California signs 33% renewable portfolio standard into law

By Dian Grueneich and Theresa Cho, Morrison & Foerster
Reaffirming California’s commitment to the development and use of renewable energy sources, Governor Jerry Brown recently signed Senate Bill X1 2, which requires all California utilities to generate 33% of their electricity from renewables by 2020. The new 33% renewable portfolio standard (RPS)—the most ambitious in the country—sends a strong message to renewable energy developers that California will continue to support both short-term and long-term investment in renewable energy sources in the state.

How the law works
While SB X1 2 revises a number of details in the existing California RPS statutes, the bulk of its impact for developers will derive from a few key provisions. The bill
• Sets a three-stage compliance period requiring all California utilities—including independently owned utilities (IOUs), energy service providers, and community choice aggregators (CCAs)—to generate 33% of their electricity from renewables by 2020

20% by December 31, 2013
25% by December 31, 2016
33% by December 31, 2020

• Requires the RPS to be met increasingly with renewable energy that is supplied to the California grid and is located within or directly proximate to California. SB X1 2 mandates that renewables from this category make up at least:

50% for the 2011-2013 compliance period
65% for the 2014-2016 compliance period
75% for 2016 and beyond

• Sets rules for the use of Renewable Energy Credits (RECs) establishes a cap of no more than 25% unbundled RECs going towards the RPS between 2011 and 2013, 15% from 2014 to 2016, and 10% thereafter. However, it does not allow for grandfathering Tradable REC contracts executed before 2010, unless the contract was (or is) approved by the California Public Utilities Commission (CPUC). The bill allows banking RECs for three years only, and lets Energy Service Providers, CCAs, and IOUs with less than 60,000 or fewer customers use 100% RECs to meet the RPS.

• Eliminates the Market Price Referent (MPR), which was a benchmark to assess the above-market costs of RPS contracts based on the long-term ownership, operating, and fixed-price fuel costs for a new 500 MW natural gas-fired combined cycle gas turbine. Using the MPR, the CPUC would provide above-market funds to cover contract costs that exceeded the MPR. Requires the CPUC to

• Establish a cost limit for each IOU, and authorizes IOUs to stop procuring renewable energy beyond the cost limit
• Adopt a standard tariff for renewable projects up to 3 MW in size with a 750 MW statewide cap on eligibility for the tariff.

Challenges and opportunities
Signing SB X1 2 is good news for renewable energy developers. The previous RPS, which required a 20% renewable portfolio by 2010, has proven to be a powerful driver of investment in renewable energy. Since 2003, the RPS has led to the development of 45 new renewable energy projects and 1,702 MW of new capacity. During that time, the CPUC has approved 181 contracts for about 14,000 MW of new and existing eligible renewable energy capacity.

The trend shows no sign of slowing. On the contrary, the past few years have seen a dramatic increase in the participation of larger and more experienced developers submitting bids, which has resulted in 100,000 GWh of bids in 2009 alone. Signing SB X1 2 should provide further momentum to this already fast-developing market.

On the other hand, eliminating the MPR—a cost-control method—and replacing it with a cost cap, SB X1 2 will compel developers to fit their projects within an IOU’s overall fixed budget for implementing the RPS. This may produce a rush by developers to get their projects on the table before there is any danger of the IOU reaching the cap. In addition, the new law requires IOUs to compare the costs of each proposed project against the costs of the others, which will force more competition in the market.

The new 33% RPS will interconnect with California’s recent substantial investment in transmission infrastructure, which allows for the efficient conveyance of electricity from renewable energy developments. In the past five years, under the leadership of the CPUC, California has streamlined the process of siting transmission lines, and has successfully permitted three major new transmission projects, resulting in more than $6 billion of new energy infrastructure to carry renewable power.

While these transmission lines will deliver much of the renewable power California needs, they are not sufficient to meet the magnitude of the increase in demand caused by the move to a 33% RPS. There is still an opportunity to develop additional interconnection lines that will facilitate the next generation of renewable energy needed to fulfill the mandate of SB X1 2.

