How The Presidential Candidates Stack Up On Energy Issues

By Ed Hirs, Energy Economist

Anyone who has been waiting for leadership on energy policy during this year’s tumultuous Presidential campaign may be waiting in vain. There’s little talk of energy and, even when the candidates offer a few proposals on their campaign websites or mention them during a debate, there is a dismaying lack of detail.

About the only talk of energy has come from Democratic candidate Bernie Sanders, who has called for a ban on hydraulic fracturing as the cornerstone of his energy and climate policy.    Sanders’ rhetoric has forced the presumed Democratic front-runner, Hillary Clinton, to say she, too, would impose more restrictions on fracking.

This is in spite of numerous studies – by the Environmental Protection Agency and the administration’s handpicked Secretary of Energy Advisory Board Shale Gas Production Subcommittee – both finding hydraulic fracturing to be benign for the environment and drinking water supplies in particular. To be fair, studies have determined that water disposal injection wells are linked to earthquakes, but hydraulic fracturing has not been so linked. And shale gas has been an enormous benefit for Americans. In 2012, my colleagues and I demonstrated that the annual gain to natural gas consumers from hydraulic fracturing is more than $100 billion—even more today.

On the Republican side, John Kasich is happy to tout the job growth drilling has brought to Ohio during his time as governor but otherwise has said little other than “we need everything” in energy development. Donald Trump has said he would end oil imports from Saudi Arabia if Saudi Arabia fails to step up its own military commitments.

Even Ted Cruz, the candidate from Houston, the oil capital of the world, has offered little more than promises to slash regulations and approve the Keystone XL Pipeline.

None of them has released a detailed and coherent energy policy, even as the impact of the oil bust – low prices, big layoffs and concerns about the global economy – collide with questions about mitigating climate change.

But whoever is elected president in November will no longer be able to ignore the subject, from the nuts and bolts of building new pipelines to balancing the climate impact of coal with policies to retire or retrofit our remaining coal plants.

And those are just the issues related to hydrocarbons. Nuclear and renewable energy should be part of a lower-carbon future. Both pose big challenges.

Public knowledge about nuclear power is largely confined to scare stories, Three Mile Island, Fukushima and “The Simpsons.” Building support for fourth-generation reactors and safer fuels won’t be easy. Neither will decommissioning existing nuclear plants. The Nuclear Regulatory Commission appears to have underestimated the cost of decommissioning the Vermont Yankee plant by more than one-half, or $600 million-plus.

Entergy, the owner of Vermont Yankee, plans not to begin cleanup until a trust fund of about $600 million grows to be $1.2 billion in some number of decades, long after current executives and shareholders have passed away. Will the cleanup costs grow beyond today’s $1.2 billion estimate also? Are there other such shortfall surprises across the current fleet of more than 100 nuclear power plants? The solution to long-term storage or remediation of nuclear waste has been avoided both by Congress and recent administrations. Such long-term thinking is usually outside the interest and beyond the competence of politicians.

Candidate Clinton has called for 500 million solar panels. Pundits have challenged the numbers behind her rhetoric, but integrating the growing amount of solar and wind energy into the grid will require re-engineering not only the grid, but reworking energy storage, intermittency, distributed generation and transmission solutions. As Spain and Germany found out with very successful subsidy programs, the success and costs of the subsidies can overwhelm taxpayers, ratepayers and utilities. Renewable and carbon free energy is not free of costs.

None of the presidential candidates has offered a blueprint for any of these priorities, or for helping the more than 200,000 people who have lost their jobs in the U.S. oil industry since prices began dropping. Federal Reserve Chair Janet Yellen recently pointed to the economic loss due to the decline in oil prices that appears to have more than offset the consumer gain of lower prices at the pump. The U.S., as one of the largest oil producers in the world, is suffering from the low oil prices even more than any member of OPEC. How to replace the conservatively estimated $200 billion cut from the nation’s GDP due to lower revenues and less drilling activity? No one is offering suggestions.

Specific policies could help. My colleagues and I have demonstrated the costs and benefits of restricting imports, and we have called for the return to that policy to reduce the nation’s reliance on foreign crude. An import quota imposed by President Eisenhower saw U.S. crude prices persist at double the world price charged by OPEC. A return to import quotas would encourage conservation and return U.S. workers to the oil industry.

