Tuesday, December 24, 2013

IEA Forecasts Sustained Energy Growth, But No "Era of Oil Abundance"

  • The IEA's latest long-term forecasts highlights the growth of unconventional oil and gas, especially in North America, but does not see this leading to much lower oil prices.
  • In their main scenario fossil fuels will still meet more than three-fourths of the world's energy needs by 2035, despite significant growth in renewable energy.
The International Energy Agency (IEA) released its latest World Energy Outlook (WEO) in November, looking twenty-plus years into our energy future. The trends it describes add nuance and detail to last year's projections, rather than upending them.  Among other things they advance the expected date of global oil production leadership by the US to 2015 but suggest these gains may be short-lived and will not lead to "cheap oil."  The IEA also envisions a reshuffling of the traditional roles of energy importing, exporting and consuming countries, against a backdrop of steadily increasing energy-related greenhouse gas emissions.

As in previous years, the new WEO examines the full range of energy supply and demand, with a focus this time on the sources and uses of petroleum, and the emergence of Brazil as an oil and energy power. While recognizing that they might be underestimating the potential for technology or additional resource discoveries to sustain the growth of "light tight oil", or shale oil, which together with oil sands and gas liquids is a primary driver of oil supply growth today, the IEA forecasts it would peak by 2025.

That puts the burden for supporting oil demand growth and the replacement of supplies lost to natural decline after 2025 back onto the Middle East producers. So in the IEA's view, OPEC's loss of market power appears temporary. A corollary to this is that the agency does not anticipate a sustained drop in oil prices, but rather a gradual increase of about 16% by 2035. That's because the unconventional oil helping to drive current market shifts is still relatively high-cost, compared to the large conventional oil resources of the Middle East.

Although the IEA expects the global oil market to grow from its present level of around 90 million barrels per day (MBD) to 101 MBD in 2035, that change would be less than their forecasted equivalent global growth in gas, renewables or even coal. The concentration of oil demand in transport and petrochemicals would also increase, while other uses contract slightly. This is consistent with last year's observation that the center of the oil market is shifting towards Asia, since around one-third of the total anticipated growth in oil demand is for diesel to fuel goods deliveries in Asia.

The shift toward Asia applies to other forms of energy, as well, including natural gas and the expanded use of renewable energy.  This trend is already altering global energy trading patterns, and with the US becoming more energy self-sufficient  the IEA sees a new role for energy exports from Canada to supply Asia. That  includes both LNG and oil sands, which Fatih Birol, the IEA's chief economist, recently indicated the agency sees as only a minor, incremental threat to the climate compared to growing coal use.

An added nuance in this year's outlook is that the IEA now expects world-leading energy growth in China to be overtaken in a decade or so by faster growth in India, while rapidly growing consumption in the Middle East could result in that region posting the  second-highest growth in primary energy demand through 2035, especially for natural gas.

In the launch presentation in London Dr. Birol assessed the consequences of strong North American energy growth and shifting exports and imports for the prices that industries pay for energy. Because any exports of low-cost North American shale gas must be priced to cover the cost of liquefaction and long-haul freight, plus a margin, global natural gas prices should converge somewhat but still not equalize among the major consuming regions. As a result, the IEA expects US-based energy-intensive industries to have a persistent cost advantage in both gas and electricity, enabling them to increase their share of global markets. That has implications for employment and economic growth, while sustained energy price disparities should also drive energy efficiency improvements in response.

Another issue that received prominent attention at the launch was the always controversial matter of subsidies, for both conventional and renewable energy. The IEA estimated global fossil fuel subsidies at $544 billion 2012--mainly in developing countries and Middle East oil producers--resulting in "wasteful consumption" and fewer benefits for the poor than commonly claimed. And while supporting the use of subsidies to promote greater use of renewable energy, the agency's Executive Director, Maria van der Hoeven, made a particular point about the necessity for such subsidies to be carefully targeted and very responsive to changes in technology cost.

