Sunday, August 21, 2016

Skeptics Wrangle While Cooling Is Coming

Subtitle:  Imminent Cooling On Display in North Atlantic  

Sometimes I am more than amazed, and this time rather amused, by the commenters such as on today's post at WUWT, by David Archibald (see link).   Commenters arguing over the proper cause of imminent cooling is rather like a family at the kitchen table, arguing over what caused the house to be on fire while the house is burning down around them: an electrical wiring fault, no, it was arson, no no, it was hot embers from the wildfire outside.

Perhaps it makes a difference in the long term, if the evident Atlantic ocean cooling is due to cold water upwelling, or more clouds blocking the sun, or more Arctic ice melting into the Atlantic (but you’re going to need an awful lot of ice for that one).

Perhaps it makes no difference. No one can stop the oceans from upwelling. No one can stop the clouds from forming. And no one can stop Arctic ice from melting now that ton after ton of black soot, ashes, and jet engine exhaust have settled onto the ice and accelerate the melting.

It would be prudent to examine the recent trends in global cooling, then try to determine exactly what can be done to stop the trends or reverse them, or at the very least reduce the rate of cooling.

I stand by my 2012 speech and article, "Warmists Are Wrong – Cooling Is Coming". see link

Roger E. Sowell, Esq.
Marina del Rey, California
copyright (c) 2016 by Roger Sowell - all rights reserved 

Wind Power Facts and Trends 2015

Subtitle:  Wind Power Costs Less and Produces More Than Before

A new report, "2015 Wind Technologies Market Report" from DoE, primary authors Riser and Bollinger, gives the present state of the US wind power industry.  see link   The Executive Summary is below.   

Summary of key findings:

o  Installed cost in the windy Great Plains is $1,640 / kW, continuing the downward trend of the past several years. 

o  Also, wind power is sold at very low prices under a Purchase Power Agreement, for $20 / MWh.  The federal tax credit continues at $23 per MWh.  

o  Finally, capacity factors for 2015 are higher than ever, at 41.2 percent among projects built in 2014.

Executive Summary

Annual wind power capacity additions in the United States surged in 2015 and are projected to continue at a rapid clip in the coming five years. Recent and projected near-term growth is supported by the industry’s primary federal incentive—the production tax credit (PTC)—as well as a myriad of state-level policies. Wind additions are also being driven by improvements in the cost and performance of wind power technologies, yielding low power sales prices for utility, corporate, and other purchasers. At the same time, the prospects for growth beyond the current PTC cycle remain uncertain: growth could be blunted by declining federal tax support, expectations for low natural gas prices, and modest electricity demand growth.

Key findings from this year’s Wind Technologies Market Report include:

Installation Trends

• Wind power additions surged in 2015, with 8,598 MW of new capacity added in the
United States and $14.5 billion invested. Supported by favorable tax policy and other
drivers, cumulative wind power capacity grew by 12%, bringing the total to 73,992 MW.

• Wind power represented the largest source of U.S. electric-generating capacity
additions in 2015. Wind power constituted 41% of all U.S. generation capacity additions in
2015, up sharply from its 24% market share the year before and close to its all-time high.
Over the last decade, wind power represented 31% of all U.S. capacity additions, and an evenlarger fraction of new generation capacity in the Interior (54%) and Great Lakes (48%)
regions. Its contribution to generation capacity growth over the last decade is somewhat
smaller in the West (22%) and Northeast (21%), and considerably less in the Southeast (2%). 

• The United States ranked second in annual wind additions in 2015, but was well behind
the market leaders in wind energy penetration. A record high amount of new wind
capacity, roughly 63,000 MW, was added globally in 2015, yielding a cumulative total of
434,000 MW. The United States remained the second-leading market in terms of cumulative
capacity, but was the leading country in terms of wind power production. A number of
countries have achieved high levels of wind penetration; end-of-2015 wind power capacity is
estimated to supply the equivalent of roughly 40% of Denmark’s electricity demand, and
between 20% to 30% of Portugal, Ireland, and Spain’s demand. In the United States, the
wind power capacity installed by the end of 2015 is estimated, in an average year, to equate
to 5.6% of electricity demand.

• Texas installed the most capacity in 2015 with 3,615 MW, while twelve states meet or
exceed 10% wind energy penetration. New utility-scale wind turbines were installed in 20
states in 2015. On a cumulative basis, Texas remained the clear leader, with 17,711 MW.
Notably, the wind power capacity installed in Iowa and South Dakota supplied more than
31% and 25%, respectively, of all in-state electricity generation in 2015, with Kansas close
behind at nearly 24%. A total of twelve states have achieved wind penetration levels of 10%
or higher.