Illinois Electric Power procurement issues for 2011

This article comes from law firm Foley & Lardner LLP. Readers with an interest in policy and financing will read how one Midwestern state and its utilities are dealing with goals in their Renewable Electricity Standard and influencing issues such as renewable energy credits.

The Illinois Power Agency’s (IPA) plan for purchasing power for Illinois’ two largest electric utilities, ComEd and Ameren, in 2011 is set to be filed for confirmation or modification in the Illinois Commerce Commission (ICC). The IPA, created in 2007, is charged with purchasing electric power for the two utilities in a way that ensures “adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time.” The IPA procures power to meet the estimated needs of the utilities’ customers described in a procurement plan in which power producers bid against each other to meet portions of the required power load at the lowest possible price. The IPA is also directed by statute to ensure that a minimum portion of the electric supplied is “generated from cost-effective renewable energy resources” (at least 6% by June 1, 2011, with 75% of that amount coming from wind generation, to the extent available, and a required percentage from solar generation starting in 2012). Many comments on the IPA’s draft 2011 plan came from utilities, government agencies, industry members and associations, and public interest groups, which highlight important issues that the ICC may have to address:

• Financial swaps versus contracts for physical delivery of electricity. Some parties raised concerns that the new Dodd-Frank Wall Street Reform and Consumer Protection Act and regulations to be adopted by the CFTC regarding swap contracts may have consequences for the IPA’s planned reliance on swaps rather than contracts for physical delivery of energy. They want language put into the plan acknowledging that the IPA may need to shift its portfolio away from swaps and more towards contracts for actual delivery of electricity depending upon how the CFTC regulations develop.
• Renewable energy credits (RECs) versus power purchase agreements. The IPA’s plan would meet the renewable energy portfolio requirements through the purchase of one-year RECs rather than by entering into power purchase agreements for actual delivery of electricity generated from wind or other renewable resources. While many stakeholders approve of this approach, members of the renewable-energy industry would prefer to see contracts for actual purchases of renewable energy to help foster development of such resources.
• Short-term versus longer-term RECs. Renewable-energy-industry groups would like the IPA to adopt use of five-year RECs rather than one-year RECs to meet the renewable portfolio requirements. They point to a growing demand for renewable resource capacity throughout the Midwest ISO and PJM states due to similar renewable-energy-portfolio mandates and other factors. This growing demand may outpace the available supply of renewable-energy resources. Five-year RECs, say some, provide more stable cash flow to renewable resource owners, thereby encouraging more development of wind and solar generation, while maintaining more flexibility for the IPA than products with a longer delivery period.
• Purchase of energy efficiency measures as an alternative resource. The IPA draft plan included a proposal that would let it use the purchase of energy-efficiency measures as an alternative resource for utility portfolios. ICC Staff and the utilities raise concerns about whether this option is permissible under the IPA Act or the Public Utilities Act (PUA), or both. ComEd raises the concern that energy-efficiency measures are not “standard wholesale products,” which is how the IPA is directed to meet its portfolio requirements by statute. There also is the question as to how the purchase of such alternatives would interface with the utilities’ energy efficiency programs and targets required by the PUA, and whether there could be double counting, because the utilities’ need estimates submitted to the IPA already factored in reduced energy demand as a result of energy-efficiency plans. Other stakeholders, however, submitted comments in favor of energy efficiency measures being purchased in lieu of supply, and look for the IPA to include energy efficiency measures beyond those included in the utilities’ statutorily required plans.

After a short period for comments, the ICC must confirm or modify the plan no later than December 28, 2010.

California Air Resources board adopts risky 33% RE standard

This article comes from law firm of Stoel Rives LLP, (stoel.com)

The California Air Resources Board (ARB) unanimously adopted its Renewable Energy Standard (RES), mandating that California’s public and investor-owned electric utilities procure 33% of their electricity from renewable resources by 2020. The RES was adopted pursuant to the authority granted the ARB in AB 32, the California Global Warming Solutions Act of 2006, which vested the ARB with the authority to promulgate regulations to reduce California’s greenhouse gas emissions. The RES requires utilities to submit compliance plans by July 2012. The regulation includes several multi-year compliance intervals.