The IEA was founded in the aftermath of the 1973-74 Arab Oil Embargo and will celebrate its 40th anniversary next year. I couldn't help thinking about that as I reviewed the updated WTO materials. They're interesting as an annual update, but also in reflecting how the world of energy has changed since the oil shocks of the 1970s.

The rapid development of unconventional oil and gas that underpins the IEA's latest forecast would likely have amazed the industry veterans I met at the start of my career, but still fit within their worldview. I think they would have found the projected growth of renewable energy, supported by climate-change-inspired subsidies that surpassed $100 billion per year in 2012 more futuristic and surprising. Yet despite the anticipated expansion of renewable energy sources over the next 22 years, the IEA envisions the share of fossil fuels in the world's total energy supply only falling from 82% today to 76% in its main "New Policies" scenario.  That will seem overly cautious to many, but it underlines the challenges involved in changing such massive systems.

I'd like to wish my readers all the joys of the holiday season and a happy and prosperous New Year.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Thursday, December 19, 2013

Is the Wind Energy Tax Credit About to Expire for Good?

  • The expiration of the federal subsidy for wind power on 12/31/13 provides an opportunity to replace it with a smaller benefit, more focused on innovation.
  • Comprehensive tax reform is the best way to approach this, including making tax incentives for energy consistent across the board.
With the end of the year fast approaching, the US wind power industry faces yet another scheduled expiration of federal tax credits for new wind turbines. The wind Production Tax Credit, or PTC, was due to expire at the end of 2012 but was extended for an additional year as part of last December’s “fiscal cliff” deal. With the PTC and other energy-related “tax expenditures” subject to Congressional negotiations on tax reform, it was looking like this might truly be its last hurrah in its current form, until Senator Baucus, Chairman of the Senate Finance Committee, released his draft proposal yesterday. Unfortunately, from what I have seen so far it falls short of sunsetting this overly generous subsidy and replacing it with a new policy emphasizing innovation.

In its 20-year history, minus a few year-long expirations in the past, the PTC has promoted tremendous growth in the US wind industry, from under 2,000 MW of installed wind capacity in 1992 to over 60,000 MW as of today. For most of its tenure, the PTC did exactly what it was intended to do: reward developers for generating increasing amounts of renewable electricity for the grid at a rate tied to inflation.

However, unlike the federal investment tax credit for solar power and some other renewables, the amount of the subsidy didn’t automatically decrease as the technology improved, with wind turbines growing steadily larger, more efficient, and cheaper to build. Instead, the PTC’s subsidy for wind power increased from 1.5 ¢ per kilowatt-hour (kWh) to its present level of around 2.3 ¢. That figure equates to up to $39 per oil-equivalent barrel, depending on which conversion from kWh to BTUs you choose.

It's also roughly one-third of today’s average US retail electricity price for industrial customers and exceeds most estimates of typical operating and maintenance costs for wind power. The latter point has serious implications for the impact of wind farms on other generators in a regional power grid.

If wind turbine installations continued at their remarkably depressed rate of just 64 MW in the first three quarters of this year, the cost of extending the current PTC for another four years and beyond, as Senator Baucus seems to be proposing, would be negligible. However, it’s evident from industry data that a major reason installations are so low in 2013 is that the uncertainty over last year’s scheduled expiration caused developers to accelerate projects into the record-setting fourth quarter of 2012. The American Wind Energy Association cites over 2,300 MW of new wind capacity under construction as of the end of September, while installations over the last three years averaged just under 8,400 MW annually.

At that rate, a one-year extension of the current PTC would add around $5 billion annually to the federal budget over the succeeding 10 years that each year's new wind farms would receive benefits. Congress’s Joint Committee on Taxation apparently came up with a slightly higher estimate of $6.1 billion for a one-year extension.