• The first commercial offshore turbines are expected to be commissioned in the United
States in 2016 amid mixed market signals. At the end of 2015, global offshore wind
capacity stood at roughly 12 GW. In the United States, the 30 MW Block Island project off the coast of Rhode Island will be the first plant to be commissioned, anticipated by the end of 2016. Projects in Massachusetts, New Jersey, Virginia, and Oregon, meanwhile, all
experienced setbacks. Strides continued to be made in the federal arena in 2015, both through  the U.S. Department of the Interior’s responsibilities in issuing offshore leases, and the U.S.Department of Energy’s (DOE’s) funding for demonstration projects. A total of 23 offshore wind projects totaling more than 16 GW are in various stages of development in the United States.

• Data from interconnection queues demonstrate that a substantial amount of wind
power capacity is under consideration. At the end of 2015, there were 110 GW of wind
power capacity within the transmission interconnection queues reviewed for this report,
representing 31% of all generating capacity within these queues—higher than all other
generating sources except natural gas. In 2015, 45 GW of wind power capacity entered
interconnection queues (the largest annual sum since 2010), compared to 58 GW of natural
gas and 24 GW of solar.

Industry Trends

• GE and Vestas captured 73% of the U.S. wind power market in 2015. Continuing their
recent dominance as the three largest turbine suppliers to the U.S., in 2015 GE captured 40% of the market, followed by Vestas (33%) and Siemens (14%). Globally, Goldwind and Vestas were the top two suppliers, followed by GE, Siemens, and Gamesa. Chinese manufacturers continued to occupy positions of prominence in the global ratings, with five of the top 10 spots; to date, however, their growth has been based almost entirely on sales in China.

• The manufacturing supply chain continued to adjust to swings in domestic demand for
wind equipment. With growth in the U.S. market, wind sector employment reached a new
high of 88,000 full-time workers at the end of 2015. Moreover, the profitability of turbine
suppliers has rebounded over the last three years. Although there have been a number of
recent plant closures, each of the three major turbine manufacturers serving the U.S. market
has one or more domestic manufacturing facilities. Domestic nacelle assembly capability
stood at roughly 10 GW in 2015, and the United States also had the capability to produce
approximately 7 GW of blades and 6 GW of towers annually. Despite the significant growth
in the domestic supply chain over the last decade, conflicting pressures remain, such as: an
upswing in near- to medium-term expected growth, but also strong international competitive
pressures and possible reduced demand over time as the PTC is phased down. As a result,
though many manufacturers increased the size of their U.S. workforce in 2015, expectations
for significant supply-chain expansion have become more pessimistic.

• Domestic manufacturing content is strong for some wind turbine components, but the
U.S. wind industry remains reliant on imports. The U.S. is reliant on imports of wind
equipment from a wide array of countries, with the level of dependence varying by
component. Domestic content is highest for nacelle assembly (>85%), towers (80-85%), and
blades and hubs (50-70%), but is much lower (less than 20%) for most components internal to the nacelle. Exports of wind-powered generating sets from the United States rose from $16 million in 2007 to $544 million in 2014, but fell to $149 million in 2015.

• The project finance environment remained strong in 2015. Spurred on by the December
2014 and March 2015 single-year extensions of the PTC’s construction start deadline and IRS safe harbor guidance, respectively, the U.S. wind market raised ~$6 billion of new tax
equity in 2015—the largest single-year amount on record. Debt finance increased slightly to
$2.9 billion, with plenty of additional availability. Tax equity yields drifted slightly lower to
just below 8% (in unlevered, after-tax terms), while the cost of term debt fell to just 4% by
the end of the year—perhaps the lowest it has ever been. Looking ahead, 2016 should be
another busy year, given the recent 5-year PTC extension and phase down.

• IPPs own the vast majority of wind assets built in 2015. Independent power producers
(IPPs) own 85% of the new wind capacity installed in the United States in 2015, with the
remaining assets owned by investor-owned utilities (12%) and other entities (3%). On a
cumulative basis through 2015, IPPs own 83% and utilities own 15% of U.S. wind capacity,
with the remaining 2% owned by entities that are neither IPPs nor utilities (e.g., towns,
schools, businesses, farmers).

• Long-term contracted sales to utilities remained the most common off-take
arrangement, but direct retail sales gained ground. Electric utilities continued to be the
dominant off-takers of wind power in 2015, either owning (12%) or buying (48%) power
from 60% of the new capacity installed last year. Merchant/quasi-merchant projects
accounted for another 29%, while direct retail purchasers – including corporate off-takers –
are buying the remaining 10% (a share that should increase next year). On a cumulative
basis, utilities own (15%) or buy (53%) power from 68% of all wind capacity in the United
States, with merchant/quasi-merchant projects accounting for 24%, power marketers 6%, and direct retail buyers just 2% (though likely to increase in the coming years).

Technology Trends

• Turbine nameplate capacity, hub height, and rotor diameter have all increased
significantly over the long term. The average nameplate capacity of newly installed wind
turbines in the United States in 2015 was 2.0 MW, up 180% since 1998–1999. The average
hub height in 2015 was 82.0 meters, up 47% since 1998-1999, while the average rotor
diameter was 102 meters, up 113% since 1998–1999.

