Top 10 Cleantech Subsidies and Policies (and the Biggest Losers) – Ranked By Impact

We all know energy is global, and as much policy driven as technology driven.

We have a quote, in energy, there are no disruptive technologies, just disruptive policies and economic shocks that make some technologies look disruptive after the fact.  In reality, there is disruptive technology in energy, it just takes a long long time.  And a lot of policy help.

We’ve ranked what we consider the seminal programs, policies and subsidies globally in cleantech that did the helping.  The industry makers.  We gave points for anchoring industries and market leading companies, points for catalyzing impact, points for “return on investment”, points for current market share, and causing fundamental shifts in scale, points for anchoring key technology development, points for industries that succeeded, points for industries with the brightest futures.  It ends heavy on solar, heavy on wind, heavy on ethanol.  No surprise, as that’s where the money’s come in.

1.  German PV Feed-in Tariff – More than anything else, allowed the scaling of the solar industry, built a home market and a home manufacturing base, and basically created the technology leader, First Solar.

2. Japanese Solar Rebate Program – The first big thing in solar, created the solar industry in the mid 90s, and anchored both the Japanese market, as well as the first generation of solar manufacturers.

3. California RPS – The anchor and pioneer renewable portfolio standard in the US, major driver of the first large scale, utility grade  wind and solar markets.

4. US Investment Tax Credit for Solar – Combined with the state renewable portfolio standards, created true grid scale solar.

5. Brazilian ethanol program – Do we really need to say why? Decades of concerted long term support created an industry, kept tens of billions in dollars domestic.  One half of the global biofuels industry.  And the cost leader.

6. US Corn ethanol combination of MTBE shift, blender’s, and import tariffs – Anchored the second largest global biofuels market, catalyzed the multi-billion explosion in venture capital into biofuels, and tens of billions into ethanol plants.  Obliterated the need for farm subsidies.  A cheap subsidy on a per unit basis compared to its impact holding down retail prices at the pump, and diverted billions of dollars from OPEC into the American heartland.

7. 11th 5 Year Plan  – Leads to Chinese leadership in global wind power production and solar manufacturing.  All we can say is, wow!  If we viewed these policies as having created more global technology leaders, or if success in solar was not so dominated by exports to markets created by other policies, and if wind was more pioneering and less fast follower, this rank could be an easy #1, so watch this space.

8. US Production Tax Credit – Anchored the US wind sector, the first major wind power market, and still #2.

9. California Solar Rebate Program & New Jersey SREC program – Taken together with the RPS’, two bulwarks of the only real solar markets created in the US yet.

10. EU Emission Trading Scheme and Kyoto Protocol Clean Development Mechanisms – Anchored finance for the Chinese wind sector, and $10s of Billions in investment in clean energy.  If the succeeding COPs had extended it, this would be an easy #1 or 2, as it is, barely makes the cut.


Honorable mention

Combination of US gas deregulations 20 years ago and US mineral rights ownership policy – as the only country where the citizens own the mineral rights under their land, there’s a reason fracking/directional drilling technology driving shale gas started here.  And a reason after 100 years the oil & gas industry still comes to the US for technology.  Shale gas in the US pays more in taxes than the US solar industry has in revenues.  But as old policies and with more indirect than direct causal effects, these fall to honorable mention.

Texas Power Deregulation – A huge anchor to wind power growth in the US.  There’s a reason Texas has so much wind power.  But without having catalyzed change in power across the nation, only makes honorable mention.

US DOE Solar Programs – A myriad of programs over decades, some that worked, some that didn’t.  Taken in aggregate, solar PV exists because of US government R&D support.

US CAFE standards – Still the major driver of automotive energy use globally, but most the shifts occurred before the “clean tech area”.

US Clean Air Act – Still the major driver of the environmental sector in industry, but most the shifts occurred before the “clean tech area”.

California product energy efficiency standards – Catalyzed massive shifts in product globally, but most the shifts occurred before the “clean tech area”.

Global lighting standards /regulations – Hard for us to highlight one, but as a group, just barely missed the cut, in part because lighting is a smaller portion of the energy bill than transport fuel or generation.


Biggest Flops

US Hydrogen Highway and myriad associated fuel cell R&D programs.  c. $1 Bil/year  in government R&D subsidies for lots of years,  and 10 years later maybe $500 mm / year worth of global product sales, and no profitable companies.

Italian, Greek, and Spanish Feed in Tariffs – Expensive me too copycats, made a lot of German, US, Japanese and Chinese and bankers rich, did not make a lasting impact on anything.