Removing the impediments to new pipelines would help, too, ensuring that people in Boston do not continue to buy LNG like the residents of Tokyo. Expanding pipelines into the Northeast will hasten the end of coal fired power plants in the Northeast and the use of dirty fuel oil for heat.

All of these issues matter. They will require leadership. Doing nothing – and the resulting environmental damage from coal-fired power plant emissions, ash ponds and mining operations, for example, and the financial and human costs of U.S. military efforts in the Middle East – will cost far more than higher gasoline prices, higher electricity rates and higher taxes.

The question is, who among the candidates can lead the nation to address these challenges?  So far, no one in either party has stepped up.

Ed Hirs teaches energy economics in the University of Houston’s College of Liberal Arts and Social Sciences. In addition, Hirs is managing director for Hillhouse Resources, LLC, an independent exploration and production company. He founded and co-chairs an annual energy conference at Yale University.



Bootleggers, Baptists And Regulating Carbon Emissions

By Jim Granato, Scott Mason an Kwok Wai Won, Hobby Center for Public Policy, University of Houston

Did you hear the one about the bootleggers and Baptists? What would these two groups have to do with energy policies, such as carbon emission regulation?

In what is now considered a classic piece of political economy, Bruce Yandle’s “Bootleggers and Baptists: The Education of a Regulatory Economist,” published in a 1983 edition of Regulation, sketched out a view of regulation showing how groups considered to be natural adversaries come together. Specifically, Yandle states:

Bootleggers, you will remember, support Sunday closing laws that shut down all the local bars and liquor stores. Baptists support the same laws and lobby vigorously for them.  Both parties gain, while the regulators are content because the law is easy to administer (page 12).

Yandle expanded upon this theory of political economy in the 2014 book he co-authored with economist Adam Smith.  And the “bootleggers and Baptists” theory sheds light on contemporary arguments over carbon emission policy. First, let us identify who fits the profiles of the two groups. The “Baptists” are members of the environmental movement and the factions therein. “Bootleggers,” on the other hand, are certain members of the energy industry, and those that depend on the success of the energy industry, including labor and governments.

What, then, would cause these “unnatural” allies to unite? The answer lies in the way carbon emissions will be regulated. It is a certainty that any new regulations affect the prices of energy commodities. The Baptists will want to encourage the use of energy commodities that have thelowest carbon footprint. Meanwhile, bootleggers – who are in the business of providing low-carbon commodities – will likewise support similar regulations, shifting market demand to their products.

As a consequence, carbon emission regulations give favored status to energy sources such as ethanol, bio-diesel, wind, solar and the like. Coal and oil production is discouraged with an emphasis on shifting to other fossil fuels, primarily natural gas.

What are the future consequences?

With the bootleggers and Baptist coalition tipping the regulatory scale in one direction – away from higher carbon emissions – the chance for meaningful energy innovations in response to emerging energy, environmental and developmental challenges is more difficult because of anti-competitive rules that both the bootleggers and Baptists support.

Worse, if Yandle and Smith are correct, the institutional rules developed will take on a life of their own – reinforced by the bootlegger and Baptist coalition – and feed new anti-competitive practices. One needs only to look at the evolution of the federal government’s Interstate Commerce Commission (ICC) as an example. It was created in 1887 and, after morphing to regulate bus lines, telephone carriers and other forms of commerce, was ultimately abolished in 1995. If anything, the 100-year experience with the ICC shows how regulatory policies can start off well meaning, but gradually and perhaps inevitably, evolve into protecting certain bootleggers and higher prices for consumers.

As a final thought, carbon emission reductions – or the reduction of any potentially harmful emission – would seem to be far more likely to happen with an open and vigorous competitive environment, with winners and losers determined by consumers and not bootleggers and Baptists. Yet,  bootlegger and Baptist coalitions have built-in advantages, particularly since in many cases the benefits they receive for the regulations they support are concentrated and lucrative, while the costs to the public are so spread out.

One way to level the policy playing field is to raise the cost to bootlegger and Baptist activity. On that score, Yandle and Smith suggest structuring policy processes so there is greater transparency (reducing the cost of the public acquiring information) but also giving states greater say, so that bootleggers and Baptists have to compete with the public in many places rather than just in Washington D.C. With the added policy diversity, some states will outperform others and, in doing so, provide avenues to a more innovative set energy innovations.

