Investment, Environmental and Security Priorities Drive High Gas Prices

Emily Pickrell, UH Energy Scholar, University of Houston

For many consumers, gasoline prices in the last couple of years have felt perplexing. 

In 2020, they bottomed out at $1.97/gallon at the height of the pandemic. Last week, gas prices hovered around a demoralizing (from the customer perspective, anyway) national average of $4.80/gallon. 

These prices are up 35% from their $3.10/gallon national average this time last summer. They have eased slightly in the last couple of weeks, after hitting a high of $4.95/gallon in mid-June.

Yet it is premature to assume that they will go back to their 2021 range anytime soon. These higher prices, driven by several interconnected considerations, will likely stick around for some time, even though oil prices have fallen from their $123 per barrel peak in March.

The current high price of oil is the obvious main reason for higher gas prices. Global oil production, especially in the U.S., has suffered from insufficient financial investment, as the focus instead shifts on a potential bonanza from the energy transition.

And while higher oil prices are encouraging the return of some of this investment, it is taking some time for investment dollars to end up as barrels of oil, ready for consumption. The disconnect between demand and supply was initially even bigger in the post-pandemic travel spike, but this is expected to normalize in the coming months, with more production coming online.

An aging and insufficient refinery network in the U.S. is an additional culprit for gasoline prices, even as the regulatory climate makes it nearly impossible to bring new refineries online.

Building a refinery is pricey: It costs an estimated $7 billion to $10 billion, and take 5-7 years, not including the time to acquire a site. Strict regulatory and environmental permitting standards are a big part of the reason that refineries are so expensive to build. Expectations that the energy transition will be rapid has likely made these challenges more formidable, even though the full transition to EVs is estimated to take several decades. Currently, EVs make up only 2.5% of vehicles on the road.  

From a refiner’s perspective, this all means that their investment decision only makes sense if the refinery can be expected to operate for several decades.

And this is one of the biggest walls that expanding our domestic refinery capacity is running up against, especially as the transition away from fossil fuel starts to take hold for passenger vehicles.

The belief that refineries may be obsolete in the coming years has essentially discouraged new investment, despite the current price spike for gasoline.

“We have not built a new refinery in four decades,” said Ramanan Krishnamoorti, the chief energy officer at the University of Houston. “The investments it would require are seen as too significant, especially if the energy transition is truly going to be happen and their products are not going to be demanded.”

The same problem has made the current fleet of refineries increasingly difficult to keep online. On the Gulf Coast, some of the refineries that had been operating were more than 60 years old. They had reached a point where the maintenance and upkeep were prohibitive. 

Again, the cost-benefit analysis has to be applied – if a refinery’s lifetime is less than 20 to 25 years, the investment is not considered to be worth it, regardless of today’s gasoline prices.

As a result, over the last three years, the U.S. has shut down about a million barrels of refining capacity, leaving the remaining refineries running at about 95% capacity.

And running at this high level will, in turn, likely lead to future operational issues for the on-line refineries, as it makes preventive maintenance impossible. (Operating at 85% capacity provides better strategies for the long-term health of the refineries.)

Added to domestic refinery constraints is impact on global gasoline supply from the Russia-Ukraine war. The war has effectively forced the European Union to make commitments of removing Russian gasoline from the European market. The EU has already stated it will lower its consumption of Russian gasoline imports by two-thirds in the next 12 months.

Prior to the war, Russia was exporting about half of the 10 million barrels per day (b/d) of crude oil and condensates it produced – and about half of this was going in turn to various European neighbors. 

Europe’s decision to shun oil and refined gasoline from Russia has been a blessing for U.S. refiners, by tightening the global gasoline supply, as Europe increases its demand of imports from the Middle East and other locations.

Some oil analysts believe that the end of the war would bring prices down.

“There’s no question if we woke up one morning and Putin was not in charge anymore, prices would drop precipitously,” said Tom Kloza, global head of energy analysis at OPIS. “That has been a catalyst taking prices horribly higher in the last 90 days or so.”

Meanwhile, the cumulative impact of these forces is showing up in domestic storage reserves. There has been a 20% drop, compared with this time last year.

And while prices have been drifting down in the last couple of weeks, it will be September at the earliest before there is significant movement on gasoline prices. These decreases will be driven first by more oil production coming online, which will cause oil prices to fall. It will also be accompanied by the expected drop in demand for gasoline consumption, as the summer ends. This drop may also be even steeper if the economic indicators of a possible recession turn out to be true.

And, of course, all of this presumes that the Gulf Coast weather will not further complicate the situation. 

“Inventories are down really low right now,” Krishnamoorti said. “One big hurricane, and we will easily surpass six dollars a gallon.”

