Playing with Fire - Part II

Posted on January 02, 2007
Posted By: Andrew Weissman
Part I of this series summarized four major observations from my recent work:

1. The severity of the crisis is much greater than I assumed might occur when I first began speaking out on the potential for sharply escalating natural gas prices almost five years ago. Prices have risen even more steeply than I assumed, and expanding supplies to keep pace with increases in demand has proven to be even more difficult. The result has been a steep increase in prices, in order to drive a sufficient number of users out of the market to match supply and demand.

Further, the increases in natural gas prices that have occurred to date could prove to be just the “tip of the iceberg.” By no later than the middle part of the next decade, a massive gap is likely to develop between the amount natural gas required by the U.S. economy and supplies available to the U.S. market. While the size of this supply gap will depend upon many factors, by 2020 it could reach as much as 10 Tcf/year. In Btu equivalent terms, this is nearly twice the amount of oil the U.S. currently imports from the Middle East.

2. An energy supply gap of this magnitude could result in hundreds of billions of dollars per year in needless energy costs and seriously impede the growth of the U.S. economy. While this massive shortfall in supplies will not necessarily result in physical curtailments of supply, at least on a routine basis, the price increases required to balance supply and demand could prove to be brutal. Further, under some plausible scenarios, by the end of the next decade, supplies to electric generators could become subject to periodic curtailments – posing a significant threat to electric supply reliability.

3. This impending crisis can be prevented by adopting a comprehensive national energy strategy to reduce U.S. dependence upon natural gas as a fuel to generate electricity. It is still possible to avoid this crisis. What has been missing to date has been an understanding of the severity of the potential natural gas supply gap facing the U.S. market and a willingness to develop and implement a comprehensive, realistic strategy to address it.

4. Action must be taken now. Given the lead time required to make major changes in the existing U.S. energy infrastructure and the magnitude of the potential supply gap, however, steps must be taken immediately to begin putting an alternative strategy in place. Delay will virtually guarantee steep further increases in natural gas prices in future years, and the permanent loss of additional manufacturing jobs, as industrial users continue to be forced out of the U.S. market, in order to free up additional supplies of natural gas for use to generate electricity – and, increasingly, to produce ethanol and synthetic crude from oil sands in Canada.

EIA’s Long-term Forecasts Significantly Understate
The Natural Gas & Electricity Price & Supply Risks Facing the U.S.

How could this be? How could the U.S. economy be faced with a potential energy supply crisis of this severity without the magnitude of this potential crisis being more widely understood?

While there is no single answer, the most important factor is the long-term forecasts of expected supply, demand and price of natural gas issued by the U.S. Department of Energy’s Energy Information Administration (EIA).

Earlier in the decade, EIA severely over-estimated the supplies of natural gas likely to be available to the U.S. market and drastically under-estimated the likely price. Unfortunately, there is a significant risk that EIA’s current estimates will prove to be just as far off the mark, potentially resulting in far reaching harm to the U.S. economy. It is important, therefore, that policy-makers begin to develop a better understanding as soon as possible of the extent of the price and supply risks faced by the U.S. economy in coming years.

The Reference Case price forecasts issued by EIA over the past 12 months provide a useful starting point for critiquing EIA’s work.

In its 2006 Annual Forecast, for example, issued this past February, EIA predicted that the wellhead price of natural gas in the U.S. would drop below $6.00/mmBtu within 24 months, averaging $6.13/mmcf (equivalent to $5.97/mmBtu) in 2007 and $5.78/mmcf ($5.62/mmBtu) in 2008. See Annual Energy Outlook 2006 (AEO 2006), Year-by-Year Reference Case Tables, Table 13.

These prices are almost $ 2.00/mmBtu below the current NYMEX 12-month strip prices for 2007.

In EIA’s 2006 forecast, however, these two years were the outliers at the high end of EIA’s range of expected future prices – i.e., according to EIA’s forecast, the last two high price years.

After 2008, EIA predicted that prices will begin falling like a rock, declining to $4.46/mmcf ($4.34/mmBtu) by 2016 (in $2004) and remaining below $5.00/mmBtu until 2023, when EIA predicted that the average wellhead price would increase to $5.05/mmBtu in $2004:

EIA’s February 2006 Price Forecast, Annual Energy Outlook 2006 ($/mmBtu)

For EIA to publish a price forecast in February of 2006 predicting that the wellhead price of natural gas would fall below $ 5.00/mmBtu for much of the next decade is little short of stunning.

As a practical matter, since liquidity in the futures market drops off dramatically after the first 24 to 36 months, EIA’s long-term price forecast is the most important long-term price signal available to the market. In addition, EIA’s long-term forecast of supply and demand provides the starting point for most private forecasts of natural gas prices and, indirectly, most electricity price forecasts.

As explained in this and subsequent articles, EIA’s recent forecasts have no hope of proving to be accurate in the real world. Unless and until the errors in EIA’s forecasts are corrected, however, serious mistakes in energy supply planning may be inevitable.

When it issues its 2007 long-term forecast, it appears likely that EIA will back off of its 2006 price forecast – at least to a limited degree. The Early Release version of Annual Energy Outlook 2007 (AEO 2007), issued earlier this month, increases EIA’s forecast of U.S. prices in most years during the period between 2007 and 2020:

Average Lower 48 Wellhead Price, AEO 2007 vs. AEO 2006 (2005$/mmBtu)

Further, this increase in predicted price levels occurs despite: (i) a decrease in expected demand; and (ii) higher expected production from U.S. on-shore wells, without any explanation of why lower demand and increased supply should lead to an increase in predicted price levels.

As discussed below, however, even with this modest bump-up in prices, EIA’s Reference Case price forecast almost certainly is far off the mark – understating significantly likely price levels in many years even in the specific conditions assumed in EIA’s Reference Case scenario, and understating price levels even more drastically in more likely, real world conditions.

EIA Has Demonstrated Repeatedly that It’s Inability to Develop
Reliable Estimates of Future Supply, Demand or Price

During the past several years, EIA’s price forecasts typically have been far off the mark. Cumulatively, for example, its 2002 Reference Case forecast underestimated U.S. natural gas costs over the past 5 years by nearly $350 billion, for natural gas alone:

Taking into account the additional impact on the wholesale price of electricity, the total increase in energy costs undoubtedly is substantially in excess of $ 400 billion – which approaches the cost-to-date of the war in Iraq.

Since 2002, EIA has increased its natural gas price forecast every year. Notably, however, despite this pattern of continuing increases, as recently as January of 2005, EIA was predicting an average wellhead price for this year of $4.55/mmBtu -- almost $2.00/mmBtu below its most recent estimate for 2006 -- and predicting that prices would decline to $3.75/mmBtu by 2008.

EIA’s recent track record should provide a strong cautionary note, therefore, regarding the likely accuracy of its future forecasts – especially since the personnel and underlying methodology EIA uses to develop its forecasts have not undergone any fundamental revisions during this period.

Nonetheless, many private forecasting firms continue to use EIA’s forecasts as the starting point for their analyses and issue long-term price forecasts that (not surprisingly) are in the same general range as EIA’s forecast.

By the Mid to Later Part of the Next Decade, Prices Could Increase To 2-3 Times EIA’s Forecast Level

The flaws in EIA’s most recent price forecast can not be easily dismissed. Instead, they are staggering in scale. They stem from EIA simultaneously:

  • Severely underestimating the amount of natural gas that is likely to be needed to meet the future needs of the U.S. economy; and

  • Grossly overestimating the supplies that are likely to be available to the U.S. market, particularly during the mid to later part of the next decade.

There also is a fundamental disconnect between EIA’s price forecast and its estimate of future U.S. demand for natural gas. Consumption of natural gas, of course, can not exceed available supplies for any sustained period. Instead, supply and demand must match.

To the extent the amount of gas needed by the U.S. economy significantly exceeds available supplies, therefore (as we believe inevitably will occur over the next decade) prices will need to be driven up -- potentially quite steeply -- to drive out of the market a sufficient number of users so that consumption matches supplies available for use.

EIA asserts in the Early Release version of AEO 2007, however, that despite more than a 40 % increase in total electric generation over the period covered by EIA’s forecast, power sector consumption of natural gas will peak in 2016, after increasing modestly from current levels, and then gradually decline, falling below current levels despite a 10 to 25 % projected decline in the real price of natural gas (depending upon the year). Further, despite this sharp decline in natural gas prices, during this same period, use of natural gas in the industrial sector is expected to increase only modestly from current post-2005 Hurricane lows.

The likelihood of EIA’s assumed scenario materializing, however, in our judgment is essentially zero. Instead, over the next 10 to 20 years, steep increases in the price of natural gas are likely to be required, in order to limit demand; the likelihood that the price of natural gas will decline significantly from currently levels and that demand will nonetheless simultaneously decrease in the power sector and remain largely stagnant overall, despite huge growth in overall energy use in the U.S. economy, defies common sense.

That is exactly the assumption that much be accepted, however, in order for EIA’s most recent long-term natural gas and electricity price forecasts to be treated as credible.

EIA’s Estimate of Future U.S. Demand is Far Off the Mark – Particularly in the Mid-to-Later Part of the Next Decade

The errors in EIA’s natural gas supply forecast will be discussed in Part III of this series. In estimating how much natural gas would be demanded at the price levels EIA forecasts, however, EIA commits at least eight major errors. Specifically, EIA:

1. Drastically understates likely future power sector demand for natural gas – in all likelihood by at least 2.0 to 2.5 trillion cubic feet per year by the mid- to later part of the next decade and potentially by as much as 5.0 to 7.5 Tcf by the 2025 to 2030 time frame;

2. Fails -- at least prior to the Early Release version of AEO 2007 -- to adequately take into account the rapid increase in demand that is occurring for use of natural gas to expand production of ethanol and other bio-fuels (which typically are very natural gas intensive, both for fuels processing and for growing crops);

3. Does not make any provision for the potential impact on natural gas consumption of requirements for reductions in emissions of Greenhouse Gases that might be enacted at either the federal or State level (such as A.B. 32, recently signed into law into California) and/or other new emissions restrictions that might result in increased utilization of gas-fired plants, even though the potential impact of such requirements, if they were ever to be adopted, is huge – potentially increasing demand for natural gas by several Trillion Cubic Feet per year;

4. Makes assumptions that could prove to be overly-optimistic regarding life extensions for aging coal-fired plants -- especially if environmental requirements are tightened;

5. Fails to assess the potential impact on demand for natural gas and likely price levels of natural gas of deviations from “normal” weather;

6. Fails to adequately evaluate the potential impact of lower-than-expected availability of other forms of generation (i.e., nuclear, hydro and coal), due to poor performance, retirements of older units, poor hydro availability, or potential conversion of coal-fired units to natural gas;

7. Examines only a narrow range of scenarios regarding potential future oil prices; and

8. Fails to adequately take into account the potential impact of higher oil prices on demand for natural gas and the price and availability of LNG.

Every one of these failings is significant; each is discussed in detail below.

The combined impact of these flaws, however, is to paint a fundamentally inaccurate picture of likely future supply, demand and pricing of natural gas in the U.S. market – and therefore electricity pricing and reliability as well, given the increasing dependence of the U.S. electricity market on gas-fired generation.

In order to have any hope of developing a realistic U.S. energy strategy, therefore, it is essential that a comprehensive new assessment of the North American natural gas market be undertaken immediately that properly assesses these issues.

Over the Past Several Years, EIA Has Repeatedly Failed to Anticipate Increases in the Use of Natural Gas to Generate Electricity

During the past several years, increased power sector demand for natural gas has been one of the primary factors driving up the price of natural gas, with an aggregate increase of more than 1.25 Tcf/year over the past 3 years.

Within the industry, the causes of this increase are well known. On a weather-adjusted basis, U.S. demand for electricity typically grows every year. Further, since the early ‘70s, no new nuclear plants have been licensed and only a handful of new coal-fired plants have been permitted.

Nonetheless, throughout the ‘80s and most of the ‘90s, as a result of surplus generating capacity that came on line shortly after the oil price shocks in the late ‘70s and improvements in plant performance during the ‘80s and ‘90s, it was possible to satisfy increased U.S. demand for electricity almost entirely by increased generation from existing coal and nuclear plants. Prior to 1998, increases in the use of natural gas to generate electricity were surprisingly small:

Beginning in the late 1990s, however, for the first time in two decades, electric utilities were required to add large amounts of new generating capacity in order to serve continuing increases in demand. At the time, EIA’s natural gas supply forecast predicted that natural gas production could be rapidly expanded, with only modest impact on the cost of natural gas, even over extended time periods.

As recently as four years ago, for example, in 2002 – in one of the costliest errors in U.S. forecasting history – EIA still was confidently predicting that supplies of natural gas delivered to the U.S. market from the lower 48 states and existing fields in Canada could be increased by almost 50%, to 34.1 Tcf by 2020, with the wellhead price of natural gas remaining in the $2.30 to $3.17/mmBtu range or lower throughout the 20-year period covered by EIA’s forecast (in $2000).

We now know, of course, that EIA’s expected 34 Tcf, $3.17/mmBtu scenario has no hope of being achieved. Within less than 12 months after EIA issued its forecast, the wellhead price reached $3.15 and has never fallen below that level since. Despite record mild weather last winter, which has helped to hold down prices through much of this year, EIA’s most recent estimate of the wellhead price for 2006 is $6.49/mmBtu – more than twice the upper end of the 20-year price range it predicted just 4 years ago.

In the interim, however, the power industry has constructed more than 225,000 MW of new generation – virtually all of it gas-fired:

This is enough generation to serve the total current load in Germany, Great Britain and France combined – assuming adequate supplies of natural gas could be found to operate these units.

The net impact of the construction of this new generation has been to fundamentally transform the generating mix in the U.S. – and to permanently eliminate a significant number of U.S. manufacturing jobs.

Prior to the addition of these gas-fired generating units, except in Texas and a few other areas of the country (e.g., along the California coast), natural gas generally was used only in peaking units, many of which were operated less than 100 hours a year.

Now that this massive construction program has been completed, however, more than 40% of all of the generating capacity in the U.S. is gas-fired. Further, gas-fired generating units are now the marginal source of electricity supply in most Regions of the country for an increasing number of hours each year.

This in turn has had the effect of causing the amount of natural gas used to generate electricity to escalate at a startling rate for several consecutive years:

As a result, in July of this year, for the first time, more than 1 Trillion Cubic Feet of natural gas was used to generate electricity in a single 31-day period – an average of 32.3 Bcf/day! In effect, during this period, almost 60% of the natural gas produced by the 500,000 + operating wells in the U.S. was used simply to generate electricity. In August, consumption of natural gas to generate electricity was almost as high.