Jim Granato is professor of political science at the University of Houston’s College of Liberal Arts and Social Sciences and director of the Hobby Center for Public Policy. His book, “The Role of Policymakers in Business Cycle Fluctuations,” focuses on how monetary policy can stabilize business cycles. 

Scott Mason is program manager at the University of Houston’s Hobby Center for Public Policy.

Kwok Wai Wan is a post doctoral fellow at the University of Houston’s Hobby Center for Public Policy.

The Solar Net Metering Controversy: Who Pays for Energy Subsidies?

By Earl J. Ritchie, Lecturer, Department of Construction Management, College of Technology

A huge controversy has arisen in California and other states over the way solar electrical generation is subsidized by net metering, or the way in which people who produce solar energy – usually through rooftop panels – are reimbursed for the energy they generate and send back to the electric grid. Proposed or already approved reductions have been greeted by public protests, lawsuits and even a proposed amendment to the national Energy Policy Modernization Act, which would limit the ability of states to reduce subsidies.

The fight pits solar rooftop owners and the solar industry against utility companies and free marketers.

The issue

Forty-three states have mandatory net metering plans. Most net metering plans in the United States require utility companies to buy back excess electricity generated from distributed (residential and business) solar installations at the retail cost of electricity.

With the slightest bit of thought you will recognize that this is not a valid business model. No business can cover the cost of operation and profit necessary while buying their product at the same price that they sell it. In the case of utility companies, they must provide billing, support services, grid maintenance and other operational functions. For the amount of electricity provided by net metering, these costs are not covered. Typically, unrecovered costs are transferred to customers who do not have solar installations by raising electricity rates.

This is not a problem as long as the fraction of feed-in energy is small. Once solar capacity becomes a significant portion of electricity generated, as has happened in California, Nevada, Arizona and Hawaii, there is a free-for-all over who will pay these unrecovered costs.

The California example

California has by far the largest amount of solar generating capacity in the United States, representing over half of total U.S. installed solar capacity. The combination of government incentives and the decreasing costs of solar photovoltaic panels has made solar installations highly profitable, resulting in explosive growth of solar installations and the industry that markets, finances and installs the equipment.


U.S. solar photovoltaic installations (Solar Energy Industries Association 2014)

Since solar electricity now represents 7.5% of California supply and is expected to continue to grow, the subsidy is no longer a trivial issue. A heated controversy began as a result of requests in 2015 by the major publicly traded utilities, Southern California Edison, Pacific Gas & Electric and San Diego Gas & Electric, to be compensated for unrecovered costs of net metering by additional fees and lowering the price they pay for net metered electricity. The solar industry and green power advocates responded with vociferous objections, with one spokesman calling it a “war on solar.”

In a 2016 decision generally regarded as a victory for the solar industry, the California Public Utilities Commission retained net metering at retail cost but imposed certain fees on residential solar installations. To some extent, the Commission kicked the can down the road by indicating that they will reconsider net metering in 2019.

The bigger picture

Net metering applies to rooftop solar, which represents about one third of U.S. solar capacity. The issue of subsidizing renewable energy is much broader: utility scale generation is roughly twice the size of rooftop solar, and subsidy considerations also apply to wind power and other renewables. In addition, it is a worldwide issue. The U.S. only represents about 10% of installed solar photovoltaic capacity; the largest capacities are in Europe and the Asia-Pacific region.

Public discussion often focuses on economic analyses, which are typically slanted to the viewpoints of the authors. Analyses by utility companies tend to focus on the cost of providing generation; analyses by solar advocates often include imputed environmental benefit and avoided cost of transmission and other generation facilities. Although pro-solar analyses may conclude that solar is currently economic, the IEA reports that only 4% of solar installations in 2014 were economic without subsidy. This means continued growth of solar in at least the near-term will be dependent upon subsidies.

How much should the subsidy be?

There is no reason net metering credits need necessarily be at full retail cost. Some international jurisdictions value credits below retail cost. A recent “value of solar” calculation by the Minnesota Public Utility Commission places the value above retail cost, largely on the basis on the value of avoided carbon emissions. Ideally, subsidies should be no higher than is necessary to achieve the desired utilization. As solar costs decrease, subsidies should also decrease.

