By Michael D. White
Over the past decade, advances in energy generation and the technologies surrounding both its process and distribution have had a marked impact on the way both the public and industry view what keeps the lights on and the wheels of industry turning.
According to a recent report released by the Alexandria, Virginia-based American Geosciences Institute (AGI), “Increased publicity about the potential hazards and impacts of energy production and transport has led to conversations about energy and the environment that have grown louder and more fraught with emotion, giving the impression of an issue defined by strongly entrenched positions and with little opportunity to find common, or middle, ground.”
But, the AGI says, the issue and its social, political, technical and environmental components has actually resulted in a growing interest in what the AGI calls the development of “a methane economy” powered by a combination of its “cousins,” natural gas and oil.
One of the conclusions of the report is that “the social license granted by consensus public opinion—at the national, state and local levels—can be either a substantial enabler or barrier to a ‘methane economy,’ and its importance cannot be overstated.”
The economic potential of the current oil and gas boom, the report concludes, “is undeniable for the United States, both as an engine of economic growth and as a measure of energy security. Yet, the rapid expansion of the domestic footprint of energy development has also dramatically increased awareness of the challenges involved.”
So, that raises questions like, what about the components of this ‘methane economy.? And what about energy’s political darkhorse, coal?
The U.S. is currently the world’s largest natural gas producer, having surpassed Russia in 2009 with the country’s natural gas production increasing from 55 billion cubic feet per day (Bcf/d) in 2008 to 72.5 Bcf/d in 2016. Most of that natural gas—about 96 percent in 2016—is consumed domestically.
Despite certain disadvantages—it contains less energy per volume than other fossil fuel sources and presents difficulties for transporting and storing it—natural gas can boast a vast supply, more efficient burning than petroleum and coal, and the development of new technologies that allow it to be extracted from shale rock are buried below the surface.
Recent data from the Paris-based International Energy Agency (IEA) projects that the U.S.’ vast natural gas production capacity, and its growing role as an overseas gas exporter, can compete with all of the major global players—Russia, Qatar, Iran, and Canada, for example—in as little as five years.
Last year, the Sabine Pass facility in Louisiana became the first operating LNG export facility in the Lower 48 states. Four other LNG export facilities are under construction and are expected to be completed by 2021. When fully operational, these five plants are expected to have a combined operational export capacity of 9.2 Bcf/day.
In fact, the IEA’s latest Short-Term Energy Outlook projects that the country’s abundant natural gas resources and production capabilities will play a large role in helping the U.S. export more natural gas than it imports beyond 2018 with the opening-up of previously untapped global markets.
Most recently, Lithuania became the first former Soviet state to import a shipment of U.S. natural gas. The shipment moved via LNG tanker from Cheniere Energy’s export terminal on the U.S. Gulf Coast to the floating Klaipeda terminal off the country’s Baltic Sea coast.
The Baltic nation has already been importing LNG from Norway since it opened its first terminal for the super-cooled fuel in 2014 and is keen to further free itself from its past as a monopoly market of Russia’s government-owned natural gas subsidiary, Gazprom.
Commenting on the shipment, Lithuania’s Energy Minister Zygimantas Vaiciunas said, “We are happy to reach a point where importing gas from the U.S. is not only politically desirable, but also commercially viable.”
Natural gas processing capacity in the Appalachian region has grown dramatically over the past several years as producers try to keep pace with increasing natural gas production in the region.
Between 2010 and 2016, the U.S. Energy Information Administration (USEIA) estimates natural gas processing capacity in Kentucky, Ohio, Pennsylvania, and West Virginia has grown from 1.1 billion cubic feet per day (Bcf/d) to 10.0 Bcf/d.
Supplies of natural gas out of the Appalachian region into the Midwestern states are likely to gradually displace some pipeline imports from Canada as well as increase U.S. pipeline exports to Canada from both Michigan and New York.
Several new pipeline projects, including the Rover and Nexus Gas Transmission pipelines, are also being developed to increase takeaway capacity from the supply regions that span parts of New York, Ohio, Pennsylvania, and West Virginia into the U.S. Gulf coast, Midwestern states, and eastern Canada.
The USEIA’s most recent Drilling Productivity Report estimates that natural gas production in the Appalachia region has continued to increase in recent months, with the Short-Term Energy Outlook expecting further growth through the rest of 2017. Natural gas processing capacity is also expected to increase by 2.5 Bcf/d over the next two years.
