World Opinion Is Changing and Reason is Here to STAY

Canada has pulled out of the 1997 anti-global warming Kyoto protocol, saying the treaty is ‘not working’. The departure comes a day after further climate talks in South Africa led to a new agreement, which is set to replace Kyoto by 2015. Piers Corbyn, the founder of the Weather Action Foundation, hopes Canada withdrawal will lead to the collapse of “useless” Kyoto protocol.

Mississippi High Court Justices Seek Reasons why PSC Reversed Itself to allow Kemper Co. Coal Plant

JACKSON, Miss. — Three Mississippi Supreme Court justices asked repeatedly Wednesday where the state Public Service Commission laid out its reasoning when it modified its decision to allow the construction of a Kemper County power plant last year.

The Sierra Club is trying to get the Supreme Court to derail the $2.7 billion power plant, now under construction in Kemper County’s Liberty community. The environmental group argues the PSC broke the law by failing to lay out its reasoning clearly when it eased the financial terms under which Mississippi Power Co. could build what it calls Plant Ratcliffe.

A lawyer for Mississippi Power said the commission didn’t have to provide such reasoning, though. He said judges could find reasons to support the decision in the 30,000-plus pages of testimony and records submitted as part of the appeal.

Mississippi Power says rates will go up about 33 percent to pay for the plant. However, Sierra Club lawyer Robert Wiygul told the court Wednesday that confidential documents he has reviewed show rates would rise as much as 45 percent. The Mississippi Business Journal reported the same amount in August 2010, citing documents obtained through a public records request.

A unit of Atlanta-based Southern Co., Mississippi Power would buy lignite mined nearby, turn it into a synthetic gas, and burn the gas, capturing byproducts such as carbon dioxide and selling them. The technology is supposed to allow coal to be burned more cleanly and cut emissions of carbon dioxide, which scientists say contribute to global warming. Mississippi Power says the plant is needed to provide more electricity for its 193,000 customers scattered from Meridian to the Gulf Coast.

The Sierra Club opposes the project, saying that the technology behind the plant is unproven and that it’s undesirable under any circumstances to build new coal mines and new coal-fired power plants. The environmental group says it would be cheaper for Mississippi Power to build a natural gas plant or buy power from independent natural gas generators.

“The law requires the Public Service Commission to choose the cheapest and most reliable technology and power plant,” Louie Miller, executive director of the Mississippi Sierra Club, said at a pre-hearing news conference. “This is neither.”

The PSC originally voted in April 2010 to cap at $2.4 billion the amount that Mississippi Power could charge ratepayers for the plant. The company is also getting about $300 million in federal assistance. Commissioners also said the power company couldn’t charge ratepayers for the plant before it started operation.

Mississippi Power said it couldn’t build under those conditions and asked the PSC to reconsider.  (Previously suggested most corrupt in MS) Lawyer Ben Stone  said Wednesday that it needed wiggle room for cost overruns, and wanted to charge ratepayers early to cut the interest customers would pay on money borrowed for the project.

"Uncle Ben Stone", Haley Barbour, and Steven Palazzo

"Uncle Ben Stone", Haley Barbour, and Steven Palazzo

“We could not go to the financial markets without some relief in both of those areas and finance the plant,” Stone said.

If this scheme had any merit it could have found investors.  With a negative credit score and historical pattern of Lignite Coal plant failure, Investors know Mississippi Power and Southern Company’s Kemper Coal Plant is a money pit with no intention of making money. It will be fined, regulated with fees, and taxed right out of any possible profits.  Among other costs to run problems they will encounter.  The profit comes in when MS power can charge a percent of its overall costs to the ratepayers.  Criminal and truly un-American, isn’t it? 

 A month later, commissioners voted 2-1 to give Mississippi Power what it wanted, raising the cost cap by 20 percent, to $2.88 billion. The commission must still agree that company spending is “prudent” for it to collect any money, even below $2.4 billion. It also allowed Mississippi Power to start charging before the plant’s scheduled start in 2014. Under state law, Mississippi Power can keep the money even if the plant is never completed.

It is not prudent to charge ratepayers for an experimental CO2 capturing mechanism that fails to produce any electricity, and  is founded on global warming science fraud, and a cap-and-trade system not yet in adopted. 