California AB-32 Cap and Trade – Late, slow, small underwhelming, instead of a lighthouse, an outlier.

REGGI – See AB 32

US DOE Loan Guarantee Program – Billion dollar boondoggle.  If it was about focusing investment to creating market leading companies, it didn’t.  If it was about creating jobs, the price per job is, well, it’s horrendous.

US Nuclear Energy Policy/Program – Decades, massive chunks of the DOE budget and no real technology advances so far in my lifetime?  Come on people.  Underperforming since the Berlin Wall fell at the least!


Small Hydro Emerging as Viable Sector for Renewable Energy Development

by David Niebauer

With many states adopting renewables portfolio standards (RPS) and the prospect of a federal RPS somewhere on the horizon, more attention is being given to hydroelectric power generation.  Renewable resources such as sun, wind and water, are those that can be harvested in a sustainable manner to provide the electric power that our society depends on. Water (or gravity moving water) has received less attention from project developers than wind and solar.  But that may be changing.

Approximately 18% of the total world energy supply is hydroelectric. But of course, all hydro is not created equal.  The bulk is large hydro, which employs dams and weirs that disrupt the environment in unalterable ways.  Most hydroelectric facilities are not considered “renewable” – at least not by environmentalists.  Large man-made reservoirs change habitats forever and are often blights on the natural settings in which they are built.

Small hydro – facilities that generate up to 30 MW – can be developed without harming the environment.  So called run-of-river facilities are designed to take advantage of flowing water in rivers and streams in such a way as to have minimal impact on fish habitats and natural settings.  Also, many of the dams in the US are not powered. These facilities, where the environmental impact of the dams cannot be undone, are ripe for small hydro development.  In September 2009, U.S. Energy Secretary Steven Chu said the hydro industry could add 70,000 MW of capacity by installing more efficient turbines at existing dams, increasing the use of pumped-storage projects and encouraging the use of run-of-river turbines. That capacity is equivalent to 70 nuclear plants or 100 coal-fired plants.

Until recently, the major impediment to the development of small hydro has been regulatory.  There are two major federal agencies responsible for hydroelectric power development – Federal Energy Regulatory Commission (FERC) and the US Army Corp of Engineers – neither of which are known for their nimble, user-friendly ways.  While wind and solar projects can often avoid federal regulation, relying instead on individual state authority, FERC is responsible for licensing all non-federal government hydroelectric projects that touch navigable waterways or affect interstate commerce (i.e., if the system is to be connected to a regional electric transmission grid).  Horror stories abound of FERC applying the same licensing and fee structure to a 500kW run-of-river system as it would to a 500MW hydroelectric dam project.  This appears to be changing.

FERC has been investigating ways to simplify the process of obtaining small hydropower licenses and exemptions and, on August 31, 2010, unveiled its Small/Low Impact Hydropower Program Internet site, explaining how developers can quickly and efficiently win FERC approval to build and operate small hydro projects.  The website is part of a FERC plan to expedite small hydro projects.  Another important component is an initiative to enter into memoranda of understanding with state governments to advance FERC exemptions for small hydro projects in those states.  In August 2010, FERC announced a pilot program with the State of Colorado, and has entered into similar MOUs with the states of Washington, Oregon, California and Maine.

Developers appear to be rising to the challenge.  FERC issued 50 preliminary permits to study small sites in 2009, compared to 15 in 2007.  There is money available at both the state and federal level, mostly untapped, in the form of low interest loans, and investors appear to be warming to the sector. An Internet search uncovered at least one developer engaged in a strategy of rolling-up small hydro assets, and undoubtedly more will follow.  A logical approach for a developer would be to acquire a portfolio of revenue-generating assets as a way to demonstrate satisfactory investor returns.  From this base, a developer should be able to build profitable projects at existing unpowered dam sites, and to pursue run-of-river and pumped storage opportunities.

Much attention has been paid to wind turbines and solar PV as ways to harness nature’s abundant energy resources.  Hydroelectric power has often been overlooked due primarily to its scale and the high regulatory hurdles facing developers.  That may be changing in regard to small hydro.  The country has countless unpowered dams that are ripe for development.  This, combined with the prospect of streamlined permitting and exemption processes at FERC for run-of-river and pumped storage facilities, has developers exploring ways to advance small hydro in the service of the nation’s renewable energy goals.

David Niebauer is a corporate and transaction attorney, located in San Francisco, whose practice is focused on financing transactions, M&A and cleantech.