• Growth in rotor diameter has outpaced growth in nameplate capacity and hub height in
recent years. Rotor scaling has been especially significant in recent years, and more so than increases in nameplate capacity and hub heights, both of which have seen a stabilization of the long-term trend since at least 2011. In 2008, no turbines employed rotors that were 100 meters in diameter or larger; by 2015, 86% of new installed wind capacity featured rotor diameters of at least 100 meters.

• Turbines originally designed for lower wind speed sites have rapidly gained market
share. With growth in average swept rotor area outpacing growth in average nameplate
capacity, there has been a decline in the average “specific power” i (in W/m2) over time, from 394 W/m2 among projects installed in 1998–1999 to 246 W/m2 among projects installed in 2015. In general, turbines with low specific power were originally designed for lower wind speed sites. Another indication of the increasing prevalence of lower wind speed turbines is that, in 2015, the vast majority of new installations used IEC Class 3 and Class 2/3 turbines.

i A wind turbine’s specific power is the ratio of its nameplate capacity rating to its rotor-swept area. All else equal, a decline in specific power should lead to an increase in capacity factor.

• Turbines originally designed for lower wind speeds are now regularly employed in both
lower and higher wind speed sites; taller towers predominate in the Great Lakes and
Northeast. Low specific power and IEC Class 3 and 2/3 turbines are now regularly
employed in all regions of the United States, and in both lower and higher wind speed sites.
In parts of the Interior region, in particular, relatively low wind turbulence has allowed
turbines designed for lower wind speeds to be deployed across a wide range of site-specific
resource conditions. The tallest towers, meanwhile, have principally been deployed in the
Great Lakes and Northeastern regions, in lower wind speed sites, with specific location
decisions likely driven by the wind shear of the site.

Performance Trends

• Sample-wide capacity factors have gradually increased, but have been impacted by
curtailment and inter-year wind resource variability. Wind project capacity factors have
generally increased over time. For a large sample of projects built from 1998 through 2014,
capacity factors averaged 32.8% between 2011 and 2015 versus 31.8% between 2006 and
2010 versus 30.3% between 2000 and 2005. That being said, time-varying influences—such as inter-year variations in the strength of the wind resource or changes in the amount of wind energy curtailment—have partially masked the positive influence of turbine scaling on capacity factors. For example, wind speeds throughout the interior and western U.S. were significantly below normal for much of 2015, which negatively impacted fleet-wide capacity factors. Positively, the degree of wind curtailment has declined recently in what historically have been the most problematic areas. For example, only 1.0% of all wind generation within ERCOT was curtailed in 2015, down sharply from the peak of 17% in 2009.

• The impact of technology trends on capacity factor becomes more apparent when
parsed by project vintage. Focusing only on performance in 2015 (to partially control for
time-varying influences) and parsing capacity factors by project vintage tells a more
interesting story, wherein rotor scaling over the past few years has clearly begun to drive
capacity factors higher. The average 2015 capacity factor among projects built in 2014
reached 41.2%, compared to an average of 31.2% among projects built from 2004–2011 and just 25.8% among projects built from 1998–2003. The ongoing decline in specific power has been offset to some degree by a trend—especially from 2009 to 2012—towards building
projects at lower-quality wind sites. Controlling for these two competing influences confirms
this offsetting effect and shows that turbine design changes are driving capacity factors
significantly higher over time among projects located within given wind resource regimes.
Performance degradation over time is a final driver examined in this section: though many
caveats are in order, older wind projects appear to suffer from performance degradation,
particularly as they approach and enter their second decade of operations.

• Regional variations in capacity factors reflect the strength of the wind resource and
adoption of new turbine technology. Based on a sub-sample of wind projects built in 2014,
average capacity factors in 2015 were the highest in the Interior region (42.7%). Not
surprisingly, the regional rankings are roughly consistent with the relative quality of the wind
resource in each region, and they reflect the degree to which each region has adopted turbines with lower specific power or taller towers. For example, the Great Lakes has thus far adopted these new designs to a much larger extent than has the West, with corresponding implications for average capacity factors in each region.

Cost Trends

• Wind turbine prices remained well below levels seen several years ago. After hitting a
low of roughly $750/kW from 2000 to 2002, average turbine prices increased to more than
$1,500/kW by the end of 2008. Wind turbine prices have since dropped substantially, despite increases in hub heights and especially rotor diameters. Recently announced transactions feature pricing in the $850–$1,250/kW range. These price reductions, coupled with improved turbine technology, have exerted downward pressure on project costs and wind power prices.

