Government cuts onshore wind deployment by 50 per cent and solar farms to zero

Yesterday the Government announced what amounts to a cut in deployment of onshore wind power by 50 per cent and a cut in the amount of large scale solar farms that can be deployed to more or less zero.

Since 2010 onshore wind has been installed at a rate of around 1000 MW (1GW) a year. But yesterdays announcement, with only �50 million per year of extra money allocated for new projects for so-called 'mature' technologies such as onshore wind and solar farms, means that there is not enough money for more than around 500 MW of onshore wind to be deployed a year until 2020. This means that only around 2500 MW,  less than half the 7000 MW of consented onshore windfarms (and none of the many proposed solar farms,) can be deployed.

(Note: �50 million a year will fund about 1.1TWh new electricity a year assuming around �45 per MWh is needed to make up the difference between a wholesale electricity price of �45-50 per MWh and a cost of �90-95 per MWh set by the Government to be paid to onshore windfarms. 1.1 TWh a year will be generated from around 500 MW of wind power).

The Solar Trade Association has highlighted the effective end of the large solar farm deployment programme. Less attention has been paid to the cuts in onshore windfarms, although RenewableUK have expressed their disappointment in the Government announcement. Both solar and wind will be competing for the same pot of money, and despite considerable falls in cost in recent years, solar is still likely to be undercut by onshore wind.

This policy speaks volumes about the Liberal Democrats lack of influence, and the extent of the policy victory won by Conservative opponents of onshore large scale renewables. Instead the Conservatives are succeeding in their policy of mainly funding only some of the more expensive renewables, namely  some offshore wind projects and some rooftop solar pv schemes.

This result falls in line with my earlier projections that the UK will miss meeting its EU renewable energy target by a large margin. See:

http://realfeed-intariffs.blogspot.co.uk/2014/06/uk-on-track-to-miss-eu-renewables.html
and the government's announcement of a 'boost' to renewable energy at:

https://www.gov.uk/government/publications/indicative-cfd-budget-notice-for-the-autumn-2014-cfd-allocation-round

No commentsRead more

Nuclear power: will it continue to fail as 'baseload' plant?

Nuclear power has a lot of the best Public Relations (PR) workers in the world, but nothing they can do can obscure the difference between the facts of UK nuclear performance and what is now wishful consensus thinking of the UK state. Should one get too annoyed with this? Or just smile? There is a cynical argument that one might as well not bother campaigning against nuclear power if you don't like it because its best enemy and destroyer is itself.

In Britain nuclear's recent record for availability is not outstanding - 65 per cent according to the Digest of UK Energy Statistics for the year 2008-2012. Remember this is for a technology that is supposed to be on for as much as the time as is possible, and the bulk of the downtime on the  figures is accounted for by unplanned, often sudden, outages that jeopardise electricity grid stability. At least you can usually make a reasonable prediction about wind output for particular windfarm, but you cannot predict sudden unplanned outages from nuclear. But we are told that nuclear is necessary as a 'baseload' plant. Well I suppose it is baseload as much as it operates some of the time, but not really if it often does not work when you want it to!

Of course the most modern plant, Sizewell B, has an average availability of around 83 per cent, and this is often held up as the comparator for the new nuclear developments planned by EDF. But Sizewell B was a very well known technology (PWR) when it was constructed, although despite that, it cost a lot more than was projected before construction started.

Hinkley C is a new, untried nuclear technology, the European Pressurised Reactor (EPR). It could well end up having at least some of the difficulties in operation as the British designed AGR nuclear plant. Ominously they took a long time to build (like the EPRs). The augurs are not good.

So we have a double risk - the usual likely outcome that nuclear construction costs will be even higher than those now projected (with the UK taxpayer guaranteeing to pick up a big tab of cost overruns) and the risk that the new power station(s) will struggle to generate much electricity, which will mean that the UK taxpayer will have to pay out even more money. Of course, without the effective UK Government blank cheque and the plant being built by a consortium of foreign state owned companies able to bear much greater risk than private companies we would  not have any Hinkley C deal at all.

It may well be that EDF will end up building only one (1.6 GW) of the twin reactor plant at Hinkley. There is, in reality, a very good chance that this will be the only one that will ever be built in the UK. By 2023 when the plant is supposed to be completed the project will no doubt be late, experiencing considerable financial difficulties, receiving more guarantees and more future support from UK electricity consumers than are planned at the moment. At the same time wholesale electricity prices will probably be less than they are now. Gas prices are sinking. This will make the Hinkley C deal look even worse than it looks now.