Further, while temperatures this summer were much hotter-than-normal, 6 of the past 7 summers have been hotter-than-normal. In addition, load is continuing to grow every year. Even if temperatures over the next few summers revert to more normal levels, therefore, summer-month consumption will soon match last summer’s levels.

Winter-month power sector consumption of natural gas also has recently begun to accelerate sharply, and could become an increasingly important factor adding to winter-month demand for natural gas in future years.

The net effect of the addition of this massive amount of new gas-fired generation has been to profoundly change the power industry’s fuel mix, leaving the industry dependent upon gas-fired generation to meet a significant share of incremental demand for electricity even in Regions that historically have relied primarily on coal and nuclear generation. Further, as a practical matter, as a result of the massive number of new gas-fired generators added since 1999, at least for the next 7 to 10 years, the industry has no alternative other than to continue to rely primarily on increased use of gas-fired generating units to meet expected growth in demand for electricity:

U.S. Dependence Upon Gas-Fired Generation Likely to Continue to Grow

EIA, however, appears not to grasp the significance of this shift. Its last several forecasts have failed almost entirely to anticipate the increase in power sector consumption of natural gas that has occurred over the past three years.

Strikingly, EIA’s most recent final Annual Energy Outlook, AEO 2006, issued in February of this year, estimated that, over the 5-year period between 2004 and 2009, power sector consumption of natural gas would increase by a cumulative total of only 40 Bcf nationwide over a 5-year period – viz., from 5.32 Tcf/year in 2004 to 5.36 Tcf/year in 2009. This is an average growth of only 8 Bcf/year (i.e., approximately 0.15 %/year), starting from a year in which summer-time weather was unusually cool, minimizing power sector consumption of natural gas!

EIA’s February 2006 Estimate of 2006-2009 Power Sector Demand for Natural Gas (trillion cubic feet)

At a time when gas-fired generation is the marginal source of supply in virtually every Region of the country, it is difficult to understand how EIA could have convinced itself this was a plausible estimate – especially since the summer of 2004 was one of the mildest in the past 30 years, holding power sector consumption of natural gas in the summer of 2004 significantly below normal levels. In effect, it’s almost as if EIA concluded that this enormous fleet of new generating units – which with expected additions will soon equal total U.S. generating capacity in 1970 – could be run on thin air.

This year alone, power sector consumption of natural gas is likely to exceed EIA’s estimate of likely consumption in 2006 by more than 1 Trillion Cubic Feet (or 20.5%) – i.e., at least 6.22 Tcf, vs. an estimate in Annual Energy Outlook 2006 (AEO 2006) of 5.16 Tcf. This is a level that as recently as this past February EIA forecast would not be reached until 2013 – 7 years from now!

This is not a minor discrepancy; instead, increased demand of this magnitude ordinarily is sufficient to cause a severe price spike. Only extremely mild weather this past January (which held withdrawals from storage in January more than 400 Bcf below normal levels) prevented natural gas prices from reaching double digit levels during the last several months of this year.

While record hot weather this past July and early August and much lower-than-normal power sector use of residual fuel oil contributed to this higher-than-expected consumption, less than ½ of the variance from EIA’s estimate can be explained based upon these factors, in part because the impact of hotter-than-normal weather this summer was partially offset by lower-than-normal power demand for electrostatic heating last winter and by favorable hydro availability in the Pacific Northwest throughout much of the year. Further, EIA projects that consumption of residual fuel oil will remain at significantly lower levels for much of the next decade.

In the Early Release version of AEO 2007, EIA recognizes that its estimates of power sector demand during the period between 2007 and 2012 are untenable, and increases sharply its estimates of power sector consumption of natural gas during this period, compared to AEO 2006:

Power Sector Consumption of Natural Gas, AEO 2007 vs. AEO 2006 (trillion cubic feet)

This drastic revision, just 10 months after EIA issued AEO 2006, should be sufficient, by itself, to raise major issues regarding the reliability of EIA’s estimates. For the period between 2007 and 2012, both AEO 2006 and the Early Release version of AEO 2007 assume a nearly identical generating mix. Further, total demand is nearly the same in both reports. The most significant difference is that natural gas prices are assumed to be higher in AEO 2007 than in AEO 2006, at least for the next few years. It is not immediately apparent, therefore, why use of natural gas to generate electricity is assumed to jump significantly during this period, compared to estimates EIA presented earlier this year.

Even with these increases during the period between 2007 and 2012, however, EIA’s estimate of future power sector consumption of natural gas almost certainly falls far short of the mark.

Notably, even with these revisions, EIA’s estimates of power sector consumption are still up to 2.0 Tcf/year below EIA’s estimates of future power sector consumption of natural gas issued just 2 years ago in Annual Energy Outlook 2005 (AEO 2005) (which in our view are still too low):

Rather than responding to evidence that there is a major flaw in its forecasts that causes it to understate growth in power sector demand for natural gas by thoroughly reviewing its methodology, therefore, and replacing it with an approach that allows EIA to more accurately assess the market, over the past two yeas, EIA has reduced its projection for long-term power sector use of natural gas dramatically.

Further, this reduction is expected future use of natural gas to generate electricity has occurred even though EIA continues to project that: (i) natural gas prices will decline significantly in real terms compared to current levels; and (ii) U.S. electricity demand will grow by more than 40 % during the period covered by its forecast!

In short, despite far higher-than-expected near-term growth in consumption of natural gas, at price levels far above EIA’s forecast levels, longer-term, EIA is projecting that power sector consumption of natural gas is likely to decline, despite a significant decline in the cost of natural gas and continued strong growth in U.S. demand for electricity!

EIA may well believe this is a plausible scenario; it is not entirely clear, however, why others should – at least without a dramatic change in national energy policy compared to the status quo.

Further, even in near-term, the revised forecast of power sector consumption of natural gas presented in the Early Release version of 2007 bears little relationship to what realistically can be expected to occur in the U.S. market.

It is entirely plausible, of course, that after this year’s record hot summer, power sector consumption of natural gas will decline in 2007 -- although even this coming year such a decline is by no means certain to occur.

Between 2006 and 2011, however, EIA’s forecast assumes that net electric generation will increase by approximately 372,000 GWhrs – a cumulative increase of 9.1 % over the next 5 years (including the parasitic load associated with new pollution control equipment).

Remarkably, even though gas-fired generation currently is the marginal source of supply in every Region of the country, EIA assumes that this massive increase in electric generation will have only a modest impact on use of natural gas to generate electricity over this 5-year period.

Specifically, it’s forecast of power sector consumption of natural gas five years from now (i.e., projected consumption of 6.51 Tcf in 2011) allows room for only 300 Bcf of increased natural gas consumption over a period of 5 years, compared to EIA’s most recent estimate of actual 2006 levels in it’s December Short-Term Energy Outlook:

Power Sector Consumption of Natural Gas vs. Actual, AEO 2007 (trillion cubic feet)

This averages out to an increase of just 58 Bcf/year – which is less than the year-over-year increase that occurred in some weeks this past summer.

EIA’s forecast then calls for power sector consumption of natural gas to: (i) increase modestly between 2011 and 2016; (ii) remain relatively flat between 2016 and 2020; and then (iii) begin to rapidly decline starting around 2021:

Power Sector Consumption of Natural Gas, AEO 2007 Projections (trillion cubic feet)

Is this forecast of future U.S. power sector use of natural gas even remotely plausible?

We believe the answer is no. Instead, both near-term and longer-term, EIA’s estimate of future power sector consumption of natural gas has virtually no chance of proving to be valid, even under the increasingly unlikely scenario in which no further emissions restrictions are adopted that create an increased preference for natural gas vs. coal.

Under any scenario in which even moderate restrictions on emissions of greenhouse gases or criteria pollutants are enacted at either the federal or state level, the gap between EIA’s estimate and actual power sector consumption of natural gas is likely to be even more extreme.

By the Middle Part of the Next Decade, Power Sector Consumption of Natural Gas Is Likely to Exceed EIA’s Most Recent Estimates by At Least 1.5 to 2.0 Tcf/year

Even before taking into account the potential impact of changes in environmental requirements, for example (some of which already have begun to be enacted at the State level), it should be clear that by the middle part of the next decade, power sector demand for natural gas in a typical year is likely to exceed EIA’s estimates by at least 1.5 to 2.0 Tcf/year in a typical year. If new emissions restrictions are adopted that increase utilization of natural gas, the increase in power sector consumption of natural gas, compared to EIA’s estimate in it’s the Reference Case forecast in the Early Release version of AEO 2007 in some years could be as much as 2.5 to 3.0 Tcf/year.

By 2025 to 2030, even if there are no new environmental restrictions that favor gas-fired generation, under some plausible scenarios, power sector consumption of natural gas could increase by 5.0 Tcf/year or more, compared to EIA’s estimates in the Early Release version of AEO 2007.

The likelihood of higher power sector consumption of natural gas, even in a “no change” in environmental requirements scenario, is due to a number of different factors. The most important, however, are the following:

1. Inability of EIA’s model to accurately model power sector consumption of natural gas on peak summer days, when consumption of natural gas is at its height. While EIA does not provide sufficient information to fully evaluate the modeling on which it bases its estimates, from the data EIA reports, it appears that the production cost model EIA uses to simulate system dispatch understates the extent of power sector consumption of natural gas on peak summer days (possibly by treating peak demand as a large block spread out evenly over a relatively long period, rather than compressing it into a relatively small number of days). This is critical, since it’s the “peakiness” of demand on hot summer days that creates the greatest need to use gas-fired generation – which is generally the last to be dispatched.

As a result of this flaw, EIA starts its analysis with an estimate of current year consumption of natural gas which is too low – understating power sector consumption of natural gas by approximately 330 Bcf in 2006, compared to the separate estimate of 2006 demand published in EIA’s Short-term Energy Outlook, after adjusting for differences in categorization between the two reports. This has the effect of skewing all of its estimates for subsequent years.

By 2020 or 2025, the underestimate could easily be twice as large as the underestimate for 2006, given the critical role peak summer demand plays in driving total power sector consumption of natural gas for the year.

2. Inappropriate assumptions regarding summer weather conditions. EIA further distorts its analysis by basing its modeling on 30-year climatological norms. While this might initially appear to be a neutral basis for preparing EIA’s forecasts, as noted earlier, only 1 recent summer has been normal or milder than normal compared to this standard (i.e., the summer of 2004). Further, at least currently, the 30-year climatological norm is not nearly as “neutral” or “objective” a standard as might initially appear to be the case. This is because the first 15-years used in calculating the current 30-year norm (i.e., the period from 1971 to 1985) included the longest stretch of generally mild summer weather of the past 75 years:

Just replacing the current 30-year norm starting in 1970, therefore, with a sequence starting in 1980 (as will occur anyway in another few years) would lead to different results.

This is not a minor issue. Basing EIA’s forecasts on a 10-year rolling average, for example (an approach used by many analysts) would increase the assumed number of Cooling Degree Days by approximately 15 %, for the summer months alone:

This would be likely to increase EIA’s estimate of power sector consumption of natural gas by 200 Bcf or more for 2007 – and more in subsequent years.

3. Inappropriate assumptions regarding hydro availability in the Pacific Northwest. Similarly, EIA uses 30-year norms in calculating hydro availability in the Pacific Northwest – which also tends to create a downward bias in its estimate of natural gas consumption. While hydro availability will sometimes match the 30-year average (as it has in 2006), the trend for some time now has been that these years are the exception rather than the norm, with availability using falling well below this level. Once again, therefore, the effect of the assumption used in EIA’s Reference Case is to understate natural gas consumption in a typical case; use of a 10-year rolling average would produce a more defensible baseline estimate.

4. Consistent use of assumptions that are far too optimistic regarding the potential for a sudden jump in the output of existing coal-fired plants. Further, every year since at least 2000, in issuing its annual forecast, EIA has assumed that, in the near future, there will be a sudden huge jump in the output of existing coal-fired plants. The timing and magnitude of this expected sudden acceleration in the output of existing coal-fired plants has varied from forecast to forecast. In the last several Annual forecasts, however, it generally has been predicted to start the year after the forecast was issued (whenever that happened to be in a particular year):

The problem, unfortunately, is that EIA’s assumption that this sudden jump in output will occur has proven to be incorrect every time. Some growth in output has occurred, but seldom at even close to the levels EIA has predicted. The fact that EIA has been wrong in this prediction, time after time, has had little impact, however, on the Agency’s apparent optimism that a major change in performance is “just around the corner” – which EIA has persisting in building into its Base Case estimates for the better part of a decade.

In the Early Release version of AEO 2007, EIA finally appears to be taking at least a slightly different approach. The period in which rapid growth in output is assumed to occur has been pushed back slightly, to begin in 2009 rather than 2008, and then continue through 2012. Further, the assumed increases are not quite as aggressive as in previous years.

During this period between 2009 and 2012, however, the output of existing coal-fired plants still is assumed to increase by almost 100,000 GWhrs, over and above the increased output that might reasonably be expected from new coal-fired plants expected to be added during this period.

The effect of this paper assumption is to eliminate, with the wave of a hand, up to 800 to 850 Bcf per year in potential power sector consumption of natural gas that is likely to occur if the output of existing plants fails to suddenly jump as EIA’s projections assume.

Is it theoretically possible that the increases EIA assumes can be achieved? Yes, the possibility that EIA’s assumed output levels could be achieved, at least in some years, cannot be entirely ruled out.

The question, however, is whether EIA’s assumption is a reasonable starting point for developing a Base Case forecast of demand for natural gas. Here, the answer is almost certainly no.

If there ever was the potential to achieve the sudden increases EIA assumes, the best prospects probably were over the past few years. Natural gas prices certainly have been high enough to create strong incentives to operate existing coal-fired units at maximum capacity. Further, in some Regions of the country, there still were extended periods in which available coal-fired units were not fully utilized for extended periods of the year.

With each passing year, however, the nation’s existing fleet of coal-fired units continues to age; a surprising large percentage of these units a very old (> 50 years) and quite small (< 200 MW).

Especially as environmental requirements tighten, it is less clear that it will make sense to continue to pour large amounts of capital into the maintenance of these units. As a result, maintaining current availability levels at many of these units may become increasingly difficult and retirements could significantly exceed the levels EIA assumes (especially if natural gas prices were anywhere close to the levels that EIA forecasts).

Further, every year, there are fewer and fewer hours in which most existing coal-fired units are not already being dispatched at or near maximum capacity.

If anything, therefore, in future years, the output from existing units may be increasingly likely to plateau – or potentially even decline (depending in part on the number of retirements).