• Lower turbine prices have driven reductions in reported installed project costs. The
capacity-weighted average installed project cost within our 2015 sample stood at roughly
$1,690/kW—down $640/kW from the apparent peak in average reported costs in 2009 and
2010. Early indications from a preliminary sample of projects currently under construction
and anticipating completion in 2016 suggest no material change in installed costs in 2016.

• Installed costs differed by project size, turbine size, and region. Installed project costs
exhibit some economies of scale, at least at the lower end of the project and turbine size
range. Additionally, among projects built in 2015, the windy Interior region of the country
was the lowest-cost region, with a capacity-weighted average cost of $1,640/kW.

• Operations and maintenance costs varied by project age and commercial operations
date. Despite limited data availability, it appears that projects installed over the past decade
have, on average, incurred lower operations and maintenance (O&M) costs than older
projects in their first several years of operation, and that O&M costs increase as projects age.

Wind Power Price Trends

• Wind PPA prices remain very low. After topping out at nearly $70/MWh for PPAs
executed in 2009, the national average level-through price of wind PPAs within the Berkeley
Lab sample has dropped to around the $20/MWh level, inclusive of the federal production
tax credit (PTC), though this latest nationwide average is admittedly focused on a sample of
projects that largely hail from the lowest-priced Interior region of the country, where most of
the new capacity built in recent years is located. Focusing only on the Interior region, the
PPA price decline has been more modest, from ~$55/MWh among contracts executed in
2009 to ~$20/MWh today. Today’s low PPA prices have been enabled by the combination
of higher capacity factors, declining costs, and record-low interest rates documented
elsewhere in this report.

• The relative economic competitiveness of wind power declined in 2015 with the drop in
wholesale power prices. A sharp drop in wholesale power prices in 2015 made it somewhat
harder for wind power to compete, notwithstanding the low wind energy PPA prices
available to purchasers. This is particularly true in light of the continued expansion of wind
development in the Interior region of the U.S., where wholesale power prices are among the
lowest in the nation. That said, the price stream of wind PPAs executed in 2014-2016
compares very favorably to the EIA’s latest projection of the fuel costs of gas-fired
generation extending out through 2040.

Policy and Market Drivers

• A long-term extension and phase down of federal incentives for wind projects is leading
to a resurgent domestic market. In December 2015, Congress passed a 5-year phased-down extension of the PTC. To qualify, projects must begin construction before January 1, 2020. In May 2016, the IRS issued favorable guidance allowing four years for project completion after the start of construction, without the burden of having to prove continuous construction. In extending the PTC, Congress also included a progressive reduction in the value of the credit for projects starting construction after 2016. Specifically, the PTC will phase down in increments of 20 percentage points per year for projects starting construction in 2017 (80% PTC), 2018 (60%), and 2019 (40%).

• State policies help direct the location and amount of wind power development, but
current policies cannot support continued growth at recent levels. As of July 2016, RPS
policies existed in 29 states and Washington D.C. Of all wind capacity built in the United
States from 2000 through 2015, roughly 51% is delivered to load-serving entities with RPS
obligations. Among just those wind projects built in 2015, however, this proportion fell to
24%. Existing RPS programs are projected to require average annual renewable energy
additions of roughly 3.7 GW/year through 2030, only a portion of which will come from
wind. These additions are well below the average growth rate in wind power capacity in
recent years.

• System operators are implementing methods to accommodate increased penetrations of
wind energy, but transmission and other barriers remain. Studies show that wind energy
integration costs are almost always below $12/MWh—and often below $5/MWh—for wind
power capacity penetrations of up to or even exceeding 40% of the peak load of the system in which the wind power is delivered. System operators and others continue to implement a
range of methods to accommodate increased wind energy penetrations and reduce barriers to deployment: treating wind as dispatchable, increasing wind’s capability to provide grid
services, revising ancillary service market design, balancing area coordination, and new
transmission investment. About 1,500 miles of transmission lines came on-line in 2015—less than in previous years. The wind industry, however, has identified 15 near-term transmission projects that—if all were completed—could carry 52 GW of additional wind capacity.

Future Outlook

With the five-year phased-down extension of the PTC, annual wind power capacity additions are projected to continue at a rapid clip for several years. Near-term additions will also be driven by improvements in the cost and performance of wind power technologies, which continue to yield very low power sales prices. Growing corporate demand for wind energy and state-level policies are expected to play important roles as well, as might utility action to proactively stay ahead of possible future environmental compliance obligations. As a result, various forecasts for the domestic market show expected capacity additions averaging more than 8,000 MW/year from 2016 to 2020. Projections for 2021 to 2023, however, show a downturn in additions as the PTC progressively delivers less value to the sector. 

Expectations for continued low natural gas prices, modest electricity demand growth, and lower near-term demand from state RPS policies also put a damper on growth expectations, as do inadequate transmission infrastructure and competition from solar energy in certain regions of the country. At the same time, the potential for continued technological advancements and cost reductions enhance the prospects for longer-term growth,
as does burgeoning corporate demand for wind energy and longer-term state RPS requirements. EPA’s Clean Power Plan, depending on its ultimate fate, may also create new markets for wind. Moreover, new transmission in some regions is expected to open up high-quality wind resources to development. Given these diverse underlying potential trends, wind capacity additions— especially after 2020—remain uncertain.