People complain now that renewable plant are being paid money that will increase electricity prices for many years. Yet the renewable plant funded by the Renewables Obligation cannot receive any premium prices beyond 2027. Future renewable projects will be on premium prices for only 15 years. On the other hand Hinkley C may have barely started operating by 2027 and will still have 35 years of premium prices to enjoy after that.

Of course you would think that the EPR programme is swimming ahead without problems. But all of the EPRs being built are increasingly behind schedule. The plants in France and Finland were begun in 2005, and the plant in China was begun in 2008. Yet the EDF PR teams manage to promote this is a success. The project, in China, at Taishan, receives glowing marks for progress. See
http://www.ft.com/cms/s/0/1061f90a-e272-11e3-89fd-00144feabdc0.html#axzz3869kNYCY

Yet, they say it is two years behind schedule. We can rely on it not taking any longer of course, because EDF says so! If they cannot get a nuclear power plant finished on time in a tightly controlled state like China, how are they going to do it in the UK?

Of course, when the Hinkley C plant proves to be uncompleted, financially ever more disastrous, and unnecessary by 2023 then we are unlikely to continue a policy of giving a blank cheque to nuclear power. And without that blank cheque it won't happen. But, I am not totally cynical. I think it is worthwhile campaigning against this, because otherwise resources could have been much better diverted elsewhere.

For some statistics and coverage see:

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/279546/DUKES_2013_Chapter_5.pdf

http://www.iaea.org/pris/CountryStatistics/ReactorDetails.aspx?current=263

http://www.telegraph.co.uk/finance/newsbysector/energy/10688788/EDF-to-miss-its-own-deadline-for-Hinkley-Point-nuclear-decision-as-EC-state-aid-investigation-drags-on.html

No commentsRead more

The Untold Story on U.S. Foreign Oil Dependency.

Oil Use

Background Points for Today's Blog: (1) In discussing U.S. foreign oil dependency, two measures are used: Gross Imports % -- Total Imports/Total Petroleum Used. Net Imports % -- (Imports minus Exports)/Total Petroleum Used. (2) Under laws imposed after the Arab oil embargo of the 1970s, U.S. companies can export refined fuel such as gasoline and diesel but not crude oil itself.

Typically when U.S. foreign oil dependency is being discussed in the Media, it will be the net imports number that is cited. Using this benchmark, the EIA states "In 2012, about 40% of the petroleum used by the United States was imported from foreign countries -- the lowest level since 1991". For 2013 (using non-finalized data from the EIA), estimated net imports were 33% -- the lowest level since 1986.

Of the total petroleum used in 2013, an estimated 52% came from foreign countries (gross imports); 19% was exported (in refined products such as gasoline); with resulting net imports of 33% (52% minus 19%).

---

¹ The above 2013 values are not official. In 2012 per the EIA, about 57% of the crude oil processed in U.S. refineries was imported.

Historical Perspective: The significance between gross versus net imports is a relatively recent development. For decades prior to the current boom in domestic oil production, yearly U.S. petroleum exports were very constant at approximately 5% of total supply. However, during the past 7 years, two things have dramatically changed:

U.S. field production of oil and other petroleum liquids has more than doubled from 5.5 million bpd (2006) to 11.3 million bpd (April 2014).

Petroleum exports (e.g., refined products of gasoline, diesel) have increased almost 400%.

---

bpd -- barrels per day.

Percentage of U.S. Petroleum Exports

Thus, while it may be technically correct that U.S. dependence on foreign oil (defined using the benchmark of net imports) is at the lowest level in almost 30 years, the composition of this benchmark measure is very different between 2013 and 1986. Using a gross imports benchmark, the U.S. is much more dependent today on foreign oil.

	1986	2013	Change
Gross Imports:	38%	52%	+14%
Exports	05%	19%	+14%
Net Imports	33%	33%	-

In a world where all oil was the same (type and price), use of net imports would be totally appropriate. After all, this would be an example of American refining technology ingenuity where we import oil, refine and then export it into world markets better (lower costs) than anybody else. However, this isn't what's happening. Not all oil is the same type (light versus heavy crude) or priced the same (U.S. versus World oil prices).

Understanding Some Oil Basics 101: In long-term forecasts through 2040, the Department of Energy projects that U.S. dependency on imported oil (net imports) will stubbornly be above +30%.