In preparing a Base Case forecast, therefore, it would have been more reasonable for EIA to take a more cautious approach – e.g., cutting the assumed rate of growth in output from existing units at least in half, if not further.

If it did so, by the end of the next decade, this would add another 400 to 500 Bcf to EIA’s estimate of projected power industry consumption of natural gas.

5. Assumptions regarding the addition of new coal-fired capacity could also prove to be wildly over-optimistic. Finally, particularly during the period beginning in approximately 2014, EIA’s estimates of natural gas consumption are highly dependent upon its assumptions regarding the addition of new coal-fired plants. EIA assumes, for example, that a total of 32,400 MW of as yet-uncommitted plants will be added by 2020, and an additional 46,400 MW in the next 5 years, bringing total additions by 2025 to 78,800 MW.

One can fervently hope that these plants will be built – since the need is clearly present, from the standpoint of national energy policy. Whether it is appropriate, however, to treat these plants as if they already were “steel in the ground” is an entirely different matter – particularly given legislative initiatives already being considered at both the federal and state level that might strongly discourage (or at least delay for several years) construction of new coal-fired plants.

Absent the construction of these plants, however, during the decade beginning in 2020, power sector consumption of natural gas could nearly double compared to the levels estimated in the Early Release version of AEO 2007 – i.e., quite literally, the amount of natural gas needed to “keep the lights on” in the U.S. could increase by as much as 5.0 to 7.5 Tcf/year compared to the level EIA estimates in the Early Release version of AEO 2007. Further, this increase could occur merely as a result of a reluctance to build new coal-fired plants, even if there are no new environmental restrictions that specifically preclude the construction of these plants.

At a minimum, therefore, given the critical importance of this issue, in preparing its annual forecast, EIA should explicitly model a range of different scenarios regarding both the amount of new coal-fired capacity that might be built over the next two decades and the likely output of existing coal-fired plants, and present the results of this analysis, rather than presenting as its Reference Case a scenario that assumes that coal-fired units will be available and dispatched whenever, on paper it would be consistent with principles of economic dispatch to build and utilize coal-fired generation.


In all five instances discussed above, therefore, EIA has used a methodology that has the potential to greatly minimize projected future power sector consumption of natural gas, compared to what is likely to occur in “real world” conditions.

Its Reference Case forecast, therefore, is hardly a “most likely” scenario. Instead, even in a “no new environmental restriction” scenario, it is much closer to an extreme “best case” scenario, in which on a whole series of critical issues, EIA has made assumptions that it should have recognized are likely to greatly understate the likely use of gas-fired capacity in the conditions that are likely to actually occur over the next 15 to 20 years.

The extent to which EIA has underestimated future consumption levels will depend on many factors, and varies for different time periods.

At a minimum, even in a “no environmental change” scenario, by the mid to later part of the next decade, in many years power sector consumption of natural gas will be 1.5 to 2.0 Tcf per year higher than EIA’s estimate.

This is a stunning figure. By 2015, for example, EIA estimates that power sector consumption of natural gas will increase by 1.30 Tcf/year over the level assumed for 2006 in its forecast – an increase of 3.6 Bcf/day. If the actual increase in power industry consumption, however, even in the “no change” scenario, is 1.5 to 2.0 Tcf/year greater (i.e., more than twice as great) this potentially would equate to an increase in power sector consumption of natural gas of as much as 9 Bcf/day – even in the unlikely event that there is no further tightening of environmental requirements that increase demand for gas-fired generation.

Further, during this same period, use of natural gas in other sectors is projected to increase by 1.76 Tcf/day. In the aggregate, therefore, by 2015, the amount of natural gas required to meet the needs of the U.S. economy, even under a “no change” scenario, could easily increase by at least 12.5 to 13.9 Bcf/day:

Increased Demand by 2015 – “No Change” in Environmental Requirements

Increased demand of this magnitude – viz., 12.5 to 13.9 Bcf/day – would be sufficient to precipitate a major crisis, even if there were no other flaws in EIA’s forecast, since there is no apparent source of supply that is likely to be adequate to meet an increase in demand of this magnitude at prices even remotely in the range EIA is forecasting.

As we move closer to 2020, however, unless large amounts of new coal-fired capacity begin to be added, the increase in the amount of natural gas required to meet the needs of the U.S. economy could begin to escalate at a much more rapid rate – potentially escalating by 400 to 500 Bcf/year on a weather-adjusted basis every year.

By the 2025 to 2030 time frame, therefore, even in the “no change” scenario, the total increase in the amount of natural gas needed to generate electricity could exceed EIA’s estimate by as much as 5.0 to 7.5 Tcf/year.

This huge potential increase in demand, of course, is no where apparent in EIA’s forecast, since EIA simply assumes that whatever coal-fired capacity is needed to prevent this demand from arising will be built – and brought on line exactly when it is needed, apparently irrespective of whether there is a regulatory mechanism in place that ensures full cost recovery for the entities expected to build these plants.

Unfortunately, however, this underestimate – as severe as it is – is just the “tip of the iceberg” in terms of the flaws in EIA’s estimate of the amount natural gas that potentially could be required to meet the future needs of the U.S. economy or any of the other factors that potentially might deter generators from building these plants.

EIA Does Not Attempt to Identify or Systematically Assess Potential Sources of Increased Demand for Natural Gas

Perhaps the most serious flaw in this regard is that EIA never attempts to systematically identify or assess the potential impact of possible sources of increased demand for natural gas, on either a short-term or long-term basis.

This is a fundamental shortcoming in EIA’s analysis, particularly because: (i) short-term elasticity of supply for natural gas is the lowest of any major fuel; (ii) even over a several year period, elasticity of supply is only modestly greater (as the experience of the past several years amply demonstrates); and (iii) natural gas is the most expensive fuel to store.

As a result, even relatively modest increases in demand (e.g., perhaps 200 to 400 Bcf in a particular 12-month period) potentially can lead to major price spikes (e.g., the quadrupling of prices that occurred in 2000).

Any omission in EIA’s estimate of future demand, therefore, potentially can “blow out of the water” EIA’s price forecast – leading to steep price increases, potentially comparable in magnitude to the total wellhead prices predicted in AEO 2006 (i.e., up to $ 4.00 to 5.00/mmbtu). These price increases, in turn, potentially could equate to $ 100 billion or more in increased customer costs in a single year.

To develop an accurate estimate of potential future costs for natural gas, therefore, it’s essential to identify and properly quantify every major factor that could lead to such increases – on either a sustained or short-term basis.

The Need to Develop Alternative Fuels is Already Beginning to Significantly Impact Demand for Natural Gas

In the past 12 to 18 months, for example, it’s already become quite clear that the need to develop alternative fuels to supplemental conventional oil supplies and replace the use of MTBE as an additive is likely to have a dramatic impact on demand for natural gas over time.

The decline in oil supplies effects demand for natural gas in at least 3 different ways:

- Huge amounts of natural gas are needed in Canada to mine and process oil sands (reducing supplies of natural gas available for export to the U.S.);

- Large increases in the use of natural gas in the U.S. already have begun to occur in connection with the production of ethanol and bio-diesel, both to grow crops and to produce bio-fuel;

- The amount of natural gas needed in the refining process has begun to increase significantly because of the need for additional hydrogen, to process heavier grades of crude.

These developing trends still are at an early stage and are likely to intensify over time. Within the next 5 years, for example, consumption of natural gas for production of bio-fuels could easily increase by an additional 500 Bcf/year, over and above the increases in the past year – making the bio-fuels industry one of the largest natural gas-using industries in the U.S. economy.

At best, only a portion of this potential growth in demand is factored into EIA’s most recent estimates of future U.S. consumption. At a time when both U.S. production and imports from Canada are likely to be declining, this is more than enough to lead to a significant increase in prices in the U.S. market.

If oil shale is developed on a major scale, the resulting increase in demand for natural gas as a fuel to generate electricity could be several times this size.

In the Current Environment, it is Irresponsible to Issue Natural Gas Price Forecasts that Fail to Explicitly Assess the Potential Impact of New Environmental Restrictions That Could Result in Increased Use of Natural Gas

Further, in estimating the potential demand for natural gas in the U.S. market, EIA makes four other limiting assumptions that would cause its forecast to be highly misleading even if there were no other fundamental flaws in its analysis. Specifically:

1. Perhaps most significantly – for purposes of its Annual Forecast, EIA does not make any effort to assess in a systematic, rigorous manner the potential impact of possible new environmental restrictions, and instead explicitly assumes that there will be no tightening in applicable emissions requirements at any time in the 25-year period covered by its forecast, even though legislation already pending before Congress could lead to dramatic increases in demand for natural gas;

2. EIA attempts to evaluate potential demand for natural gas and likely price levels only under assumed “normal” weather conditions;

3. For purposes of its analysis of likely power sector consumption of natural gas, EIA assumes “normal” availability of all other forms of generation (i.e., nuclear, hydro and coal), with only minimal future retirements; and

4. EIA examines only a narrow range of scenarios in terms of potential future oil prices, and does not explicitly link the price or availability of LNG to the price of oil.

These are huge flaws, which go to the heart of the mission we should be asking EIA to undertake.

At first blush, to an outsider to the industry, EIA’s use of these simplifying assumptions might seem understandable. Attempting to systematically assess uncertainties, and developing a reasonable set of scenarios to evaluate is not an easy task – and could easily create controversy. Indulging in the assumption that there will be “no change” in the future, and that weather conditions will match historical norms, simplifies EIA’s work, and – at least in a limited sense – eliminates a potential source of controversy.

Fundamentally, however, the issue is whether EIA’s mission is to inform policy-makers, energy users and others of the range of potential outcomes which reasonably could occur in future years or instead to assess future supply and price of natural gas only in purely academic terms, in an assumed “future world” that in all likelihood will never exist.

If EIA’s goal is to provide useful information to decision-markers, it has no choice other than to try to face squarely the major uncertainties that affect the future price of natural gas and to lay out clearly and candidly the range of possible price outcomes that could occur depending upon how these uncertainties are resolved.

At least thus far, however, EIA has steadfastly refused to undertake this task – at least for purposes of its Annual Energy Outlook, the official Agency forecast relied upon by many policy-makers at the federal and state level, and the only forecast ever reviewed by many in the private sector.

The result has been a disaster – i.e., an annual price forecast that ultimately misleads more than informs. The examples listed above helps to illustrate this point:

1. Assumption of “no change” in environmental requirements. Perhaps the single most important flaw in EIA’s annual forecasts is that it does not explicitly present or evaluate the potential impact on demand for natural gas or on natural gases of potential changes in environmental requirements. (At the request of certain members of Congress, EIA has periodically performed analyzes of the potential impact of certain legislative proposals pending before Congress. While these analyzes are available on EIA’s web site, many members of the public are not aware they exist. EIA does not discuss these studies in its annual forecasts or attempt to incorporate the results of these studies into the analysis its presents in its Annual Energy Outlook.)

The end result is that EIA’s forecast is highly vulnerable to being misinterpreted by policy-makers, and runs the risk of giving highly misleading signals to both energy producers and end use customers regarding potential future price levels.

EIA’s long-term forecast covers a 25-year period. Implicitly, therefore, EIA’s forecast is based on the assumption that there will be no changes in relevant environmental requirements that will significantly affect the use of natural gas or other fuels over the next 25 years.

It is possible this assumption will prove to be valid, but it obviously is not the only plausible outcome. Instead, changes already are started to be adopted at the state level that could result in huge increases in demand for natural gas, and it clearly possible that other such changes will be considered at the state level or the federal level or both over the next several years.

Some of these proposals could increase the amount of natural gas needed by the U.S. economy by the 2020 to 2025 time frame by as much as 2 to 4 Tcf per year, with far-reaching potential repercussions for the price of natural gas and electricity in the U.S. market.

There is a critical need, therefore, for EIA to explicitly address the potential impact of these requirements on future demand for natural gas and future price levels as part of its annual forecast – both to better inform decision-makers of the potential consequences of their decisions, and to inform end users of the potential price risks down the road.

Major decisions are being made every month regarding long-term investments in energy supply infrastructure and in buildings and equipment across the entire economy tied to the future cost of energy.

There is no hope that these decisions can be made intelligently if they are made in a complete vacuum regarding the range of possible future energy price scenarios. Right now, however, that is exactly what is occurring – with potentially disastrous consequences.

2. “Normal” weather assumption. Historically, for purposes of its natural gas price forecasts, EIA – like many other forecasters -- has prepared its forecasts based upon an assumption of “typical” weather. To take this approach, however, reflects a profound misunderstanding of how the natural gas market functions in the U.S. and the risks facing end use customers – virtually guaranteeing that EIA’s price forecasts, on average, will significantly understate the price end use customers pay for natural gas.

Why? Because natural gas prices are extremely sensitive to weather, but the impact of weather on natural gas prices is not symmetrical. When extreme mild weather conditions occur – as occurred last winter – the market finds ways of reducing supply (e.g., shutting in production, burning natural gas in lieu of oil-fired or coal-fired generation). As a result, price declines tend to be temporary and modest. By contrast, when weather-related demand is high – as may well occur this winter – the market’s ability to adjust is more limited. Prices could spike to very high levels – and potentially stay at high levels for several annual cycles, unless there is intervening mild weather (as we also may learn soon).

If we have learned anything in the past few years, therefore, it should be that events that put pressure on the system can lead to steep and last price spikes that can lead to huge cost increases.

By its choice of a simplifying methodology, however, EIA has simply factored these events out of the equation. In effect, it’s put itself in the same position as FEMA – planning for the possibility of Category 3 Hurricane striking New Orleans, but willfully ignoring the potential consequences of a Category 4 or Category 5 events, even though it’s these events that will cause the greatest harm.

This doesn’t mean, of course, that natural gas price forecasts should be developed on the assumption that weather conditions always will be extreme – or that the extremes will necessarily be unfavorable. (To the contrary, it is only a successive of three very mild winters, back-to-back-to-back that has kept natural gas prices from exploding to even higher levels over the past 3 years.)

It does mean, however, that: (i) potential natural gas demand and potential future prices cannot be properly assessed without looking at a wide range of scenarios (both favorable and unfavorable): and (ii) any such examination is likely to show the potential risk of much higher prices, potentially over sustained, several year periods than EIA projects using its current methodology.

3. Assumption of “normal” availability of non-gas fired generating capacity. EIA then compounds its error with respect to the weather by assuming the same level of hydro availability that will occur in climatologically normal years, and assuming high availability for nuclear generating capacity. In the past decade, however, “normal” hydro availability has been rare (this year is the exception); using this assumption, therefore, significantly biases EIA’s forecast. Further, while we certainly can hope for continued strong (i.e., in recent years, near perfect) performance from this nation’s nuclear fleet, as existing plants continue to age, this assumption becomes increasingly problematic, and the potential for at least some early retirements (not factored into EIA’s analysis) becomes an increasingly significant risk.