The key issue in Wednesday’s case is not whether the plant is a good idea, but whether the PSC adequately laid out its rationale for what Miller labeled a “flip-flop” by commissioners Leonard Bentz and Lynn Posey, who voted for the amended conditions.

The Sierra Club said the PSC didn’t adequately explain. “That’s going to require some evidence you can see and really get your arms around,” Wiygul said.

He said judges shouldn’t have to pick and choose reasons from the overflow of material submitted with the appeal, and the three justices sitting Wednesday seemed sympathetic to that argument.

“I did not see and still do not find anywhere where the commission explained to the court why this was now not too risky,” said Associate Justice Randy “Bubba” Pierce. “I want to know what happened between April 29 and May 26. What additional facts were submitted to the record?”

Stone said the new facts were contained in Mississippi Power’s motion to reconsider and its post-hearing briefs. “It’s very obvious to us that all those matters are supported,” he told the justices.

More importantly, though, he said the PSC was not required to summarize its reasoning for court review. Stone said that a prior court case says that as long as the court can find the reasoning in the record leading to the decision, the court must let the PSC’s decision stand.

JEFF AMY  Associated Press

Not Heeding the Warnings From Other Energy Companies

Why is Mississippi ignoring the warnings from other energy companies?  Others have determined that CCS fails to make economic sense at this point in time.  Is this the deal Haley Barbour made to gain  support for his now scrapped presidential run?  The residents of Mississippi will pay for this error forever because they have now paved the way for Cap and Trade to embark. There is no going back because there is
NO RISK TO MISSISSIPPI POWER COMPANY BECAUSE WE ARE PAYING FOR IT, NOT THEM!!!
————————————————————————————————————————————–
AEP Places Carbon Capture Commercialization On Hold, Citing Uncertain Status Of Climate Policy, Weak Economy

COLUMBUS, Ohio, July 14, 2011 – American Electric Power (NYSE: AEP) is terminating its cooperative agreement with the U.S. Department of Energy and placing its plans to advance carbon dioxide capture and storage (CCS) technology to commercial scale on hold, citing the current uncertain status of U.S. climate policy and the continued weak economy as contributors to the decision.

“We are placing the project on hold until economic and policy conditions create a viable path forward,” said Michael G. Morris, AEP chairman and chief executive officer. “With the help of Alstom, the Department of Energy and other partners, we have advanced CCS technology more than any other power generator with our successful two-year project to validate the technology. But at this time it doesn’t make economic sense to continue work on the commercial-scale CCS project beyond the current engineering phase.

“We are clearly in a classic ‘which comes first?’ situation,” Morris said. “The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effective generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry’s share.”

In 2009, AEP was selected by the Department of Energy (DOE) to receive funding of up to $334 million through the Clean Coal Power Initiative to pay part of the costs for installation of a commercial-scale CCS system at AEP’s Mountaineer coal-fueled power plant in New Haven, W.Va. The system would capture at least 90 percent of the carbon dioxide (CO2) from 235 megawatts of the plant’s 1,300 megawatts of capacity. The captured CO2, approximately 1.5 million metric tons per year, would be treated and compressed, then injected into suitable geologic formations for permanent storage approximately 1.5 miles below the surface.

Plans were for the project to be completed in four phases, with the system to begin commercial operation in 2015. AEP has informed the DOE that it will complete the first phase of the project (front-end engineering and design, development of an environmental impact statement and development of a detailed Phase II and Phase III schedule) but will not move to the second phase.

DOE’s share of the cost for completion of the first phase is expected to be approximately $16 million, half the expenses that qualify under the DOE agreement.

AEP and partner Alstom began operating a smaller-scale validation of the technology in October 2009 at the Mountaineer Plant, the first fully-integrated capture and storage facility in the world. That system captured up to 90 percent of the CO2 from a slipstream of flue gas equivalent to 20 megawatts of generating capacity and injected it into suitable geologic formations for permanent storage approximately 1.5 miles below the surface. The validation project, which received no federal funds, was closed as planned in May after meeting project goals. Between October 2009 and May 2011, the life of the validation project, the CCS system operated more than 6,500 hours, captured more than 50,000 metric tons of CO2 and permanently stored more than 37,000 metric tons of CO2.