This past summer, a group of West Virginia state legislators formed an interim committee to explore more ways the state can attract and increase investment in shale gas development. According to State Senate President Mitch Carmichael, the committee “will hear more from the industry about best practices, opportunities for economic expansion and more ways to compete for investment capital with Pennsylvania, Ohio and other producing basins across the country.
Undergirding the AGI report and the growing interest in a ‘methane economy, ‘natural gas and oil “will be crucial components of the world’s energy future,” according to Norway-based classification group DNV GL’s forecast of the energy transition. “While renewable energy will grow its share of the energy mix, oil and gas will account for 44 percent of the world’s energy supply in 2050, compared to 53 percent today,” it says.
The demand for oil, says DNV GL, will peak in 2022, driven by expectations for a surge in prominence of light electric vehicles, accounting for 50 percent of new global car sales by 2035.
However, the group says, the stage is set for gas to become the largest single source of energy towards 2050, and the last of the fossil fuels to experience peak demand, which it expects will occur in 2035.
For generations, the words Texas and oil have gone together like the proverbial horse and carriage with the Lone Star State serving as home to nearly a third of U.S. refining capacity with operations that sit in low-lying areas along the Gulf Coast from Corpus Christi, Texas, to Lake Charles, just over the border in neighboring Louisiana.
In early September, that capacity was severely threatened when Hurricane Harvey, the first major hurricane to seriously threaten the U.S. Gulf Coast in several years struck the region with a hammer blow.
Disruption of the state’s critical oil production capacity was threatened earlier when Hurricanes Gustav and Ike in 2008, and Hurricane Isaac four years later, slammed into the Gulf, combining to knock out a total of more than one million barrels of Gulf oil production and temporarily disrupting the region’s refining capacity.
Harvey struck first at Corpus Christi, then Houston and the Baytown region, shutting down operations at eleven major oil refineries, which, under normal conditions, have the capacity to refine about 2.7 million barrels of oil a day, or about 14 percent of the nation’s total refining capacity.
In addition, the monster storm forced shutdown of Colonial Pipeline, which transports more than 100 million gallons of gasoline, heating oil and aviation fuel every day from refineries in the Houston area as far as the Port of New York/ New Jersey.
According to Guy Caruso, senior energy and national security adviser at the Center for Strategic and International Studies and a former EIA Administrator, all industry segments – upstream, midstream and downstream, including refining – were affected by Harvey.
“There were refinery and pipeline shut downs, yet these pieces of infrastructure are coming back,” he said. “Government has played a role by temporarily waiving certain restrictions and regulations and granting crude oil exchanges from the Strategic Petroleum Reserve. Ultimately, an important factor is the role of the marketplace itself.”
“There is,” he adds, “an overarching point that I can make based on my experience … [in the past] price controls, rigid allocations – those, in my view and in many studies that have been done about disruptions, were part of the problem as opposed to part of the solution. Today we have open markets, less restrictions on the movement of crude and products, and I think that has shown itself to be an effective allocator supply, even during Katrina [in 2005] and now even more so during Harvey.”
Meanwhile, in the weeks and months ahead, “we will have ample time to reflect on this calamity, the risks and challenges posed by our new-found energy role in the world, and how we ensure that we develop and deploy advanced and informed technology, engineering, policy, and planning to mitigate the impacts of such events in the future.”
But, as dire as Harvey, and Hurricane Irma, which struck Florida on Harvey’s heels, were their impact on the oil industry and its ability to rebound was not nearly as dire as first thought.
In the time since both storms made landfall, oil and gas companies have mostly been able to rebound as lessons learned from previous storms, in particular hurricanes Katrina and Rita in 2005, have made operations more resilient. Jamie Webster of the BCG Center for Energy Impact, told The Financial Times that, “This storm was a test for how well the U.S. can deal with these threats. The industry, I would say, has passed with flying colors so far.”
Webster’s observation was underscored by Robert McNally, a fellow at the Columbia University’s Center on Global Energy Policy and former international and domestic energy adviser in the Bush Administration.
“The history and what we’re seeing right now shows that the oil industry and the government – the federal government and the state government – is going to move heaven and earth to make sure that the energy disruptions are as short as possible,” he said
In terms of production, one oil producing region that’s seen a growth surge as of late is the Anadarko Basin, which covers a large portion of western Oklahoma and the northeast corner of the Texas panhandle.
According to the USEIA, the Anadarko Basin is expected to “significantly contribute” to U.S. production growth, given anticipated market conditions over the next 16 months. The government agency forecasts production in the region to grow to 500,000 barrels per day by the end of 2018.
