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U.S. crude exports to alter world market

The swift passage by Congress that struck down the export ban on U.S.-produced crude oil could bring a few changes in the next 18 to 24 months.

On New Year’s Eve, NuStar Energy and ConocoPhillips loaded what they said was the nation’s first export cargo of U.S.-produced light crude oil in four decades—except for limited sales of Alaskan crude—at the Port of Corpus Christi, Texas. The cargo was produced in the Eagle Ford Shale. Enterprise Products Partners LP announced plans to ship a tanker of crude during the first week of January.

U.S. production is set to decline in 2016 and may fall in 2017 as well. But with an open market, the backlog at the Cushing, Okla., crude trading hub could be relieved within 18 to 24 months, resulting in higher wellhead prices for E&Ps.

Kenneth Medlock, senior director of the Center for Energy Studies at Rice University’s Baker Institute for Public Policy, said that lifting the ban should level the playing field for the U.S. Oil from the Bakken and Eagle Ford is superior in quality but has faced discounted domestic crude-oil prices relative to internationally traded crudes such as Brent.

In a study published last year, Medlock found that if the majority of light, tight oil produced from U.S. shale formations was exported, it would fetch higher prices than West Texas Intermediate (WTI) and Brent in the international market because it is of quality.

With oil locked inside the U.S., oil producers had little choice but to discount light oil to refiners.

But in the international market, higher API gravity numbers—meaning lower density—tend to raise the price of crude relative to Brent while higher sulfur content tends to lower the price relative to Brent.

WTI typically has a higher API gravity and lower sulfur content than Brent, making it more valuable. Some oil produced in the Bakken and Eagle Ford has far lower density than WTI.

Development in the Bakken and Eagle Ford shales has driven the bulk of the increase in domestic crude oil production to date, but it’s been sold for a discount because of the configuration of U.S. refineries.

Based on their open-market values, Medlock calculated that at $100 per barrel (bbl) Brent prices, WTI would trade at nearly $102 per bbl while Eagle Ford crudes would fetch prices of $111 per bbl. And in an unconstrained market, those crudes would already be delivered at a premium.

As with any global commodity, U.S. production will be dependent on the overall global price as well as finding appropriate markets, said John Kneiss, director of macroeconomics, geopolitics and policy for Stratas Advisors.

Heavy crude production, for instance, will continue to be used in the U.S. because the nation’s refinery configurations are mostly designed to handle that.

“The lighter crudes coming out of the shale deposits and other formations will be competing against the North Sea and other producers out of Africa and the Middle East,” he said. “Certainly we think there’s going to be some opportunity in the Asian market, probably some opportunity in the South American market.”

Oil and gas a sure bet, API chief promises

Place your bets: The domestic oil and gas business may be a safe number to lay some money on in 2016 despite the current gloom—and the midstream will contribute to that future payoff, according to the American Petroleum Institute.

API President and CEO Jack Gerard emphasized the industry’s positives during his sixth annual “State of American Energy” address in Washington, D.C. What’s crucial right now is assuring the public sees those positives and responds accordingly, he pointed out.

“The United States begins this new year leading the world in energy production, economic growth and lowering our greenhouse gas emissions—a trifecta unmatched by any other country today,” Gerard said. “The gains we’ve made and our ability to sustain them in the years to come are largely dependent on the energy policies we pursue.

“Fortunately, we know how to bring about America’s brighter energy future, which means lower costs for American consumers, a cleaner environment and American energy leadership, because it is today’s reality. We call it the U.S. model,” he added.

“As the president’s last full year in office begins, we hope that he will take note of and help foster the U.S. model. We hope that he’ll see that overregulation—nearly 100 regulations and counting on the oil and natural gas industry—hinders rather than advances what he hopes to be one of his administration’s defining legacies, environmental improvement.

Gerard’s remarks came with the trade association’s release of “Vote 4 Energy,” its 2016 report on the status of the U.S. energy business. The study focuses on “economic, job creation, energy security and global leadership opportunities created by our nation’s 21st century energy revolution and the policy challenges we must overcome to ensure that these benefits extend for generations to come.”

