Energy Insights http://blogs.mccombs.utexas.edu/titman Energy Policy and Discussion from a Financial Economist’s Perspective Thu, 06 Jan 2011 00:19:01 +0000 en-US hourly 1 http://blogs.mccombs.utexas.edu/?v=3.8.1.1 Shale Gas Regulation Q&A with David Spence http://blogs.mccombs.utexas.edu/titman/2011/01/06/shale-gas-regulation-qa-with-david-spence/ http://blogs.mccombs.utexas.edu/titman/2011/01/06/shale-gas-regulation-qa-with-david-spence/#comments Thu, 06 Jan 2011 00:18:13 +0000 http://blogs.mccombs.utexas.edu/titman/?p=413 There is almost no question that natural gas will play an important role in the U.S. energy future. With the almost continual upward revision of reserves from shale gas, there is sufficient supply to replace some coal burning power plants with cleaner burning natural gas power plants, and perhaps, use natural gas as a transportation fuel, either directly or indirectly with electric vehicles.

Professor David Spence, the UT McCombs expert on energy policy, provides his insights on the future of shale gas in a recent energy brief. I followed up on his findings with a few brief questions:

We have seen how BP’s Deepwater Horizon disaster has affected the business of every offshore oil producer in the United States. Is there a comparable scenario for shale gas, one in which a single bad actor may poison the well (no pun intended) for other producers?

David responds:
Certainly this is a politically delicate time for hydraulic fracturing, particularly in the Marcellus Shale, where there is a great deal of popular trepidation about fracking and its risks. The movie “Gasland,” a documentary being broadcast on HBO right now, portrays fracking as an inherently dangerous activity. There has already been an apparent spill near the towns of Dimock and Damascus, in Pennsylvania, one that is reputed to have affected drinking water wells. Presumably, whatever contamination occurred there was the product of surface activities (spilled fracking fluids or produced water from the well) rather than of the fracturing process itself. However, it is certainly theoretically possible that are poorly designed or constructed well could leak gas or fracking fluids or produced water into a drinking water aquifer through which the well passes. It only takes one mistake to provoke fear, and the average voter will not care about distinctions between contamination caused by surface spills and contamination caused by the fracturing process. Voters may think that if it can happen there, it can happen here, irrespective of the overall safety record of the industry. We saw this with nuclear power in the 1970s and 80s.

On the other hand, it seems unlikely that fracking could ever produce an enormous disaster of the Deepwater Horizon variety. Each fracturing operation affects a relatively small area, by definition. The rock is fractured in order to free up gas within a confined space, as contrasted with the blowout of BP’s Maconda well, which allowed oil to spew into the Gulf uncontained. Nevertheless, the industry’s regulatory exemptions and the desire of contractors to withhold information about the composition of fracking fluids feed fears about the risks, and play into the hands of fracking’s opponents.

Then why don’t the companies embrace some sort of self-regulation or moderate regulation?

David responds:
Part of the problem is that gas producers and their contractors are divided on the disclosure issue. I suspect that most gas producers, certainly the big oil and gas companies, would just as soon adopt a policy of full disclosure about the composition of fracking fluids. It is their contractors, who consider the exact composition of their fracking fluids to be their intellectual property and part of the value they bring to the industry, who oppose disclosure. Oil and gas companies recognize, however, that this position is jeopardizing the availability of shale gas as a resource in some places. At some point in time, one suspects that oil and gas companies will exert some leverage over their contractors on this issue.

As for the industry’s opposition to the remainder of the FRAC Act, presumably the industry fears prohibitions or severe restrictions on hydraulic fracturing if the process becomes regulated under the Safe Drinking Water Act. However, as states in the Northeast begin to exert regulatory jurisdiction over hydraulic fracturing, the issue of federal regulation may become moot. Indeed, we may eventually find oil and gas companies seeking federal regulation so as to preempt more stringent state regulation.

I understand the need for regulation when there is a potential for environmental damage. However, I generally like to find free market solutions when it is possible. In this particular case, would it be possible to have the drillers post a bond or show that they have adequate insurance to cover potential liabilities before drilling. If the drillers are compelled to cover all potential damages, and have the financial wherewithal to do so, is there a problem?

David responds:
Your proposal is an approach we use in other contexts, such as hazardous waste treatment, storage and disposal facilities, and surface mining operations. The Resource Conservation and Recovery Act requires hazardous waste facilities to post a bond (or other financial assurance) in order to secure the permission they need to operate; this is to ensure that there will be resources available for cleanup in the event of a spill. Similarly, the Surface Mining Control and Reclamation Act requires strip mining operations to post a bond to ensure that the mining site will be reclaimed (revegetated, and contamination and other damaged remedied) upon closure of the mine. This is a barrier to entry for undercapitalized or unprofessional firms, by design.

Both of these financial assurance requirements, however, are supplemented by additional regulations and standards governing how the job is done – such as technical standards governing hazardous waste landfills and incinerators, and environmental standards of performance for surface mining regulations. NGOs, neighbors and others concerned about environmental and health risks might see ex post liability as an insufficient deterrent to bad behavior. They may worry that compensation will be inadequate because (i) they don’t see money damages as adequate compensation for damage to their, or their children’s, health (which they might fear from hydraulic fracturing), and/or (ii) they otherwise suspect that they will be undercompensated for property-related damages. (For example, they may worry that in the event their wells are contaminated, they will be compensated for reduction in fair market value, which may miss or underestimate their actual out-of-pocket costs or loss of use damages.) For all of these reasons, neighbors may tend to favor the application of ex ante standards, through permit requirements, in addition to financial assurance requirements.

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Nick Olds of ConocoPhillips Canada Talks Oil Sands http://blogs.mccombs.utexas.edu/titman/2010/12/15/nick-olds-of-conocophillips-canada-talks-oil-sands/ http://blogs.mccombs.utexas.edu/titman/2010/12/15/nick-olds-of-conocophillips-canada-talks-oil-sands/#comments Wed, 15 Dec 2010 17:44:46 +0000 http://blogs.mccombs.utexas.edu/titman/?p=390 In February, 2010, Nick Olds of ConocoPhillips visited The University of Texas at Austin to talk to us about the oil that is being extracted from the oil sands in Alberta, Canada. Nick is the Senior Vice President, Oil Sands, for ConocoPhillips Canada.