These are huge factors, which during the next decade could easily add 500 Bcf/year to power sector demand for natural gas in some years.

4. Restriction to examining only a limited range of oil price scenarios/failure to consider link between oil prices and availability of LNG. EIA further compounds the errors in its analysis by examining only a narrow range of potential future oil price scenarios. There is a direct link, however, between higher oil prices and increased demand for natural gas, and potentially between high oil prices and reduced availability of LNG. Failing to consider these factors, therefore, seriously distorts EIA’s analysis.

Cumulatively, the affect of these factors is to vastly understate the potential future natural gas requirements of the U.S. economy. Even in a normal weather scenario, by 2025, the total amount of natural gas required to meet the needs of the U.S. economy would be likely to increase by an additional 2 to 5 Tcf/year:

Potential EIA Underestimate of Future Natural Gas Needed by U.S. Economy

In years in which weather conditions are unfavorable, or in scenarios in which nuclear generation declines, or any of a number of EIA’s other assumptions prove to be invalid, this shortfall could easily increase by still another 2 to 4 Tcf/year.

EIA’s estimate of the amount of natural gas that is likely to be needed by the U.S. economy in future years, therefore, is profoundly flawed. Unfortunately, these errors – as serious as they may be – are not necessarily the most serious deficiency in EIA’s assessment of future supply and demand. Instead, as we’ll discuss in Part III, if anything, the errors in EIA’s estimate of the supplies that are likely to be available to the U.S. market in future years are even more severe.

Authored By:
For any questions, comments or reactions, please don’t hesitate to contact Andy Weissman directly at or 202-589-2391. Visit our new web site at

Other Posts by: Andrew Weissman

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January, 02 2007

Ferdinand E. Banks says


I don't know what the situation is in the US these days, but in Sweden envy of any kind of excellence has now reached the fever stage. Fortunately I'm not Swedish, because if I were I would be throwing fits over these wonderful papers of yours. As soon as I give my next lectures on oil I intend to dive into your work, and do whatever I can to help it to attain the circulation it deserves. (That may not be much though given certain personality shortcomings on my part.)

About the EIA. They have an agenda to sell which, to my way of thinking, belongs in a video clip. Namely, they are trying to convince somebody, somewhere that actually there is plenty of oil and gas, and so they should sell whatever is available at bargain basement prices. Since I am on the buy side of the market, and have absolutely no association with the folks on the other side, I have nothing against this 'strategy', however it doesn't work any longer. Of course, certain ignoramuses in Sweden still think that they can shut down the nuclear sector because eventually it can be replaced with gas and wind, and so every chance I get I try to explain that this is nutty. They don't listen to me, but I don't mind since I enjoy talking to myself, and if I were them I might not listen to me either.

By the way, I hope that the discussion below sticks to gas, because in the previous one - when the talk moved from gas into some looney-tune speculation on monte carlo methods - I was forced to reach for the aspirin.

January, 02 2007

Jim Beyer says

Another great article and with it, a great deal of good information.

And I second Banks' comment to stay on topic.

I want to ask a basic question, however. If the EIA is so chronically bad about predicting NG prices, then wouldn't major users already know this and obtain better estimates from other sources? I'd think a major company like Archer-Daniels (for example, just pulled out of thin air) would note how much NG use affects their bottom line and either obtain better estimates from outsiders or even hire analysts to figure this out for themselves. I know that fertilizer production has basically pulled up stakes in the U.S. and moved out, because NG is too expensive. Obviously, they were not relying on EIA estimates for their business decisions.

The DOE is also known for advocating the hydrogen economy, which has been widely debunked by several sources, including writers of EnergyPulse, but also the American Physical Society and the National Academies of Sciences (sort of).

If you are saying that we are rudderless with respect to energy policy in the U.S., then I agree with you. If you are saying that this should be surprising, then I also agree with you. If you are saying this IS surprising, then I respectfully disagree. A few years ago, I'd would've been surprised, but no longer.

January, 02 2007

Len Gould says

Another excellent article. One factor which I don't see in your list of factors which can affect the price of gas is the value of the $US. As much as all forms of energy can be linked to the price of crude (which I think will increasingly happen in future), and the price of crude in the US is set on competitive world markets, the price of gas in the US should be heavily exposed to sharp increases in future as the $US adjusts further to current trade imbalances.

January, 02 2007

James Carson says

<< By the way, I hope that the discussion below sticks to gas, because in the previous one - when the talk moved from gas into some looney-tune speculation on monte carlo methods - I was forced to reach for the aspirin. >>

1> YOU moved it there in a failed attempt to discredit me. Hypocrite.

2> The discussion had long diverged from gas before I joined the fray.

3> I quite agree that we should stay on topic.

Mr. Weissman, I do have a question. Daniel Yergin has for some time been saying that we have plenty of oil and gas for the next two decades. Where would you fault his analysis? Please note that I am not necessarily in agreement with Yergin.

January, 02 2007

Jose Antonio Vanderhorst-Silverio says

James said, "My intention is not to convince Professor Banks… is to challenge his assertions with which I disagree. Thousands of people read these forums, and I think it is a bad idea for them to get the impression that… Banks reflects the prevailing consensus. Frankly, I expected a more spirited clash. He merely makes pronouncements with little support and fails to respond to my rejoinders."

As I will show, readers can reverse Banks and Carson’s names without any loss of generality. That shows that Jim opinion does not reflect the prevailing consensus either.” Bad ideas “must be killed, the sooner the better.”

After working for 30 years at FPC and at FERC, Jack Duckworth – a professional engineer, not a politician - predicted the 14th August Blackout in the very illuminating article The Fatal Flaw in Electric Power Deregulation. Mr. Duckworth said that “[D]eregulation can work, but it will not work unless those overseeing the deregulation initiative recognize the inherent flaw and install a mechanism that will fill the gap by guaranteeing the availability of electric power without guaranteeing the price.”

As a mechanism, he said: “When I saw in 2001 that the market was failing to ensure adequate generating reserve margins, I proposed in my book, Power to the People, that the government put national rules in place that would require any power generating company to maintain a set reserve generating capacity margin as a condition of doing business. Such a mandatory reserve margin would ensure that there could never be a disastrous shortage of supply that could blackout an entire electric power supply region. It would also ensure a level field for all competing generating companies.”

This is what Jim, the practical analyst, advised to all readers of EnergyPulse on Feb 18, 2003:

Sorry, I did not find this article at all illuminating.

The principal objection appears to be that reliability is not considered in the market price of power, and cannot be. This is true, as far as it goes. However, there are several market mechanisms that have been developed that specifically address this.

First, capacity. It is not perfect, but it does work after a fashion. More work must be done to improve this mechanism.

Seond, spinning reserve markets are already functioning in PJM and, I believe, ERCOT. So far, so good on these efforts. The notion that electricity is somehow 'different' from other commodities must be killed, the sooner the better. One could make the similar points about wheat and natural gas. Indeed, the histories of both of those commodities are replete with similar concerns.

Power as a commodity is distinguished by two 'interesting' features, both of which contribute to its incredible volatility. First, with a few exceptions, power cannot be stored. However, now that we have functioning markets, we can measure the value of storage. I have already worked on one project that required an estimate of the value of storage.

Second, the elasticity of the demand curve at any particular moment for power is essentially zero. That is, a marginal change in price produces no change whatsoever in demand. Even a large change in price produces no change in demand. That is why the marketplace is working so hard on 'demand side' management programs. Again, the market is responding, albeit slowly.

James Carson

January, 02 2007

Jose Antonio Vanderhorst-Silverio says

Jim, remember that you are not your opinion.

January, 02 2007

James Carson says

Please refrain from posting non-gas related responses on THIS discussion as has been requested.

January, 03 2007

Roger Arnold says

Uhm, moving right along...

Regarding the need to "reduce U.S. dependence upon natural gas as a fuel to generate electricity", I'll point out something that I've said before, and will no doubt have ocassion to say again: generating power is by no means the worst way to employ natural gas.

With new CC gas turbines getting 60% thermal efficiency, and SOFC-CT hybrids promising as much as 80% in the near future, using natural gas for power generation looks sweet. What really sucks is squandering it for low-grade space heating--the sacred residential home heating market.

At a minimum, if you're going to use gas for space heating, at least run fuel cells or small generator with it first. There will be plenty of waste heat left over for space heating. Oh, and use thermal energy storage, so that power generation and heating are decoupled. That allows the generator to be run when power is needed, independent of when heat is needed.

I understand that in Denmark, distributed CHP with thermal storage is fairly widespread. I don't know if all of those DG systems are tied in to an information system that allows them to respond to electrical demand, but if they were it would sure be a great way to accommodate all that wind power that they produce.

January, 03 2007

Ferdinand E. Banks says

"all that wind power" you say Roger. That's funny, I recently got the idea that the Danes are tired of claiming how great wind power is, altough you probably won't hear any really loud noises from them as long as their economy is doing as well as it is now.

January, 03 2007

Len Gould says

Roger: Your comment on "--the sacred residential home heating market" is right on. Gas industry participants should be agressively pursuing systems like home CHP and the metering required for it to be successful, as a means to optimize production and therefore income from the must-serve baseload of home space and water heating. And incidentally, the strategy also makes a neat way to directly compete with the electrical utilities for the customer's utility dollar.

January, 03 2007

Todd McKissick says

Hey Len. That sounds like a neat idea. Why hasn't it been thought of before? I bet you could use solar thermal collection to displace most of the gas needed. On top of that, the generation (or DR from the grid standpoint) could be called for in sync with the grid peak, but that would require smart meters which is a different article.

I wonder what kind of aggregate reduction in gas demand that could attain if it became cost competitive.

January, 03 2007

Jim Beyer says

(not really disagreeing with Len or Roger)

Roger makes a good point (though for some reason, kind of painful to hear -- we can't even afford to heat ourselves now).

But would combined cycle gas turbines really be better than CHP in residences? I don't see how it could. CHP NOW can get 90% utility of the the fuel (25% electricity, rest as heat). And that's with not too expensive diesel IC engines. SOFCs probably would make even better sense in a residence, and could play a part in thermal storage as well. Since solar can't do everything (or even very much in the cold of winter) then some kind of fuel needs to be burned. It might as well perform CHP, so I don't see large scale ng turbines making much sense.

But for CHP to be deployed, we gotta get our metering ducks in a row (see Roger's articles). It seems to come back to that again and again.

In Michigan, we don't have much gas-generated electricity (mostly coal) , but we do use NG for heating. And respectfully, I think residential space heating is kind of sacred. Last year in Detroit, some people (many of them diabetics) had to choose between fuel and medicine, and a number of them died. Unlike gasoline, heating fuel is something that you can't avoid by taking the bus.

The answer, of course, is more solar heating (if only to help in Spring and Fall) as well as more insulation. And even new construction. Easy to say, but hard to accomplish for a lot of people. If it was all so easy, we could just wave a wand and fix everything.

A chemical engineer (who moved his plants overseas due to the high price of NG) said exactly the opposite of Roger: "I can't believe you are using it to generate power." He'd rather use it to make high-valued chemical products. I guess I can see all points of view. Heating is probably the worst (but way convenient -- Have you ever dealt with a leaking heating oil tank? Yuck!) , power generation is second worst, something else (like making fertilizer) is probably better. But if one is concerned about GHG, what are the alternatives?

CHP seems to be the least intrusive change that addresses our new realities.

January, 03 2007

Jose Antonio Vanderhorst-Silverio says

Andy had said: “This is the first of a four part series of articles on the natural gas and electricity price and supply risks facing the U.S. economy.”

The topic is: natural gas and electricity price and supply risks.

Electric power market architecture and design is right at the center of the topic. Two generic electricity systems models have been implemented: Model 1: old vertical integration controlled market and Model 2: faulty deregulation, based on open transmission access and “native” loads.

As an emergent system is Model 3: electricity without price controls. Since Model 1 and Model 2 have barriers on the development of the resources of the demand side that are being addressed on a piecemeal basis. Model 3 is based on an integral development of the resources of the demand side.

As gas prices rise, in Model 1 gas price volatility are transferred to the electricity price volatility; in Model 2 gas prices volatility are amplified into higher volatility to the electricity prices; and in Model 3 gas price volatility is mitigated into less volatile electricity prices.

Physical supply side risk management of Model 1 was not fully transfer to Model 2, making it unstable under shocks conditions. Model 3 has both supply side and demand side physical risk management. Demand price elasticity development barriers under Model 1 and 2 are fully eliminated under Model 3.

Model 2 incredible volatility is a flaw that goes against electricity as a commodity. The flaw is the lack of ultraquality. McKinsey has an article on electricity as a special commodity.

The key suggestion to develop a generative dialogue is thus right on the topic. The decade old debate around Model 1 and Model 2 is no longer necessary.

By developing two or three plausible scenarios, one of which is the “continuity” scenario, my opinion is that Model 3 will result as a predetermine element – fits on any of the scenarios. Model 1 will only be on the “continuity scenario”. On the “playing with fire” scenario Model 2 won’t cut it, while Model 3 is the best to face the severity of the crisis. Piecemeal changes to Model 2 towards Model 3 will make it very inefficient.

The adoption of a comprehensive national energy strategy should be based on a generative dialogue, including strategic conversations around the scenarios and system dynamic runs that include all the mental models of the interested parties. Major changes to the existing U.S. energy infrastructure, with the wrong market architecture and design is nothing more than playing with fire. Andy’s contribution is a welcome input to such strategy.

For some more details read the following recent posts:

EWPC: People Coordinating and Cooperating with Electrons Part 4

EWPC: People Coordinating and Cooperating with Electrons Part 3

EWPC: People Coordinating and Cooperating with Electrons Part 2

EWPC: People Coordinating and Cooperating with Electrons

© 2007. José Antonio Vanderhorst-Silverio, Ph.D.

January, 03 2007

Jim Beyer says

I really don't think electricity prices are strongly tied to NG prices. I think there is something rather Californian about that way of thinking, because in the rest of the country, about 70% percent of electricity is generated from coal and much of the remainder from nuclear.

I won't dispute the problems with using coal w.r.t. GHG emissions, but in the short term, a shortage of NG shouldn't raise electricity prices too much -- at least not in California.

January, 03 2007

Jose Antonio Vanderhorst-Silverio says

Mr. Beyer,

As far as I understand, under Model 2, prices reflect the marginal plants costs, not the base load units costs; under Model 1, the usual mechanism is to transfer energy costs increases to the customer or the tax payer with a time delay. The timing is for a comprehensive national energy strategy.