His introduction to the 54-page study includes a lengthy discussion of the midstream as the nation continues “building a brighter energy future through strategic infrastructure investments, providing greater choice to America’s consumers, and securing America’s energy future through smart and responsible development and science-based energy policies.”

The API study opens with a review of the rapid development of the game-changing Marcellus and Utica plays. Getting that production to the key Northeast and New England markets is a major challenge for the midstream sector that could create significant economy benefits for the East Coast. It quotes the New England Coalition for Affordable Energy, which estimates failure to build new pipelines and midstream infrastructure to these markets would cost the region’s consumers $5.4 billion or more in higher energy costs and block the creation of thousands of new jobs by 2020.

“Apart from access to reserves and common sense regulation, America’s shale revolution needs infrastructure investment and a regulatory process that supports private investment in these vital projects,” the report adds. “In the oil and natural gas industry, America has a proven partner that has demonstrated its willingness to invest in the United States. Six oil and natural gas companies earned places on the Progressive Policy Institute’s top 25 in 2014 U.S. capital investments with $44.7 billion. Infrastructure needs in the East are one example of the energy infrastructure necessary across the United States to fully capitalize on increased domestic oil and natural gas production.”

Former energy chief: perception defines downturn

Commodity down cycles are nothing new to industry veterans, former U.S. Energy Secretary Spencer Abraham told a crowd of executives and observers at The Economist’s recent “The World in 2016 Breakfast” in Houston. It’s the nature of this particular downturn, especially the shifting perception of price, which sets it apart.

“The interesting thing about the cycle, unlike any that I’m familiar with, is that from the standpoint of the United States, we have spent decades in which as a matter of public policy, as a matter of politics, all of the political community has been excited when the prices of commodities were low,” Abraham said. “When I was energy secretary just 10 years ago, we regarded creeping prices of gasoline as a bad political signal for the American electorate.”

The last decade of rapidly increasing oil and production from the exploitation of shale plays has enabled a dramatic sea change, he said.

“We’ve gone from a country where low commodity prices were considered to be very positive for the economy to a situation where there’s a much different feeling about t today,” said Abraham, who served under President George W. Bush and also served as a U.S. senator from Michigan. “Now in Texas, stronger prices have always been pretty good news, but for American politics that’s not been the case.”

Abraham, now chairman and CEO of The Abraham Group, a Washington-based strategic consulting firm, also sees significant shifts in OPEC’s approach from building a floor under prices to maintaining its grip on market share. Saudi Arabia, in particular, has altered its philosophy in reaction to increases in oil production in the U.S. and Russia, and the potential for increased output elsewhere.

“I don’t think the Saudis in particular or OPEC as a group are prepared to back off of their policy,” he said.” My feeling is that their hope is—and it’s already happening—you’ve seen significant reductions in capital expenditures among the major oil companies around the world. You’ve seen some of the high-cost projects, particularly the offshore type projects, curtailed.”

A number of other factors on the demand side are the reverse of just a few years ago, Abraham said. Rising global demand has been hindered by a weakened European economy and slower, though still relatively strong, growth in China. The regulatory environment—particularly environmental regulations—hinder increased production, he said.

Pipeline pacts: beware point of no return

Those negotiating contracts to move hydrocarbons by FERC-regulated pipelines need to keep in mind that sometimes a deal’s a deal, even when the dealmakers themselves want to make adjustments later on.

Two attorneys who guide clients through the liquids pipeline regulatory landscape discussed the impact of plunging oil prices on those who sign contracts at the Institute for Energy Law’s recent Midstream Oil & Gas Law Conference in Houston. They noted that there has been a seismic shift in the industry in the direction of long-term commitments.

“Typically if you have a contract and the two sides agree to change it, you can change it,” said Elizabeth Kohlhausen, Houston-based partner with Caldwell Boudreaux Lefler PLLC. “Here, the problem with that is that FERC [Federal Energy Regulatory Commission] would say, ‘These contracts were entered into as part of an open season where everyone was given equal opportunity. So, if you enter into them and then five years down the road, you change the rate 30% but you’re still giving people firm service on your pipeline, then there’s a whole host of people who may have entered into it five years prior if they had known that the rate was going to be 30% less.’”