California TREC Decision Side-steps Energy Infrastructure of the Future

By David Niebauer

Most of the discussions of tradable renewable energy credits (TRECs) in California revolve around the extent to which the State’s large utilities can use TRECs for compliance with the California renewables portfolio standard (RPS) program.  The utilities would like a free hand to use as many RECs as possible, derived from sources both in-State and out-of-State – presumably RECs will be easier and cheaper to acquire than new renewable generating facilities are to build.  The interests of the utilities are balanced by those of rate-payers as well as policy initiatives, such as AB 32.  These interests move sometimes in opposite directions, one toward less expensive retail energy and one toward more environmentally sustainable energy generation.

As the revised decision on TRECs winds its slow and tortuous way through the California Public Utilities Commission (CPUC), it is becoming clear that there will be a price cap ($50) and there will be a limit on use (30% likely) and that the cap and limit will expire at the end of 2013 “to give Energy Division sufficient time to develop [an] evaluative framework” to make sure the system works without snafu.  See procedural trail to CPUC Proceeding R06-02-012.

Lost in the shuffle, however, is what many believe will be the energy infrastructure of the future – distributed generation (DG).  The California Energy Commission (CEC) defines DG in the California Distributed Energy Resource Guide as “small-scale power generation technologies (typically in the range of 3 to 10,000 kW) located close to where electricity is used (e.g., a home or business) to provide an alternative to or an enhancement of the traditional electric power system.” The term “distributed” is borrowed from the computer industry where it has long been recognized that widely disbursed or “distributed” computing is more economic, more efficient and more secure than centralized systems.

In energy generation, “distributed” means fewer centralized generation facilities and little or no transmission.  Utilities don’t like it, naturally, because a fully implemented distributed generation infrastructure would obviate the need for a publicly subsidized electric utility monopoly – the institution feels justifiably threatened.  Whether DG will ever supply all of our energy needs is a question for the future.  In the meantime, policy makers should guard against steering the market away from its proper implementation.

Because there are a number of technologies and a variety of ways to implement DG, the California Public Utilities Commission (CPUC) and the CEC have defined DG as those technologies and implementations that generate electricity on the “customer side of the meter”.   See the CEC’s Renewables Portfolio Standard Eligibility Guidebook (3d ed., December 2007), at 17-19. These would include home installations of solar photovoltaics (PV) and would also include commercial PV such as rooftop and ground-based solar being implemented by large energy users (food processing, cold storage, manufacturing, etc.) and others.  For this purpose, DG does not include solar rooftop programs being sponsored by the large utilities that utilize commercial rooftop space in order to generate energy that is then sold into the grid.  It is energy used on-site that does not require a central transmission and distribution system.

To some extent, DG has been an afterthought in the TREC considerations and decisions.  This is because the market is currently quite small compared with utility-scale projects.  However, it seems likely that DG is the next frontier in renewable energy generation.  As PV continues to drop in price, and new technologies are developed, more and more commercial enterprises will come to realize that generating their own energy from the sun (or from fuel cells or other new technologies) is simple, safe, and less expensive than being beholden to large utility monopolies.
The CEC is concerned that TRECs for DG would provide an excessive subsidy in light of current programs in place for such projects.  The CEC’s current position is as follows:

“Facilities that receive funding under the Energy Commission’s New Solar Homes Partnership program, Emerging Renewables Program, or Pilot Performance‐Based Incentive Program, under the CPUC‐approved Self Generation Incentive Program or California Solar Initiative, or any similar ratepayer‐funded program, and facilities that benefit from net metering programs or tariffs approved by the CPUC or any POU, are considered distributed generation and may not be certified as RPS‐eligible at this time.”  RPS Eligibility Guidebook p. 25.

However, as argued persuasively by the Solar Alliance in its comments on the revised RPS Eligibility Guidebook:  “given the reality that, as the incentives under the California Solar Initiative [and other programs] decline, the sale of TRECs is likely to become a critical means for financing distributed solar generation.” To meet the state’s aggressive RPS goals, it only makes sense to allow TRECs for DG.  The CPUC anticipates this eventuality as it takes great pains in the revised proposed decision of Commissioner Peevey to “clarify the relationship of [the CPUC’s] discussion of TRECs from DG sources to the CEC’s authority…to determine what resources are RPS eligible.”