The Anadarko Region accounted for 437,000 barrels per day of oil production and 4.9 billion cubic feet per day of natural gas production in July alone. Production in the region has increased since the beginning of the year with the region accounting for 13 percent of all new wells drilled in the country in July 2017 with substantial expansion expected.
In fact, in 2010, the U.S. Geological Survey completed an assessment of the entire Anadarko Basin and estimated that there is technically-recoverable, and still undiscovered, resources of 495 million barrels of oil, 27.5 trillion cubic feet of natural gas, and 410 million barrels of natural gas liquids.
The American Petroleum Institute (API) recently released a study it had commissioned which claims that not only will production in the Anadarko Region and other oil producing areas grow in the near- and medium-term, investment in oil and gas infrastructure will contribute between $1.5 trillion and $1.9 trillion to the U.S. GDP by 2035, or between $79 billion and $100 billion annually.
The focus for that area, the API said, “has been and will continue to be” on developing and transporting the vast amount of natural gas resource contained in the Permian Basin in West Texas and the Marcellus/Utica producing basin, which covers about 60 percent of the entire State of Pennsylvania.
Another region targeted for enhanced development is the Northeast U.S., which will also witness “a significant investment in oil and gas infrastructure moving forward, with total investment for the area ranging between $204 and $278 billion. These values equate to roughly 20 percent of the total oil and gas infrastructure investment across the U.S.”
Energy infrastructure “is a leading catalyst for economic growth,” the study said, concluding that “rapid oil infrastructure development is likely to continue for a prolonged period, with total capital expenditures for U.S. oil and gas infrastructure development between 2017 and 2035 ranging from $1.06 trillion to as much as $1.34 trillion spent “on improving existing and new infrastructure for surface and lease equipment; gathering and processing facilities; oil, gas, and natural gas liquids (NGL) pipelines; oil and gas storage facilities; refineries and oil products pipelines; and export terminals.”
Infrastructure development is expected to employ an average of 828,000 to 1,047,000 individuals annually across the U.S., not only in the states where infrastructure development takes place, and including indirect and induced labor impacts, the API study said.
The projections, it noted, “are only for employment associated with oil and gas infrastructure development, and do not include jobs more broadly across the upstream and downstream segments of the industry, nor do they include jobs related to operating and maintaining oil and gas infrastructure, each of which would add millions to the U.S. labor pool.”
The study also assesses economic benefits of the projected infrastructure development. Economic benefits of oil and gas infrastructure development are very significant with Texas, Louisiana, Pennsylvania, California, and Ohio, in that order, benefiting the most from increased infrastructure development.
“Infrastructure development will have wide-ranging benefits for millions of Americans,” the API study concluded. “The midstream business is critical to the growth of the upstream and downstream portions of the oil and gas business. Without adequate infrastructure to support processing and transport of oil and gas, the upstream and downstream will develop less fully over time, and the foregone economic benefits would be very significant.”
But, what of the odd-man out in the visionary ‘methane economy’?
An across-the-board reversal in Washington, D.C.’s past policies restricting coal mining and a strong demand from U.S. steel makers have driven U.S. coal production up 14.5 percent nationwide compared to last year, according to the USEIA.
Coal exports, the Agency said, rose nearly 60 percent in the first quarter of this year from the same period last year.
In August, the U.S. Department of the Interior scrapped rules on coal royalties that mining companies had criticized as burdensome and costly, and challenged in federal court.
Rules in place since the 1980s have allowed coal companies to sell their fuel to affiliates and pay royalties to the government on that price, then turn around and sell the coal at a higher price, often overseas. Under the now-repealed rule, the royalty rate would have been determined at the time the coal is leased, with revenue based on the price paid by an outside entity, rather than an interim sale to an affiliated company.
Repealing the rule “provides a clean slate to create workable valuation regulations,” said Interior Secretary Ryan Zinke, adding that the repeal will reduce costs that energy companies would otherwise pass on to consumers.
Also in August, the Corsa Coal Corp., which mines for the metallurgical coal used in the production of steel and other metals, announced the opening of a second coal mine just two months after opening its Acosta mine operation in Somerset County, Pennsylvania.
The Acosta mine, located about 60 miles south of Pittsburgh, was the first new coal mine to open in a decade. The second mine will be operational in the first quarter of 2018.