Historical and Projections of U.S.
Oil Production & Consumption:So with the U.S. oil boom, why are we importing so much foreign oil? The answer is found in the fact that not all crude oil is created the same. It can be heavy or light, sour (high sulfur content) or sweet.

With the exceptional increase in U.S. oil production from tight shale formations/fracking (e.g., North Dakota, Texas, etc.) there is good and bad news. Most of this oil is high quality light crude, relatively easy to refine in refineries that are not terribly complex. The bad news is many U.S. refineries (especially on the West Coast and Atlantic Seaboard) can not use this lighter oil. Prior to the shale boom, U.S. refiners spent billions of dollars to configure their plants for heavier and sour foreign oils (from Canada and OPEC countries of Venezuela, Saudi Arabia, and Iraq).

The below chart from the EIA illustrates this above point. While U.S. imports of light crudes have been reduced dramatically in recent years (displaced by new oil production from North Dakota, Texas, etc.), imports of heavy crudes have remained constant.

Digging Deeper into the Data: Contradictory to what is reported in the Media, OPEC (not Canada) remains the largest oil importer to the U.S. While statements that Canada is the largest crude oil importer is not a "pants on fire" misrepresentation -- it is "Spin Doctors" at work. Although it is again technically correct that Canada is the largest single country importer, this fails to recognize that OPEC (comprised of 12 countries) is a cartel and operates as a single entity.

U.S. Petroleum Imports (2013)OPEC is the largest Importer to the U.S.

U.S. Petroleum Exports (2013)U.S. is becoming the Oil Refiner for the World.

In addition to gasoline exports, a major growth market for U.S. refiners is diesel fuel (especially Europe and South America). A large number of European refining plants have closed, as they can not compete with U.S. produced diesel.

U.S. Petroleum Exports: As discussed in prior blogs, a major reason in the unprecedented surge in U.S. petroleum exports is the price difference between U.S. and Internationally traded crude oil.

Current Oil Prices:
U.S. (WTI) Versus International (Brent)

During the current U.S. oil boom, the benchmark price for domestic oil (West Texas Intermediate -- WTI) has been below the international benchmark for crude (Brent). As a result, many U.S. refineries have been using lower cost WTI priced oil, refining it (e.g., gasoline, diesel), and then pricing the refined products into international markets (where competing foreign refiners must pay the higher cost Brent price for crude oil).

Since it is legal for refined oil products to be exported, a refiner's access to lower cost domestic oil does not necessarily translate to cheaper gas for the U.S. driver and consumer. A U.S. refiner could as easily sell their product to the international market if that would maximize their profit. This explains why even with dramatic increases in domestic crude oil production (especially in the last 3 years), U.S. gasoline prices have basically remained unchanged.

Yearly Average of U.S. Gas Prices Putting the Pieces Parts Together: While Politicians and Talking Heads make environmental issues (e.g., Keystone Pipeline, Global Warming, ethanol use²) the center of the U.S. Oil Policy debate -- here is what's really going on:

---

² As this Blog continues to point out, the current blending of ~10% ethanol in gasoline achieves well established health science benefits (lead removal, oxygenate for cleaner air).

Drivers Of U.S. "Net Imports" Oil Dependence
Note: Notice that there are no major oil pipelines to the West Coast or Atlantic Seaboard.

Foreign Oil Imports: Using 20/20 hindsight, the crystal ball of many U.S. refiners (on the West Coast and Atlantic Seaboard) was not very good. They did not foresee the magnitude of the current domestic oil boom coming -- investing billions to configure their refineries to use foreign heavy oil. These refineries are simply not going to walk away from this capital investment and re-configure their plants yet again to use domestic light crude in making gasoline.

Refined Products Exports: Many U.S. Refiners (along the Gulf Coast) use lower cost domestic oil (WTI), but price their products (gasoline, diesel) into an international gasoline and diesel market based heavily on more expensive Brent. The cheaper WTI becomes in relation to Brent, U.S. refiners make more profits and increase world market share.

Facebook:

---

Related News Stories:
U.S. Oil Boom Drives Gasoline & Diesel Exports -- (Fox Business News).
Impact of Lifting Ban on U.S. Crude Oil Exports -- (Wall St. Journal).
World Refinery Margins -- (BP Energy Outlook).
Technical Chemical Engineering Discussion: Why U.S. Gasoline Refiners use so much Imported Heavy Oil
Where the U.S. got its oil in 2015 -- (Fortune Magazine, Robert Rapier).

JGHG5CK4C5MZ

No commentsRead more