The constraint is based on the interests of those who chose not to enter into the contract. Does that mean, Kohlhausen is often asked, that those who agreed to the contracts cannot agree to change them on their own?

Kohlhausen brought a different perspective to agreements made before pipelines are built than her co-presenter, Erica Rancilio, attorney with Edwards & Floom LLP in Washington, D.C.

“I can think of a client in 2005 that thought it needed an expansion and put a very expensive expansion in the ground,” Kohlhausen said. “Then 2008 happened and that expansion was no longer needed—they had already put everything into the ground; spent the money. Here, pipelines are getting some assurances that when you spend the money, you’ll get some type of return off that. I think that’s the biggest benefit.”

Rancilio, whose firm represents shippers, agreed that those able to pay the contract rate are assured certainty of rates over time, along with increased access to capacity and priority rights on the lines. However, she also saw drawbacks.

“First, from a shipper perspective, these long-term contracts obviously don’t take into account changing market conditions,” she said. “The economics of the oil pipeline industry have been changing rapidly and we have some contracts that we’ve entered into as recently as 2011 that are completely non-economical because the rate that we agreed to exceeds the value to us in moving our product to market.”

The other drawback Rancilio mentioned was one of fairness. A pipeline company with market power can put a shipper at a disadvantage when setting the rate.

“We’ve seen imbalanced bargaining here in the open season where a pipeline will offer a contract rate and call it a take-it-or-leave-it rate when a prospective shipper wants to negotiate,” she said. “Shippers have no way of assuring that they are paying a fair price; they are essentially paying what the market will bear. When a pipeline has market power, it can be an excessive rate over and above competitive rates.”

Export LNG to be change agent

The Australian Energy Market Operator’s (AEMO) second annual National Gas Forecasting Report (NGFR) was recently released and indicates a transformation of eastern and southeastern Australia’s interconnected gas markets over the next five years, following the ramp-up of gas consumption to supply LNG exports.

While annual gas consumption in Australia is projected to remain relatively flat for all sectors over the rest of the outlook period—to 2035, LNG consumption is forecast to grow at an average annual rate of 32.5% in the short term (to 2020) to supply LNG exports. Total annual LNG consumption is forecast to increase from approximately 354 petajoules (PJ) in 2015 to 1444 PJ by 2020.

“LNG export facilities in Queensland have brought international demand and international pricing to Australian gas markets,” said AEMO Managing Director and CEO Matt Zema. “This is expected to more than double total gas consumption in eastern and southeastern Australia over the next five years, compared to aggregated consumption in 2014 before the Queensland LNG projects began.”

Securities told Midstream Business. “I felt there might have been a little bit of tension between Icahn’s team and Charif, considering that they were trying to bring in very different kinds of approaches. Carl Icahn is more about returning cash to the shareholders. Charif, on the other hand, is a big visionary who did not have returning cash to the shareholders as his first priority.”

William Frohnhoefer, managing director of BTIG LLC, also saw a showdown coming, with Icahn’s board members pushing for a tighter focus on balance sheet management and cash return to shareholders. He did not expect such an abrupt change.

“I was more assuming that there was going to be a debate with an eventual meeting of the minds and compromise on both sides,” he told Midstream Business. “Apparently there was a lot less room for compromise than I thought in the attitudes of the two parties.”

Souki’s free-wheeling approach to spending put him on a collision course with Icahn, but it was the struggles of the commodity markets that brought the conflict to a head. Cheniere’s stock price, which was cut in half last year, echoes the woes of many in the industry.

How access to energy can save the world

If you want to know what the world would be like without access to affordable energy, look at a satellite photo of the two Koreas at night.

“South Korea is lit up like Houston,” Charles McConnell, executive director of Rice University’s Energy and Environment Initiative, told attendees at the recent Center for American and International Law’s Midstream Oil & Gas Law Conference in Houston. “North Korea is as dark as your closet. People in that country have been living in the dark for the last 50 years and those politicians like it that way, but I don’t think that’s stable long term.”