-----  End of Executive Summary 2015 Wind Technologies Market Report ----

Roger E. Sowell, Esq.
Marina del Rey, California

copyright (c) 2016 by Roger Sowell - all rights reserved for original material

Sunday, August 14, 2016

US Coal Supplies Dwindling Rapidly

Subtitle:  Only 10 Years Supply at Present Prices in Powder River Basin

A quiet transformation is occurring in the electric power industry, with many people unaware of the facts and the implications.   My recent interactions over the internet show that some, perhaps many people still believe that the US has hundreds of years of coal supplies, and worldwide there are 10,000 years of supplies.   However, the facts as shown below are clear: at present price of $9 per ton for Powder River Basin coal, only 10 billion tons are economically recoverable.   The market report for coal prices from EIA for August 5, 2016 shows Powder River Basin coal at $8.70 per ton.   The chart below is from Figure 123 of the USGS Professional Paper 1809, 2015 by Luppens et. al. 
Coal reserves vs coal price for Powder River Basin
source: Luppens, J.A., Scott, D.C., Haacke, J.E, Osmonson, L.M., and Pierce, P.E., 2015, Coal geology and assessment of coal resources and reserves in the Powder River Basin, Wyoming and Montana: U.S. Geological Survey Professional Paper 1809, 218 p.,

Far lesser amounts exist in the Appalachian and Illinois basins.    With US coal consumption at approximately 700 - 800 million tons annually, there are less than 20 years of coal remaining.  

A bit of perspective on this follows.  Coal reserves is not the same as total coal in the ground.  Reserves refers to the quantity that can be brought to market using best available technology and at present prices.   An analogy can be made to relieving the chronic drought in the western United States.  It is well-known that enormous amounts of fresh water exists in the glaciers of Alaska, only a few thousand miles away.  The frozen water in those glaciers can be considered a water resource.  It exists, we know where it is, and we know approximately how much water there is.   

However, capturing an iceberg that calves off a glacier and into the ocean, then transporting that iceberg to Los Angeles, melting the ice into water, purifying the water to health standards, then delivering the water costs enormous amounts of money.  In effect, none of the Alaskan glacier water is recoverable at present prices and with present technology.   Therefore, the water reserves from Alaska is zero.  

Another example is from gold mines.  Many gold mines exist, but only those that can yield a profit at the present price of gold.are actively mined.   The same is true for almost any mineral resource, including oil and natural gas.  Many oil and gas deposits are known to exist but are left idle because the cost to extract and move the product to market is simply too great to yield a profit at present prices.  

Coal mining is no different.  As the chart above shows, approximately 160 billion tons of coal exist in the Powder River Basin, but the price required to recover that coal is $50 per ton.  That is approximately 6 times the present price.    

Roger E. Sowell, Esq.
Marina del Rey, California

copyright (c) 2016 by Roger Sowell - all rights reserved

Sunday, August 7, 2016

Another Record for Solar Power in California

Subtitle:  8214 MW - Solar Power Production Records Keep Falling

UPDATE 8/13/2016:  A higher solar production was set on Monday, August 8, 2016 at 1:08 pm, with 8,363 MW reported by CAISO.  -- end update

Yesterday, 6 August, 2016, saw yet another record production from grid-scale solar power plants in California.  From the California Independent System Operator, CAISO, combined PV and thermal solar power reached 8,214 MW at 1:25 pm.  

The graphic at right is a screenshot captured on a smart phone from at that time.  

More solar power plants are under construction in California and will soon be adding their output to the grid.  

As written before on SLB, the state's ambitious renewable portfolio standard requires 50 percent renewables on an annual average by 2030, only 14 years away.  

Present annual average renewables is a bit more than 25 percent.   It is clear, then, that renewable output must double within 14 years to meet the mandate. 

With wind resources limited and almost fully exploited in California, solar power will be the growth area.  Solar thermal power plants are far more expensive to build than the PV plants, and I expect no more solar thermal plants.  The attraction of solar thermal is the ability to include a few hours of storage that can allow electricity production after the sun sets and when power demand peaks.  

However, a better solution to electricity storage is now available with batteries at grid-scale size.  Solar PV is cheaper to install and has far less impact on birds and other aspects of the environment, compared to birds killed by a solar power tower plant.  

The future of California renewables is solar PV in grid-scale sizes, with appropriate battery storage to manage grid fluctuations and storage.    The gigafactory that Tesla is building to turn out batteries will not only supply the electric car market, but also will supply the grid-scale battery market.  