“The lessons we learned from the validation project were incorporated into the Phase I engineering for the commercial-scale project,” Morris said.

American Electric Power is one of the largest electric utilities in the United States, delivering electricity to more than 5 million customers in 11 states. AEP ranks among the nation’s largest generators of electricity, owning nearly 38,000 megawatts of generating capacity in the U.S. AEP also owns the nation’s largest electricity transmission system, a nearly 39,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines than all other U.S. transmission systems combined. AEP’s transmission system directly or indirectly serves about 10 percent of the electricity demand in the Eastern Interconnection, the interconnected transmission system that covers 38 eastern and central U.S. states and eastern Canada, and approximately 11 percent of the electricity demand in ERCOT, the transmission system that covers much of Texas. AEP’s utility units operate as AEP Ohio, AEP Texas, Appalachian Power (in Virginia and West Virginia), AEP Appalachian Power (in Tennessee), Indiana Michigan Power, Kentucky Power, Public Service Company of Oklahoma, and Southwestern Electric Power Company (in Arkansas, Louisiana and east Texas). AEP’s headquarters are in Columbus, Ohio.

This report made by American Electric Power and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: the economic climate and growth in, or contraction within, AEP’s service territory and changes in market demand and demographic patterns; inflationary or deflationary interest rate trends; volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing AEP’s ability to finance new capital projects and refinance existing debt at attractive rates; the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material; electric load and customer growth; weather conditions, including storms, and AEP’s ability to recover significant storm restoration costs through applicable rate mechanisms; available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters; availability of necessary generating capacity and the performance of AEP’s generating plants; AEP’s ability to recover Indiana Michigan Power’s Donald C. Cook Nuclear Plant Unit 1 restoration costs through warranty, insurance and the regulatory process; AEP’s ability to recover regulatory assets and stranded costs in connection with deregulation; AEP’s ability to recover increases in fuel and other energy costs through regulated or competitive electric rates; AEP’s ability to build or acquire generating capacity, including the Turk Plant, and transmission line facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates; new legislation, litigation and government regulation, including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of AEP’s plants; timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance); resolution of litigation (including AEP’s dispute with Bank of America); AEP’s ability to constrain operation and maintenance costs; AEP’s ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities; changes in the creditworthiness of the counterparties with whom AEP has contractual arrangements, including participants in the energy trading market; actions of rating agencies, including changes in the ratings of debt; volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities; changes in utility regulation, including the implementation of electric security plans and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP; accounting pronouncements periodically issued by accounting standard-setting bodies; the impact of volatility in the capital markets on the value of the investments held by AEP’s pension, other postretirement benefit plans and nuclear decommissioning trust and the impact on future funding requirements; prices and demand for power that AEP generates and sells at wholesale; changes in technology, particularly with respect to new, developing or alternative sources of generation; and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.

http://www.aep.com/newsroom/newsreleases/?id=1704

Carbon Capture and Storage‬‏ is Very Inefficient

 

@ 3:15 he talks about how we have a process to “economically” capture co2.  This process, is very inefficient as you can see, cooling the exhaust gasses, reabsorb the co2, then reheating the ammonia solution, then re-cooling it again…

 

 

Brandon Presley: Consumers lost in Mississippi Power’s planned Kemper County plant | Better MS Report

Brandon Presley: Consumers lost in Mississippi Power’s planned Kemper County plant | Better MS Report.

From Better Mississippi Report:

JACKSON (Tuesday, July 6, 2010) – Public Service Commissioner Brandon Presley says consumers lost in Mississippi Power Co.’s planned Kemper County coal plant because the utility doesn’t have to guarantee the technology behind the project will ever work.

Mississippi Power’s plant, the first of its kind in the world, will use a new technology that converts a soft coal called lignite into a gas to fuel turbines and create electricity. The concept is high risk because no one can guarantee that the technology to be used in the plant will work.

Presley said Gov. Haley Barbour and U.S. Energy Secretary Steven Chu sent letters asking for support of the Mississippi Power plant. But Presley voted in April and May against forcing Mississippi Power ratepayers to finance the plant.

