Counting 2.175 billion cubic feet of “dry” natural gas production, BPX Energy produced the equivalent of 499,000 barrels daily in 2019, a 43 percent jump in overall oil, gas and liquids production compared to the year before.

BPX Energy’s production is expected to decline in 2020, largely because it’s selling natural gas-producing assets to focus on its West Texas crude oil and liquids business, which has higher profit margins than natural gas, the company said.

“We estimate the impact of divestments to be in the range of 200,000 to 250,000 barrels of oil equivalent a day in 2020,” Gilvary said, noting more than half of that volume will be reductions in its dry natural gas production as a result of divestments.

He explained BP sold or is selling about $9 billion in assets — including BPX Energy natural gas operations — mostly to private equity buyers, Gilvary said.

BP had, when it acquired the Texas oil assets for BPX Energy, forecast selling $10 billion in assets to offset what it spent. That was nearly completed in 2019. BP projects divesting another $5 billion assets in coming months.

By Greg Avery – Reporter

Courtesy of Houston Business Journal

Texas energy data wrap: Oil and gas cos. face ratings downgrades in 2019

One of the big three credit ratings agencies reported a downward trend in the ratings of oil and gas companies throughout 2019 — and it reached a fever pitch during the fourth quarter. Read more about that and other data points to know in Texas energy this week.

Credit ratings

Moody’s Corp., one of the big three corporate credit ratings agencies, gave out more credit downgrades than upgrades to oil and gas companies for the fifth consecutive quarter in the final quarter of 2019, according to a report published by the firm on Jan. 31. The fourth-quarter downgrades vastly outnumbered the upgrades during that period, marking an acceleration of a trend that has been present since Q4 2018. The firm downgraded the credit rating of 15 companies during the fourth quarter, compared to two upgrades.

“Volatile oil prices throughout 2019 and natural gas prices that steadily declined in the second half of the year led speculative-grade investors to shun all but the strongest oil weighted companies, increasing default risk for companies that already had low ratings,” Moody’s said in the report.

Texas jobs

Texas accounted for 40 percent of all oil and gas jobs in the U.S. during 2019, according to a report by the Texas Independent Producers and Royalty Owners Association. There were a total of 361,271 direct oil and gas jobs in Texas in 2019, up 5,550 from the prior year. Those jobs paid an average wage of $132,104 per year, higher than the national average oil and gas pay of $114,745 annually.

Oil and gas prices

NYMEX crude futures cost $53.48 per barrel on Jan. 28, according to the most recent data available from the U.S. Energy Information Administration. That marks a significant decline since highs in the $63-per-barrel range seen at the beginning of the month. Natural gas futures reached $1.829 per million British thermal units Jan. 30.

Rig count

The Texas oil and gas rig count decreased again in the week that ended Jan. 31, falling by two to land at 395 at the end of the week, according to data published by Houston-based Baker Hughes Co. (NYSE: BKR). That’s down 119 rigs from the comparable date in 2019. The North American rig count was down by a single rig to end the week at 1,037. That’s 251 rigs lower than the prior year date.

By Joshua Mann – Senior Reporter

Courtesy of Houston Business Journal

Haynes and Boone partner on energy bankruptcy wave: ‘We have not seen the end of this’

Oil and gas industry bankruptcies accelerated in 2019, and while they may not continue on an upward trajectory in 2020, they probably won’t be heading down either.

Oil and gas companies brought $34.96 billion in debt to bankruptcy courts in 2019, more than double the $17.12 billion they brought in 2018, according to a report published by Haynes and Boone LLP. And this latest wave isn’t over yet, said Charles Beckham, a Haynes and Boone partner.

“I wouldn’t say I’m anticipating an increased pace in the number of bankruptcies in 2020, but I would anticipate a similar pace,” Beckham said. “We have not seen the end of this.”

Shifting investor expectations have put a lot of pressure on energy companies, especially those in the upstream business: oil and gas producers and their equipment and service providers. Investors aren’t as interested in growth anymore — they want to see more free cashflow, said Buddy Clark, another Haynes and Boone partner.

That shift, combined with low oil prices and large amounts of debt taken on to fund growth when the market was more optimistic, has led to the resurgence of bankruptcies.

Looking ahead, market participants have stopped depending on promises of stronger oil prices swooping in to save business plans, Beckham said.

“After four or five years of bad news relative to distress in the market, there is quite a bit of fatigue among some energy bankers,” Beckham said. “As a result, the hope that, ‘Gee, commodity prices are just around the corner, please be patient’ — no one is listening to that anymore.”


That shifting pressure from investors has reverberated across the industry, too, Clark said. Large producers have taken the signal to slow down their acreage purchases, which in turn means smaller producers are left holding onto assets for longer than they expected, Clark said.

Most of those smaller companies are backed by private equity, which generally looks for an investment horizon on the scale of years, not decades, Clark said.

“They were looking for quick investments; they’re not looking to build an oil company for a 25-year investment,” Clark said. “There are repercussions all the way down the food chain for the institutional investors wanting to see the major oil companies operating within free cashflow.”

The limited partners at private equity companies are starting to tell their firms to stop bringing them oil and gas deals because of the exit difficulties, Clark said.

Clark said he’s particularly interested in watching what happens when lenders carry out redeterminations on the borrowing bases they allocate to the oil companies under their auspices. Producers borrow money from commercial energy banks with their oil and gas properties as collateral. When things are going well in the industry, redeterminations of the borrowing bases will trend upward, but things aren’t going well right now, Clark said.

“This is not a great time for the industry, so it’s possible that borrowing bases will more likely go down than up on average,” Clark said. “It will put more pressure on producers.”

Houston has already seen an example of this in Alta Mesa Resources Inc.’s bankruptcy. The issue that finally brought Alta Mesa to the court was an August redetermination of its reserve-based loan that brought the borrowing base below the amount the company had already borrowed. The company would have had to make five consecutive payments to make up the $162 million deficiency.

By Joshua Mann – Senior Reporter

Courtesy of Houston Business Journal