In addition to providing us with access to his slides from the talk, he has graciously agreed to answer some of my questions:

How much oil is currently being produced from oil sands in Alberta? Can you give me a sense of the total available reserves from oil sands in Canada? Are there other areas in the world that have significant unexploited oil sands?

Nick responds:
The oil sands are an enormous resource. Most of the oil sands of Canada are located in three major deposits in northern Alberta. These are the Athabasca-Wabiskaw oil sands, the Cold Lake deposits and the Peace River deposits of Alberta. Between these three resources, there is approximately 1.75 trillion barrels of bitumen in place. The Alberta oil sand deposits contain at least 85% of the world’s reserves of natural bitumen (representing 40% of the combined crude bitumen and extra-heavy crude oil reserves in the world). That’s a lot of oil, and probably the largest hydrocarbon deposit we know about.

There are several other similar deposits in North America and Venezuela. In addition to the Alberta oil sands, there are major oil sands deposits on Melville Island in the Canadian Arctic islands which are unlikely to see commercial production in the foreseeable future. In the United States, oil sands resources are primarily concentrated in eastern Utah. These comprise a total of 32 billion barrels of oil (known and potential) in eight major deposits in Utah. Oil is not currently produced from oil sands on a significant commercial level in the United States.

There are also deposits farther south. The Orinoco oil deposit located in eastern Venezuela, north of the Orinoco River, vies with the Canadian oil sands for the largest known accumulation of bitumen in the world.

In your presentation you describe two basic technological processes for extracting oil sands: mining-like operations that dig up the oil sands and technologies like steam assisted gravity drainage (SAGD) that heat the oil sands in situ and then extract them through a production well. It is my understanding that ConocoPhillips recently shifted its focus to SAGD. Was this decision related to costs? Environmental impacts? Do you see any new technologies in the future that will make oil sands even more attractive from an economic or technological perspective?

Nick responds:
Our oil sands portfolio has always been heavily weighted towards SAGD rather than mining, largely because our oil sands deposits are very deep. We had a small interest in a mining company until earlier this year that we divested because it made business sense to do so. It also enabled us to focus our attention on the rest of our portfolio, which will be developed using in-situ technology. Currently SAGD is the only commercially viable method of in-situ production.

On the surface SAGD recovery looks much like conventional oil recovery, but what happens below the surface is quite different.

The concept of using steam to assist with heavy oil recovery is not new. As an example, steam floods have been used as an enhanced recovery method in California since the 1960s. What is new is that the SAGD process uses gravity and the pressure of the steam to drain the oil and there’s a complex water treatment and water recycling process that occurs. We target to recycle 90% of the water to make more steam to put back in the ground.

There is definitely a large opportunity for technological advancement for SAGD. We are planning to spend over $300 million over the next five years to progress heavy oil technology, a large portion of which will be dedicated to our oil sands business. Our technology program is focused on reducing environmental impacts while improving economics. One of the technologies we’re testing right now is insulated tubing. Insulated tubing reduces heat loss, and therefore reduces greenhouse gas emissions and water use because less steam needs to be generated per barrel of oil. That’s one example of many different technologies we’re looking at for application to current and future projects.

My understanding is that it is easier to both increase and decrease the production of oil from oil sands, at least in comparison to the production of conventional oil that is produced in the Gulf. Is this correct? For example, how quickly was production increased in the 2006-2008 period when oil prices were rising, and to what extent was production decreased when oil prices collapsed at the end of 2008?

Nick responds:
SAGD is a complex process. It is not easy to increase or decrease the production of oil sands from a SAGD facility, especially in comparison to conventional oil development.

In the SAGD process, we drill two horizontal wells into the ground one on top of the other and then pump steam into the top well. The steam rises and heats up the oil to a point where it can flow into the bottom well as an oil and hot water mixture. We then produce the oil and water mixture to the surface. This sounds like a quick process, but it can take months for the steam to heat up the oil to the temperature needed for it to flow. For example, in our Surmont Phase 1 facility, we first injected steam into the ground in July 2007 and we saw our first oil production in October of that year. It took about three months for us to get from first steam to first production.

Because of front end costs involved in developing and operating a SAGD project, you need to invest a lot of money for many years before you even start to get the bitumen out of the ground. It can take about 10 years to get a SAGD project from conception to operation. Shutting down or slowing down production at a SAGD facility would mean potentially losing the initial financial and operational investment of the steam and heat that is already underground.

As well, there are operational and safety risks to keep in mind. The winters are cold in northern Alberta, so we need to keep an eye on the temperature and movement of our liquids within the pipelines to ensure they don’t freeze. Shutting down or slowing down production can have an effect on these balances as well.

With these considerations in mind, we prefer to run our facilities with a focus on our long-term commitments to the oil sands. The operations of our oil sands projects were steady during the economic downturn. We did slow down the pace some of our future oil sands development and construction plans during this time to maintain some flexibility in our plans in case we needed to adjust them in response to the economy, global financial markets and oil prices.

Of course, if there were a safety or environmental reason that required the facility to stop production there are safeguards in place to make that happen.

I understand that producing oil from oil sands is quite expensive, and that your exact production costs are proprietary. However, can you give us some ballpark estimates? What I would really find useful is a comparison between the costs of oil from oil sands and the cost of extracting oil from deep water in the Gulf, or alternatively, really deep water off the coast of Brazil. If we see a moratorium on deep water drilling can this be economically offset by extracting more oil from oil sands?

Nick responds:
We don’t speak about the capital costs or profitability on a project-by-project basis, partially because it’s a very complex. It’s misleading to quote one number for costs, breakeven prices or profitability because the profitability of any one project relies on several fluctuating factors – natural gas prices, original capital investment, labour costs, royalties, the cost of carbon, market demand and the light-heavy oil differential. I’ve seen estimates by different analysts that provide this comparison but I can’t provide it for you.

What I will say about the oil sands is they represent a safe and secure resource that is in close proximity to the United States – Canada’s top export market and a net importer of oil.