“I received letters urging me to support the project from everyone from Gov. Barbour to Steven Chu, secretary of energy in the Obama administration,” said Presley, who represents the Northern District on the three-member PSC.

“If they thought it was such a good project, why didn’t they find a way to pay for it rather than forcing Mississippi Power’s customers to be the sole investors in the plant?” Presley told the Better Mississippi Report.

The PSC voted 2-1 in April to allow Mississippi Power Co. to build the Kemper County plant at a cost of no more than $2.4 billion. Commissioners said they would decide at a later date whether to grant Mississippi Power’s request for ratepayers to finance the plant before it begins operating.

Less than a month later in May, the PSC voted 2-1 to increase the cost cap of the Mississippi Power plant to $2.88 billion and also allowed the company to charge ratepayers for financing costs before the plant is completed.

Presley cast the sole no votes at the April and May meetings.

Presley, 32, a lifelong resident of Nettleton, is in his first term on the PSC – winning the position in 2007 after serving as mayor of Nettleton from 2001 to 2007. He talked about the Mississippi Power plant and other issues in an interview with the Better Mississippi Report.

Better Mississippi Group: You were the only member of the Mississippi Public Service Commission to oppose the Mississippi Power Co. plan to build a coal-burning plant in Kemper County. Can you explain your concerns about this proposal and why you voted against it?
Brandon Presley:
Very simple. Mississippi Power wanted the ratepayers to pay in advance hundreds of millions of dollars in financing costs and then $2.4 billion (now up to $2.88 billion) for the plant itself, and after hours and hours of sworn testimony and days of hearings they would not, and to this day, still will not, guarantee their new technology to be used in this plant will work.
If I had voted yes for this plant, I would have been a part of forcing ratepayers in one of the poorest states in the nation to pay, in advance, for something the company can’t even guarantee will work and that was, obviously, a big concern to me. I strongly support innovative technology, and I have a deep admiration for the scientists and engineers who bring about groundbreaking ideas that could make our lives better. But I believe the companies themselves and private sector investors should be willing to take some of the risks and not force all the risk on ratepayers who don’t have a choice in their providers. Remember, customers of Mississippi Power can’t choose who provides their electricity. They must use Mississippi Power or be in the dark, literally. So they are now being forced, via their electric bill, to invest in this plant.
I received letters urging me to support the project from everyone from Gov. Barbour to Steven Chu, secretary of energy in the Obama administration. I wondered if they thought it was such a good project, why didn’t they find a way to pay for it rather than forcing Mississippi Power’s customers to be the sole investors in the plant?
Also, I felt strongly that since there are so many unknowns out there, especially about the technology itself, that nothing would have been harmed by waiting. As I have said, Henry Ford built a better car five years after he started on his first one.
In a few years, we should have a better idea about other discoveries going on now, such as the impact of shale natural gas and also about the technology in the plant. Maybe then Mississippi Power will be able to guarantee that it will work. In a few years, we should also have a better understanding of the current energy legislation and environmental regulation that is being debated in Washington.
If Mississippi Power is going to ask consumers to pay up to $2.88 billion, plus hundreds of millions in banking fees (before the plant puts out any electricity), they need to have their ducks in a row with technology that they can guarantee works and share some of the risk. They didn’t. So I voted “no” twice.

Better Mississippi: The vote was a total change from a stand the PSC took days earlier. Can you tell us what led to the about-face on the PSC?
Presley:
I’ve been consistent – I voted no both times. You would have to ask the other two commissioners that question. Even though I could not support the project after hearing and studying the facts presented to us for months, I felt the first order on April 29th was strong and at least had some good protections in it for the ratepayers. I do not know why the majority voted to ease up on that order and grant the company another $480 million in spending authority under certain circumstances.

Better Mississippi: Mississippi Power Co. won’t release the possible increase in electric rates that customers may have to pay to finance construction of the Kemper County plant. Is this something that should be released to the public? Why?
Presley:
Absolutely. They should have been disclosed before the plant was approved. It was one of the reasons I voted against the project. Two times before the final votes, I asked if the rate impacts were going to be made public before the project was approved, and both times the answer was “no.”
The customers of Mississippi Power have a right to know how this plant is going to impact their bills. They shouldn’t have to wait until they get the bill out of their mailbox to understand how much it is going to cost them. I had proposed changing the rule that allowed Mississippi Power to deem these rate impacts “confidential” prior to the final vote on Kemper. I raised the issue of changing this rule in May but was out-voted. The issue was taken up in our June meeting, at which time it passed unanimously.