As for your suggestions of the development of CHP, Model 1 and 2 are biased againt the development of the resources of the demand side.

January, 03 2007

James Carson says

<< In Michigan, we don't have much gas-generated electricity (mostly coal) , but we do use NG for heating. And respectfully, I think residential space heating is kind of sacred. >>

Being from Minnesota, I quite agree!!!!

<< I really don't think electricity prices are strongly tied to NG prices. >>

I disagree. The key to understanding the role of NG in driving power prices is NOT how much energy is produced from which fuel source, nor is it how much capacity is available by fuel source. The key is HOW OFTEN during the day is NG fueling the marginal unit in the dispatch queue. You will find that NG is the marginal fuel the vast majority of the time during peak hours, and often during non-peak hours. Since variations in weather are the principal determinant of variations in load, variations in weather conditions become the principal driver determining which NG unit in the dispatch queue is selected on the margin.

In my view, the primary driver of forward electricity prices is the price of natural gas, along with weather normals. Inside two weeks, deviations from weather normals become increasingly important.

January, 03 2007

Jose Antonio Vanderhorst-Silverio says

James says: “I disagree that your discussion of power market design is pertinent to the natgas discussion.”

January, 04 2007

Roger Arnold says

Len has the right terminology for residential heating; it is a "must serve" baseload. The situation of people being constrained to choose between heating fuel and medicine is an outrage. However, it's the symptom of a much deeper problem than anything we are going to be able to address in our discussions of DG, CHP, variable metering, etc.

The scary thing about about the existence of so much poverty is that it's a sucking vortex. It hangs on to those who have slipped into it, and threatens to pull in anyone who drifts too close. Burning natural gas for low grade heat is a terrible waste of a high-grade fuel, but it's the cheapest solution available, for those who can't afford the cost of a heat pump, or even decent insulation. Never mind that good insulation and high-quality solar heating could save them money, in the long term. When you can't afford the up-front costs, there is no long term.

January, 04 2007

Roger Arnold says

Jim, the reason that CCGT is better than residential CHP is called "summer". One does not want a mix of 25% power / 75% heat when there is no use for the heat.

It's possible, with a little more elaborate system, to turn some of that waste heat into cooling via absorption cooling units, but the efficiency is not great. Even with absorbtion cooling, the net fuel usage of the CHP approach would be more than double that of CCGT + conventional AC.

January, 04 2007

Len Gould says

Roger: Such a sweeping statement as "CCGT is better than residential CHP" assuredly need a few qualifiers such as "1) provided the CCGT has at least a 20% efficiency advantage over the CHP units" and "2) depending on the climate in question", among others.

eg. if the climate in question is a mixed heating and cooling environment, a 35% mechanical efficiency gas-fueled engine directly driving a ground source heat pump compressor in summer and recovering waste heat as well as pumped heat in winter will dramatically outperform your CCGT. Direct drive eliminates at least a 10% electrical-to-mechanical comversion loss, distributed eliminates a(n up to) 10% transmission loss. Add a generator to the drivetrain and enough digital intelligence to manage the unit properly ...... and surely with technologies such as HCCI, digital valves, direct gasoeus injection etc. etc. 35% in a fixed-rpm small engine is more easily achievable than some of the present targets for (heavily federally subsidized) turbine research projects? Or put a relatively tiny amount of research money into a Stirling design I know of and it'll give you significantly higher efficiencies than that from a silent, very low maintenance, 100,000 hr engine with no exotic materials.

Naturally I realize it will have to be a Japanese company with enough forsight to develop such a system. Too bad everybody's so sure of their truths.

January, 04 2007

Jim Beyer says

Ugh. Some conversions here.

One MMBTU of natural gas is roughly $8-12.00 and contains 293 kwh of energy. Of course, you can't get all that into electricity, but depending on the conversion rate (25%, 50%, 60%) we'd have 73 kwh-e(25%), 146 kwh-e(50%), or 176 kwh-e(60%).

Natural gas is sold in 100 cf units, 10 of which roughly make 1 MMBTU. My old leaky house can use up to 3 ccf per day in the winter, so that would be about 3 MMBTU per month. If I instead took this as electricity, I'd need to use 219, 438, or 528 kilowatt-hours per month, depending on the efficiency of conversion. That is very high -- I don't think I ever use more than 200-300 kw-hrs per month, even in the summer.

The point I'm trying to make here (in a vague, general way) is that much more energy seems to be put into heating residences than electrifying them, at least for places that need to heat them occasionally. And for the rest of you all, if you are using an electric hot water heater, then you are using perhaps 300-400 kwh-e per month just for that.

And if you take all the residential electric loads devoted to heating, hot water heating, cooling, and refrigeration, you'd probably be talking about the majority of your electrical use. According to the EIA (har, har...) end use consumption chart, of the total residential electricity use, 13.7% goes to refrigeration, 16% to A/C, 10.1% to heating, 9.1 to water heating, and 5.8% to clothes drying. That's a total of 54.7% of our electrical load devoted to heating or cooling stuff. More than half. And that does not include the oil and gas used to heat homes and run nat. gas hot water heaters, and nat. gas dryers. So the overall heating/cooling load for residences is quite high, much higher than our pure electrical load. (Check out )

So, I think that Len makes sense that the role of CHP needs to be qualified a bit. What size system at what efficiency and at what cost would make sense in a certain proportion of residences? Even discounting the inherent benefits of distributed generation noted by Len above, there is at least some role for CHP to play, in theory.

For example, what if one had a tiny CHP unit that only ran if you needed hot water, so then it might produce, say 200 kwhrs equivalent of heat per month. Give it a poor efficiency of 15% (because it has to be cheap), then the unit would use 235 kwhr of fuel and produce about 35 kwhr-e (electricity) per month. Even at $12 per MMBTU, this equates to only about 4 cents per kw-hr. Not too bad. (You get to apply the 100% conversion efficiency because you'd be making the heat anyway.)

So, I guess the main point I'd make to Roger is that there DOES seem to be a use for the heat. For space heating, for clothes drying, for hot water heating. Because CHP is competing against such a low quality energy need, it seems that almost any kind of configuration could produce benefits. And the grid would benefit from these additional electricity sources as well, provided it can be configured to receive them.

January, 04 2007

Jose Antonio Vanderhorst-Silverio says

For those of you interested on the generative dialogue of Part I of this series, please go to the following posts:

A Generative Dialogue Without Illusions Part 7 A Generative Dialogue Without Illusions Part 8 A Generative Dialogue Without Illusions Part 9

Part 7 is the main post and the others are support posts.

Thanks, José Antonio Vanderhorst-Silverio, Ph.D.

January, 04 2007

Todd McKissick says

Roger, Great articles. The way the comment have gone, I'm curious of the next topic. Regarding your statements:


These show a split in the goals of two different groups tackling the problem from different directions. One side has no problem hooking up to the centralized life support and forever trusting that it will always be there, while the other side thinks it's only ok as a necessary evil on path to a better way. Being from Nebraska, I see local news about thousands of people in neighboring towns without power. Last night a power company rep refused to commit to power being up in a couple months. This is not a good situation in January in NE. There's a couple thousand people held up in a school in one town and the school doesn't even have power. My point here is that if viable alternatives had existed for them, there's a good chance that some would still have power and would now be hosting a party.

The alternatives mentioned above all tend to have one thing in common - They can be made to stand alone. I saw one guy being interviewed that had a brand new wood stove that doesn't work without electricity. This is the type of problems we've been headed for for decades under the control of money centric conglomerates. IMHO, the discussion needs to address all options comprehensively. Some people want DG. Some want DR. Still others want AMR, TOU, CHP, heat pump control or them all together with solar assist. We all know the electronics cost isn't the problem on a scale being discussed. (except for a few power SCRs) The problem is the continued support of the past paradigm of a few deciding for the whole.

I predict that as soon as an area installs a large base of meters with all these capabilities, the market will begin to change on it's own. The reason? Getting back to your comment, it's because these devices and options will finally begin to be classified as a part of the residence. Why can't an electricity generator, solar collector, or CHP heat recovery unit be included. Why is is just blindly accepted that we have to buy electricity, etc. each month? Every house purchase contains a purchase of a furnace, water heater and A/C (if equipped). Let's combine some of these systems, add a heat pump, add heat and/or cold storage tank and possibly some renewable source that works for that site. That way, once their house is paid off, so are these pieces of equipment, just like today's furnace.

January, 04 2007

Todd McKissick says

Hmm... my quoted lines disappeared. Second try....

"The situation of people being constrained to choose between heating fuel and medicine is an outrage. However, it's the symptom of a much deeper problem than anything we are going to be able to address in our discussions of DG, CHP, variable metering, etc."

"Burning natural gas for low grade heat is a terrible waste of a high-grade fuel, but it's the cheapest solution available, for those who can't afford the cost of a heat pump, or even decent insulation. Never mind that good insulation and high-quality solar heating could save them money, in the long term. When you can't afford the up-front costs, there is no long term."

January, 04 2007

James Hopf says

Concerning using natural gas (CCGT) for baseload power generation, I’m afraid this is one point where I have to respectfully disagree with Roger. Despite its efficiency, this is something that simply has to stop, for the many reasons given above in Mr. Weissman’s article. We shouldn’t be using an expensive, limited and depleting, imported (from the Middle East) fuel for baseload power when far cheaper, domestic, abundant, and in most cases cleaner (e.g., nuclear and renewable) alternatives clearly exist. IGCC coal is also preferable. Gas vs. dirty, conventional coal? Tough call. For other gas-based applications, including space heating, it is far less clear that alternatives are readily available, although heat pumps should definitely be looked at. Getting more out of gas that will be used anyway (e.g., CHP applications) should also definitely be looked at. But large, centralized baseload power generation using gas has simply gotta go, and be replaced with nuclear, coal and renewables.

Mr. Carson made reference to the fact that, under a market system, gas plants will set the market price of power during all hours of the day when they operate. Two things result from this. First, building gas plants (vs. more capital-intensive baseload plant types) is less financially risky for the utility, since no matter how high the price of gas goes, the cost will just be passed along to the consumer (as the market price will go up accordingly). Meanwhile, the up-front capital costs and construction time are low. The cost of generating power, and the charged price, is much more volatile, but the economic risk to the utility is actually lower. As far as what’s good for the consumer, as well as the nation as a whole, on the other hand…..

Second, for a utility that has a large amount of existing coal or nuclear capacity, adding enough gas plants so that they are the incremental supplier for most (or all) hours of the day will greatly increase profits under a market system. In fact, an increase in gas price will actually increase profits, as the costs of the gas plant are simply passed to the consumer, and the spread between the coal/nuclear plants and the market price increases.

Thus, under the market system, utilities (and their investors) have little incentive to build new plants in general, and very little incentive to build non-gas plants. They also have an incentive to keep old, ultra-dirty coal plants running as long as possible. Both of these practices that are encouraged by the “free market” (building gas plants and keeping old coal plants open forever) are very much against the interests of the public, ratepayers, and the nation. These are the main problems with the free power market (i.e., deregulation) as I see it.

Applying external costs by taxing or limiting CO2 emissions, air pollution and foreign gas/oil imports would help solve the problem, especially concerning coal. Even these measures may not curb the desire to build only gas plants, however, for the reasons I give above. Anything that adds to the cost of gas-fired power may actually increase the utilities incentive to build them. Some type of policy that protects the interests of the consumer must be applied. Right now, I’m partial to resurrecting the Fuel Use Act. I’ll bet Mr. Weissman would agree. The old rate base system doesn’t look bad either.

January, 04 2007

James Carson says

<< Mr. Carson made reference to the fact that, under a market system, gas plants will set the market price of power during all hours of the day when they operate. >>


<< Two things result from this. First, building gas plants (vs. more capital-intensive baseload plant types) is less financially risky for the utility, since no matter how high the price of gas goes, the cost will just be passed along to the consumer (as the market price will go up accordingly). >>

On the contrary, because the natgas units receive only their marginal costs, or just a bit more, they are almost certain to lose money as long as long as there is excess capacity in the region. I guess a certain loss entails less risk, but don't think that is not what you meant.

<< As far as what’s good for the consumer, as well as the nation as a whole, on the other hand... >>

Imo, arriving at an economically efficient fleet compostion and use patterns is very good for both consumers and the nation.

<< for a utility that has a large amount of existing coal or nuclear capacity, adding enough gas plants so that they are the incremental supplier for most (or all) hours of the day will greatly increase profits under a market system. >>

They don't have to own or build so much as one megawatt of natgas capacity to reap those profits. Moreover, wouldn't such a situation drive the market to build more coal and nuclear, if that kind of capacity were so profitable? Isn't that what's happening right now?

<< Thus, under the market system, utilities (and their investors) have little incentive to build new plants in general, and very little incentive to build non-gas plants. >>

Why, then, did we just undergo the largest capacity building spree in history? Why are we now drenched in EXCESS capacity?? Why are utilities making numerous applications to build coal plants? Why is nuclear suddenly back under discussion?

<< They also have an incentive to keep old, ultra-dirty coal plants running as long as possible. >>

That is true, as far as it goes. However, there is ALSO an incentive, AND sufficient cash flow, for regulators to insist that coal burners implement clean technologies, which is exactly what is happening.

<< Applying external costs by taxing or limiting CO2 emissions, air pollution and foreign gas/oil imports would help solve the problem, especially concerning coal. >>

Those public policy moves would guarantee that all new capacity would be natgas. Well... unless you believe that wind power will save the day.

January, 05 2007

Len Gould says

James Hopf: << for a utility that has a large amount of existing coal or nuclear capacity, adding enough gas plants so that they are the incremental supplier for most (or all) hours of the day will greatly increase profits under a market system. >>

James Carson: <>

Jim H makes a very valid and clear point here, which is not rebutted by James C. Every participant operating under the currrent "de-regulated" standard market have a huge incentive to ensure that whoever sets the marginal price-to-pay sets it as high as possible, eg. with simple turbine peakers etc., and I see no way for normal competitive market forces to change that. Any group analysing a given location for possible construction of a low-cost baseload addition which finds that the primary result of the build will be reducing the hours in a day when the market price is set to eg. $0.15 by gas peakers from eg. 12 to 4 will definitely need to re-evaluate the economics of the decision to build, especially if they happen also to be the owners of other baseload generation in the territory. That's just ECON101.