I have heard a lot about the impact of oil sands on the environment. My impression is that to a large extent the disturbance associated with the operation can, and will be, cleaned up, but there are still questions about the carbon footprint of oil extracted from oil sands and the use of water. In the not too distant future, we are likely to put a substantial cost of carbon emissions, and water is likely to be much more expensive. Do we expect oil from oil sands to be economically viable in such a scenario?

Nick responds:
We believe the oil sands can be developed responsibly and are working hard to minimize the impact of our operations on the environment. Right now, we’re innovating ways to reduce our land, water and air impacts. Take land, for example. We just piloted a new aggressive reclamation program we call Faster Forests. We give forests a head start by planting trees on areas we’ve disturbed, which is a step above traditional reclamation processes. Since 2009, ConocoPhillips Canada has planted over 130,000 trees at our Surmont project.

We also have a heavy focus on oil sands technology development. In fact, we’re planning to spend over $300 million on heavy oil technology over the next five years. We think we can find a balance between delivering the energy we need, managing our environmental impact and benefiting the economy.

SAGD technology is a relatively new technology, only about a decade old in terms of commercial application of it, and we expect to see it evolve in the future to become even more efficient and to have an even smaller environmental footprint. Some of the facts of SAGD production are as follows:

• Water – SAGD producers, on average, recycle 90% of their water.
• Land – SAGD production looks very similar to conventional oil production. In fact, it has
a smaller surface footprint than some forms of conventional oil production.
• Air – The greenhouse gases produced in the production of a SAGD barrel of oil are about 5 to 15% higher than those produced in the production of the average barrel of oil consumed in the United States.

I can’t speak for all other members of industry, but I know we’re focusing our technology program on reducing our water use, managing greenhouse gases, reducing our land footprint, and improving our economics and efficiency.

We believe a technology investment will allow us to continue developing this resource in a responsible, safe and economically feasible way. We’ll find ways to recover the resource more efficiently and cost effectively over time. We’re an industry of bright and innovative people and I have no doubt we’ll rise to meet this challenge.

The oil sands are concentrated in a remote area with little infrastructure or local workforce. Further, some of the sites are on First Nations land. Can you comment on how these factors complicate oil sands production and how ConocoPhillips is mitigating these problems?

Nick responds:
In the oil sands area, many of our neighbours are Aboriginal peoples and we work with them through a community consultation process to understand local issues and how our projects may impact their communities.

Additionally, we collaborate with First Nations in identifying important areas. These areas may have historical value or be important for maintaining a traditional way of life.

We also work with them to create local benefits from our projects. We place a high priority on purchasing goods and services locally and give local and Aboriginal contractors and suppliers the opportunity to participate in projects through a competitive bid process.

In addition to economic benefits, we are developing programs to support youth development. This series of programs, collectively called Gen Y: We Care, provides youth with development opportunities targeting areas such as self-esteem and leadership.

We are continuously working with the community organizations, governments, communities, health and safety, industry and environment professionals in the region to ensure that there is mutual benefit in the development of our oil sands projects. It is an ongoing process.

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What are “legitimate claims” for oil spills and other disasters? http://blogs.mccombs.utexas.edu/titman/2010/06/15/what-are-legitimate-claims-for-oil-spills-and-other-disasters/ http://blogs.mccombs.utexas.edu/titman/2010/06/15/what-are-legitimate-claims-for-oil-spills-and-other-disasters/#comments Tue, 15 Jun 2010 14:43:34 +0000 http://blogs.mccombs.utexas.edu/titman/?p=373 BP has been criticized for offering to pay all “legitimate” claims. However, a recent suggestion of the Obama administration has provided an example of the type of claim that is not legitimate, by suggesting that BP compensate oil industry workers laid off because of the federal moratorium on deepwater drilling.

The claims of beach resort owners and fishermen are legitimate, since BP’s actions have clearly caused financial harm to these individuals. It is also true that BP’s action led to the deepwater drilling moratorium, which harmed many oil industry workers in the Gulf. However, the moratorium did not arise because of the spill per se, but because the spill revealed that deepwater drilling may not be as safe as we may have originally thought. In a sense, this is the one good thing that we can say about the spill – that it may have lead to actions that will prevent future spills.

To understand this a little bit more clearly consider a hypothetical situation where an explosion in deepwater resulted in a spill that was immediately capped, with very little damage to the environment. Seeing the near disaster, the administration puts a halt on all new deepwater drilling, leading to changes that prevent future disasters. In this case, it is clear that the near disaster had social benefits that outweigh the social costs.

The moratorium following an actual disaster is no different. The moratorium certainly has its costs; however, it was imposed because we learned something from the disaster that suggests, at least to some people in the administration, that the moratorium has benefits that exceed those costs.

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An Interview with Branko Terzic on Energy Legislation and Regulation http://blogs.mccombs.utexas.edu/titman/2010/06/02/an-interview-with-branko-terzic-on-energy-legislation-and-regulation/ http://blogs.mccombs.utexas.edu/titman/2010/06/02/an-interview-with-branko-terzic-on-energy-legislation-and-regulation/#comments Wed, 02 Jun 2010 21:21:29 +0000 http://blogs.mccombs.utexas.edu/titman/?p=353 With the recent passage of the Lieberman-Kerry energy bill earlier this month, energy policy is again a hot topic in Washington, D.C. The Deloitte Center for Energy Services will be having a conference to discuss these issues in early June, but to get a head start thinking about key trends and topics, I had a conversation with Branko Terzic, who is the Regulatory and Policy Leader in Deloitte’s Energy & Resources group.

We’ve heard very good things about you, Branko–that you’re the expert to talk to about what’s going on in terms of regulation and legislation. Let’s start by talking about the Lieberman-Kerry bill. It looks like Congress is converging on what has been described as a “cap and trade” system, rather than a tax. What do you see as the advantage of a cap and trade system?

Branko responds:
The Senate bill has cap and trade because the House bill that it’s supposed to reconcile with (the Waxman-Markey bill) has cap and trade. This way when they go into conference, they are easier to reconcile. In terms of the benefit of cap and trade, versus a tax, the electric power industry is familiar with cap and trade with respect to NOx and SOx and other pollutants and so they already understand how the markets work–it’s something that they can mechanically handle well and conceptually handle well.

As you know, politicians have an aversion to raising taxes, at least directly. Consequently, since the additional cost of CO2 in the form of emissions permits to electricity is an indirect tax instead of an explicit tax — you don’t have Congress directly raising taxes. Having said that, opponents of cap and trade call it cap and tax.