Better Mississippi: With the Sierra Club taking the Mississippi Power Co. Kemper County issue to court, how do you see things working now? Will this be a long, protracted case?
Presley:
All I know is that I will keep fighting for taxpayers and ratepayers no matter what happens.

Better Mississippi: You are one of three commissioners on the PSC. Can you tell us about your relationship with the other commissioners? Do you all tend to get along? How do you handle disagreements on major issues, such as the one with Mississippi Power Co.?
Presley:
I like my fellow commissioners and think they’re good men. As with any three-member commission, we are going to disagree from time to time.
With that said, I tend to be very passionate about the job the people elected me to do. I’m passionate about what I believe a regulator is supposed to do. I won’t back down when I believe consumers are getting a raw deal or when I see something unfair about the process. I think that’s what the ratepayers expect and it’s certainly how an elected official who is protecting the public’s interest should act, in my opinion.
When you have the courage of your convictions, you don’t mind going against the grain or standing alone. I recently heard a pretty good saying that fits this situation, “Even a dead fish can go with the flow.” I don’t plan to be a “go with the flow” commissioner.

Better Mississippi: What do you see as the biggest challenge of the PSC these days?
Presley:
The single biggest challenge is making sure that consumers aren’t left out of the picture at the PSC. It seems that almost every rate plan, service plan, rule and regulation was written for and by the utilities for their benefit. Too many times the people who actually have to pay the utility bills have just been left out of the process and forgotten. The simple fact is that if the PSC doesn’t stand up for the consumer, nobody else is going to.
We desperately need balance at the PSC. And by that, I mean that we need to remember that there are real people, families, small businesses and industries that have to pay for these rate hikes and proposals. The utilities have a vast reservoir of attorneys, lobbyists, experts and cheerleaders. All the general public has is the PSC.

Better Mississippi: What do you see as the most important regulatory issues facing the PSC and consumers in the state?
Presley:
So many Mississippians are facing very tough economic situations in their homes and at their businesses. My mission is to do everything possible to keep money in the pockets of taxpayers and ratepayers and not help the big utilities make undeserved profits. That is our single biggest challenge. I believe we can craft policies that are pro-consumer and pro-business. Letting utilities increase rates whenever they want hurts so many small businesses that are the backbone of our state’s economy. I am proud to say that I have voted against more spending and rate increases than any other commissioner in the history of the PSC.

Better Mississippi: How do you see your role on the PSC?
Presley:
I see my role as a watchdog for the public interest – period.
A commissioner I’ve gotten to know from another state says it best. One time, when the hearing room was full of attorneys and high-paid lobbyists for the utility companies, he called the meeting to order by asking everyone who was there on behalf of the utilities to please stand up. Almost the whole room, of course, stood to their feet. Then he told them to sit down. He then asked, “Who is here on behalf of the ratepayers?” Nobody responded and he stood up and said “You see, folks? That’s why I’m here. That’s my job.” I couldn’t agree more.

Better Mississippi: Statewide and district elections will take place in 2011. Do you plan to run for re-election? Why or why not?
Presley:
I honestly haven’t given it much thought. I’m consumed daily with issues at the PSC and getting my job done. I will make a decision about the election in the coming months.

 

Obama, Van Jones, Barbour, Bentz, & Posey

Van Jones and U.S. Energy Secretary Steven Chu are both on Obama’s payroll to lead the progressive movement for Economic Justice.  The chickens-have-come-home-to-roost right here in Kemper County Mississippi.

Prepare for your electric bill to increase up to 45% starting Jan 1, 2012. I think this delay is to assure successful reelections of the submissive PSCs.  Bentz, PSC South District, said the economy will rebound by 2012 and that is why he waited to raise rates.  Really?