The CEC has also stated “[t]he Energy Commission will not certify distributed generation [DG] facilities as RPS-eligible unless the CPUC authorizes tradable RECs to be applied toward the RPS.”  This pronouncement, combined with the revised proposed decision on TRECs, which will permit tradable RECs to be applied toward the RPS, will presumably make customer-side DG eligible for the sale and trading of TRECs, notwithstanding the CEC’s concern over excessive rate-payer subsidies.

The numbers for DG are small at present.  As pointed out by the CPUC, the California Solar Initiative (CSI) will have provided incentives for approximately 1,100 GWh by 2011.  At $50 per TREC, this would amount to only about $50 million State-wide in additional financing for solar DG projects (1 TREC = 1,000 kW hrs of renewable generation).  However these numbers are anticipated to grow significantly.

It’s useful to look at TRECs for DG from a commercial application perspective.  A 250 kW solar PV system can be expected to generate at least 300,000 kWh per year in a relatively high solar radiation area, such as the LA basin.  Even at the $50 per TREC cap set by the CPUC, this is still $15,000 per year in new financing for a commercial system.  At $200 per TREC, it amounts to $40,000 per year.  Assuming the facility owner could forward-sell these TRECs, even discounted to present value, this is a significant amount of money that could be used to finance installation and maintenance of the system over its useful life – especially in the face of declining or vanishing solar incentives.

We agree with the Solar Alliance and others who urge the PUC and the CEC to coordinate their agency actions so as to accommodate TRECs for DG and to do it soon.  Other states are way ahead of California in allowing RECs to stimulate the renewable energy markets.  For example, New Jersey, which has a specific solar set-aside, has allowed RECs for RPS compliance for a number of years.  Solar RECs sold at auction in New Jersey were recently trading for as much as $600 per REC (see  California cannot afford to continue to ignore the energy infrastructure of the future.

David Niebauer is a corporate and transaction attorney, located in San Francisco, whose practice is focused on clean energy and environmental technologies.

California Tradable RECs – Will They Ever Materialize?

by David Niebauer

California has led the nation in solar development on many fronts for a number of years, but there is one area where California has lagged significantly – the implementation of tradable renewable energy certificates (or TRECs).

As of this writing, there are five regional renewable energy tracking systems operating in North America, one national registry and three state systems. As early as June 2007, the California Energy Commission launched the Western Renewable Energy Generation Information System (WREGIS), which was designed to track renewable energy generation and create and track renewable energy certificates (RECs) for that generation. TRECs are an important tool for utilities in other states striving to meet their renewable portfolio standard (RPS) goals and help developers finance renewable energy projects in other parts of the country where TRECs are available. So why not in California?

The Basics

In California RECs are not yet tradable – all electric utility renewable energy purchases are “bundled” transactions. That is, the environmental attributes (e.g., RECs) are tied to, or bundled with, the energy itself. Therefore, the only way for utilities to comply with RPS requirements is to purchase renewable energy in bundled transactions from a qualifying renewable energy facility.

In States with unbundled or tradable RECs, electric utilities have two ways to meet with RPS goals: purchase renewable energy in bundled transactions (like in California) or purchase RECs on the open market. In States with TRECs the REC has been “stripped” from the energy and is traded separately. The energy is sold separately and is still supplied to the grid. The utility purchasing the REC may be and likely is completely different than the purchaser of the energy. Only the REC purchaser can count that energy toward its RPS goals.

Proponents of tradable RECs point out that the scheme will assist the State in achieving its RPS goal by balancing out geographical and transmission constraint differences from utility to utility. In California, for example, the State as a whole has considerable renewable resources, from geothermal to wind to solar – but these resources are not evenly distributed geographically throughout the State. Further, some areas with strong renewable resources have significant transmission constraints, making grid connection prohibitively expensive. A tradable REC regime would allow resources to be developed where cost and fit are most appropriate, and allow the environmental attributes (the RECs) to be traded among the utilities (and through intermediaries) to balance out these geographical and transmission constraint issues. As stated in the April 2006 California Public Utilities Commission (CPUC) Staff White Paper: “Importantly, under an unbundled and/or tradable REC framework, [a utility] can purchase RECs from renewable facilities largely irrespective of where those facilities are located or where the energy is ultimately delivered.”

From the energy developer’s perspective, RECs can provide an advantage for developing renewable energy sources. The ability to sell RECs in an unbundled transaction would mean that a developer would be able to negotiate with any utility or other buyer of RECs, rather than negotiating with only one utility in a bundled transaction. In states with TREC developers contract with one utility to provide energy at a relatively low cost and then sell the RECs to another utility or other buyer to enable his project to be economically viable. Where the developers must sell the energy and the REC to the same utility, the price of the energy might be too low to justify development. For this reason, tradable RECs can be a way to speed the development of renewable generation.