For this legislation to have any teeth – for it to appreciably change carbon output — it has to raise prices enough to curtail consumption; is that correct?

Branko responds:
Yes, in order to curtail consumption on the basis of consumer pass-through, it would have to have some significant cost increases. As you know, people don’t use energy–their devices do. After the 1970s and ’80s, it took about five to six years for the capital equipment to be changed out and to reflect the higher energy cost.

In the case of consumers, you might turn back your thermostat. But, the bigger savings will come when you buy a new air conditioner, when you buy a new natural gas furnace, when you buy a new refrigerator with the new higher efficiency rating. Even for industry, it will be when they buy new equipment or install insulation or do something else to lower their costs. But all of that generally requires capital investment, rather than changes in operations.

So, we’ve got a new bill, electricity prices are going to be increasing over time, and people will anticipate that and buy more energy efficient appliances and use more insulation and so on.

Branko responds:
That’s assuming consumers see the right price signals in the right format. One of the ways that can be accelerated is in areas that introduce smart metering and real-time pricing where you don’t have an average price per kilowatt hour during the day. In those areas, consumers will be able to more quickly feel the effects or see the benefits of conservation because they’ll see a much higher impact, based on time of day and other factors. They can more easily use that information to change their behaviors to increase energy efficiency.

This ability to inform consumer behaviors will mostly be a function of state public service commissions allowing additional capital investment into the rate base for smart meter and the smart tariffs which have to accompany the smart meters. One would hope that they would have real-time pricing to match the ability of the meters to actually bring consumers that information.

I believe that another feature of the new bill is a set of various subsidies for alternative energy. To what extent are we subsidizing R&D, which will (for example) improve the efficacy of solar cells, rather than using direct subsidies on the use of alternative energy, like tax credits on solar installations?

Branko responds:
There is funding for clean energy research and development, advanced vehicle technologies and advanced manufacturing. So there are some pieces in this bill that would go toward the use of technologies like smart meters. Of course, there was some in the stimulus package, as well. There is $18.5 billion to increase the innovative technology loan program, which is the nuclear bill. There’s carbon capture and sequestration funding. There’s additional research and development funding in the bill. There’s infrastructure funding of electrification of the improvement of the highway system, electric vehicle funding. So the bill has, you know, quite a bit of different funding. There are tax benefits that may be extended and may be added to the bill, as well. The bill does not contain a renewable portfolio standard or a renewable electricity standard, which is an interesting omission.

Can you be a little bit more specific about the renewable energy standard?

Branko responds:
The Kerry-Lieberman bill does not have a renewable energy standard or renewable portfolio standard, but the House bill, I believe, did. So that will be one of the things that, if Kerry-Lieberman passes the Senate, would then have to be reconciled with the House bill. Standards for renewable energy or portfolio standards, already in place in about 27 states where, if you are the provider of electricity in that state, it is required that a certain percentage of the power that you acquire be from renewable sources, whether or not there is cheaper conventional power available. So, for example, in states with those laws, as a utility in that state, you might have to buy 15 percent of your power from solar or wind, even if there is a very low cost coal fired or natural gas fired or nuclear generation available. The discussion is whether there will be a federal portfolio standard that will supersede the various state standards.

What would be your guess on the likely outcome of this process? Do you think we will have new legislation by the end of the summer? What would you expect it to look like, if so?

Branko responds:
Based on discussions with people here in town, the bill has a low probability of passing between now and the end of this Congressional term. In any case, should something pass in the Senate, they’re going to have to reconcile that with the House bill when the two houses get together.

At this point in time, given what’s going on in energy, what’s going on with legislation having to do with pulling back the EPA, the fact the Senate will be tied up in a contentious Supreme Court nomination, financial services reform, climate legislation dropped way down on the local priority. You know, the Pew Trust people did a survey recently where they asked people to rank 20 issues. Climate change was the twentieth.

The consensus of people I talk to is that we’re not going to get an energy bill by the end of the summer — and if you don’t have one by the end of the summer, starting after Memorial Day, you’ve got the entire Congress out campaigning for reelection. My guess is that probably comprehensive climate change legislation will not survive this year and we will have to start all over again with a new Congress in January of 2011.

It’s likely that the new Congress will have more Republicans than the current Congress, which means that the Democrats are going to have to collaborate more with Republicans to get anything through. Do you think that’s likely to happen?

Branko responds:
Well, yes. I think it’s likely they will collaborate. There are enough Republican energy business leaders out there who want more certainty in our energy policy. These are some of the leaders at some of the large utilities who have been calling for climate change legislation, calling for a cap-and-trade program. They’ll still be around. And there’s just a lot of talk in town that may be bringing the Republicans around — that if it’s too difficult to make capital investment decisions in the electric power industry today without some notion of what are the rules I’m going to operate under.

It’s very difficult to estimate the running cost of a new coal-fired power plant or even a natural gas fired power plant if you don’t know whether you’re going to include the cost of carbon in future calculations. It’s very difficult for the companies to make the economic analysis and it’s very difficult for the regulators who have to approve most of these power plants that are built to make any decisions. If you propose a nuclear power plant, which is a very high capital cost, that power plant looks much more attractive with a higher carbon cost than it would otherwise. Certainly on the electric power industry side, the companies have to make capital decisions; because they have the responsibility of delivering reliable electricity in the future, no matter what the environmental or other laws are. It’s very difficult to make those decisions if you have no idea what the law will be, what form it’s in, what the details will look like. You can’t even model that.

My prediction is that there’s going to be pressure on the Republicans to show more leadership on energy legislation after the elections and do their jobs and seriously look at Democrat-proposed legislation, make their modifications, and then vote up or down because it’s in the national interest. Maybe comprehensive climate change legislation won’t go through, which was the original Obama intent. But there’s a very large consensus from the utility industry that they can live with and they can operate under a cap-and-trade system. They could work with it and would like to go ahead, have Congress set it up, and then they can get on with it.