That's the problem I was trying to address in my article on market design by having the market manager (as an agent of the customers) sign fair fixed long-term contracts possibly with loans guaranteed by the public to keep interest down, for baseload, which would then be purchased by the market manager at eg. $0.06 / kwh per contract and re-sold into the market at eg. whatever the peak price might be as set by the market operating as usual on 15 minute intervals, BUT with the market manager then using the resulting gain mainly to reward customers who can manage their peak usage in a way that levels off the peaks. And in that case it is not rational to then allow the market manager to also own any generation themselves, as the question of fair bidding on new plant installs could never be resolved. Which is why I excluded the existing utility companies from acting as market manager, assuming they would prefer to own generation.

January, 05 2007

Jose Antonio Vanderhorst-Silverio says

Comments are invited under the generative dialogue about Demand Response Under EWPC , where I said, among other things, that "... the parallel discussion with Fred Banks, Len Gould, Arvid Hallén, and James Carson, seems to have ended in favor of my suggestion of the emergent conceptual architecture and design of Market 3, electricity without price controls for the customers (EWPC) approach."

January, 05 2007

James Carson says

<< Jim H makes a very valid and clear point here, which is not rebutted by James C. >>

I beg to differ. Jim H made the point that it would benefit a baseload heavy provider to build peakers so as to set the marginal price high, I pointed out that such an action would be pointless.

<< Every participant operating under the currrent "de-regulated" standard market have a huge incentive to ensure that whoever sets the marginal price-to-pay sets it as high as possible, eg. with simple turbine peakers etc., and I see no way for normal competitive market forces to change that. >>

If the baseload units are making so much money, then won't there be a powerful incentive to build more or uprate them? Isn't that exactly what has been happening?

<< Any group analysing a given location for possible construction of a low-cost baseload addition which finds that the primary result of the build will be reducing the hours in a day when the market price is set to eg. $0.15 by gas peakers from eg. 12 to 4 will definitely need to re-evaluate the economics of the decision to build, especially if they happen also to be the owners of other baseload generation in the territory. That's just ECON101. >>

Of course.... Every new market entrant must assess the impact that their own entry will make on the margin in that market REGARDLESS OF THE MARKET. A large baseload unit is not going to simply affect market pricing in a tightly restricted area, it is going to affect hundreds, maybe thousands, of LMPs over a wide area.

<< BUT with the market manager then using the resulting gain mainly to reward customers who can manage their peak usage in a way that levels off the peaks. >>

Why don't we just let the market 'reward' customers? Isn't THAT just Econ101?

January, 06 2007

Len Gould says

Fails to convince, James.

January, 06 2007

Len Gould says

It's something that I've known intuitively all along, but am just coming to clarity on the details now. The real problem with de-regulation as currently advocated variously in North America is the LMP pricing model. The justification for LMP pricing is "aure it often pays far too much to the large low-cost baseload generators, but those plants will have that added value built in to their capital value as they are bought and sold on the open market, so the shareholders who own the plants will have paid such a high price for the plant that they will not be making an unusually/unfairly high return on their investment."

LMP practiced as designed essentially makes the capital value of generating assets fluctuate according to the aggregate of the marginal costs of the price-setting generating plant(s) in its region at the particular time it is valued, and the value bears almost no relationship to the capital cost or operating cost of the plant. That logic still works fairly well if the costs of the marginal plants are fairly stable BUT (and here's the tie-in to Andrew's article) when huge supply uncertainties and/or shortages affect the fuel costs of the fuel-cost-intensive marginal price-setting plants, as we are seeing now in Natural Gas and apparently will see more of in future, it becomes impossible to establish with sufficient certainty for long-term investors what the capital value of a new baseload asset might be EXCEPT by paying them exhorbitant risk premiums.

Those exhorbitant risk premiums are the first reason I dislike the LMP market. Second is the huge un-earned rise in asset value for the low-cost baseload owners when LMP is first implemented. eg. why should the owners of the long-paid-off Niagra Hydro station, happy to generate profitably at $0.025 / kwh suddenly find themselves selling much of their power at the price where a simple low-efficiency gas turbine generator buying his fuel in a rising market, can make a profit operating only part of the time? It's a huge arbitrary re-evaluation of generating assets resulting in a huge cash windfall for the lucky owners of the baseload assets, financed on the backs of the average customers.

Proposing middleman "retailers" as Jose Antonio does, who hedge their customers with longer-term "bets" in the market (as was for some reason barred in California) can potentially address some of these issues, but only by shielding the customer from market realities such as the costs / benefits of on-peak consumption vs. load-shifting to off-peak, and CHP etc.

I simply don't see why LMP is a better market design than having every customer make specific 15 min contracts a day in advance with any of the individual generating entities capable of delivering to them, which is a real market and given a bit of technology will work just fine. And IF as some above argue, longer-term contracts exploiting the low credit risk of the taxpayer base to get preferred baseload built are not needed, then fine. But I'd still prefer to see that option made available, possibly by government legislation only.

See my coming article for more.

January, 06 2007

James Hopf says

I’ll expand/clarify some of my points in response to James C’s comments.

Under an “ideal” market system, the optimum (maximum profit) amount of gas generation would be just enough so that it is the incremental supplier most hours of the day, no more, no less. If there is less, then the market price would drop dramatically for the many hours of the day when coal (which has much lower variable costs) is the incremental supplier. On the other hand, increasing the amount of gas used when it is already the incremental supplier for most (or all) of the day simply raises overall generation costs w/o significantly raising the market price for power.

While existing coal and nuclear plants are indeed making large profits now, it only makes sense (i.e., increases profit) to build new coal/nuke plants if it does not prevent gas from being the incremental supplier a significant percentage of the time. In some parts of the country (such as the MidWest) there is “not enough” gas generation, whereas in places like the Southeast, there is “too much” gas generation. Not surprisingly, we are seeing a slew of proposals for new coal and nuclear plants in the Southeast (generally), whereas few if any such proposals are being pursued in areas like the MidWest. Apparently, the costs, inefficiencies and grid investments required to ship large amounts of power all over the country are too high, so there is this effort to “balance” the generation portfolio in all regions of the country, so that something close to the “optimum amount” of gas generation I refer to above is present in all regions.

Back in the day (the rate base day), utilities like ComED (Exelon) were proud of the fact that they didn’t use any gas or oil for power generation. Now you don’t hear much from them about building new nukes or coal plants. They are (quietly) content to just build gas plants for now, and their behavior is explained by the reasons given above. Note that Exelon just succeeded in Illinois in establishing a “power auction” (i.e., a free market) to set power prices. The prices will be set by gas plants, of course, and consumers can expect large price increases. Another side note that confirms the theory; Exelon seems to have lost its initial enthusiasm for building nuclear plants, at least in its home territory. But low and behold, they recently announced that they ARE interested in building new nukes in Texas. Hmmmmm…. (Remember, Texas has excess gas capacity.) Anyway, the reasons given above explain why coal and nuclear plants are indeed being built (as James asks) but only in some parts of the country, where they have “too much” gas for maximum profit.

Yes, the last incremental supplier will lose a small amount of money, as its fixed costs are not paid. That is something I never understood about the “pure” free market, i.e., how people would get paid for capital/fixed costs. The only way to survive would be to have a few high cost plants like simple turbines setting the market price (and taking a small, fixed loss on them) and making up for the loss on the margin enjoyed by existing baseload plants. Note, however, that if you had a capital intensive, non-gas plant whose overall (variable + non-variable) costs were the same as a gas plant, both would make, or lose, as much money on average, in a free market. But the risks would be higher for the non-gas plant, because the market price can be counted on to closely match the variable costs for the gas plant, which are almost all of its total costs. Thus, the net effect is an incentive to use gas, all other things being equal, and it increases the cost difference required in order to get people to build non-gas plants. The point I was trying to make (“what I meant”) was to show how under the free market gas plants are the lower risk option for the utility, even though they involve a more uncertain price (i.e., a higher risk for the consumers and for the nation). I was talking about risk, not cost.

January, 06 2007

James Hopf says

Concerning helpful policies,

Legislation limiting or taxing pollution, CO2 and energy imports might not encourage new gas plants. It depends on how serious the policies are (i.e., how serious we are) about limiting gas imports relative to limiting CO2 emissions. I didn’t say that the CO2 policy should necessarily be stronger than the gas import policy. Note that both nuclear and renewables have neither problem. Both the pollution and energy import policies would give them an advantage versus gas, and an even larger advantage versus, coal, especially non-IGCC coal. Depending on how the policies are structured and balances, an IGCC coal plant could have an advantage over a gas plant for baseload generation. Conventional coal? Let's hope not.

If what Mr. Weissman says is true, than gas will be so expensive that sources like nuclear, wind or IGCC will not even need such policies to beat gas. This maybe true already. Given the seriousness of the gas problem, however, it is annoying that other policies such as deregulation are having the unintended consequence of actually incentivizing the choice of gas. This is one aspect/effect of deregulation that cries out for some kind of fix.

I don’t believe that wind alone can do it all (i.e., “save the day”). I do believe, however, that a combination of nuclear, IGCC coal and various renewables can (and should) be used to replace gas, at least for baseload generation.

January, 06 2007

Jose Antonio Vanderhorst-Silverio says

Please be advised that today, before Len posted his last comment, I responded to Len's observations, under the article Demand Response Under EWPC Part 2, about his IMEUC proposal with a revised IMEUC retail to customer switchboard approach. The main reason is that his analogy of the gasoline market does not support his IMEUC wholesale to customer proposal, as gasoline stations are simply retailers that operate under competition just as suggested for EWPC.

If you read closely to the above message, Len is making up a distorted view of EWPC. The reason I perceive is that he now sees the LMP concept in the way of his wholesale to customer switchboard. LMP is the signal where supply meets demand at every location. Under Model 2, LMPs could be very high as transmission lines get congested without sufficient demand response close to the location.

Under Model 3, however, ultraquality long run system planning and design will aim to mitigate congestion with a mix of supply side and demand side resources. In general, LMP calculations before considering the demand side will signal the demand response needed. LMPs are part of the better designs possible. It is with the credibility that is inherent in long run ultraquality, not short run LMPs, that base load generators investments get built as they will get many dispatch hours during the lifetime. Technology obsolescence risk, however, should stay with the investors.

January, 07 2007

Ferdinand E. Banks says

In the classroom, working with cost and load curves, it is easy to get the 'merit order' correct, and so this business of 'too much' or 'too little' gas generation that James Hopf mentions does not come up. A problem appears in the real world because the load curves shift and the parameters of the cost curves can change, and often in a non-predictable way. I don't want to go into this too deeply however because after being called a hypocrite (= fraud or charlatan) because I said that ELECTRIC DEREGULATION HAS FAILED, IS FAILING OR WILL FAIL JUST ABOUT EVERYWHERE, I notice that I have become very sensitive. Perhaps too sensitive for macho forums like this.

January, 07 2007

Jose Antonio Vanderhorst-Silverio says


There is a difference between classroom perfect competition and real life workable competition.

To operate in real life there is a need for a robust power system, where the resources of the demand side and the resources of the supply side are available to manage systemic short run and long run physical risk in time and space.

The T&D grid should be integrated in every geographic - control - area and its operation and control planned and executed by a system engineering institution, with both supply side and demand side resources pre-committed.

There is an urgent need to develop the resources of the demand side. That development requires business model innovations which in turns require competition, as customers need will evolve in significant ways. A regulator is not prepared to do that job, since neat customer classes and rates will be insufficient to get the most value for society out of rationing electricity. The demand side is today highly undeveloped and to develop it true leadership – commercial retailers - will be required, to allow the workable competition that should be emerging in a complete, integral and fully functional Market 3.

Piece meal extensions to the incomplete, fractured and not fully functional Market 2 will maintain valid to your statement that “deregulation has failed, is failing or will fail just about everywhere.”

With T&D grid electric regulated under ultraquality and generation and commercial wholesale and retail deregulated, EWPC should not failed just about anywhere, if the commercial market architecture and design is properly implemented, under competent leadership and management.

January, 07 2007

Jose Antonio Vanderhorst-Silverio says

I’m adding “© 2007. José Antonio Vanderhorst-Silverio, Ph.D. to my last post.”

January, 07 2007

Ferdinand E. Banks says

Jose, I am strictly a classroom guy. In fact I'm more or less amazed to recall that when I was wearing my engineer's cap, I was able to design various shipboard things for the U.S. Navy. On the other hand, I am also a bottom line guy: Where electric deregulation is concerned, NO TINKERING WITH THE DEMAND SIDE CAN COMPENSATE FOR GAMING AND THE LACK OF INVESTMENT ON THE SUPPLY SIDE!

I sent a paper on oil to a gentleman who was once pointed out to me as an academic mover-and-shaker. He replied by telling me to get his name off my circulation list. What I did then was to make a few inquiries, and found out that he was some kind of advisor on deregulation (liberalization) to the authorities in China. Well, hopefully some day I will get a chance to repeat the anti electric- deregulation performance I gave in Hong Kong, where I think that I convinced just about everybody that electric deregulation HAS FAILED, IS FAILING OR WILL FAIL JUST ABOUT EVERYWHERE.

One more thing. During my best days as an engineer and engineering student, I doubt whether I was able to come close to the people who contribute to this forum, but when it comes to economics 101and electric deregulation, well... And on the basis of what has been going on in Europe, the natural gas is market is also going to be adjusted/manipulated to scam the consumers.

January, 07 2007

Jose Antonio Vanderhorst-Silverio says

Thanks Fred for your timely response. I guess you are right that "no tinkering with the demand side can compensate for gaming and lack of investment on the supply side" is highly likely under Model 2 and its piecemeal extensions.

To face gaming and lack of investment under EWPC there is an ultraquality requirement to be performed by a system engineering institution. The commercial activities of generation, and wholesale and retail of electricity to end-customers need to operate under a no-nonsense prudential regulation.

If the expert to the authorities in China is pushing Model 2 and its extensions, I also agree that your "anti-electric deregulation performance" statement is very likely to occur. If vertical integration – Model 1 – becomes the default solution, the little guy is bound to pay more for the investments than he should. The development of the resources of the demand side equity criterion - Market 3 - should lead to the effective development of the Chinese market at the bottom of the pyramid, which is the largest in the world.

Unless Northamerican, Chinesse and European leaders listen very closely to the first and second part of these comments, discussions, debates, and dialogues, they will certainly be playing with fire. My humble recommendation is that they retain a system architect expert on EWPC to help them coordinate a generative dialogue to come up with a new vision and develop a transition to EWPC. An expert on gas without price controls (GWPC) should no be difficult to develop in a parallel generative dialogue.

© 2007, José Antonio Vanderhorst-Silverio, Ph.D.

January, 08 2007

Len Gould says

Prof Banks: "In the classroom, working with cost and load curves, it is easy to get the 'merit order' correct"

Fully agreed, LMP will normally always dispatch the ideal mix of generation in the ideal order. Presuming that the ideal price to pay for an item is its total cost of production and delivery plus a sufficient markup to incent it's continued production in future, but no more, LMP will unavoidably very often significantly overpay especially the lowest cost generation at a node.