The RES is met through the retirement of Western Renewable Energy Generation Information System (WREGIS) certificates. Unlike the current 20% Renewable Portfolio Standard (RPS) that applies to investor-owned utilities, there is no requirement that any energy be delivered to California. WREGIS certificates may be retained or traded for up to three years. Utilities may also bank the certificates for RES compliance indefinitely. The RES also provides that ARB will conduct comprehensive reviews of the program by December 31, 2013, 2016, and 2018, and that those reviews may trigger modifications to the RES.

The proposed RES faced vigorous opposition from a variety of sources. Senate President Pro Tempore Darrell Steinberg and Speaker of the California Assembly John Perez sent a joint letter to ARB Chair Mary Nichols, urging the ARB to set aside consideration of the RES, as the ARB’s proposed action was “contrary to law, creates economic uncertainty and potential job losses…and creates an inefficient and duplicative state bureaucracy.” The letter noted that the Legislative Analysis Office had opined that the ARB lacked the authority to implement the RES, and recommended that the legislature de-fund those positions being used by the ARB to proceed with RES adoption.

The letter also noted that California has two energy agencies already involved in implementing the legislative 20% RPS—the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC)—and that the ARB’s efforts to regulate the increase from a 20% RPS to a 33% RES would lead to inefficiencies and wasteful spending.

Perhaps to address concerns about inefficiencies and duplications of effort, the following day, the ARB, CPUC, CEC, the California Environmental Protection Agency and the California Independent System Operator released the report “California’s Clean Energy Future,” a plan for reaching 33% renewables by 2010. In adopting the RES, the ARB also emphasized its intent to cooperate with the CPUC and CEC on implementating the RES.

One area of potential conflict between the 20% RPS administered by the CEC and CPUC, and the RES is the lack of delivery requirements under the RES—compliance is demonstrated through the surrender of renewable energy credits unbundled from the associated renewable energy. In contrast, the 20% RPS requires that energy be delivered to California. The CPUC is then proposed a decision that would allow the use of unbundled or tradable renewable energy credits for compliance with the 20% RPS, but would put caps on the amount of such credits that could be used for compliance.

However, the ARB resolution adopting the RES states that no later than 30 days after the CPUC adopts its decision regarding tradable renewable energy credits, the ARB will initiate a rulemaking to ensure “continued harmonization of the two programs, specifically incorporating provisions related to Tradable Renewable Energy Credits for all regulated parties under the RES regulation.”

There remain significant questions as to whether the RES will ever be implemented. In addition to comments from the legislature concerning potential de-funding of any positions used to implement the regulations, the November 2010 elections may also change the course of implementation. A new governor may seek to suspend the ARB’s implementation of the regulation, or modify it. Also on the November ballot is Proposition 23, which would suspend implementation of AB 32, the Global Warming Solutions Act. ARB’s claimed authority to implement the RES is primarily based a grant given it under AB 32. Continued efforts underway are to have the legislature pass a 33% renewable statute that would preempt ARB’s efforts. Finally, given the uncertainties concerning ARB’s authority to implement the new regulation, a legal challenge to that authority is also a possibility.

Stephen Hall, (503) 294-9625, schall@stoel.com

Seth Hilton, (916) 319-4749, sdhilton@stoel.com

Is the U.S. Wind Industry Losing Ground?

We’ve all read the news that the United States has, after four years of remarkable growth, relinquished its’ position as the most attractive country for renewable energy investments. But rather than state the news, I want to discuss why we are slowly slipping behind our foreign competitors.

One key factor in the U.S. decline is the failure of congress to provide any form of certainty to the market. You’ve no doubt heard that the pleas for a national Renewable Energy Standard (RES) have fallen on deaf ears as senators and representatives shy away from legislation that may negatively impact their re-election chances in November. Several pieces of pro-renewable energy legislation have been proposed and brought before Congress, but in the spirit of partisan behavior our beloved congress has failed to produce any results. As such, the tax credits and cash grants that have led to a booming renewable energy economy over the last four years are coming to an end, and no legislation is in place to support the industry afterward. On top of this (and a bit of a side note) the “Bush Tax Cuts” are coming to an end as 2010 concludes. Although this is not directly related to renewable energy, increasing tax rates also increases the level of investment uncertainty in our country.