The recession has delayed the need for new power plants. It’s given us a breathing period. Otherwise, with a warmer than average summer, every part of the United States would be vulnerable to brownouts and blackouts because we have delayed construction of new facilities. Because we had negative growth in electricity sales and demand the last two years, we’ve been able to dodge the bullet. But if the economy picks up as we all hope it does, we’re going to have to build new power plants. We need to know what the rules of the game are in order to attract the capital to be able to finally build those units.

With the Republicans taking a more active role in drafting the legislation, do we expect, whatever comes out, nine to ten months from now, to look considerably different than the Kerry-Lieberman bill?

Branko responds:
I think it will be similar to the Kerry-Lieberman bill, because the Kerry-Lieberman bill was crafted when Lindsey Graham was still on it. When he dropped out, I don’t think they changed it dramatically. And so I think it has enough in there that is supportable and realistic that makes decent policy.
No bill is going to be perfect, and we all have our quirks and preferences. The bill compromises over where the funding should go. It doesn’t answer the most difficult questions, though, of how allocations will be made within the sectors and where the allocations will go. These are things that are left in the bill to the future EPA or other agencies. But I generally prefer that Congress give legislation or state legislators broad guidelines and let the agencies hammer out the details.

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The Politics of National Energy Policy Reform http://blogs.mccombs.utexas.edu/titman/2010/05/20/the-politics-of-national-energy-policy-reform/ http://blogs.mccombs.utexas.edu/titman/2010/05/20/the-politics-of-national-energy-policy-reform/#comments Thu, 20 May 2010 23:43:15 +0000 http://blogs.mccombs.utexas.edu/titman/?p=326 An Interview with David Spence

With the introduction of the Lieberman-Kerry energy bill earlier this month, energy legislation is again on the Senate agenda. My colleague David Spence has been doing research on energy policy and the legislative process and is the McCombs expert on this topic.

When I look at the various proposals I get the impression that our Congress prefers complicated, rather than simple, solutions. For example, I would like to see a simple tax on oil, coal and natural gas that is proportional to their carbon content. Is there an inherent bias against simple solutions, or are these solutions “simplistic” rather than just simple? Would you say we have complicated proposals because we have complicated problems, or are the proposals complicated because we have a complicated process?

David answers:
Economists have favored emissions taxes over other regulatory instruments since the earliest days of environmental regulation in the United States, yet Congress almost never chooses that option. Companies tend to prefer taxes over marketable permits or other forms of regulation as well, because taxes provide cost certainty in pollution control. By contrast, marketable permit prices can vary wildly, as we’ve seen in the European carbon trading scheme. Environmental groups distrust environmental taxes because it is difficult to predict exactly how much pollution will occur at any given tax rate, and they fear that the rate would be set too low. They also tend to believe that the American the acid rain program, a marketable permit system for sulfur dioxide emissions from coal-fired power plants, has worked well.

However, the most likely answer to your question is a logically unsatisfying one. In American politics, “tax” is a four letter word, and has been for several decades now. Public support for regulation wanes when regulation is described as a “tax.” This may be because consumers associate taxes with higher energy prices more readily than they do other forms of regulation. Taxes may also be associated with “big government” in public mind. Members of Congress have no preference for complex policy solutions, except when complexity can be used to disguise costs. They have a strong preference for policies they think their constituents want, and an even stronger aversion to policies that they fear might be portrayed as harmful to their constituents in the future.

Hence, marketable permits have been the instrument of choice in all of the recent climate change bills. There was speculation that the bill that Senators Kerry and Lieberman unveiled recently would substitute a carbon tax for marketable permits in the regulation of the oil industry. Instead, the bill tries to provide more cost certainty for the oil industry by “setting aside” a number of emissions allowances (marketable permits) on a quarterly basis, and refiners will then purchase the allowances they need for that quarter at that the price for that quarter. Hardly a simpler solution.

If this is anything like health care, we can expect substantial division between Democrats and Republicans on this energy bill. Can you very briefly where these differences are likely to arise? Do you think these differences arise because of philosophical differences (such as different views on big government) or because of their different constituencies?

David answers:
It appears as though the partisan split in Congress, particularly the Senate, is every bit as stark on this issue as it has been with healthcare. Lindsey Graham (R-SC) who was part of the “Gang of Three” who tried to develop a bipartisan Senate bill, dropped out of the process a short time ago. While he cited displeasure over the administration’s immigration reform proposals as the reason, some commentators believe that Graham was under tremendous pressure from his party not to cooperate with Democrats on energy.

The partisan split can be traced to differences over particular issues, as well as differences over basic philosophy. The fact that these bills would impose significant regulatory costs on a wide swath of industry makes small government Republicans wary. Carbon capture and sequestration will impose very large costs on coal-fired power plants. A national renewable portfolio standard for electric utilities would impose significant costs electric utilities, particularly in parts of the country with few renewable energy resources such as the southeast, where Republican support is very strong.

In addition, the base of the Republican Party views climatologists’ consensus view — that the earth is warming, and that human activity is very likely driving that warming — with great skepticism. These claims are the very factual foundation of the effort to address climate change: that is, they are what justifies the costs these bills would impose. Naturally, one who disbelieves these claims will see no purpose to bearing those costs.

Finally, can you make a guess of the likely outcome of this process? Do you think we will have new legislation by the end of the summer? Any guess on what it will look like?

David answers:
This is very difficult to predict. Right now, the prospects for passage of a bill in the Senate look very bleak. Public support for action on climate change is actually declining. On the other hand, catalyzing events, like the oil spill in the Gulf of Mexico, can change political dynamics quickly. For now, the administration seems more focused on financial reform. If that legislation passes, with Democratic support overcoming Republican opposition (as it did with healthcare), Republicans may revisit their strategic and tactical approach to major regulatory legislation, which could also change the political dynamics of the energy bills. Add to that the midterm elections coming up in the fall and it is anybody’s guess what will happen.

If I had to guess, I would guess that’s we will get either (i) no energy legislation during this Congress, or (ii) relatively weak legislation which offers more financial incentives for conservation, efficiency and development of nuclear power, but no mandatory reductions in greenhouse gas emissions, efficiency standards for buildings, or national renewable portfolio standard.