Before reflexively supporting or opposing another status quo PTC extension, we should ask what we’d be getting for that $5 or $6 billion a year. One of the commonest rationales I encounter justifying the continuation of the current PTC is that conventional energy still receives billions of dollars in subsidies each year. Without getting bogged down in arguments over the definition of a subsidy, or the real and imagined externalities associated with using fossil fuels, it is certainly true that the US oil and gas industry benefits from deductions and tax credits in the federal tax code to the tune of around $4.3 billion per year, based on figures in the latest White House budget.

If we compare these benefits on the basis of the energy production they yield, the PTC starts to look pretty expensive. For example, wind capacity additions in 2012 of over 13,100 MW increased wind generation by 20 billion kWh over the previous year. That’s the energy equivalent of about 140 billion cubic feet of natural gas in power generation, or 66,000 barrels per day of oil. (Although less than 1% of US oil consumption is used to generate electricity, oil is still an easily visualized common denominator.)

By comparison, US oil production expanded by 837,000 bbl/day, while natural gas production grew by the equivalent of another 606,000 bbl/day. So on this somewhat apples-to-oranges basis, oil and gas added more than 20 times as much new energy output to the US economy as wind power did, for roughly the same cost to the federal government.

Now, it’s true that domestic oil and gas both had banner years in 2012, in terms of growth, reversing longer-term decline trends in earlier years, but US wind had its biggest year ever last year. Another factor making this comparison more reasonable than it might otherwise seem is that these are all essentially mature technologies. Wind turbines are still improving, but these improvements are mainly incremental at this point. Nor do they or the billions in annual subsidies for wind address the single biggest obstacle to the wider adoption of wind energy, arising from its fundamental intermittency and disjunction with typical daily and seasonal electricity demand cycles.

When the PTC was first implemented in 1992, by its very existence it fostered innovation in a technology that was still in its infancy as a commercial means of generating meaningful quantities of electricity. That’s no longer the case. I’ve seen various ideas for reforming the PTC to make it more innovation-focused, but while these might be preferable to the status quo, they strike me as overly narrow. We don’t just need wind innovation, but energy innovation, and in fact innovation across the whole US economy if we want to remain globally competitive, and if we want to make more than incremental reductions in our greenhouse gas emissions.

It’s ironic in that context that the federal 20% research and development tax credit is also due to expire at the end of the year. If it came down to a choice between extending the R&D tax credit and extending the PTC, I’d hope that even the wind industry would opt for the R&D credit. That’s not entirely a false choice, considering the scale of ongoing federal deficits and debt, and the need for the government to borrow around 20% of what it spends.

Now is the ideal time to rethink the Production Tax Credit. Its expiration now wouldn’t be as abrupt as was foreseen at the end of 2011 or 2012, because last year’s extension redefined how projects qualify for the PTC. Any wind project that has either started significant work or spent 5% of its budget by year-end could still qualify for the current PTC in 2014. I have seen analysis suggesting a project begun now might even qualify after 2015, as long as work on it had been continuous.

That sets up a smoother transition, while Congress and the wind industry reevaluate what role, if any, specific wind-energy subsidies have in a national energy economy that looks very different than the one in which the PTC was first conceived in the 1990s. Making tax incentives more uniform across competing energy technologies, as Chairman Baucus's draft would do, is a good start, but instead of locking in a perpetual subsidy for current wind power technology at 50 times the rate of today's disputed oil & gas tax incentives, Congress should focus on making the tax incentives for all energy production consistent across the board, at levels that taxpayers can afford no matter how much these energy sources grow in the future.

A different version of this posting was previously published on Energy Trends Insider.

Thursday, December 12, 2013

The LPG Echo of the Shale Gas Boom

  • Increased US production of LPG and natural gas liquids is an outgrowth of the shale gas revolution and a key ingredient for translating its benefits into industrial growth.
  • The infrastructure investments, export opportunities and price relationships for these liquids represent a microcosm of the similar issues for shale gas and LNG.
An article in the Wall St. Journal last month on the impact of a Midwest propane shortage on farmers trying to dry their corn harvest caught my attention. How could propane be in short supply, when US production is soaring due to shale gas? While it turns out that the shortfall in question was localized and temporary, it prompted me to take a closer look at LPG supply and demand than I have in many years. I found yet another market that is being transformed by the shale gas revolution.