So why is Congress having such a hard time passing a bill that will both improve our economic future and decrease our dependence on foreign energy? In a word: Money. It all boils down to money, cold hard cash. Businesses and their lobbyists are working away on Capitol Hill, whispering in the ears of our representatives, planting the idea that if the federal government supports renewable energy development than energy prices will jump to a level that is too high for businesses to maintain their global competitive advantage. Unfortunately this is just not the case. In fact, the U.S. has by far the lowest energy costs in the world. Our national average (commercial) price is under $0.05/kWh whereas our nearest competitor, China, spends roughly $0.11/kWh. Though, even if we were to put that point out of the way, there is still enough evidence to refute these anti-renewable energy lobbyists in just one point. The implementation of a national 15% Renewable Energy Standard will only increase our energy costs by a fraction of one cent per kilowatt-hour.

Furthermore, this discussion of costs is only looking at the short-term cost increases and brings into account the possible decommissioning of old and heavily polluting coal-fired plants. However, if we were to look at the long-term outcome we would find that the costs level out, or hit an equilibrium point, after somewhere in the neighborhood of 30 years. As we look further into the future, say 50 or 60 years, renewable energy and the hedge that it provides will likely prove beneficial on a national cost perspective.

Now, to wrap up my thoughts, I’d like to address the issue of infrastructure and innovation right here in the U.S. of A. Though we as a nation have among both the highest wind and solar potential in the world, we are severely behind in manufacturing infrastructure and innovation advances. Often we make the mistake of assuming that the U.S. is the world’s thought-leader, and that we inherently have (almost) the right to innovate while other countries will manufacture and produce. Though this may have been the way of the past, countries like China, India, and South Korea are stepping up to the plate while simultaneously we as a country are withering away, unsure of our future, and afraid (at least Congress is) to take a stance and become the leader in renewable energy.

Top 10 best practices for avoiding construction change orders

Although change orders are not always a bad thing, site developers and construction companies have formulated a few guidelines for minimizing them.

By: Paul Dvorak/Editor

Contract change orders are so ubiquitous in some industries that if you Google the term, spaghetti-like flow charts pop up showing how a few organizations handle the changes. The charts are mostly from state organizations and aimed at road construction companies.

Change orders are often requests subcontractors present to site developers because of unanticipated conditions usually in the soil or scheduling. The general impression is that change orders are from oversights or embarrassing mistakes. But that is not always the case, say the people we interviewed. Wind farms are considerably different from general road and construction jobs because so much is influenced by their remoteness, large and complex schedules, and that coveted PPA.

Where do they come from? The first wind farm finished many projects ago, so why do change orders still crop up? There are many reasons, but our sources focused on these:

It’s the roads. “From our experience, it’s the roads and the reason is that they cover a large part of the construction work in wind projects,” says Blair Loftis, Kleinfelder Engineering’s VP and national director of alternative and renewable energy. “A turbine site might occupy only a quarter acre, but you can have many miles of roads for construction access and permanent use.”

Scheduling errors. “We’ve had only two noteworthy change orders on wind projects in the last 12 years and both involved late supply of wind turbines,” says Andrew Fowler, Executive VP of Construction with RES Americas. “Both occasions involved the late delivery of turbines due to new facilities and technology. The first occasion was from issues at the new turbine factory and the second was due to the slow delivery of a brand new turbine model,” says Fowler. “RES Americas has a successful record of BOP construction projects, but obviously, if the delivery of the turbines is delayed, the impact on the construction schedule can be significant. If a turbine design is new or the turbines are being shipped a long distance, that can affect delivery in a bad way.”

In addition, each state DOT has different rules on width, length, and divisible roads. Some states, for instance, let trucks piggyback two components, two blades or a blade and a hub. Other states insist that if such a load can be divided, then it’s an oversized load, and must be divided into two.

What’s more, truck loads may be fine when they leave the factory. But when they come to a border, they may have to go far to the east before heading west because one state on a more direct route says the truck isn’t loaded properly.