The California Log Jam
California has been taking slow, halting strides in the direction of permitting tradable RECs. In 2006 the California legislature passed Senate Bill (SB) 107, which gave the CPUC express authority to allow the use of tradable RECs for RPS compliance.
Three and half years later on March 11 2010 the CPUC issued a decision authorizing TRECs for RPS compliance in California (Decision10-030-021). The proposed scheme had a number of limitations but appeared to be a workable model. Most notable of the limitations was a maximum cap for IOUs of 25% of RPS compliance targets that could be met with TRECs. This limitation was to last only until the end of 2011 and was intended as a way to monitor the program before allowing unfettered use of TRECs. The other significant limitation was a price cap of $50 per REC. Again, this limitation was scheduled to expire at the end of 2011 unless the CPUC determined to extend the cap at that time based on further market studies.

The CPUC decision was made after conducting numerous workshops and receiving comments from interested parties. However, the entities that would have been most impacted by the Decision were not at all happy with the final outcome. Notably, the State’s IOUs and the Independent Energy Producers Association (IEP), whose members make up most of the merchant power producers in the State, filed objections and forceful motions to stay the decision. Prior to its implementation on May 6, only a few weeks after issuing the Decision, the CPUC granted an indefinite stay of Decision 10-03-021. This stay in still in effect.

The reasons for the stay, and the larger implications, are not at all clear. On its face, the stay was implemented in order to resolve objections raised by the IOUs and the IEP. Neither party liked the 25% limitation on use of TRECs to meet RPS requirements. Further, the IOUs, in particular, argued that the CPUC’s definition of a REC-only transaction would limit access to most out-of-state renewable resources, making implementation the TREC scheme unworkable.

Commissioner Grueneich’s Dissent

Commissioner Dian M. Grueneich filed a dissent to the stay that may shed some light on what is really going on. Commissioner Grueneich focused on the motion by the IOUs and claimed that the modifications urged by the IOUs would cause the “outsourcing of California’s renewable economy.” She points out that nothing had changed in the 60 days or so between the Decision and the Stay other than “the relentless lobbying by the utilities at this Commission and in Sacramento to overturn a decision they dislike.”

She continues:

“Since the RPS mandate was first signed into law, one message that has been repeated again and again from developers, from investors and from members of this Commission itself, is that market players need certainty and consistency in decision making in … order to make long term investments in California. This decision will disrupt renewable energy markets, threaten financing for existing and future projects, and compromise the careful work of the Governor’s office to ensure that renewable energy projects obtain their CEC permits and break ground expediently.”


Perhaps this is the (cynical) goal of the IOUs: to entangle the entire RPS movement in delay and uncertainty so that their own foot-dragging can be explained away and excused. Without clear guidance on a TREC program, the argument might go, how can they be expected to meet the State’s aggressive RPS goals? The IOUs have a long way to go to even comply with the 2010 RPS requirement of 20% renewable generation. In 2009, the IOUs collectively served 15.4% of their load with renewable energy. The CPUC estimates that the IOUs are expected to be at about 18% in 2010 and 21% in 2011 – assuming that existing contracts can be converted into operating facilities within that timeframe.

Or it may just be a bureaucratic quagmire that still requires time to work out. After all, the IOU’s fundamental argument in support of the stay, that out of state bundled transactions should not be defined as REC-only transactions and counted toward the 25% cap, makes sense.

California needs to get this right. Whatever system gets developed in California will be followed by other states, especially those in the WREGIS System, so a region-wide system must be supported by the final CPUC decision. We need a workable final decision soon so that we can move forward on the larger goal of lowering greenhouse gas emissions and building a truly sustainable energy infrastructure.

David Niebauer is a corporate and transaction attorney, located in San Francisco, whose practice is focused on clean energy and environmental technologies.

Irrigation Scheduling for Agricultural Crops: It’s Not Just a Flip of a Switch!