The company made the decision owing to a robust steel marketplace, Pennsylvania-based Corsa Coal’s CEO, George Dethlefsen, said at the time. Deregulation, he said, “has been a tremendous help for the industry. The war on coal is over.”
Also in August, another Pennsylvania-based coal company, Xcoal Energy and Resources, announced that it had won a contract to supply coal to Ukraine’s state-owned power company in preparation for that country’s winter heating needs.
The deal, potentially worth about $79 million, calls for the company to ship 700,000 tons of anthracite coal to the Ukraine to heat homes and businesses. The first shipment left the Port of Baltimore and later arrived at the Black Sea port of Odessa.
Energy Secretary Rick Perry said U.S. coal “will be a secure and reliable energy source’’ for Ukraine, which, he said, has been “reliant on and beholden to Russia to keep the heat on. That changes now.”
In Montana, another state dependent on coal, production is more than two million tons ahead of where it was at this time last year with most of the increase generated by Spring Creek, a mine operated by Cloud Peak Energy in southeast Montana.
The increase, says the company, is based, in large part, on increased sales to customers in Japan and South Korea. By the end of June of this year, the company had shipped 1.8 million tons of coal to Asia, up from the 200,000 tons exported during the same period in 2016 through the Westshore Terminal, a coal port off the shore of Vancouver, British Columbia.
According to a recent industry report by SNL Analytics, plans for more coal-fired power plants in South Korea and Japan could boost demand for coal.
But, coal politics in the U.S., especially at the state level, continues to hobble attempts to boost export sales, despite the declaration that, “the war on coal is over.”
Since 2010, six projects to construct export coal terminals have been proposed in Oregon and Washington, alone, primarily on sites along the Columbia River and the shore of Puget Sound. Not one has been built— all of them blocked by environmental or land-use regulations, tribal fishing rights, or roller-coaster variables in pricing.
The latest coal export project that won’t see the light of day was squashed in late September when the Washington Department of Ecology denied a permit for a proposal to build what would have been North America’s largest coal export terminal at the Port of Longview.
The proposed $640 million Millennium Bulk Terminal was a joint venture of Australia’s Ambre Energy and Arch Coal, the second-largest coal producer in the U.S. and, when fully operational, would have had the capacity to move 44 million tons of coal annually, hauled westward by train from mines in Wyoming.
There were, said Washington State Ecology Director, Maia Bellon, “simply too many unavoidable and negative environmental impacts for the project to move forward.”
In April, Howard Gruenspecht, Acting Administrator of the USEIA, told attendees at the 44th Annual International Energy Conference in Boulder, Colorado, that, with strong domestic production and relatively flat demand, the United States will become a net energy exporter through next year.
U.S. crude oil production, he said will rebound from recent lows, “driven by continued development of tight oil resources; with consumption flat to down compared to recent history, net crude oil and petroleum product imports as a percentage of U.S. product supplied decline across most cases.”
Across most cases, he said, “natural gas production increases despite relatively low and stable prices, supporting higher levels of domestic consumption and natural gas exports.”
And what of coal? With modest electricity demand growth, he said, “the primary driver for new electricity generation capacity in the Reference case is the retirement of fossil fuel units, largely spurred by the U.S. Environmental Protection Agency’s Clean Power Plan (CPP), the near-term availability of renewable tax credits, state-level policies to promote renewables, and nuclear retirements.”
Even if the CPP is not implemented, he concluded, “natural gas and renewables are the primary sources of new generation capacity as the future generation mix is sensitive to the price of natural gas and the growth in electricity demand.”
Bio: Michael D. White is a published author with four non-fiction books and well more than 1,700 by-lined articles on international transportation and trade to his credit.
During his 35 year career as a journalist, White has served in positions from contributor and reporter to managing editor for a number of publications including Global Trade Magazine, the Los Angeles Daily Commercial News, Pacific Shipper, the Los Angeles Business Journal, International Business Magazine, the Long Beach Press-Telegram, Los Angeles Daily News, Pacific Traffic Magazine, and World Trade Magazine.
He has also served as editor of the CalTrade Report and Pacific Coast Trade websites, North America Public and Media Relations Manager for Mitsui O.S.K. Lines, and as a consultant to Pace University’s World Trade Institute and the Austrian Trade Commission.
A veteran of the United States Coast Guard, White has traveled in both Japan and China, and earned a degree in journalism from California State University and a Certificate in International Business from the Japanese Ministry of Trade & Industry’s International Institute for Studies & Training in Tokyo.