Providing accessible, affordable and environmentally safe energy to the world’s 1.3 billion people who live in “energy poverty” is the challenge facing the industry and society, said McConnell, who served two years as assistant U.S. secretary of energy. And a direct correlation between the tendency of those who live in energy poverty to engage in terrorism, shown in studies conducted at Rice, should make this effort a priority.

“What people want, I believe, is for people from the U.S. and the developing world to come to them with solutions that actually make their lives better,” he said. “Give them access, give them affordability and provide environmental responsibility.”

The way to achieve this is through transformative technologies, McConnell said, much like the approach used to reduce emissions from coal-fired power plants in the 1970s.

“In the early 1970s, our country passed legislation specifically aimed to require us not to use natural gas for power generation,” he said. “It incentivized and required us to use coal because the natural gas needed to be saved, reserved, utilized in the most productive way possible.”

The result was what McConnell called a perfect storm of public-private partnerships to ensure that burning coal would not create an environmental crisis during a time of fear about the consequences of acid rain. Technologies put into place included scrubbers, detox systems and purification units.

“So what actually happened in that 30-year period?” McConnell asked. “We actually doubled our electric generation powered in this country from coal. During that same 30-year period, we reduced [nitrogen oxides], [sulfur oxides], mercury and suspended particulates by 90%.”

A similar success story is the deployment of catalytic converters to limit tailpipe emissions. Over 20 years, government and industry were able to work together to develop regulations and utilize technology to reach a desired outcome.

Today, McConnell argues, the country has lost its way by focusing too much attention on environmental responsibility and ignoring accessibility and affordability.

“What we need to be doing is getting into a conversation about leadership in transformative technology so that the rest of the world can deploy that transformative technology and actually make an impact where it needs to be—in China, in India, in Indonesia, in Africa,” he said. “These people are not going to think about whether or not they should use fossil fuels. I’m here to tell you, they’re going to use fossil fuels.”

He cited International Energy Agency projections that 80% of the world’s energy would still be derived from fossil fuels in 50 years—about the same percentage as today—despite the growth of renewable sources and other alternative forms of energy.

The transformative technology that can allow the safe growth of fossil fuels is carbon capture and storage, which can intercept up to 90% of CO2 emissions heading toward the atmosphere. The debate in Washington exasperates McConnell because many Republicans are reluctant to acknowledge climate change and are therefore loathe to support a bill that would presume to solve a problem they don’t believe exists. Democrats, he said, don’t want to back anything that would encourage more oil production, even a technology that rids the atmosphere of a greenhouse gas.

Stuck in a glut: Moody’s issues downgrades

With low prices firmly rooted in the E&P sector, upstream companies face EBITDA declines of up to 25% and cash flow pressures brought on by vanishing commodity hedges, Moody’s said.

The shorthand of Moody’s Investors Service outlook for oil, gas and its producers is 2016 will be a new, but fairly unhappy year.

Oil is likely to stay oversupplied in 2016 and Moody’s tamped down on already low prices in a yearend 2015 report.

Moody’s made changes to its forecasts for prices and segments of the oil and gas industry due to market events, including various reports that oil demand won’t grow to match production in 2016. The firm expects financial pressure to hit E&Ps, drilling and oilfield service companies and integrated corporations.

“OPEC oil producers continue to produce without restraint as they compete for market share, exacerbating the currently saturated markets,” said Terry Marshall, a Moody’s senior vice president. “Russia has also greatly increased production, and the possibility that sanctions wMoody’s significantly lowered its 2016 price assumptions for crude and natural gas as high levels of production globally have significantly exceeded growth in oil consumption. For crude, Brent prices fell 19%, WTI by 17%. For natural gas, Henry Hub by 18%.ill be lifted on Iran in 2016 could flood the market with even more supply.”

Moody’s said the integrated oil and gas sector will grapple with negative free cash flow through the year and companies will need to further trim capex despite a 20% cut in 2015, according to a report, “Global Oil & Gas 2016 Outlook: All Regions and Sectors Facing Lower-for-Longer Environment.”

Some help will emerge in 2016, though none are game changers, Moody’s said.