Building Climate Resilience: Why Lessons from Houston Matter

Ramanan Krishnamoorti, Chief Energy Officer, University of Houston

Aparajita Datta, UH Research Scholar, University of Houston

In our latest @Forbes blog, UH Chief Energy Officer @krishnamoorti and Research Scholar Aparajita Datta examine the matter of climate resilience, and why the nation could stand to learn from Houston in combating climate risks.https://t.co/wHLNRD8pBy

— UH Energy (@uhoustonenergy) May 30, 2022

Most of the conversation around addressing climate change has focused on what the federal government and global community can do. In energy-centric Houston, pledges by oil companies to cut emissions have drawn attention. But when it comes to the risks of climate change, cities are on the front line, and nowhere is that better illustrated than in Houston and along the Gulf Coast, where much of the nation’s refining and petrochemical manufacturing capacity is concentrated. With the start of hurricane season and an overheated Gulf of Mexico and Atlantic Ocean, the issue of our preparedness are front and center.

Like other cities, Houston has worked to promote energy efficiency and a cleaner transportation sector, which are important for addressing climate risks. But cities aren’t equipped to adopt other policy innovations that can quickly and adequately mitigate the impacts of a changing climate. Climate resilience requires coordinated policies across all levels of government and the private sector, but the nation has fallen short on building this resilience and breaking down silos. Houston tells the story of why it is critical to empower local governments with the right resources and facilitate integration across local, state, and federal jurisdictions to build a more resilient country.

It has been almost five years since Hurricane Harvey battered the city and brought the national economy to a temporary halt, as refineries and petrochemical plants that supply the country with gasoline, jet fuel, and other products were shut down. The impact on Houston has been far longer lasting. Every extreme weather event since then, from tropical storm Imelda in 2019 to winter storm Uri in 2021, has tested the limits of Houston’s resilience. As the risks continue to grow, Houston’s future depends on the pace of coordinated policy change and on rethinking how to build resilience within communities and across the systems that connect us.

The Houston Metropolitan Area is expected to add 3 million people, growing from about 7 million to 10 million between now and mid-century. The projected population growth, accompanied by an increasing urban sprawl, will compound the risk presented by flooding—a threat well-known to Houston-area leaders and residents—and two that have received far less attention: sea-level rise and land subsidence.

Currently, about a quarter of the homes in the Greater Houston area face a significant flood risk. Increased precipitation by 2100 means that the annual risk of at least one flood exceeding 7 feet will double. While homeownership in Houston once provided working-class families with the promise of upward mobility, this increased risk will expand the homes experiencing significant or repeated flood damage. This will push and keep low-income families in neighborhoods that face enduring impacts, increase the cost of homeownership, and make it harder for them to access safe and livable housing.

Simultaneously, sea levels along the Gulf Coast are expected to rise by 5 feet over 1992 levels by 2100. Storm surges are expected to grow 10 times by 2050, resulting in a three-fold increase in the number of homes at risk, potentially displacing 500,000 people.

Population growth in the city will increase demand for water and housing over the next three decades, exerting additional pressure on our land and water resources. The increased groundwater pumping and developed land cover directly affect the magnitude and extent of land subsidence, which in some areas of Houston is already as much as 0.3 feet per decade.

Houston’s extensive commercial infrastructure is threatened, too. The Port of Houston, one of the U.S.’ largest ports in terms of waterborne tonnage, and the Houston Ship Channel are among the most vulnerable to climate and extreme weather risks. Operational disruptions of the Ship Channel from past extreme weather events have caused economic losses of more than $300 million per day. Similarly, a third of the petrochemical facilities in the region are prone to inundation during a 100-year flood, the frequency of which is now likely to increase to every one to thirty years along the Gulf Coast. Over the next decade, the cost of climate risks to the Houston Ship Channel and petrochemical facilities in the Gulf Coast region could increase by as much as 800%, while the cost of the failure of critical equipment and the associated punitive fines will be much higher.

In the absence of upgraded standards of engineering, design, and remediation based on realistic risk analysis, not only would property damages and costs be significant, but the functionality of the city’s energy facilities will be threatened. Robust governmental policies in line with high-resolution real-time modeling of facility-level risks are generally lacking and unable to capture the effects of land subsidence and encroachment in watersheds and wetlands. As a result, the impacts of extreme weather events extend beyond immediate damages, operations, supply chain disruptions, and personnel safety, and have lasting consequences for the neighboring communities and the environment.