The drafters of net metering legislation recognized the limitations discussed here and often included reductions when caps on the amount generated are reached. This has not prevented the beneficiaries of subsidies from complaining when they are reduced.

Who pays?

There is strong public support for alternative energy development and renewable energy incentives. This does not answer the question as to what the form and amount of incentives should be. Net metering at full retail cost transfers the cost to utility customers who do not install solar. Other forms of incentive, such as tax credits, are paid by state or local governments out of general tax revenue.

Even if the imputed environmental benefits and avoided costs of future fossil fuel power plants are taken at face value, someone has to pay the up-front cost of new solar installations if solar capacity is to grow at the rate that solar advocates desire. It has been well demonstrated that the number of homeowners and businesses willing to install solar drops dramatically if subsidies are reduced. For example, when the Nevada Public Utilities Commission voted to reduce net metering credits, the solar installation companies SolarCity, Vivant and SunRun announced they would pull out of the state. Plaintiffs in a lawsuit filed against the changes were quoted as saying they would never have invested in their PV systems had they known Nevada’s net metering program would be scaled back.

So, who is to pay? Will you and I pay through general taxes? Will utility customers pay through higher rates? At present, the utility companies would have solar users pay through lower credits. The solar companies would have utility customers and the general public pay. Free marketers would eliminate subsidies and have no one pay. As the late Sen. Russell B. Long said, ”Don’t tax you, don’t tax me, tax that man behind the tree.”

Econ 101 And The Oil Markets: Where Are We? And How Did We Get Here?

Bill Gilmerdirector of the Institute for Regional Forecasting

Forecasting the future is next to impossible. It is hard enough just to figure out where you are and how you got there. But I think we can find some perspective on current oil markets by applying the elementary logic of Econ 101 to the current price collapse. Throw in a few facts about the size of oil markets and how they work, apply a little informed speculation and we actually know a lot about where oil prices are and why – and even where prices are going.

First, as scary as oil markets look today, there is no analogy to 1987. The 1970s saw a series of supply shocks, brought on by turmoil in the Middle East and the rise of OPEC. As oil markets worked their way back to long-run equilibrium by bringing on vast new oil supplies, and while OPEC grotesquely overplayed its hand as a cartel, it unleashed a flood of at least 8.0 million barrels of excess capacity, equal to 13 percent of global production.

It took a decade for the world economy to absorb this oil surplus.

Second, references to supply and demand shocks in oil markets are thrown around loosely these days — and sometimes incorrectly. For example, the decline in oil prices that began in 2014 is sometimes called a U.S.-based shale supply shock. But it is really the messy endgame of a demand shock that began in 2004, driven by rapid economic growth in emerging markets. The 2014-15 drop in oil prices began as the return of oil prices from a short-run, price-signaling level near $100 per barrel to a long-run equilibrium near $60.

The market’s recent overshoot to near $30 per barrel is a second phase of the ongoing price crash, and it results from events that weren’t foreseeable as the correction began in 2014. In particular, oil markets now are struggling with the return of Iranian exports and a global economic slowdown. The current price correction is brutal, coming immediately on the heels of the long-run adjustment to $60, and the pain is most acute for marginal suppliers like shale and oil sands. But wherever oil prices are today, they should be headed back to $60 in a matter of months.

Three basic tools       

Let’s start with Figure 1 and three basic tools: the demand for oil, the short-run oil supply curve and the long-run supply curve. The per-barrel price of oil in today’s dollars is on the vertical axis, and the quantity supplied or demanded is on the horizontal. We have many studies about how these curves behave in oil markets.