It should be noted that the above production numbers are for metered, grid-scale solar facilities only.  Behind-the-meter rooftop solar PV installations are not included in those numbers.  California Public Utility Commission and California Solar Initiative report that 537,000 rooftop PV installations exist at present.  Output from those rooftop systems is not known with accuracy, but estimates based on average installed capacity of 5 to 7 kW each show an additional 2,100 MW of solar-based electricity was produced yesterday.  

And in a direct comment to the nay-sayers, it is noted that the grid performed admirably with no reported problems of stability, brownouts, nor blackouts.   

Roger E. Sowell, Esq.
Marina del Rey, California

copyright (c) 2016 by Roger Sowell - all rights reserved

Saturday, July 30, 2016

A Week That Was July 2016

What a week.  So much happening, and much of it already impacting, or will impact, topics that are of interest to me.  In no particular order, then, 

o  Hinkley Point C nuclear power plant in the UK is having another look for viability by the new government under Theresa May; seems the cost to construct is a bit too high and subsidies also too high; see link

o  California survived a second heat wave, with a second FlexAlert issued, even though the natural gas shortage is still in effect - Aliso Canyon gas storage system is not yet fixed; 

o  Meanwhile, California's solar power production broke all-time records at more than 8,000 MW; a very good thing to have when the grid is struggling to send power to the people; even more solar power is under construction in California; see figure at right from CAISO website showing 8,132 MW produced on 26 July 2016;

o  Pacific Ocean surface temperatures are plunging fast and are already in the La Niña condition (the El Neutral didn't last long, as the ocean switched from hot El Niño to cool La Niña very quickly); 

o  Sunspots disappeared completely a few days ago, for approximately 7 or 8 days; this is rather early in the sunspot cycle for a week or more of spotless days to occur; see link to and refer to left column of that site. As of today, 30 July 2016, the sun has had 18 spotless days in 2016. 

o  A serious doubt for the future of manned space exploration re-surfaced this past week, with evidence and a report that lunar astronauts suffer (and some have died) from much higher incidence of cardio vascular disease; almost none of the non-flying astronauts, nor the low-earth orbit astronauts have this; the explanation is exposure to intense deep-space radiation and ionizing high-energy particles (galactic cosmic rays) by those astronauts that flew past the Earth's Van Allen Belts and went to the moon.   This has deep implications for the proposed moon-orbiting manned space station, any manned Mars missions, and especially a Mars colony.   The long-term orbiting astronauts on the International Space Station provide valuable data on some medical aspects of space life, but that is all within the protective shield of the Van Allen Belts.  see link to Nature article on deep-space radiation effects on astronauts, "Apollo Lunar Astronauts Show Higher Cardiovascular Disease Mortality: Possible Deep Space Radiation Effects on the Vascular Endothelium"

o  As always, it is amusing to read the derogatory comments on other blogs, and find irrefutable evidence that the commenters are wrong; in this case, EIA published a nice map of the US' regional electrical grids that show multiple states tied together to share electricity; some idiot challenged a piece I wrote by his statement that a good utility never purchases power from outside its own geographic area.    Ronald Reagan's quote remains so true: "It's not that our ... friends don't know anything, but that so much of what they know just isn't so." see link to EIA article on US grids, and graphic nearby.   

o  In US politics, we have the unusual fact of a billionaire businessman outsider, Donald Trump, as the official Republican Party presidential nominee, and a rich, old, scandal-plagued, white female, Hillary Clinton, as the official Democrat Party presidential nominee.   Their respective views on climate change, energy policy, immigration, foreign affairs, and national security could not be more different.  

o  In the oil markets, world crude oil price is low and headed lower as the summer driving season ends; I tend to scoff at most so-called experts that tell us what crude oil price will be because they are almost without exception very wrong.  The fact is that oil production world-wide is much greater than oil demand, with recent reports showing huge inventory increases world-wide to support oil production rates.  Economic malaise and improved technology reduce oil demand, which will cause oil prices to plummet.   Just yesterday, pundits predicted prices of $30 per barrel after this summer ends.   I will be surprised if oil does not fall to $25 or even lower.  

 I hope to have time to write a full article with links to sources and explore each of these in more detail. 

Roger E. Sowell, Esq.
Marina del Rey, California

copyright (c) 2016 by Roger Sowell - all rights reserved

Sunday, July 3, 2016

A Perfect Correlation - US Electricity Price v Consumption

Subtitle: A Bit of Gathering Into Groups Gives Good Results

It is not often that one creates a graph using actual data and discovers an almost perfect linear relationship.   It is even more rare to have a software package calculate the least-squares trend line and obtain a correlation coefficient, R-squared, of 0.99 or higher.   Yet, that is exactly what occurred for data from calendar year 2014 for US residential electricity consumption per customer, and average price per kWh.    The graph and simple statistics are shown below, then a discussion.   Note the R-squared value of 0.9997, indicating an almost perfect correlation.  
Figure 1.   Data from US Energy Information Agency, by state
Shows 39 states, excludes 10 states with lowest prices and Hawaii
This article follows another SLB article (see link) that ascribes the relatively higher price for residential electricity in California compared to the US average to mild climate and large population.  Conventional wisdom is very wrong in blaming solar power and wind power for the higher California prices.  