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The Gulf Oil Spill: The View of the Financial Markets http://blogs.mccombs.utexas.edu/titman/2010/05/14/the-gulf-oil-spill-the-view-of-the-financial-markets/ http://blogs.mccombs.utexas.edu/titman/2010/05/14/the-gulf-oil-spill-the-view-of-the-financial-markets/#comments Fri, 14 May 2010 19:02:37 +0000 http://blogs.mccombs.utexas.edu/titman/?p=296

Chart A: Stock price performance of BP, Transocean and Halliburton.

While financial markets are not always right, it is useful to see what they have to say. Chart A plots the stock price performance of the three companies that are most closely tied to the oil spill–BP, Transocean and Halliburton. As you can see, the stock prices of the three companies have been hammered, realizing loses in the neighborhood of $35 billion, which is substantially greater than most estimates of the various damages and cleanup costs.
Chart B: Stock price performance of ConocoPhillips, ExxonMobil and Petrobras.

Chart B: Stock price performance of ConocoPhillips, ExxonMobil and Petrobras.

As a comparison, as I plot in Chart B, the stock prices of ConocoPhillips and ExxonMobil were not affected by the spill. However, Petrobras, which was in no way associated with the accident, has also suffered significant declines in their stock price.

What is the connection with Petrobras? Petrobras is essentially betting the company on very deep water drilling, and the stock market, in light of the Gulf disaster, appears to be questioning that bet.

Chart C: Long term futures market for oil.

Chart C: Long term futures market for oil.

Finally, it is worthwhile looking at the long term futures market for oil, which is plotted in Chart C. Are the markets expecting a moratorium on deep water drilling that will lead to a future shortage of oil?

Apparently, the markets response suggests that the Gulf event will not have a major effect on oil prices. The move in five year futures prices has not been material, and the spread between Brent and WTI has actually widened a bit, suggesting that–if anything–oil is likely to become scarcer in Europe than in the U.S.

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Drilling in Deep Water http://blogs.mccombs.utexas.edu/titman/2010/05/12/drilling-in-deep-water/ http://blogs.mccombs.utexas.edu/titman/2010/05/12/drilling-in-deep-water/#comments Wed, 12 May 2010 18:54:59 +0000 http://blogs.mccombs.utexas.edu/titman/?p=285 The recent BP incident in the Gulf of Mexico raises an important policy issue: Should we put a moratorium on new drilling? Should we be drilling now or drilling later? Some might respond with “drill never,” but never is a long time and it is a pretty safe bet that the oil will eventually be extracted. In any event, although the question is pretty straightforward, the issues are not. I cannot provide a definitive answer, but hopefully, I can offer a little clarity.

First, some very simple economics

Let’s first assume that markets are competitive, that we do not expect technical progress, and that there exists oil that can be extracted cheaply, as well as oil that is expensive to extract. Under these conditions, it is straightforward to show that it is best to extract the cheap oil first and the expensive-to-extract oil later. The idea is that it is optimal to minimize the net present value of the extraction costs, and this is accomplished by putting off the high extraction costs until later.

So if we lived in a less complicated world, we would put off deep water drilling and speed up the extraction of oil in low cost places like the Middle East.

Keeping things relatively simple, let’s now assume that technology will get better, making deep water drilling both cheaper and safer in the future. The possibility of cheaper and safer drilling in the future provides an added incentive to delay deep water drilling. Of course, the possibility of technical progress makes this issue more complicated, since by putting off deep water drilling we slow down the technical progress. But still, the possibility of technical progress favors the idea of at least slowing down the deep water drilling.

The economics of the real world

Unfortunately, we live in a more complicated world, which makes the economics of delaying the deep water drilling program much less straightforward. In particular, the international oil markets are not perfectly competitive and there is a relation between oil production and international politics that cannot be ignored.

The first argument to consider is that OPEC, which controls most of the oil that is cheap to extract, restricts supply and artificially inflates oil prices (an assumption, by the way, that not everyone agrees with). If this is the case, then as consumers of oil, we may want to take actions that limit OPEC’s ability to set prices by increasing U.S. production by drilling in deep water.

The second argument is that the U.S. is running an unsustainable balance of payments deficit, and a large portion of that deficit comes from the importation of foreign oil. As T. Boone Pickens told Congress last month, “In January 2010, our trade deficit for the month was $37.3 billion — $27.5 billion of that was money we sent overseas to import oil.” It is certainly the case that at least on the margin, producing more oil domestically, all else equal, will reduce our trade deficit. However, the lower deficit may actually be less sustainable since by consuming our oil today we are more dependent on foreign oil in the future.

The third argument is that increasing production in the low cost Middle East puts more money in the hands of governments that are not always friendly to Americans and reduces what has been referred to as our energy security. This is a complicated issue that I am not really qualified to address, however, it should be noted that there is clearly a time dimension to the political problem as well as the economic problem. If we extract all of our domestic reserves now, we will be more dependent on oil from the Middle East in the future. Perhaps, we should be using their oil now and saving ours for later. This requires, of course, that the costs of continuing to depend on foreign oil do not overwhelm us. Remember Keynes’s admonishment — in the long run, we are all dead!

A proposed exchange agreement

While these are all valid arguments for pursuing high cost drilling programs, we might want to consider other alternatives that provide the benefits from extracting the cheapest (and safest) oil first, while minimizing some of the costs. I will suggest one possibility that may or may not be feasible.
To keep this simple, I will illustrate the idea with a transaction that involves only two parties, the United States and Saudi Arabia.

So here’s the deal: The U.S. agrees to place a 5 year moratorium on all new deep water drilling. In return, the Saudis agree to increase their oil production by an equivalent amount, perhaps to 1 to 2 million barrels per day, which they will sell to the U.S. at a price of, say, $80 barrel. The kicker is that 70% of the dollars spent on this additional oil needs to be spent or invested in the U.S.

If this is done right, the world-wide supply and the price of oil should not be affected; the increase in Saudi oil production directly offsets the decrease in deepwater production. The transaction will, however, increase our trade deficit somewhat, but with the increased Saudi investment in the U.S. this will not create a problem. Moreover, there is an added benefit associated with placing Saudi assets in the U.S. If the Saudis have investments in the U.S., it will decrease the political risk faced by U.S. companies when they invest in Saudi Arabia, since it opens up the opportunity to use the U.S. court system, and to attach U.S. assets, in the event of a default.

What are the disadvantages of this transaction?