January, 08 2007

Jose Antonio Vanderhorst-Silverio says

Thanks Len for your insistence against LMPs.

What you intuitively think is "the ideal price" seems to me what a monopolist wants. It is completely wrong in a market where demand has elasticity.

There are a lot of risks involve for the generator under competition. Just one example suffices: if the generating unit is not available they need to pay somebody else the LMPs to cover for him, under Model 3.

In addition, LMPs are much lower when demand has enough price elasticity. In a robust supply and demand market there should no be very often significant overpayment, nor very often significant underpayment.

January, 08 2007

Len Gould says

Jose Antonio: In a node where baseload is comprised solely of eg. an IGCC coal plant with costs of eg. $0.06 / kwh and an old hydro facility with costs of eg. $0.02 / kwh, and both are always required to run 24 x 7 to satisfy baseload, The LMP price will never come below the eg. $0.07 bid by the IGCC plant, and that's what the hydo facility will also get paid 24 x 7, even though it may be consistently bidding in at $0.025. Presuming eg. the IGCC gen station is the lowest cost competitor which can be built under then-current pollution regulations, then the hydro plant winds up making a ridiculous profit simply from the market design. Many other conditions can also demonstrate this condition without resorting to pollution regs., eg. coal-rail-transport capacity, transmission approval difficulties, etc. etc.

It is also logical to propose than under LMP a region should experience a dramatic increase in difficulty getting approvals for new transmission lines.....

January, 08 2007

Jose Antonio Vanderhorst-Silverio says


Generating facilities are dispatched on their variable costs, not on average costs. Hydro facilities variable costs are nearly zero and those units are usually energy limited, but their new development costs are usually very high. In the US, old hydro developments expected benefits are already committed. The LMP price is relative to variable costs. Bidding systems of Model 2 are suspect, as they are in your proposal.

In order to make sense of the data it is not possible to do simply arithmetic calculations as you propose. It is necessary to simulate what the expected random LMP values are for a long over a long period of time. That depends on the probabilities of rainfall or the snow that is expected to fall and melt into the hydro plant. In addition, the power flows at a given node depend on the system as a whole at every moment.

If a region does not allow central or distributed generation, energy efficiency, and transmission development, they should know they will be playing with fire, not matter what the model is.

January, 08 2007

Len Gould says

"The LMP price is relative to variable costs. "

Unclear. eg. I think my discussion above is correct per

If so, how do you get to your statement?

January, 08 2007

Jose Antonio Vanderhorst-Silverio says

Sorry Len,

The document talks about marginal cost which are variable costs by definition. New hydro units can apparently make "a lot of money" at zero marginal costs, but they have to pay for the large fixed costs.

Just take a look at “Accounting Systems Interaction Glossary of Terms Assets The ...,” to see the definition: “marginal costs are variable costs which vary in direct proportion to the level of activity.”

January, 08 2007

Arvid Hallén says

James (Hopf),

I felt really glad to read your argument about "too much" or "too little" gas as it pretty much exactly mirrors what I have felt would be the way it would work when I have pondered these things in my ivory tower while I am trying to get hold of energy economics textbooks (remember I am just a humble student while almost everyone else here is a professional of one sort or another). :)

January, 08 2007

Ryan Ferris says

There are some straightforward simple solutions available now to the coming natural gas cataclysm:

(1) Shift heating to air-source or ground-source heat pumps (2) Shift electrical production to photovoltaics (3) Shift water heating to on-demand units with solar thermal as appropriate

I made the (1) and (3) this year. For the first six months of use (July-Dec) of the new HVAC = 140 therms. Last year for those same six months were 487 therms. I can cut that much lower as I like since my Carrier Infinity 16 heat pump will heat down to -5 F. Of course, my electrical usage is greater 4980 Kwh (2006) vs 3950 Kwh (2005) for the same six month period. I still save money since electrical is quite cheap in Bellingham, WA. (48th parallel) and we have need for lots of heat here.

Ultimately, the solution for electrical usage is photovoltaic cells which will also power my plug-in hybrid someday, thus solving the liquid fuel transportation crisis. An 8 - 11 Kwh array from Sun Power (Cypress Semiconductor) will do just fine when electricity starts to rise astronomically, which will be soon. Sun Power releases their 315 watt panels in Spring. 400 watt panels can't be far behind. Get them before the pure silicon supply runs out.

The trick is to suck the money out your house before that financial well drys up and spend it on heat pumps and photovoltaics. All the other stuff (e.g. new windows, doors, insulation, caulking, radiant barrier, solar attic fans...) that's a given...These solutions work for everyone. Homeowner, business, DoD. You just apply them or you are stuck on LIHEAP for the rest of your energy impoverished life. As the crisis continues to occur, consumers will get the message that decentralizing the production of heat and electricity is the media. Photovoltaics and Heat Pump technology is *very* local. They work, They are available now, They deconstruct the security risk of centralized energy production. And the technologies are improving quickly.

January, 09 2007

Ferdinand E. Banks says

It's not easy to argue in favor of Long Run Marginal Cost Pricing, but if I remember correctly, the excellent French colleagues did it all the time. The two points that were always brought up were stability of output prices, and recovering capital costs. What they probably meant was recovering them faster than they would have been recovered with SMC pricing, but in any event they were not particularly tolerant of opposing points of view.

January, 09 2007

Andrew Gill says

I'm puzzled by some earlier posters who say that residential gas heating is somehow "sacred" compared with industrial use. Surely most consumers can only pay their heating bills out of income, and that only comes from a thriving industry. So, industry buys all the gas it wants, and then pays its workers, who then bid for whatever gas is left over to heat the house.

What else can we do - heat the houses in winter and run the businesses in summer, like farmers? Not likely - return on investment would vanish and so would industry. And if gas price rises make another fuel competitive then I would expect industry to grab it first once again.

Gas also makes fertiliser and synthetics, and I suppose consumers will ultimately choose what that gas makes. Food, warm clothes, warm air - pick any two. On the plus side, we'll probably be able to buy a house in Minnesota for peanuts - is that why lousy heating within ten years is unthinkable to so many people?

January, 09 2007

Jose Antonio Vanderhorst-Silverio says

LRMC works when your have an adapted system. Things like congestion and price spikes make a lot of noise and the expected value of short run deviates a lot from long run values. To mitigate congestion and price spikes - both of which signal whole system risk of failure - ultraquality is needed based on both resources of the supply side and on the demand side.

The dimension of the demand side, however, is well undeveloped. So, EWPC innovation opportunities abound in the demand side, which definetly should include differentiated customers interruption costs, and not only the power bill in the rationing optimization. That is how the whole system - not its parts - is adapted to resolve both the stability of output prices and recovering of capital costs, by making the expected value of short run marginal costs get closer to the long run marginal costs.

January, 09 2007

Jim Beyer says

Andrew makes an interesting point that should be addressed.

I don't think residential heating, gas or otherwise, is sacred. It is, however, like the low cost of energy in general, assumptive. Our society, with its drafty homes, long commutes, and growing industry, has assumed an infinite source of consequence-free energy.

Fertilizer production has already shut down in the United States. On a practical level, it probably makes more sense now to have all our fertilzer made for us in Qatar or some other place. It's far easier to ship ammonia than it is to ship NG. Production of synthetics is likewise leaving North America for the same reason.

If low cost energy is assumptive to our industry, we can see why many corporations rail at the notion of limiting GHG. It's too expensive. If you stop and think, if the Bush administration has finally agreed that global warming is real, then it is probably REALLY BAD, maybe worse than we even know. But industry needs their cheap energy - long term consequences be damned.

Another assumption that industry needs (usually, like 99% of the time) is a GROWING market. Even though humanity is reaching or has already reached the population size that is sustainable for our planet. How can industry react to a stable population?

We all have assumptions we are in need of re-assessing. A few drafty homes in Minnesota are the least of our concerns.

January, 09 2007

Len Gould says

Jose Antonio: I think you're playing a game with me. No discussion of Locational Marginal Pricing at all in your reference, and I don't see how an accounting primer has any relevance.

Thanks Prof Banks:

All: "Under conditions of natural monopoly, private contracts or government regulation may attempt to avoid inefficiency by setting up a pricing formula. Once the capital stock is chosen, the right price to charge the buyer is marginal cost. But the point of this paper is that marginal-cost pricing provides the wrong incentives for the choice of the capital stock by the seller. If the seller can achieve a high price by deliberately under-investing and driving up marginal cost, there will be a systematic tendency toward too small a capital stock."

Hall, Robert E., "The Inefficiency of Marginal-Cost Pricing and The Apparent Rigidity of Prices" (May 1984). NBER Working Paper No. W1347. Available at SSRN SSRN Stanford

I think the concept here can be applied to electricity markets because at any locational node there very often exists a monopoly or at best a duopoly ON THE PARTICULAR TYPE OF GENERATION SETTING THE LMP PRICE MOST OF THE TIME AT A NODE. The point is that Natural Gas peakers don't directly compete with big continuous baseload nuclear reactors or coal units, they only compete with each other, so they shouldn't be in the same pricing calculation together.

January, 09 2007

Ferdinand E. Banks says

Interesting comment, Len, but let me add the following. Microeconomics books are filled from one cover to another about production and pricing, but what you don't find in those books are systematic discussions dealing with investment, although it's a simple matter to throw something together if you are discussing perfect competition. In this case, in a classroom situation, it probably makes sense to start with marginal cost pricing.

Electricity markets are not perfect competition markets, as you point out. They are monopolies or most likely duopolies. Duopolies are best handled using game theory, in which case the solution is the one that we see just about everywhere in the world, whether the players know game theory or not: invest as little as possible. Professor Bill Hogan is a very smart man, but when he visited the UK some years ago he expressed his surprise that deregulation did not bring about more investment. What's surprising about that - the game theorists in the nearest pub who had never opened a book on game theory could have told him that that was going to happen, given that duopolists prefer more money to less.

January, 09 2007

Jose Antonio Vanderhorst-Silverio says

Hi Fred and Len,

Good points Fred about what is known. As far I know, this is what is emerging with EWPC.

Part 1 of 2.

In what I posted today, when I said “To mitigate congestion and price spikes - both of which signal whole system risk of failure - ultraquality is needed based on both resources of the supply side and on the demand side,” should be sufficient to take care, together with no/nonsense prudential regulation, in disallowed that “the seller … achieve a high price by deliberately under-investing and driving up marginal cost…”

Electricity reform is a very complex problem and as such it can only be useful in a generative dialogue, where insights are placed on the right spot to solve the puzzle. On important insight about EWPC is emerging as central generation is being displaced from center stage.

In a post to both of you, on 11.23.06, under the article AMI Services Solutions for Alberta's Deregulated Market, by Nick Clark, I said:

Most electric power reforms are unstable. For example, European market liberalization will run into a wall if distribution is kept separate from transmission and let generators exercise and abuse market power. Market power is neutralized by keeping a T&D only wires monopoly that assures long run and short physical risk management. In the new paradigm center stage changes from generation to the T&D infrastructure.

The result will be a robust, complete and fully functional non-real time market that does not interferes with real time power system operation, as the T&D (engineering) system operator takes charge of committed resources on the supply and demand side… I like to see competing paradigms that are also emerging.

January, 09 2007

Jose Antonio Vanderhorst-Silverio says

Locational “marginal” prices come in many flavors. This is what the paper mentioned by Len says “LMP is still a new model and only time will definitively demonstrate its successes or failures. LMP will probably never be a perfect solution for all wholesale market concerns. It has its limitations. At this time, LMP is largely a supply-side focused approach to organized markets. Integration of demand-side factors to such issues as transmission congestion or generation shortages remains to be considered.

There is another flavor in the article Demand Response and the FERC Standard Market Design NOPR:

Demand Response, Locational Marginal Pricing, and Centralized Markets

In the proposed Standard Market Design (SMD), the key elements that would encourage demand response are locational marginal pricing (LMP) and the establishment of centralized day-ahead and real-time markets for energy, ancillary services, and transmission services. LMP and centralized markets provide efficient wholesale price signals to which LSEs and customers might respond if retail market designs allow such response. Over the longer term, LMP and centralized markets will lead to more efficient investment in generation, transmission and demand response technology, resulting in lower costs and ultimately lower prices to consumers.

LMP will allow demand response to play a role in relieving transmission constraints, both in the short and the long term, by communicating the cost of electricity service to customers. Locational marginal prices are the only prices that are consistent with efficient system dispatch, and they are the only prices that induce self-interested loads to consume efficient quantities of power and profit-maximizing generators to produce efficient quantities of power.

There is still another flavor under EWPC, which will be much better than what was though for the SMD, as the system engineering institution satisfies the ultraquality requirements. Retailers will concentrate no on lower prices to customers, but on lower costs and/or higher value, as business designs innovations will aim to that. Most of the customers will – eventually - have lower prices. However, customers that are receiving energy cross-subsidies and/or hidden supply security cross-subsidies might have higher prices later on.

January, 10 2007

Steven Rosenstock says

Getting back to the discussion about GAS issues:

Mr. Weissman wrote a nice article, but he was only focused on one piece of the gas pie. Based on data (from EIA, of course :-) for 2004, the percentage of gas consumption in the US is as follows:

Industrial - 40% Buildings (homes and businesses) - 35% Electric Generation - 23% "Other" (transportation, etc) - 2%

So to talk about electric generation (about 1/4 of the "pie") while ignoring the bigger piece doesn't make sense.

I wonder why the author didn't discuss the fact that over 68% of new homes use gas for space heating (and probably water heating as well), and probably a similar percentage of new businesses are at that level or higher? Shouldn't a national priority be to reduce as a fuel to heat homes and businesses, or to reduce it as a fuel in industrial processes?

In terms of other comments, how about demand response and smart meters on the gas side? They are putting in gas "smart meters" in CA. Maybe real time or critical peak pricing can significantly reduce gas usage in the winter.

CHP for the home? That would mean more gas usage as electric usage in the home currently powered by coal, nuclear, hydro, wind, etc would be probably replaced with natural gas (since it would be a lot cheaper than a solar system). How does that help the natural gas supply / demand situation?

Environmental pressures may eliminate coal as an option for new generation. Do we really want to do that?

In terms of gas supply, do we really want to import gas like we import oil? I think that the country with the 2nd or 3rd most proven reserves is led by a Holocaust denying bigot (Iran), and if Mr. Weissman's predictions come true, we are going to be putting more money in his pocket.