With the data ready at hand from US Energy Information Agency files from their website, it was a simple matter to sort the data for each state by annual average residential price in cents/kWh.   Being previously aware that low residential prices tend to correspond to high consumption, and vice-versa, inspection of the data for 2014 confirmed that relationship.  However, when the data is grouped into quintiles, a convenient grouping as there are 50 US states with ten members in each quintile, an almost perfect straight line resulted, as shown in Figure 1 above.   However, there are only four data points in Figure 1.   

The R-squared of 0.9997 resulted when only the four quintiles with highest prices are graphed, that is, the quintile with lowest prices was excluded.  Also, Hawaii is excluded as a high-priced outlier.   More on that in a moment.  

The data for each quintile is shown in table form below. 

Quint  kWh/y      Cents/kWh
1 13,528       9.67 
2 12,178     10.78 
3 11,445        11.89 
4 10,550     13.15 
5 7,311     17.58 

Next is shown in Figure 2 the graph of all five quintiles for 49 states - Hawaii is excluded as being a-typical and an outlier.   This graph has only a slightly lower correlation coefficient, R-squared of 0.9931.   

Figure 2.   Showing 49 states (excludes Hawaii)
The conclusion that can be drawn is that there is indeed a correlation, and a very good correlation, between average price for residential electricity and the quantity of electricity consumed on an annual basis by each utility customer.    California is in the fifth quintile for high price but low consumption (16.2 cents/kWh and 6,741 kWh/yr/customer).  Other states with California in the fifth quintile are almost all in the North East sector, Massachusetts, Vermont, Rhode Island, New York, Maine, New Jersey, and Connecticut.  Example states at the other extreme, in the first quintile are Louisiana, Arkansas, and Oklahoma - all hot, humid, and consuming 14,000 kWh/yr/customer on average, more than double that of California. 

In fairness, it should be noted that the high correlation coefficient only results when the quintiles are graphed.  For all 49 states individually, again excluding Hawaii as an outlier, a much lower correlation coefficient results, of R-squared 0.546.

UPDATE - 7/7/2016:  The graph shown below as Figure 3 is a repeat of Figure 2 above, with the highest (in red) and lowest (in green) states shown, as their average price's deviation from the national trend line.   California, the green circle at top left, is 2 cents below the trend.  Other states substantially below the trend include Maine, Colorado, Illinois, Utah and Montana. Those states with the highest deviation above the trend are Alabama, South Carolina, Tennessee, Mississippi, Connecticut, Louisiana, Maryland, and Texas.  -- end update
Figure 3 - Showing individual states
with greatest deviation from trend
as colored circles

Roger E. Sowell, Esq.
Marina del Rey, California
copyright (c) 2016 by Roger Sowell - all rights reserved

Saturday, July 2, 2016

Why California Electricity Costs More than US Average

Subtitle:  Mild Climate and Large Population Contribute to Prices

One of the more amusing aspects of writing a blog and commenting on other blogs is the almost unending stream of false information and wrong beliefs one encounters.   As former President Reagan said, "It's not that our . . . friends don't know anything, it's that so much of what they know just isn't so."  In this case, these people get to vote, and make their opinions known to elected officials, so it is somewhat important that what "just isn't so" gets pointed out.  Hence, this post on the disparity between US average electricity prices and the higher prices in California.   The facts show that California residential electricity use is below the national average, and the price per kWh consumed is slightly above average.  The reason for the higher price is low electricity consumption in a mild climate, by a very large number of customers, approximately 15 million customers. 

The common wisdom (that "just isn't so") is that California electricity prices are 1) higher than the rest of the country, 2) higher than they should be, and 3) higher because of stupid California policies to build renewable energy plants such as solar and wind.   Each of those three things are addressed in turn below. 

Higher Than Rest of US

Figure 1
California residential electricity is approximately 25 percent higher than average, but not the highest in the country.  Data from EIA for 2014 shows that California is 9th highest, that is, 8 states have higher residential electricity prices.  

In tabular form, the states with highest residential rates and their 2014 prices in cents/kWh were:

CA 16.25 
RI 17.17 
MA 17.39 
VT 17.47 
NH 17.53 
AK 19.14 
CT 19.75 
NY 20.07 

HI 37.04

Those are Rhode Island, Massachusetts, Vermont, New Hampshire, Alaska, Connecticut, New York, and Hawaii.   The same data is shown in Figure 2, below, as a bar chart. 