The most important is that this could make the U.S. even more exposed to political events within Saudi Arabia and the Persian Gulf, at least in the short-run. But by saving our own oil for later, we may be increasing our long-run energy security.

The other downside is that a halt in deepwater drilling will clearly weaken the domestic oil industry. The recent disaster notwithstanding, the success of this industry to extract oil from increasingly hostile environments has been remarkable. While this proposal would certainly slow down the drilling, the policy should reflect the likelihood that we will eventually drill off the coast of California, as well as in the Gulf, and that it is in all of our interests for the domestic oil companies to continue to innovate so that in the future oil can be extracted more cheaply and more safely.

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The Curse of Technological Improvement: Should You Buy a Better Light Bulb? When? http://blogs.mccombs.utexas.edu/titman/2010/04/21/the-curse-of-technological-improvement-should-you-buy-a-better-light-bulb-when/ http://blogs.mccombs.utexas.edu/titman/2010/04/21/the-curse-of-technological-improvement-should-you-buy-a-better-light-bulb-when/#comments Wed, 21 Apr 2010 19:20:10 +0000 http://blogs.mccombs.utexas.edu/titman/?p=249 Suppose you are choosing between two light bulbs.

  • The first is the energy efficient forever light bulb, which lasts forever, costs $52, and uses $2 of electricity per year.
  • The second is a traditional light bulb, which costs $2 dollars, lasts 1 year, and uses $4 in electricity per year.

Which light bulb would you choose?

The economics of this problem is a fairly straightforward if these numbers are going to stay the same going forward. If you buy the energy efficient forever bulb you are effectively making a $50 investment relative to the investment in an old fashioned light bulb (your upfront cost is $52 rather than $2) and each year you save $4, a $2 reduction in electricity costs and the $2 cost of replacing the bulb. You can thus say that your $50 investment in the more expensive forever bulb generates an 8% return, which is pretty decent.

But technology does not stand still and newer forever light bulbs are likely to become more energy efficient and cheaper over time. To make this simple let’s ignore the improvement in energy efficiency and suppose that, because of anticipated improvements in the technology and the manufacturing process, the forever light bulb is expected to cost only $49 next year.

What are the early adopters getting in benefit from their decisions? What are the late majority?

What are the early adopters getting in benefit from their decisions? What are the late majority?

Given the possibility of technical improvements, the economics of the light bulb choice changes considerably. We now must compare the choice of buying a forever light bulb today with the choice of buying the traditional light bulb today and buying the forever bulb in one year. As we show below, the rate of return on buying the forever bulb today (early adoption) relative to this wait-and-buy-later alternative is considerably less than the 8% return we described above.

  • With the forever bulb we pay $52 today for the bulb and $2 for the electricity over the next year.
  • With the second alternative, we pay $2 for the traditional bulb, $4 for electricity over the next year and $49 for the new forever bulb at the end of one year.

The second alternative costs a dollar more over the year; however, it requires $50 less upfront. In other words, the $50 incremental investment in the forever bulb yields a return of only 2%, which is not particularly impressive. Faced with these two alternatives, the consumer should probably wait.

Now if the light bulb technology was simply going to improve on its own, this wouldn’t cause a problem. It would make sense for us all to wait until the improvement in forever bulbs was sufficiently far along before we changed to the new technology. The fact that we are in some sense wasting electricity using inefficient traditional bulbs for another year is more than offset by the fact that in the future we will be using more efficiently produced forever bulbs.

However, we do have a problem if the technology for improving forever bulbs requires that they actually be produced and used. In an earlier post (Why do we subsidize green energy?) I listed this as the 5th reason to subsidize green energy. The idea is that while it makes economic sense to wait for improvements in technology, if we all wait for the perfect forever bulb, the forever bulb doesn’t get produced and the technology never improves .

The early adopters of forever bulbs are providing an important service–they are finding flaws in the product and giving the manufacturers the experience needed to improve the manufacturing process. So, it does make sense to provide them with a subsidy to induce them to provide this service. However, it is important to understand that the subsidy on the new technology, to be effective, needs to be viewed as temporary. If, we attach a $5 tax credit to the forever bulb for the next two years it won’t help. In the above example, the consumer will still rationally wait a year if he can get the cheaper bulb and the tax credit in the second year.

It is also important to understand the effectiveness of subsidizing purchases versus subsidizing research and development (R&D). One would not want to subsidize the purchase of forever bulbs if the early adopter experience effect has only a minor effect on improvements in bulb technology and the real improvements come about from R&D.

If improvements do come about because of R&D rather than manufacturing experience then it might make sense to subsidize R&D and keep the bulbs off the market until the costs are sufficiently low. This is true even when the current economics allow the forever bulbs to compare pretty favorably with the traditional bulbs. Since these bulbs last forever, being slightly better than the status quo is not good enough–we want to wait for them to be considerably better.

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The Future Oil Production in Venezuela http://blogs.mccombs.utexas.edu/titman/2010/03/23/the-future-oil-production-in-venezuela/ http://blogs.mccombs.utexas.edu/titman/2010/03/23/the-future-oil-production-in-venezuela/#comments Tue, 23 Mar 2010 16:22:36 +0000 http://blogs.mccombs.utexas.edu/titman/?p=180 A Conversation with Professor Carlos Molina

In a recent Energy Brief, Carlos Molina, Associate Professor at IESA Business School in Venezuela, comments on the current situation in Venezuela noting that though Venezuela has the potential to eventually become the largest oil producer in the world, there are also considerable challenges.

I would like to follow up with a few brief questions. First, Carlos, you mention that there is a disconnect between the production numbers provided by PDVSA, the Venezuela national oil company, and the numbers provided by the International Energy Agency. To what do you attribute this discrepancy and which numbers do you think are more reliable?

Carlos responds:
Since oil activities by PDVSA represent between 13 and 18% of the Venezuelan GDP, and about 70% of the country exports, the Venezuelan economy as a whole is dependent on these figures. It benefits the Venezuelan government to manipulate PDVSA’s oil production figures in order to window-dress the outlook of the Venezuelan economy. My belief is that the International Energy Agency figures are more credible. They are consistent with the OPEC (Organization of the Petroleum Exporting Countries) figures and with the estimations of the U.S. Energy Information Administration (EIA) and the U.S. Department of Energy for Venezuelan exports to the U.S.