Like most Americans--except for those in the roughly 5% of US homes heated with it-- I normally think about LPG only when I have to change the tank on my barbecue grill. That wasn't always the case; early in my career I traded LPGs for Texaco's west coast refining system. I'm happy to see that some of my former colleagues from that period are still involved and frequently quoted as experts on it. Although the LPG market is obscure to many, it represents a microcosm of the issues of reindustrialization and product exports arising from the recent turnaround in US energy output trends.

In order to follow these developments, we first need to clarify some confusingly similar acronyms, starting with LPG. Although often used synonymously with propane, it actually stands for "liquefied petroleum gas" and covers mainly propane and butane, though some in the industry include ethane in this category. The term reflects the oil refinery source of much of their supply, both historically and to an important extent today.  LPG overlaps with natural gas liquid (NGL)--ethane, propane, butane, isobutane and "natural gasoline"-- that has been separated from "wet" ( liquids-rich) natural gas during processing. NGLs are entirely distinct from the anagrammatical LNG, or liquefied natural gas, which consists mainly of methane that has been chilled until it becomes a liquid. By contrast, NGLs and LPG are typically stored at or near ambient temperature but under pressure to keep them in the liquid state.

LPG and NGLs make up a distinct segment of US and global energy markets, falling between the markets for natural gas and refined petroleum products. They are also linked to these larger markets, both logistically and economically. For example, gas marketers vary the amount of liquids they leave in "dry gas" to meet pipeline natural gas specifications based on price and other factors, and oil refiners blend varying quantities of butane into gasoline, depending on seasonal requirements. Propane and butane are mainly used as fuels, while ethane and isobutane are chiefly chemical feedstocks.

The development of shale gas in the US and Canada has affected the supply of NGLs and LPG in several important ways. First, starting around 2007 increasing shale gas output helped to halt and then reverse the decline in US natural gas production from which US NGLs are sourced. Then, following the financial crisis, diverging natural gas and crude oil/liquids prices pushed shale drillers toward the liquids-rich portions of shale basins like the Eagle Ford in Texas, in order to maximize their revenue. The resulting surge of US NGL production in late 2009 reinforced the decline of US LPG imports that began with the recession. According to US Energy Information Administration data, the US became a fairly consistent net exporter of LPG in 2011.

The current US LPG surplus is around 100,000 bbl/day, out of total production of around 2.7 million bbl/day. That surplus and its expected growth provides the basis for a number of announced LPG  export projects, as well as the anticipated development of new domestic chemical facilities such as ethylene crackers that would consume substantial portions of new supply, particularly of ethane.

The success of those projects depends on significant investments in new infrastructure, including gas processing, NGL fractionators to split the raw NGL into its components, and pipelines to deliver NGL to fractionators and LPG to markets. This is particularly true for the Marcellus and Utica shale gas in the Northeast, from which little or no ethane has been extracted due to limited local demand. Not only is that a missed manufacturing opportunity, but it constitutes a potential constraint on further liquids-rich gas development, since leaving too much ethane in the marketed gas would cause it to exceed pipeline BTU specifications.

In the meantime we're left with a situation that's analogous to the growth of tight oil production from the Bakken  shale. New sources of production have come on-stream faster than the infrastructure necessary to deliver them efficiently to where they can be processed or consumed. That puts a growing US surplus of propane and other NGLs in tension with tight regional markets for these fuels in the Midwest and Northeast, where residential propane prices are running well ahead of last year's at this time.  The resolution of this apparent paradox will depend on which infrastructure and demand projects are eventually completed, and how soon.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Tuesday, December 03, 2013

Making Petrochemicals from CO2

  • R&D is under way in Germany to see whether CO2 emitted from power plants or other facilities could become a useful feedstock for manufacturing chemicals.

  • This could have several advantages over producing fuels from CO2, while providing modest emission reduction benefits.