Figure 2
What is also true of California electricity prices is that they have been a bit higher than the US average for many years.   Even in the late 1970s and early 1980s, it was common knowledge in the chemicals and petroleum industries that electricity prices in California were higher than in most other states.   

Therefore, it can be seen from the above that California residential electricity prices are a bit higher than the US average, but by no means are the highest in the US 50 states. 

Higher Than Should Be

California residential electricity prices are where they are, and where they should be, due to a number of factors.   The most important factor is the state has a large population, 38 million people with 15 million residential customers as of 2014, but has very low electricity consumption per customer.  The low consumption per customer is due to the mild climate with low humidity.  Or, as the EIA states, "In most of the more densely populated areas of the state, the climate is dry and relatively mild. More than two-fifths of state households report that they do not have or do not use air conditioning, and almost one-seventh do not have or do not use space heating. Residential energy use per person in California is lower than in every other state except Hawaii."    Things have changed, but only slightly, since EIA wrote that, as Maine has barely edged out California for second place in residential electricity use per customer.  

The second important factor, after the mild, dry climate, is the large infrastructure for transmission and distribution that must be built over mountainous areas within the state.  In contrast to the nearest state in size and population, Texas, California has many more mountainous areas where transmission and distribution costs are much greater.  

Combined, a low per-customer electricity use and large, costly network or grid requires that each kWh sold command a higher price to pay for the grid's assets.  The utilities are allowed a 10 percent return on capital employed, so smaller volume of electricity sold must command a higher price.  

Finally, the 16 cents/kWh and 562 kWh/month, on average, yields a lower electric bill for the average customer compared to the US average.   The average bill for a California customer is only $91 per month, compared to the average for the US at $114 per month. 

The data for all states and DC are shown below, in kWh/month:  (Note, US average is 911.3 kWh/month)

Figure 3
  HI 506.4 
 ME 549.4 
 CA 561.8 <====
 VT 568.5 
 RI   583.0     
 NY 591.0 
 AK 605.1 
 MA 614.9 
 NH 619.4 
 NM 633.4 
 MI 653.6 
 NJ   669.7 
 CO 687.4 
 WI   694.4 
 DC 721.5 
 CT 729.7 
 IL    745.2 
 UT 746.7 
 MN 809.6 
 MT 853.8 
 PA    853.9 
 WY 863.2 
 IA   891.4 
 NV 894.2 
 OH 901.3 
 US 911.3 
 KS 928.0 
 OR 929.5 
 DE 949.8 
 ID    982.1 
 WA 1,005.5 
 IN 1,008.6 
 AZ 1,012.7 
 NE 1,022.4 
 MD 1,024.9 
 SD   1,045.6 
 FL   1,092.3 
 MO 1,094.8 
 NC 1,135.7 
 OK 1,137.7 
 AR 1,142.6 
 GA 1,151.5 
 WV 1,158.0 
 TX 1,158.1 
 VA 1,171.5 
 KY 1,177.3 
 SC 1,186.6 
 ND 1,239.6 
 MS 1,247.9 
 AL   1,264.7 
 TN 1,285.8 
 LA 1,291.4 

Higher Due to Renewable Energy Policies

This third "just isn't so" reason is easy to debunk after showing in point 2, above, that California residential electricity prices are not higher than they should be, nor higher than the US average.  As shown above, both the average monthly bill, and the consumption in kWh/month are less than the US average.  In fact, the average consumption per customer is third lowest out of 50 states plus the District of Columbia, DC. 

Yet, the impact of renewable energy policies in California may have some small impact on electricity prices.  Solar power, and wind power are addressed separately. 

Solar Power

Solar power, as shown earlier on SLB, had almost zero impact in California as little as 5 years ago.  Only in the past 5 years, since 2011, has solar power been added at the grid scale.  At present, there is almost 8,000 MW of solar power installed, almost all of which is PV.  The remainder is solar thermal.   The contribution of solar power is small, at approximately 6 to 7 percent of annual power sales.  It is clear, therefore, that the impact of solar power could not be a factor before 2011, yet California prices (see Figure 1) were 25 to 30 percent higher than the national average since 1990. 

Wind Power

The contribution of wind power in California has increased from 1.5 percent in 2001 to approximately 6 percent in 2014 of all electricity generated in-state, per the California Energy Commission data.   The fact is that wind resources in the state are few in number and below average in output, as measured by percent of installed capacity.  California wind turbines produce approximately 22 to 26 percent of installed capacity, compared to the Great Plains states of 45 to 42 percent of installed capacity.  Essentially, the wind blows stronger and more steady in the Great Plains states.    

It can be seen, then, that wind power contributes only a small fraction of total electricity in the state, and the electricity prices are higher due to low average consumption and a large asset base.  There can be no validity to the argument that policies on wind energy cause California electricity prices to be higher than the US average. 

Roger E. Sowell, Esq.
Marina del Rey, California

copyright (c) 2016 by Roger Sowell - all rights reserved