Houston’s economic recovery from Harvey has led to the common misperception that the city has fully and successfully bounced back since 2017. Some of the most vulnerable and marginalized Houstonians are still rebuilding from Harvey, and Uri was yet another setback. It held a mirror up to the city that is unprepared and ill-equipped, and, like the rest of the nation, is faced with deep political divergences between local, state, and federal agencies. What remains unaddressed is that building climate resilience goes beyond immediate recovery. It requires systems-level planning for the unanticipated, equipping local governments with the resources that can serve the unique needs of its people, and facilitating communication with federal and state counterparts to safeguard infrastructure, social systems, and communities. Houston is the harbinger of America’s future- demographically and climate-wise- and how the city persists and thrives in its efforts to build resilience will shape the nation’s path forward.

UH Energy is the University of Houston’s hub for energy education, research and technology incubation, working to shape the energy future and forge new business approaches in the energy industry.

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The Future Of Oil And Gas? Look To The Past

By Chris Ross, Executive Professor, C.T. Bauer College of Business

In the early days of 2017, it behooves oil and gas companies to reflect on the past, while making plans robust to an uncertain future outlook. There are several questions that should be asked:

• Where are we in the oil and gas price cycles?
• How will politics and policies affect the business outlook?
• What are the appropriate strategies?

Learning from the Past

It will not surprise any investor in oil and gas and related businesses that theirs is a cyclical business. Prices run up when supplies fall short of demand, hover on the summit for a few years, then tumble as new supply sources are developed and demand growth slows down (Figure 1).

After the collapse of 1986, oil prices remained volatile through 1990, then declined further through 1998 as production from the Middle East, Norway, Iran and Venezuela increased to meet demand growth and replace declines in Russia and North America. One consequence of the price decline in 1998 was major oil company mega-mergers. These resulted in high-grading of projects, reduction in aggregate capital spending and slowdown in production increases, setting the stage for the run-up in prices after 2002.

The period from 1986 through 2002 can be seen in retrospect to have been a “long grind,” as oil prices were set by the long-term marginal costs of incremental production sources needed to satisfy demand growth and replace declining production from mature oil fields and political turmoil.

Tightly controlled wellhead natural gas prices in the 1970s led to supply shortages. The 1978 Natural Gas Policy Act (NGPA) started a process of decontrol and broadened the responsibility the Federal Energy Regulatory Commission held over the industry.

In 1985, FERC issued Order No. 436, which changed how interstate pipelines were regulated. This established a voluntary framework under which interstate pipelines could act solely as transporters of natural gas, rather than filling the role of a natural gas merchant. However, it wasn’t until Congress passed the Natural Gas Wellhead Decontrol Act (NGWDA) in 1989 that complete deregulation of wellhead prices was enabled. Issued in 1992, FERC Order No. 636 completed the final steps towards a competitive market by making pipeline unbundling obligatory.

Natural gas became a traded commodity subject to its own cycles (Figure 2).

The decontrolled market opened new sources of supply, enabled by new seismic technologies that uncovered large resources of natural gas under the Gulf of Mexico (GoM) continental shelf. A gas bubble was inflated, holding spot prices below $3/million British Thermal Units from 1989-1999. New markets, notably independently owned cogeneration plants empowered to sell electricity to industrial plants and the grid at prices representing the “avoided cost” that new utility projects would have incurred, caused rapid demand growth.   The bubble burst as gas production in the Gulf of Mexico peaked, natural gas prices increased and LNG import terminals were built.

Higher prices induced innovation on the supply side as George Mitchell figured out how to extract natural gas from tight shale rock, and the technologies were deployed in other gas and then oil shale plays. Natural gas prices collapsed in 2009: demand accelerated as natural gas displaced coal in the power sector, somewhat constrained by limitations on pipeline transportation. New pipeline connections were built despite opposition; LNG import facilities were converted to export facilities.

Mark Twain wrote “History doesn’t repeat itself, but it does rhyme.”  If history were to repeat itself, oil prices would remain low for another “long grind”, mirroring 1986-2002 by declining further over the next 15 years; natural gas prices would start strengthening in 2019.

Politics and Policies

For oil markets, turmoil in the Middle East and Africa withdrew about 3 million barrels per day from world markets between 2005 and 2015. Ideological conflicts, coupled with the demographic realities of a growing number of young men with few employment opportunities, suggest continued instability.

OPEC’s agreement to reduce production with apparent support from Russia will be tested by inducing expansion of U.S. shale production. But the need for cash to meet social commitments is likely to reduce funding available for capital spending by the national oil companies and will lead to lower production, regardless of the OPEC quotas. The “long grind” seems likely to be shorter this time around, more likely five rather than 15 years.

The past eight years have seen a series of rules designed to suppress coal use, to the benefit of natural gas as well as renewables. Several of these rules are still being litigated, and the new administration may choose not to defend constitutional challenges by various individual states. There may also be a reduction in subsidies and mandates favoring renewables, but natural gas will likely find it difficult to displace coal at the pace seen in recent years. LNG exports will allow further production growth, but the resource available in shale plays in 2017 is significantly larger than the GoM shelf resource available in 1989. Expect natural gas volumes to grow but prices to remain capped by coal through the mid-2020s.

