Repowering older wind turbines, which involves replacing aging turbines or components, is becoming more common in the United States as the turbine fleet ages and as wind turbine technology advances. Newer turbines tend to be larger and installed at greater heights, allowing for more capacity per turbine. About 12% of the wind turbines in the United States were installed before 2000, but these turbines make up only 2% of the installed wind electricity generating capacity.
Federal production tax credits provide an incentive to increase electricity generation from existing wind turbines. In December 2015, the production tax credit (PTC) was extended until the end of 2019. The four-year extension and legislated phase-out of the PTC is expected to encourage many asset owners to repower existing wind facilities to requalify them to receive another 10 years of tax credits. A facility may still qualify for the PTC as long as at least 80% of the property’s value is new. This provision allows many owners to repower existing turbines without completely replacing them.
Fully repowering wind turbines involves decommissioning and removing existing turbines and replacing them with newer turbines at the same project site. Full repowering has mostly occurred in California, where many turbines were installed at high-wind sites before 1990.
Partial repowering involves leaving some portion of the existing wind turbine and replacing select components. By partially repowering, owners can increase hub heights and rotor diameters to produce more energy.
Although wind turbines are designed with lifespans of between 20 and 25 years, wind capacity factors decline with age as mechanical parts degrade, according to the U.S. Department of Energy’s Wind Technologies Market Report. The United Kingdom’s Engineering and Physical Sciences Research Council in 2014 indicated that, on average, the output of wind turbines declines by 1.6% each year. Repowering can increase the output of a wind facility, improve reliability, and extend the life of a facility by taking advantage of advances in wind turbine technology.
Newer turbines tend to rotate much more slowly and quietly than older, smaller turbines, turning at 10 to 20 revolutions per minute (rpm) instead of 40 to 60 rpm. Slower wind turbine rotations alleviate issues such as bird mortality and shadow flicker.
Repowering generally requires significantly less investment compared with new projects. However, repowering wind turbines does present some challenges. For example, the risk of failure may increase when reusing components such as towers and foundations that were designed for smaller turbines. Other challenges may include renegotiating power purchase agreements, interconnection agreements, and leases.
According to General Electric (GE), the largest wind turbine installer in the United States, repowering wind turbines can increase the fleet output by 25% and can add 20 years to turbine life from the time of the repower. General Electric has repowered at least 300 wind turbines, and the company expects this market to grow. MidAmerican Energy recently awarded a contract to GE Renewable Energy to repower as many as 706 older turbines at several wind farms in Iowa. After repowering, each turbine is expected to generate between 19% and 28% more electricity.
The National Renewable Energy Laboratory (NREL) has indicated that annual U.S. wind repowering investment has the potential to grow to $25 billion by 2030. EIA data indicate that three projects are currently planned for repowering: Mendota Hills, LLC in Illinois and Sweetwater Wind 2 LLC in Texas are scheduled for repowering in 2018, and Windpark Unlimited 1 in California is scheduled for repowering in 2022.
In addition, Rocky Mountain Power has announced its intent to repower wind turbines in Wyoming and is currently awaiting a public hearing on the issue. NextEra Energy is planning to repower two wind farms in Texas by the end of this year.
More information about electric generators in the United States is available in EIA’s Annual Electric Generator Report. The early release of the 2016 version of this report was made available in August; the final version is scheduled for release in November.
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It has been 21 years since Japanese upstream firm Inpex signed on to explore the Masela block in Indonesia in 1998 and 19 years since the discovery of the giant Abadi natural gas field in 2000. In that time, Inpex’s Ichthys field in Australia was discovered, exploited and started LNG production last year, delivering its first commercial cargo just a few months ago. Meanwhile, the abundant gas in the Abadi field close to the Australia-Indonesia border has remained under the waves. Until recently, that is, when Inpex had finally reached a new deal with the Indonesian government to revive the stalled project and move ahead with a development plan.
This could have come much earlier. Much, much earlier. Inpex had submitted its first development plan for Abadi in 2010, encompassing a Floating LNG project with an initial capacity of 2.5 million tons per annum. As the size of recoverable reserves at Abadi increased, the development plan was revised upwards – tripling the planned capacity of the FLNG project to be located in the Arafura Sea to 7.5 million tons per annum. But at that point, Indonesia had just undergone a crucial election and moods had changed. In April 2016, the Indonesian government essentially told Inpex to go back to the drawing board to develop Abadi, directing them to shift from a floating processing solution to an onshore one, which would provide more employment opportunities. The onshore option had been rejected initially by Inpex in 2010, given that the nearest Indonesian land is almost 100km north of the field. But with Indonesia keen to boost activity in its upstream sector, the onshore mandate arrived firmly. And now, after 3 years of extended evaluation, Inpex has delivered its new development plan.
The new plan encompasses an onshore LNG plant with a total production capacity of 9.5 million tons per annum. With an estimated cost of US$18-20 billion, it will be the single largest investment in Indonesia and one of the largest LNG plants operated by a Japanese firm. FID is expected within 3 years, with a tentative target operational timeline of the late 2020s. LNG output will be targeted at Japan’s massive market, but also growing demand centres such as China. But Abadi will be entering into a far more crowded field that it would have if initial plans had gone ahead in 2010; with US Gulf Coast LNG producers furiously constructing at the moment and mega-LNG projects in Australia, Canada and Russia beating Abadi’s current timeline, Abadi will have a tougher fight for market share when it starts operations. The demand will be there, but the huge rise in the level of supplies will dilute potential profits.
It is a risk worth taking, at least according to Inpex and its partner Shell, which owns the remaining 35% of the Abadi gas field. But development of Abadi will be more important to Indonesia. Faced with a challenging natural gas environment – output from the Bontang, Tangguh and Badak LNG plants will soon begin their decline phase, while the huge potential of the East Natuna gas field is complicated by its composition of sour gas – Indonesia sees Abadi as a way of getting its gas ship back on track. Abadi is one of Indonesia’s few remaining large natural gas discoveries with a high potential commercialisation opportunities. The new agreement with Inpex extends the firm’s licence to operate the Masela field by 27 years to 2055 with the 150 mscf pipeline and the onshore plant expected to be completed by 2027. It might be too late by then to reverse Indonesia’s chronic natural gas and LNG production decline, but to Indonesia, at least some progress is better than none.
The Abadi LNG Project:
Headline crude prices for the week beginning 10 June 2019 – Brent: US$62/b; WTI: US$53/b
Headlines of the week
Midstream & Downstream
A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.
That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.
That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.
Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.
Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?
Expectations at the 176th OPEC Conference