• North American LNG exports and petrochemical plants will develop slowly;

• Long-term coal-to-gas switching for power generators;

• Industrial demand improving; and

• Commercial transportation and other users of gasoline/diesel starting to convert to natural gas.

U.S. chemical renaissance just beginning—report

The U.S. chemical industry grew 3.6% in 2015 despite a strong appreciation of the U.S. dollar and a weakness in several key global markets, according to a new report by American Chemistry Council (ACC).

The ACC’s “Year-End 2015 Chemical Industry Situation and Outlook” forecast a 2.9% increase in domestic chemical production in 2016, followed by a 4.4% expansion in 2017. During the second half of the decade, production is expected to increase at a pace of more than 4% per year on average, outpacing that of the overall U.S. economy, according to the annual report.

“The U.S. chemical industry renaissance is just getting started,” Kevin Swift, chief economist of the ACC and lead author of the report, was quoted as saying.

“The fundamentals are strong,” he added. “Key domestic end-use markets expanded, consumer spending accelerated, the job market began to firm and households enjoyed extra savings from lower energy costs.”

Light vehicle sales were up 5% in 2015, and housing starts up 12% in 2015, Swift noted. Each light vehicle contains about $3,500 worth of chemical products, while each new home about $15,000. According to Navigant Research, light-duty vehicle sales are expected to grow from 88.8 million vehicles in 2015 to 122.6 million in 2035.

New capacity that is set to come online in the next several years will also help continue the momentum, according to Swift. More than 261 new chemical production projects had been announced with a total value of more than $158 billion, which 36% is completed or under construction, the report noted.

“Due to shale gas and the result of horizontal drilling, its resulting in very renewed competitiveness for the U.S. chemical industry, petrochemicals in particular,” Swift told Hart Energy.

According to the ACC, “the global economy faltered in 2015 with geopolitical uncertainty and recessions in Brazil, Russia, Japan and other nations, as well as a pronounced slowdown in China.” However, the economies in the U.K. and the Euro area advanced, the agency stated.

Price hikes crimp Saudi petrochemicals

Saudi petrochemicals companies are expected to retain an edge over their global rivals despite a rise in energy prices that will lead to higher operating costs and smaller margins, according to a recent report in The National. Faced with the prospect of low oil prices for the next few years, Saudi Arabia recently announced a range of reforms that included lower government spending in 2016 and an unprecedented increase in water, electricity, fuel and gas prices.

The kingdom raised the price of ethane to $1.75 per million Btu (MMBtu) from $0.75 per MMBtu. U.S. ethane traded around 80 cents to 85 cents per MMBtu in January. Most of the petrochemical projects in Saudi Arabia rely on ethane and methane gas for feedstock. Lower prices of naphtha have made ethane-based projects less competitive relative to naphtha.

“They [Saudi petrochemical producers] will have less margins, but that doesn’t mean they will be less competitive,” said Raheel Shafi, a Nexant senior consultant for the Middle East. “The competitive advantage of all ethane has, however, taken a big hit in comparison to lower naphtha prices over the past 18 months.”

Globally, petrochemical producers’ profits are narrowing because the prices of petrochemicals are linked to crude prices. The revenues of Arabian Gulf petrochemical producers are expected to decline further this year after sliding 20% to 30% in the 12 months to June because of the oil price slump, according to Abdulwahab Al Sadoun, the secretary-general of the non-profit Gulf Petrochemicals and Chemicals Association in Dubai.

Saudi cement and petrochemical companies were quick to announce the effect of the new energy prices on their operating costs and revenue after the government revealed the new fuel pricing at year end. Several of the companies said they would cut or streamline expenses to cope with the new energy prices.

The companies are unlikely to increase product prices or lay off staff, analysts said.

“They won’t be able to compensate for the loss of this margin by increasing product prices,” said Sanjay Sharma, vice president of IHS Chemical Consulting for the Middle East and India. “The only way they can compensate this to some extent is by improving efficiency. The Saudi producers, being one of the lowest-cost producers globally, are essentially price-takers not price-setters for petrochemical products.”