Strategies

For upstream companies, the not-so-long grind through the early 2020s calls for a conservative approach to strengthen balance sheets, sustain dividend payments and drill within cash flows. Prices will be volatile and excessive exuberance will be punished by periods of low prices. However, it will be important to see around corners and monitor closely the factors that could shift the outlook to a new run-up in prices, requiring an expansionary emphasis on capturing new resources and a greater tolerance for debt.

The oilfield services sector has been hammered by the downturn and will likely consolidate further. It remains to be seen whether the consolidation will be lateral or vertical. Halliburton failed in its attempt to strengthen its verticals by merging with Baker Hughes; Schlumberger and Technip have taken a French solution of lateral extension by acquiring Cameron and FMC Technologies, respectively, and the forthcoming merger between GE Oil & Gas with Baker Hughes is also mainly lateral extension of business lines. Historically, oil companies have preferred to purchase equipment and services from best-in-class providers, and the new conglomerates will need to work hard to overcome past preferences and create a persuasive value proposition for bundling purchases of equipment and services from a single vendor.

Midstream companies should be able to resume organic growth as companies “replumb” energy infrastructure, aided by a supportive rather than hostile federal government and underwritten by producers seeking access to liquid markets.

Refiners and petrochemicals companies should benefit from an increasing gap between natural gas (used as feedstock and energy) prices and crude oil (setting international petroleum and petrochemicals products prices) as the oil price cycle will be out of phase with the gas price cycle. Nevertheless, these sectors will see limited volume growth and should continue to focus on limited capital improvements, operations excellence and accretive, synergistic acquisitions.

Well managed companies created value for shareholders through the 1990s by leveraging new technologies, simplifying their organizations to improve productivity, partnering creatively with providers of equipment and services and making acquisitions when prices were low. That playbook should be dusted off and updated for the next five years.

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 As a consultant, Professor and Energy Fellow Chris Ross works with senior oil and gas executives to develop and implement value creating strategies. His work has covered all stages in the oil and gas value chain.

UH Energy is the University of Houston’s hub for energy education, research and technology incubation, working to shape the energy future and forge new business approaches in the energy industry.

Upstream Bust Meets Downstream Boom In Houston: The East Side Earns Some Respect

By Bill Gilmer, Institute for Regional Forecasting, Bauer College of Business

The oil industry divides itself between upstream exploration, production and oil services, and downstream refining and petrochemical operations that turn crude oil and natural gas into useful products. Since 1980, Houston’s upstream sector has been through five major downturns in drilling, all with adverse consequences for the local economy. The current drilling downturn — the worst since the 1980’s – has hit Houston’s West Side particularly hard.

Meanwhile, largely neglected compared to its upstream sibling, the downstream refining and chemical plants in East Houston are enjoying a massive and unprecedented $50 billion construction boom. A combination of strong US economic growth and this downstream construction may be just enough to keep the Houston economy out of recession, despite the current collapse of drilling. If, in fact, newfound economic diversity keeps Houston out of a drilling-driven recession in 2015 and 2016, who would have thought the key piece may turn out to be refining and petrochemicals?

Eastside/Westside

Blame it on the wind. In North America, prevailing winds follow the jet stream and blow from west to east. So if you were looking to locate a smoke-belching factory, you put it on the East Side of the city so the wind can blow smoke and soot right out of town. Put the nice homes and shops on the West Side, where smoke is hardly ever an issue. Of course, factory workers will live in more modest East Side homes close to the factories.

This is the history of many American cities, and what we mean when we refer to East Los Angeles, East Chicago, East Austin and East Houston.  Heavy industry and working-class housing goes east, upscale suburbs and shopping moves to the west, and we create a civic divide that is both industrial and cultural – factory vs. office, blue collar vs. white collar.

In Houston, the split comes along Highway 59, and the Galleria, Energy Corridor, Katy and Sugar Land define the white collar, professional west, while Ship Channel cities like Pasadena, Baytown and Deer Park are inevitably tabbed as blue collar and working class. Since 1980, seven years out of 10 have seen the West Side out–perform the East Side, as drilling thrived, and the eastside refineries and chemical plants got little recognition.

This has been all the more true since 2004, as high oil prices set off a boom in fracking, and soaring drilling activity mostly worked to the benefit of West Houston. Petroleum engineers, geologists, geophysicists and high-level executive talent were in strong demand, local wages grew  and tens of thousands of professional workers poured into Houston. Demand soared for high-end apartments inside the Loop, upscale retail, millions of square feet of new office space and shiny new suburbs around Beltway 8 and the Grand Parkway.

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