Remote locations: When equipment companies deliver machinery to conventional locations, they go to an address on a paved road most drivers can easily find. But when delivering turbines to a wind farm, the “address” is a dirt road in a corn field that looks like every other corn field in the country. To make matters worse, components are coming from all points on the compass and they must arrive in a four-hour window. That kind of precision invites delays.

Hurry, get the power purchase agreement: Owners are trying to get their power to market quickly and do what they can to limit the capital put forth in early design stages. “They have to put enough capitol up front to acquire the purchase agreement or PPA, and to do that they must move forward to final construction stages,” says Kleinfelder’s Loftis. But most planning for the pro forma is done off of limited engineering. For instance an owner may only take the project up to 60% of engineering design to secure the PPA because that gives the project financial legs. That PPA comes with a hard date to get the project grid connected. Hence, rushing and risks.”

Owners will take risks to cut costs. “Change orders are not always bad,” says David Hattery, a partner with Seattle-based law firm Stoel Rives LLC. Hattery has 20 years of legal experience with energy construction projects. “Change orders can be good for a project because they may lead to lower costs. The insinuation some make is that something sinister or bad has happened. The reality is that, change orders merely deal with unanticipated situations. A lot of what goes into a contract is the allocation of risk.”

A tower foundation provides a simple example. “A contractor may assume in its bid price that the foundations will be built in good soil based on the owner’s soil report,” says Hattery. “If the contractor starts work and finds something not shown in that report, say, hard rock, which is more expensive to deal with, then that will call for a different foundation and a redesign. If a contract makes the contractor responsible for these extra costs, then it will reasonably increase its bid price to cover the risk of encountering rock, pocketing the difference if no rock is encountered. However, if the contractor knows that it will get a change order if it runs into rock, it will price the foundations for the less expensive foundation, and the owner will only pay the extra costs if and when the foundations hit rock. This results in a fairer price and a more efficient project overall.

A few best practices. For construction firms, detailed plans are one way to avoid change orders. “Ideally, everyone will have their engineering correct at the beginning of the project,” says RES Americas’ Fowler. “It’s important to have the construction team involved in the development phase. That way, development benefits from the experience of the construction team and construction is able to better plan its work with a better understanding of the entire project.” But the ideal is infrequently encountered, so our experts suggest these best practices for avoiding construction change orders.

Best practice 1: Get subcontractors involved as early as possible. All contributors agree that the secret, if it’s a secret, is to get everyone onboard early on. “Having everyone working from the same plan at the outset makes it easier to iron out wrinkles before construction commences. That let us avoid change orders,” says Fowler.

Others concur. “We normally know about a project six months to a year in advance,” says Kleinfelder’s Loftis. “That’s when we start working with owners in a controlled format looking for encumbrances and constraint issues that can be built into an evaluation. And if not, the issues can be raised and contingencies planned.

Loftis says a few early questions to ask include: How much of the real-estate is available for wind development? Can we anticipate intervening concerns? What issues surround habitat or jurisdictional delineations? What about the community or stake holders that may intervene and want some land conveyance? There may be some specific creature, flora or fauna, relevant to that region. “Working with owners early in a consulting approach lets us anticipate these things so they are not surprises,” he says.

Best practice 2: Walk the site. Surprisingly, some projects are bid sight unseen, in engineering terms, says Kleinfleder’s Loftis. “Bidders will look at photo imagery. Google is sufficiently advanced for that, after which they will put together an order-of-magnitude bid. You really have to get out there, look at the site, and see what the constraints may be and what conditions vary across the site. There is no substitute for putting boots on the ground. Otherwise, bidders make gross generalizations. We often go out with the developer and a team that includes a representative from the construction company, the site’s geotechnical engineer, its meteorologist for wind resources, the site’s biologist, and the civil design engineer. The team approach is to look at the site and evaluate the issues to incorporate into the plan, the scope, and ultimately, the cost.”

Also, look at alternative surveys, any sort of exhibit from the developer. This information will assist in developing a useful field exercise, a site walk or reconnaissance.

Best practice 3: Thoroughly review the contract to alleviate risk. Just as you walk the site, “walk” the contract. “Identify the project areas you think are going to be problems and spend your powder there,” says Stoel Rives’ Hattery. As the industry grows, it moves toward standardization, even though every project differs. Hattery suggests several questions in a contract review. For instance, how remote is the site? A lot of project work involves moving large equipment. A lot of it on rough roads that are fairly dicey, and in windy places. “Every site will have a different challenge be it roads, weather, or rain,” he says.