  • The curve DD represents the demand for oil, sloping down and to the right. The shape of the demand curve varies over time. It is quite inelastic (close to vertical) in the short-run when the stock of energy-using capital is fixed, meaning that oil consumption barely responds to price changes. In the long-run, as the housing stock is upgraded, new energy-efficient machinery is installed or fuel-efficient cars are produced, the curve flattens and we get a larger response of oil consumption to price changes. Two widely cited studies by Dahl and Cooper say that a 10 percent increase in oil prices results in only a 0.5% to 0.7% fall in short-run consumption, but a 2-3 % response in the long run. For simplicity, I use only a single curve DD, since the important distinction in this analysis is between short- and long-run supplies.
  • The short-run marginal cost or supply curve is also nearly vertical, so a spike in the price of oil brings on little new production in the short-run. A series of statistical estimates by Krichene, for example, failed to find any short-run production response at all.[1]
  • The long-run adjustment of oil production to price appears to very long in oil markets. We might build a factory to expand widget production in 12 to 18 months. But the supply shocks of the 1970s persisted from 1973 until 1982, and the emerging market demand shock from 2004 to 2014. The stylized version of the curve in Figure 1 slopes up and to the right as new oil reserves come from higher-cost sources.


  • Figure 2 is a more explicit representation of the long-run supply curve as we work to provide the world with 96 million barrels of oil per day.[2] The first reserves developed are the least expensive, from the on-shore Middle East at $10-$25 per barrel, then the Offshore Shelf at $40, and then from a variety of sources that keep price near $50 until we need 85 million barrels per day. Then the price to bring on new supplies rises rapidly, with U.S. shale at $65, oil sands at $70 and Artic oil at $75. These marginal suppliers all find themselves on the cusp of the 96.3 million barrels produced in 2015. Looking back, it is hard to imagine the long-run price of oil slipping under $50. Looking forward, global growth in demand at 1.0 to 1.5 million barrels per year will require higher prices near $65-$70.


The 1970s Supply Shock     

In the 1970s, U.S. oil production began a long decline, while domestic demand continued to grow. There were ample supplies of low-cost crude available from the Middle East, and the locus of power in world oil markets quickly shifted from the Gulf of Mexico to the Persian Gulf. One important result was the repeated involvement of the U.S. in the political turmoil of the region, beginning with the 1973 Arab Israeli War and the subsequent Arab oil embargo. Throughout the period, OPEC gained economic power and used it repeatedly to leverage political unrest into higher oil prices. By the middle of the 1970s oil prices (measured in today’s dollars) rose from $17 to $55 per barrel; following the Iranian Revolution in 1979, and the Iran-Iraq War in 1980, the price pushed well over $100.

Using our simple tools in Figure 3, suppose we are initially in equilibrium at price P1 and quantity produced of Q1. The OPEC cartel constrains production, and the short-run supply curve is shifted back from SR Supply1 to SR Supply2. A new short-run equilibrium is found at a much higher P2, and this high price becomes the signal to markets to increase global oil production.

In this case, the new price signal was seen and acted on, triggering a frantic search for oil reserves. In the 1970s, Alaska, the North Sea and Nigeria all large delivered new oil supplies that put downward pressure on oil prices. OPEC fought weakening prices, cutting production as prices slid from $100 to $60 per barrel between 1982 and 1986. OPEC’s share of global oil production declined from 49% to 28%, led by the Saudi decline from 15% to 6%.

In 1987, OPEC finally realized that – like King Canute – this rising tide of oil would never be reversed thorough their own efforts. To capture revenue, OPEC capitulated on price and began pumping at high levels; the price of oil collapsed to $20 in today’s dollars.


With the cartel resigning its position, shouldn’t we just return to the old equilibrium at P1, Q1? Unfortunately, no. By withholding its own reserves from the market for too long, and allowing the disequilibrium oil-price signal to stay too high, OPEC allowed production capacity to rise far above what was needed. Worldwide oil production in 1986 was 62 million barrels and the price was $60 and falling when OPEC suddenly added back 8.0 million barrels per day it had been holding off the market. World oil demand didn’t reach 70 million barrels until 1995. In Figure 3, shift the curve SR Supply3 to the right, resulting in price P3 that now is below long-run equilibrium.

Figure 2 tells us that the long-run equilibrium price for 62 to 72 million barrels per day of production should have been near $50 per barrel in current dollars. Instead, OPEC left a decade-long hangover at a below-equilibrium price that averaged only $35 from 1987 to 1995.

Emerging Market Demand Shock

The decline in oil prices that began in 2014 is sometimes described as a supply shock. It is true that from 2009 to 2015, oil production in the U.S. rose by 4.85 million barrels per day, accounting for all the increase in non-OPEC production. But I would argue that this new production was the response to a decade-old demand shock and the 2014-2015 price adjustment – at least initially – was the return to long-run equilibrium near $60 per barrel.