A recent article in Chemical & Engineering News described current German research and development work focused on devising new industrial processes for making organic chemicals from CO2. These public/private partnerships capitalize on that country’s long expertise in industrial chemistry and its highly successful chemical sector. They are also extremely timely, not just because of growing concern about steadily increasing levels of CO2 in the atmosphere, but because Germany’s “Energiewende”, which includes the rapid phase-out of nuclear power, appears to be raising the country’s emissions as it relies increasingly on coal for baseload electricity generation.

In my last post I explained why it is unlikely that fossil fuels could be phased out rapidly enough to threaten the current valuations of oil and gas firms. But if carbon-based fuels will be with us for some time, that leaves open the large question of what to do about the CO2 emitted when they are burned, particularly from stationary installations like factories and power plants. The long-mooted approach of carbon capture and sequestration (CCS) still faces significant obstacles in terms of cost and social acceptance. That makes CO2 utilization efforts such as those underway in Germany especially intriguing as a way of turning lemons into lemonade.

It’s impossible to predict today whether any of the CO2 utilization processes that German companies and universities are pursuing will ever become commercial. However, they share some key advantages over “classic” CCS and various efforts to produce fuels and other chemicals from CO2 captured directly from the atmosphere:
  1. Producing chemicals, rather than fuels, finesses a fundamental obstacle to recycling CO2. Thermodynamics dictate that reversing the results of combustion requires more energy than the fuels released when burned. As long as most energy globally comes from fossil fuels, it will be hard to come out ahead from an energy, emissions or cost perspective when turning CO2 back into fuels. However, if the output is valuable chemicals, that energy deficit might not be such a hindrance.
  2. The target chemicals for these projects, including polyols, polypropylene carbonate, and acrylates, are widely used and have a global market. While most don’t quite fall into the category of premium specialty chemicals, they are unlikely to become as commoditized as motor fuels. So while cost is an important consideration, there’s probably a bit more leeway for a new process to compete and become successful.
  3. The scale of production for these chemicals is much smaller than for motor fuels, by orders of magnitude. That means that a company investing in producing them from CO2 can hope to capture meaningful revenue and market share with a manageable scale-up from the laboratory. Yet they’re not so small that a single new plant on a scale large enough to demonstrate CO2 utilization would swamp the global market and destroy the margins that made the investment attractive in the first place.
  4. These projects appear to be focused mainly on using the CO2 effluent from other industrial processes or power generation, ranging from 4-14% for power plants and up to 90% for some industrial processes, rather than having to collect it from the atmosphere, where it is present at just 0.04%. Starting with a CO2 concentration 100-1000 times higher than in air entails much less surface area for absorption, and likely lower energy consumption and overall capture cost.
  5. Germany is committed to significant CO2 reduction, but the German public seems uncomfortable with the prospect of burying CO2 underground. Lacking large numbers of mature oil fields that could be revived by CO2 injection, a commercial-scale CO2 utilization industry would solve Germany’s problem of what to do with at least some of the CO2 it will eventually want to capture from the country's coal- and gas-fired power plants and other sources. 
As promising as these efforts look, they are unlikely to reduce global CO2 emissions by enough to meet current goals. While chemical markets are big enough to take up some captured-and-converted CO2, they are much smaller than the global fossil fuel consumption responsible for most man-made CO2 emissions. If carbon capture really took off, the volumes of concentrated CO2 involved would require multiple additional large-scale dispositions including enhanced oil recovery, fuel production–perhaps driven by advanced nuclear power–underground burial, and possibly chemical sequestration as carbonate rock.

In the meantime, turning some CO2 that would otherwise end up in the atmosphere into organic chemicals that will end up in more durable products seems worth pursuing. If these processes can become commercial, they will help move us in the right direction, and more cost-effectively than some other approaches receiving large ongoing government subsidies, rather than the modest seed money involved in these cases. I’ll be very interested to see how these efforts turn out.

A different version of this posting was previously published on Energy Trends Insider.