For this second post in the “Sustainable Agriculture on Cleantech Blog” series, I decided to invite Dave Doll, UC Cooperative Extension Farm Advisor, and fellow blogger at Almond Doctor Blog, to share his expert knowledge about irrigation management for agricultural crops.
Agricultural use of water within California use has been a media magnet these days. With the reductions of pumping into the California Aqueduct from the Delta, California in its third straight year of a drought, and an increasing population that is putting strain on an aging infrastructure, it is not much of a surprise to find that water is on many people’s mind. In a normal year, 48% of the water is used for environmental reasons, 41% for agricultural purposes, and 11% for urban uses. In drought years, these percentages change, usually with reductions facing both the environmental and agricultural uses. Most water “rights” discrepancies come in terms of river restoration and/or protection of native species, which usually reduce water to local growers who then rely more heavily on groundwater to maintain agricultural production. One can see that battles between growers and environmentalist are common and fierce. An example of these can be found with court rulings of the Delta Smelt and the restoration of the San Joaquin River.
Being with water in high demand, are there ways that the water used for agriculture be used more efficiently? The answer is “Yes.” Agricultural water use efficiency can be improved by delivering water to the right place, at the right amount, and at the right time. The “Three Rs” is not a new concept: the most primitive irrigation systems established over 5000 years ago were reliant upon these same principles. Growers would water when the plants showed some sign of water stress (i.e. wilting), and water would be delivered to the root zone at an amount that appeared to wet the soil to the appropriate level. Thankfully, through the use of certain technologies, we can increase the efficiency of our irrigations through tools to that help refine the three Rs.
If the “Three Rs” have worked for 5000 years, why change now?
The current face of agriculture is changing. Water costs are increasing. In drought years, water prices may be over $500 an acre foot in some production areas of the West side of the San Joaquin valley. Increased rates are not just due to droughts; rates throughout California are increasing as urban and environmental water demand increases while supply has not increased. Secondly, the costs involved to apply the water are also high. Fuel and electricity for pumps, cost of irrigation filters and lines, and irrigation maintenance are not cheap and require hours of labor to install and repair. Furthermore, especially within the San Joaquin Valley, water must be properly applied to prevent run-off, prevent plant diseases, ensure adequate soil penetration, encourage leaching and prevent accumulation of salts, reduce evaporation, and produce maximum profits/yields. Knowing all of this, it is easy to understand why wasting of water is unacceptable as well as the reduction of yields caused by under irrigating.
So, how do we do maximize yield but reduce water waste?
Proper irrigation is achievable through monitoring the plant-soil-environment complex. The amount of water within the soil and its ability to be accessed by the plants roots can be measured/estimated through a variety of technologies. These include the low cost feel method, to the more accurate neutron probe. For most irrigation water management systems, one of the several electrical resistance or tensiometers systems are used. These are connected to data-loggers and can be transmitted wirelessly to computer software programs to help growers monitor soil moisture. Soil moisture readings are often used by themselves to schedule irrigations, but they are most valuable when used with data that takes in consideration the water demands influenced by the environment and plant.
Plant water use varies by the stage of growth of the plant. Typically, water use is the highest when the plant is fully leafed out, with maximized leaf surface. This is because the more leaf surface transpiring, the more water is lost through the opening of the stomates. As stomates open and close, water vapor, which is at a high concentration within the plant, is released into the low moisture environment through diffusion. This is also why plant water use is the highest on days with high temperatures and low humidity. To simplify the plant-environment water interaction, the term evapotranspiration is often used. This term encompasses the loss of water by both the evaporation off of the surface of the plant and soil, and the water lost through transpiration. This value is determined by weather stations and multiplied by the respective crop and crop growth stage to determine the water use. Throughout California, these values are recorded and calculated from over 100 weather stations and made available through the California Irrigation Management Information Systems.
Outlined above were brief explanations of the tools available to calculate how much water is in the soil, and how much water is used by the plant and environment. Knowing this information, how can we use the “Three Rs” to reduce water use by increasing irrigation efficiency? By viewing the soil profile as a reservoir for the plant’s water, and calculating the daily water needs of the plant, we can determine how long the plant can survive off the water available within the soil profile. When the soil profile is close to depletion, a timed irrigation of the proper amount can refill the profile, restarting the cycle. This is the premise of basic irrigation scheduling. As one can see, proper crop irrigation encompasses more than “just a flip of the switch.”
Complexities within soil texture and soil water holding capacity, variance in efficiencies of different irrigation systems, plant water potential, and regulated deficit irrigation are all topics

that increase irrigation efficiency and will be discussed in later articles.

Marguerite Manteau-Rao is VP Marketing for Terraqualo, a new venture in precision irrigation for growers of specialty crops. Marguerite is the creator of La Marguerite, a popular environmental blog, and has written extensively for a number of other blogs, including Huffington Post Green. She has a multidisciplinary background as an engineer, marketer, and social worker.