Let’s ignore political issues for the moment and consider only what is technically and economically feasible. From a purely technical and economic perspective, how many barrels per day of oil can be produced in Venezuela by 2015, and by 2020?

Carlos responds:
PDVSA’s current strategic plan forecasts 5 mbpd for 2015 and 6.5 mbpd for 2020. (The previous plan, in 1997, had forecasted 8 mbpd for 2010.) Any oil production forecast depends on what the Venezuelan government wants to do, and how they structure the oil business. I think that current strategic plan is perfectly attainable. Moreover, I believe with a more aggressive investment agenda Venezuela could reach 10 mbpd by 2020. Of course, this agenda would require substantial private investment and have attractive conditions and protection for the investors, which is not likely to occur under the current government.

Of course, political issues cannot be ignored. Can you comment on the extent to which the Chavez administration currently influences oil production and how they will affect the ability of PDVSA to increase oil production over the next 10 years?

Carlos responds:
Chavez’s current term ends in 2012. I think PDVSA will be producing about the same oil output by 2012 that it is producing today. Given the negative environment for private investment in Venezuela, it is unlikely that Venezuelan oil output will increase in the next two years.

The recent auction of the three Orinoco oil belt blocks proves there is still interest in investing in Venezuela, even under current conditions. However, the investment is likely to be small relative to the Orinoco oil belt potential, particularly given the reserves that have been found.

If Chavez stays in power after the 2012 elections, I think that current PDVSA’s forecast of 6.5 mbpd by 2020 will be difficult to reach, given the negative influence of Chavez’s administration on PDVSA’s oil production. As we have said before, large investments are needed in order to exploit the heavy oil reserves of Venezuela; unfortunately for this administration, legal security and political risk are likely to impede these investments.

However, if Venezuela’s government changes in 2012 we could have a different story. With open policies and adequate investor protection, Venezuela’s vast oil reserves could attract the necessary investment.

What advice would you give the foreign oil companies that are engaging in joint ventures with PDVSA? Is there considerable political risk associated with doing business in Venezuela? Is it possible for them to structure contracts in ways that mitigate this political risk?

Carlos responds:
There is certainly a high political risk of doing business in Venezuela. Poor investment protection, continuously changing laws, arbitrary expropriation of lands and companies, and a lack of international arbitration create a difficult business environment. Under these circumstances it is almost impossible to structure contracts in ways that mitigate Venezuela’s political risk.

There is, however, a substantial opportunity for those ready to assume the risk. Foreign oil companies that decide to face current adverse conditions could profit in the future by being awarded oil projects with favorable geological conditions, vast proved reserves, comparably low production costs, and weak competition. Foreign oil companies that enter and stay in today’s Venezuelan oil market may be those that benefit the most if and when current political conditions change. Companies already in the Venezuelan oil business will be the best positioned to exploit the Venezuelan vast reserves tomorrow, in exchange for the risk they are assuming now.

In addition, foreign oil companies know that given Venezuela’s current economic uncertainty, Mr. Chavez needs them. PDVSA’s current oil production is falling every month, the Venezuelan economy is deteriorating fast, and there is an electricity and water crisis. The current vast oil reserves are of no use to him while they are buried in the Orinoco Belt. The current administration needs private investment and expertise to exploit Venezuela’s oil potential, now more than ever, which may be a deterrent against political risk.

Do you have any suggestions for PDVSA and the Chavez administration? What should they be doing differently to facilitate the development of the Venezuelan oil industry?

Carlos responds:
Chavez’s administration needs to make PDVSA more efficient and productive, certainly. Bringing private investment into PDVSA will only help country’s oil output (especially with a goal of doubling current oil production) and my main recommendations are in that vein.

My suggestions for PDVSA and the Chavez administration is to open the Orinoco oil belt for a large international auction, in which better conditions are offered to foreign oil companies. Conditions such as: a) giving at least 50% participation to the foreign oil company in the business in a sort of joint venture, b) including international arbitration in the contracts to give legal security, c) lowering the royalty rate from 33% to 16.67% as it is in other countries, and d) looking into financing alternatives such as those used in the past in the Petrozuata joint venture.

An alternative is to sell a portion of its stocks in the international and local stock markets, in a similar way to what Colombia’s ECOPETROL and Brazil’s PETROBRAS have done.

In an economy that depends that much on the oil profits, Venezuela needs to be open to private investment, not only for the oil sector of their economy, but also for their overall economic well-being.

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Why Do We Subsidize Green Energy? http://blogs.mccombs.utexas.edu/titman/2010/03/10/why-do-we-subsidize-green-energy/ http://blogs.mccombs.utexas.edu/titman/2010/03/10/why-do-we-subsidize-green-energy/#comments Wed, 10 Mar 2010 21:45:42 +0000 http://blogs.mccombs.utexas.edu/titman/?p=162 Alternative energy is heavily subsidized in the United States and even more so in EU countries like Germany. Billions of dollars are spent each year on subsidies, yet there has been relatively little discussion of the motivations for the subsidies and even less on how alternative energy should be subsidized.

I would like to start a stream of blog posts that explore these subsidies in more detail and ask how the public sector should be encouraging the development of these new technologies.

As a first step, let’s lay out seven principle motivations for subsidizing alternative energy:

1. To reduce carbon emissions.
2. To reduce our dependence on foreign oil.
3. To create jobs.
4. To increase the scale of investment in these emerging industries to take advantage of economies of scale.
5. To foster new innovations that will drive down the cost of using the new technology.
6. To diversify the country’s sources of energy.
7. To encourage entrepreneurial ingenuity and the positive spillover effects of innovation.

Even if we are convinced of the benefits of subsidizing the development of alternative sources of energy there remains the question as to the form the subsidization should take. For example, should we:

1. Tax carbon emissions, making fossil fuels less competitive relative to alternatives.
2. Subsidize research and development of alternative energy technologies.
3. Provide investment tax credits to reduce capital costs.
4. Have utilities pay more for electricity generated from alternative sources.

To help us think about optimal subsidies and taxes I would like to start by getting the opinions of our readers.

Thinking about what you’ve read about green energy subsidies, please respond to the following five questions. Thank you for your help.

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