January, 10 2007

Len Gould says

Steven: The point about CHP for the home is that if you are going to burn gas to heat the home anyway, then you should first be generating electricity with it, then using the waste heat for space heating. If you have a use for the waste heat, you can get the electricity out at about 90% efficiency, much better than central gen.

January, 11 2007

Jose Antonio Vanderhorst-Silverio says

Steven has given some of the elements to be considered in a scenario - named playing with fire - centered on Model 2 to protect vested interest in electric power. I think it will be a plausible scenario to be avoided. Environmental pressures are denied; holocaust is an issue, etc.

Another scenario based on EWPC should be written, whose elements are in Part I and II of Playing with Fire. The EWPC for the customer scenario - named putting out the fire - should be promoted. The resources of the demand side, including energy efficiency, demand response, CHP-waste heat heating , hybrid cars and other distributed resources, should have the same opportunities as central stations by taking down the "native" load barrier. Environmental pressures are acepted; holocaust is not an issue, etc.

January, 11 2007

Arvid Hallén says


"Environmental pressures may eliminate coal as an option for new generation. Do we really want to do that?"

Yes, yes, yes and yes. Even if we don't believe in human induced climate change, a modern IGCC coal facility will create environmental and health costs of 16 billion dollars over it's 60 year lifetime, compared to a nuclear reactor of the same size (800 MW). At least according to Nathan Nadir at

Furtermore: "The United States operates more than 100 nuclear plants. If the Brunswick station is typical of them, replacing them all with IGCC coal plants without sequestration would amount to and additional cost 1.4 trillion dollars over a sixty year plant life. With sequestration the additional cost would be "only" $210 billion dollars. Of course no one really knows where one might sequester 60 years worth of such carbon dioxide. The concept is pure wishful thinking."

Coal is evil, even with all the scrubbers and no CO2 emissions, and should not be used where there are viable alternatives. Like in the US and Europe.

January, 11 2007

Steven Rosenstock says

To respond to the comments to my post:

1) Mr. Gould, yes, if you can use the waste heat, you get great efficiencies. However, the more South you go, the less waste heat you need. Also, since most people have electric AC in the US, the waste heat in the summer season would be just that - waste to be exhausted. From the data I have seen, microturbines have fuel to electric efficiencies of 22-26%, and fuel cells are between 33 and 40%, so even after T&D losses, less gas would be used in a combined cycle gas turbine to make the same electricity.

2) Mr Vanderhorst-Silverio: There are vested interests everywhere, and to go after one sector of the economy while ignoring equally important factors in other sectors does not make sense. If there is sacrifice to be made, it should be shared, and not just on the sector that is easiest to attack politically. You have your scenarios and I have mine, and I enjoy the free exchange of ideas.

3) Mr. Hallen: I am sorry, I must disagree with you, especially since we do not import any coal from the Middle East. Oil is a lot more "evil" than coal ever was or is, in my opinion.

It will be fascinating to see what European countries will do with older nuclear plants, especially if CO2 policies are made even tougher after 2012. There are many people who think that nuclear is so "evil" that all nuclear plants should be shut down yesterday.

My other point was that if gas DG is promoted, as more is adopted, there would be a switch from diverse supplies (coal, nuclear, wind, hydro, etc) to primarily gas. That is my thought on the probable end result, in the absence of significant incentives for solar electric and thermal systems.

January, 11 2007

Len Gould says

It interests me how the group of people who will argue all night that "free markets will solve everything" are then often the first to advocate an enforced embargo or a military invasion to bypass market forces when a resource comes under the control of a group not of their liking.

January, 11 2007

Arvid Hallén says

Steven (or maybe I should call you Mr. Rosenstock? :) ),

Coal and oil do not occupy the same niche. Coal is almost exclusively used for power generation and steel manufacture (and some chemical industry like ethanol) while oil is mainly a transportation (and heating) fuel and a chemical feedstock.

Using more coal does not reduce oil consumption, or oil imports. It's not like anyone much use oil to generate power anymore in the US.

Of course, coal can be turned into synthetic diesel. A very good idea, but then CO2 emissions must be cut by phasing out coal power plants and replacing them with wind and nuclear to make space for these new emissions.

When it comes to aging European reactors, I believe the same thing will be done here as is done in the US, that is, maintain, modernize and run them for another 20 years (for a total of about 60). And then build new ones. Opposition to nuclear energy in Europe is waning fast as people worry ever more about climate change and Russian supply and the high cost of energy. Even in Germany.

January, 11 2007

Jose Antonio Vanderhorst-Silverio says

Thanks Mr. Rosenstock for your useful response that allows me to explain, as you will see, why my suggestion makes a lot of sense.

As a promoter of a generative dialogue, I also enjoy the free exchanges of ideas, especially to learn about what has been emerging for electricity customers since the 80's, when Fred C. Schweppe led the development of Spot Pricing of Electricity at MIT.

Faulty deregulation - Model 2 – was not allowed to emerge in the 90s, to overextend the useful life of the utility business model – how to win cases to the regulator - and fragmented the transportation system, by placing a tough barrier to Schweppes’s homeostatic utility control, as is explained in the post A Generative Dialogue Without Illusions Part 7. The so called “native” load is a barrier to the development of the resources on the demand side. That is the main reason of the decade old debate, as those resources remain mostly undeveloped.

Hence, there will be no such sacrifice for those vested interests, as they have more that a decade of advantage. The sacrificed have been the little guys, not just in the U.S., but all over the world. “Deregulation, as explained in 2001 was designed as a scam. Donella Meadows got it very close to its essence in the article Restructuring and Faith in the Market. She said:

…electricity restructuring is not being driven by the goal of reducing residential rates. The drivers are technology and industry. New ways of making electricity, such as combined-cycle natural gas generators, and soon fuel cells, allow industrial users to produce their own power at lower cost and with less pollution. One by one they are slipping off the grid, leaving the utilities, with their huge, outmoded, unpaid-for power plants, in a panic.

To save themselves, the power companies meet in back rooms with politicians. They must accomplish three things. First, they must allow big customers to lock in low rates, so they will stay on the grid. Second, they must pay off the debt for their dinosaur plants. Third, they must sell the deal to the public by promising lower rates.

The only way to pull off this miracle is with a public bail-out, called "stranded costs" in the back rooms. Stranded cost payments mean that your electric bill will actually be higher, but a chunk of it will be hidden in your tax bill. This maneuver has nothing to do with a free market. It is perverse socialism. Prop up a dying industry by forcing the people to pay for bad investments. Order utilities to cut rates for awhile to lull taxpayers. Then let the people shop for power in competition with the big guys. That's where the market will come in, but markets aren't kind to little players competing against big ones.

To further justify immediate action, I repeat what I said on 10.3.06, under the article Divorcing Electricity Sales from Profits Creates Win-Win for Utilities and Customers:

I suggest reading what Walter Wriston, chairman of Citicorp said in 1981 about the rights of inherited markets (see Megatrends: ten new directions transforming our lives, by John Naisbitt). That was the lesson of the railroads - a very capital intensive business that didn’t know it was on the business of transportation.

Under EWPC, retail business design innovators will be on the business of electric energy service - light, heat, conditioned air, etc. - which is right after the customer end-use devices. Vested interest should start learning that they will be like the railroads very soon, as EWPC – the wining market model - gets developed and implemented.

© 2007, José Antonio Vanderhorst Silverio, Ph.D.

January, 11 2007

Jose Antonio Vanderhorst-Silverio says

A correction on the 3rd paragraph, which should start as: "Faulty deregulation - Model 2 – overextended the useful life of the utility business model – how to win cases to the regulator - and fragmented the transportation system,..."

January, 16 2007

bill payne says

Natural gas depletion may be more serious than oil depletion?

Then there is the coal problem.

January, 17 2007

Malcolm Rawlingson says

Some interesting observations here about the relative efficiencies of centralised CHP over household gas heating systems. But a major thing missing. Who is going to pay for the hundreds of thousands of systems that would be required to make CHP in households a viable alternative to natural gas in those places where it is available. The investment has to be in the billions of dollars. One commentator above subscribes to the notion that it is more efficient to generate electricity in a modern Combined Heat and Power plant to produce electricity than it is to use it to space heat houses. That really all depends on what the end use of the electricity is doesn't it? There are millions of homes that are still heated with baseboard heaters and electric furnaces since this is the only energy source available (no gas in the area). Using gas to produce electricty and then to use that electricity to space heat is just a little nonsensical don't you think? Of course if one can guarantee that the end use of the electricity so produced is for electronics etc for which there is no viable alternative then perhaps you have a point. But in this real world of ours the argument is very thin. I have investigated ground source and water source heat pumping systems for my home which is currently heated with natural gas which I guess makes me an energy criminal in the eyes of some. The systems studied have payback times at current and foreseeable natural gas prices of the order of 20 to 30 years. They also require a significant chunk of land to collect the heat from or you incur massive costs of drilling vertical holes if you do not have the space. In the typical urban environment with a 30 foot lot in which millions live heat pumps are just not viable. Less efficient air heat pumps may be but they are all but useless in cold climates and you need a supplemental heat source anyway. Now you require two systems and two capital costs expenditures to do the job. Not very cost effective. At one time I used electricicy to heat my house. Very expensive but the only source of energy available to me apart from wood. I had the choice whether to freeze in winter or to have some level of habitability....or move to a warmer climate. When natural gas became available the differential cost justified the purchase of a new gas furnace (98.5% efficient condensing gas furnace) with a payback time of 4 years. In fact since electricity prices rose faster than the price of gas the payback time was only 2.5 years and the economics made sense to this simple man. Clearly worth the effort and expense I thought. After the two and a half years my total energy bills were substantially lower and have been since. When I do the same calculations wrt to home based combined heat and power the cost is simply not justified. As much as I would like it to be the economics are not there. Sure it works thermodynamically but when all one wants to do is keep warm in winter at a cost that does not cause bankruptcy then the numbers simply do not make sense to me. Natural gas and electricity prices would have to at least quadruple to make the investment repayable in a reasonable time frame.

And as for using solar panels - the situation is even worse. They never repay their costs. Should the costs of these systems decrease substantially then one might draw a different conclusion but at time of writing none of it is financially feasible for the average householder.

If it was they would already be doing it.

A better investment would be to upgrade older less efficient gas furnaces to the very high efficiency levels currently available. The gas supply so liberated could then be used for other applications. Natural gas driven vehicles for example.

In general while all these ideas are interesting one needs to apply a bit of common sense....sadly missing these days I fear.


January, 19 2007

Len Gould says

Makcolm: Unfortunately for us all, your analysis is likely correct "with currently available technology". So I ask you, how low a price point per KW and what ideal size in KW would a silent gas-fueled stirling engine-generator with 40% electrical efficiency and 90% thermal efficiency CHP "furnace/water heater" unit need to achieve to change your decision? Automated, 120,000 hr life, 4 qt oil / yr O&M, 1 $400 o/haul each 40,000 hr.

January, 22 2007

Harold Waldock says

My concern with gas is not the power industry but the consumer. The consumer is more unprotected than industry and has fewer choices than power industry for getting off gas. This is where the bleeding will be terrible when gas shortages sting. Granny going to freeze in her unheated house because either there is no supply (like 1976) or she can't afford it.

This discussion gets itself tangled in thinking that government can and will look after the people. Who can trust governments with debt, unkept promises, fiat currency and other ills? Assume that government policy then is a poor waste of time for all but the most talented an patient statesmen.

For the rest of us can we trust the market to provide? Well that depends on whether they wish to serve us with alternatives and we have the means to pay them well enough. History have shown that even well paid suppliers do not always supply their traditional buyers. OPEC was not formed for buyers benefits. Did the robber barons, coal barons or steam (train) barons supply their markets as a benefit? During the depression when people starved did the farmers feed the people or did they dump their produce to raise prices? Can you really trust the market to provide for you in your time of need?

So given that the power supply industry is somewhat diversified compared to the consumer for electricty and heat what can be done to reduce the risks to consumers? Consumers in NA 65%-85% of the market is gas heating. 10-15% oil. 5% wood 10-15% electricty. That is not very diversified. We have a situation where the consumers have few choices. In considering what we might do at our 30 unit Strata Ecovillage I thought we had 3 choices to get off gas:

1) Groundsource heat pump hybrid with cord wood or pellet stove back up for peaking and power outage necessary because we are semi rural and can get to -15c for weeks. with diesel backup power gen. for black outs

2) Pellet wood furnace (we are in BC we export these pellets to Europe by the boatload. It is storable and transporable like oil yet renewable. 1/2 density of oil. Sweden gets 8-15% of power from it cofired with coal etc) hybrid with solar hot water with diesel back up power to recharge batteries to run the fans & augur. Note hydronic heating.

3) Electricity is cheap and will be cheap for a while yet here in BC. Hybrid with solar hotwater Nothing like big hydro. Only a small fraction of our electricity is nat gas. Under 20%. One local ng fired plant 800mw has been in reserve for years just sitting waiting to be used mothballed.

An opportunity for some places is District heating fired by what have you. Every place has something. These are a good places for DG.

Last winter we had 6 days of sun in 60 days Jan-Feb. Solar will never be useful in winter for the temperate zone where most people live.

I wish public forums would discuss consumer alternatives more often because they will affect the whole market. If the above alternatives were to be chosen over a 10 year period (just like the big switch to nat gas 1975-1985) 30% each then what would the energy futures be like? Air pollution? Nat. Gas prices? Electricity prices?

Now is the time to act. Andrew M. has provided the view into the future. We must provide our clients the consumers with alternatives they themselves can choose. Government and free markets will be slow to supply any change. Markets only react to the price but one can't say they are always rational. People providing creative alternatives based on reality will be a saviour to the people - those working on alternatives before the price signals change. Markets react after the fact but that pain will be great for consumers - markets (its price signal) will be too late for many.

Andrew M. has shown that it is rational to look at very uncomfortable future price scenarios. It is rational and generous to be looking at alternatives now. For some they may even be profitable in the future but for the vast majority of consumers this switch over will be painful worse than 1970- 1980s.

Who can tell me of other reasonable alternatives to heating and hotwater for consumers?

January, 23 2007

Jose Antonio Vanderhorst-Silverio says

Harold asks:

"For the rest of us can we trust the market to provide?"

"Can you really trust the market to provide for you in your time of need?"

My response is about electricity, but an extention could be provided for natgas by an expert. See my post of 1.3.07.

Market Model 2 cannot be trusted, nor provide you in time of need.

EWPC market - architecture and design - Model 3 has a controlled market under a system engineer to manage short run (system crashes) and long run (boom-bust behavior) systemic risks. Those are restrictions to satify both questions under which a free market value chain "generation - retailer - customer "can allow businesses to operate under prudential regulation.

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