“In this practice, you literally read through each and every contract clause and think: What’s different about this project? Talk to developers and owners. The question I like asking is: ‘What do you think is going to be the problem?’ Engineers know this. Are they worried about a tight schedule? Worried about the turbines being delivered all at once or about crane availability? Are they worried about not getting the A-team from a particular contractor?” says Hattery.

Best practice 4: Write your preferences into the contract.Ask for key people, those you trust, and write their names into the contract, says Hattery. “The last thing to worry about is getting inexperienced crews. As contract director, you can go into all levels of detail.”

Best practice 5: Let the BOP contractor supply the turbines.“This gives the contractor responsibility for coordinating turbine delivery so the units arrive when they are ready to be lifted,” says Fowler. “On the two occasions I mentioned when we did encounter significant delays due to the late delivery of turbines, we had big cranes on site just waiting, for six months in one case and nine months in the other. That is a long time for any construction project to be on hold, and like any industry, delays cost money. A contractor in control of the turbine supplier would have total responsibility to short out the issues.”

Best practice 6: Keep the bidding competitive.“This is important for strategic reasons,” says Fowler. “If someone comes in way under two or three bids that you know are about right, then you have be careful.” A bid of 20 or 30% less than the budget should be a red flag.

Hence, it is always a good idea to keep bidding competitive. “There is always someone else lined up for the next project. Aligning yourself with multiple trusted partners puts you in a stronger position. If you have just one company bidding some aspect of a

project, then it is more difficult to spot issues as you have no comp-arison and are in a far weaker position to fix the problem when you find them.”

Fowler admits that his advice comes from events that occurred two years ago when conditions were different than they are today. “For example, a lot of projects were moving forward, but there was a shortage of turbines. Consequently, companies were ordering turbines a couple of years in advance. Things have changed a lot since then. One big difference is that the supply of turbines has increased, so people need not order too far ahead and turbine suppliers need not be on critical path with different projects competing for the same production slot.”

Best practice 7: Use face-to-face conferences to find problems.“I’m a big advocate of, at some point, sitting down with the project team in a face-to-face meeting,” says Stoel Rives’ Hattery. “Only so much can be done on the phone, so at some point you need to sit down in a quiet room, turn off the cell phones, and think about the project, the site plan, and carefully consider the appropriate allocation of risk for this specific project. As a gatherer of issues, I’ll try to get those risk points clearly covered in the contract. I’m very respectful of the professional developers and engineers. They know what they are doing,” he says.
Hattery suggests a few titles to invite. “If we represent owners, as we do more often than we do contractors, there will be a key leader or project developer, and they will also bring in an outside engineering firm or two. and a project developer who is responsible for things such as permit siting. A director of construction often comes into a project after development has progressed to a point where construction is the issue and they really put in the details. Those are the people you want because their issues converge,” he says.

Best practice 8: Work on clear communications and good relationships. Good relationships should link the owner, contractor, and equipment vendor. Make sure the subcontractor is able to complete its tasks on time. “If bidding out to subcontractors, use people you have used before and you like. They are more likely to understand the requirements and give you a better idea of what real costs should be,” says Fowler.

“Include the OEMs because they typically come on site and commission their turbines,” says Hattery. The turbine OEMs will deliver, but the BOP contractor mechanically completes the equipment. “The contractor and OEM will walk through each turbine and say this is mechanically complete after which the OEM representative will commission the turbine. The better those people talk to each other, respect each other, and believe that one is not trying to get into the other’s pocket, the more smoothly the project flows.

Lawyers will spend a lot of time on how turbines will be considered mechanically complete. “I want an agreed checklist so that the owner, the BOP contractor, and OEM are all on the same page,” says Hattery.
In addition, these details should be clearly listed in a document for all significant parties. “Then everyone can stay in their lanes, they know what to do, and have a clear expectation that if something is not done, it’s on their watch. If it’s on someone else’s watch, we know it too,” he adds.