A supply shock in this context requires that the long-run marginal cost curve in Figure 2 shift down or to the right. In Figure 2, for example, if we found a new and unexpected source of 10 million barrels of $53 oil, it would displace all the higher cost sources on the right side of the curve – ultra-deep water, shale, oil sands, Artic drilling – and we would not need them until global demand reached well over 100 million barrels. It is hard to argue this was the story for U.S. shale. There was some technological innovation, but shale staked out its place as a marginal option at a relatively high price. The $100 price signal did much more to expand U.S. shale production than any innovation along the long-run marginal cost curve.

A better way to understand today’s decline in oil prices is as a response to the emerging market demand shock that began in 2004. Brazil, Russia, India and China accelerated growth, and as they raised their standards of living, they put upward pressure on the price of metals, food, agricultural raw materials and oil. The price of oil rose faster and further than other commodities, but prices all rose sharply. Figure 4 shows that since 2003, all of the increase in global oil demand has come from developing non-OECD countries, while demand from the developed nations was falling.


The textbook solution for a demand shock is shown in Figure 5. Demand shifts up from D1 to D2, and inelastic supply moves price up sharply from P1 to P2. Let’s say that this new price signal to expand capacity is P2 = $100 per barrel, and stays there for several years. We know this is well above the current long-term equilibrium price, which is $60 per barrels at 96.3 million barrels of global production.


I am simply suggesting that the current price correction than began at the end of the 2014 marked the end of the 2004 demand shock and required a shift in oil prices to a new $60 long-run equilibrium. In fact, that seems to be exactly what was playing out between April and June of last year.  The price of oil stabilized near $60 per barrel, the domestic Baker Hughes rig count bottomed in June as drilling turned up briefly and oil-related layoffs came to a halt. It was as if the equilibrium price adjustment had fallen into place and a V-shaped drilling recovery was underway. This was no replay of 1987 with an OPEC build-up of surplus capacity – it now holds less than 2 million barrels per day – and no decade-long wait to work off that surplus.

Oil Prices at $30 and below?

How do we find oil at $30 per barrel today? Two subsequent events turned last summer’s fragile equilibrium into a rout: the Iran Nuclear Agreement signed in July 2015 and the devaluation of Chinese currency that followed in August. Economic sanctions against Iran were imposed in 2011, and Iran’s daily oil exports fell by about 1.2 million barrels. With the lifting of sanctions, Iran has made it clear that it plans to quickly regain its previous export position. Our long-run supply curve just got a million barrels per day longer, starting with low-cost onshore Middle East production that must be absorbed before high-cost shale oil returns.

Meanwhile, China is making a tricky transition from a manufacturing and export-led economy to a consumer-driven economy, and it has long been anticipated that annual Chinese economic growth would slow to near 6%. Concerns are frequently expressed that China might not make the legal, financial, labor market, energy and other reforms necessary to continue even on this more modest growth path. But the August devaluation of the yuan, accompanied by significant turmoil in Chinese stock markets, distilled these concerns into real fear about the Chinese economy – fear that quickly spilled into oil markets.

I leave it to you to guess if we should shift the oil demand curve down – and how far we lower the short-run equilibrium price. The forecast for 2016 from the International Energy Agency in Table 1 more or less dismisses the China growth problem, seeing India filling any demand void left by China. IEA points to slow growth in Europe and Latin America as the source of poor demand growth in the global economy.

That said, unless there is much more to the China story than is now apparent, this should be a routine correction for oil markets. There is no massive 1987 supply shock and the surplus currently driving oil prices should be resolved in a matter of months. How many months before oil returns to a long-run $60 or $65 per barrel? 6 months? 12? 18?  That is the difficult and painful detail that remains to be resolved.


[1] Noureddine Krichene, “A Simultaneous Equations Model for World Crude Oil and natural Gas Markets,” IMF Working Paper WP/05/32, February 2005.

[2] Figure is adapted from a chart that seems to be based on Morgan Stanley research, but is widely copied in many places on the internet.  For example,

Bill Gilmer is director of the Institute for Regional Forecasting at the University of Houston’s Bauer College of Business. The Institute monitors the Houston and Gulf Coast business cycle, analyzing how oil markets, the national economy and global expansion influence the regional economy.