Best practice 9: Update the project checklists as the industry changes. Each project will probably require several checklists before the final walk-through. The box, Change orders for late bolts, tells of seemingly inconspicuous items that are absolutely essential but were overlooked until they were needed.

Bake the details of a checklist into the contract, says Hattery. Most such checklists are proprietary and everyone has a little different way of going about them, but such lists can be points of negotiation. “There is a confluence of three interest here,” says Hattery. “It’s where to interface with a construction guy from the developer’s side, with the contractor’s project manager, and the turbine manufacturer.”

One construction firm tells of a distribution to which it sends its most recent compilation of lessons learned from the previous job. The list goes to subcontractors, suppliers, staff, and supervisors from the project. And the firm expects its subs to implement the lessons.

The firm also builds the lessons learned into preconstruction planning meetings that are reviewed
for follow-on projects. Checklists of this sort can approach 100 items and includes lines for sales tags, labor relations, community relations, to engineering check-offs and budgets.
And don’t wait for subcontractors to ask for copies of the list. Send it to them and expect to see its ideas in their next proposal.

Best practice 10: Put the schedule on a Gantt chart and share it. A Gantt chart is a schedule of interdepend-ent tasks, predecessors, a critical path, leading and lagging events, milestones, resource loading all of which require buy-in. Loftis suggests several scenarios and how they might play out guided by a Gantt chart.

“A Gantt chart can be overlaid with the construction schedule and so let teams head off conflicts. For instance, suppose someone suggests finishing the geo-technical work in a month. The chart might indicate the task as doable if that team runs four crews instead of two, and at an additional cost.”

Another scenario might show need for an 80% complete civil design because a category supervisor has to review it before getting building permits. “Suppose the 80% mark must be reached by December while the Gantt chart shows the work not done until March, then you can respond with a need for more resources to accelerate work and request additional costs. Go through this approach so teams understand the interconnections between scope, schedule, and budgets,” says Loftis.

The design gets buy-in this way. “The final thing we do is assign a qualified project manager, whose only role in the project is to manage the iron triangle – scope, schedule, and budget. Every project needs someone accountable for making sure things stay within the bounds of the triangle,” he adds.

So change orders are not always some-thing bad, they are just part of contract administration. There are often no-cost changes, and occasionally they are deductive cost changes. Sometimes prices go down. “We’ve seen projects with dozens of change orders, and that does not mean there are bad things going on,” says Hattery. “It can mean that the parties are on top of all the little changes and people are being careful contract administrations. And then there are projects with few change orders but huge problems and law suits. So, the two things do not necessarily correlate.”

Fowler says his goal is always zero change orders to the client, something his company has delivered more than once in the past few years. “In cases where we had a few from subcontractors, we handled them in a way that resulted in none to clients. It’s how you get repeat business.” And this business, some say, is all about repeat business. WPE

Is the lack of an RES in the latest ‘energy bill’ a big deal?

There has been a lot of hype these past few days, much of it stemming from the AWEA lobbyists, about the lack of a strong RES in the latest so called “energy bill”. After some research and a bit of thought, I’ve come to the conclusion that the lack of an RES is the “energy bill”, also known as the Clean Energy Jobs and Oil Company Accountability Act, is not going to lead to the downfall of renewable energy in the U.S. And let me explain why.

This so called “energy bill” isn’t even an energy bill per se. The focus of this bill is actually the “Oil Company Accountability” portion, not the “Clean Energy” portion. From my findings, nothing in the proposed bill even addresses energy production measures. After reading through a summary of the bill, I learned that the five main points this bill is addressing are: oil spill response and accountability, reducing oil consumption and pollution, clean energy job creation and consumer savings, protecting the environment (land and water resources), and finally enacting an oil spill liability trust fund.

As you’ll see, the clean energy job creation and consumer savings division is the only one of the above that would address an RES, and with it being more of a side note to the bill the Clean Energy Jobs and Oil Company Accountability Act bill just isn’t the right venue for a strong national RES.

For those of you who would like to learn more, or do a little research on your own, you can find a summary of the bill here. Or you can visit Senator Reid’s official webpage here. If you have any additional thoughts, I’d be happy to read them.