The Kemper CAP AND TRADE project is slightly funded by Obama’s stimulus package for Green jobs.   When our Public Service Commissioners initially set financial limits to Mississippi Power’s estimate for construction,  Mississippi Power concluded the project could not proceed. ( I understand MSP has horrible credit and cannot get a loan.)

So at that junction, I understand, our PSC’s  could place the burden on families to fund the billions or Obama takes his cap and trade and shoves it to some other gullible state.  (Not Florida they rejected it)  That is where U.S. Energy Secretary Steven Chu, with Obama’s  magic comes in.

Please see the article on Steven Chu and his vodoo-like ability change the minds of Leonard Bents and Lynn Posey to suddenly approve the most widespread economic destructive path starting with gullible Mississippi.

Power’s High Price Will Cost Jobs PSC LEONARD BENTZ:

PSC COMMISSIONER LEONARD BENTZ: Power’s High Cost Will Cost Coast Jobs

Sunday, February 08, 2009 12:53 PM

(Source: The Sun Herald (Biloxi, Miss.) tracking By Mary Perez, The Sun Herald, Biloxi, Miss.

Feb. 8–Leonard Bentz knows this week he has to sign off on a fuel-cost adjustment requested by Mississippi Power and he knows it will mean job losses in South Mississippi.

“I believe I’ve had every single casino call me,” said Bentz, chairman of the Mississippi Public Service Commission. He said they’ve told him, “The fuel-price increase is going to make us have to lay people off.”

Mississippi Power has requested a 9.2 percent increase for residential customers. The increase is higher for commercial and industrial customers because fuel costs make up a larger portion of their bills.

For Northrop Grumman it could mean an increase of $2 million this year. Beau Rivage Resort and Casino faces a $700,000 to $800,000 increase and Island View Casino around $300,000.

“Those are just some of the numbers we are hearing,” said Bentz.

He tells everyone who calls him about the increase, “If you have an idea, please give it to me.”

Bentz said, “I should have signed that order two months ago. I’ve not allowed them to put the new fuel prices in place yet.”

Business owners knew the increase was coming. In July and August representatives from Mississippi Power gave all major business customers an estimate of the increase, said company spokeswoman Cindy Webb.  (I strongly question the effectiveness of this communication, for I have asked multiple Business owners and members of Chamber and rarely did one say, “oh yes I heard about it.”  And no one said MS power told me.)  In November, when the utility filed for the fuel-cost adjustment, representatives went back and gave the businesses specific costs.

“It’s our annual true-up on fuel,” said Webb. It’s not the largest annual fuel adjustment. That was 10 percent in 2006. In 2008 Mississippi Power customers paid a 4 percent fuel-adjustment increase, and Webb said there were decreases in 2002 and 2003.

“It depends on the fuel markets,” she said.

Mississippi Power Company hasn’t had public hearings on fuel increases, but Bentz scheduled one for Dec. 29 in Gulfport. Only a handful of residents and business owners attended. (that is because no one knew about the meeting.  Bentz cares more about his no call list than a change that will affect the homes of every Mississippian.)“It was not the best time in the world to have a hearing,” Bentz said, “but I wanted to have a public hearing anyway.” He said at the meeting the dollar-for-dollar “pass-through,” in a regulated market such as Mississippi’s, allows the utility to pass on the cost of doing business to the customer. If the company spends $100 million on fuel and is allowed a rate of return of 10 percent, the company can bill the customers for the additional $10 million.

“Mississippi Power Company can only earn what the state regulators allow them to earn,” Bentz said.

Mississippi Power uses coal and gas to operate its power plants.

Mississippi Power CEO Anthony Topazi said gas was up 100 percent in 2008 and coal was at an all-time high.

“I’m spending more to provide the same amount of energy,” he said.

When the prices were steadily climbing last year, the company negotiated multi-year contracts on the futures market to lock in the cost and be assured a supply of coal and gas.

“It’s a great deal when you lock that contract price in and the prices skyrocket,” said Bentz.” It’s a horrible deal when you lock that price in and the prices go down,” as they did in this case.

Bentz said he doesn’t have the staff or the $1 million it would take to do an audit to see if the utility paid the lowest price possible for fuel.

“There needs to be a disincentive, or some type of incentive to the power company for purchasing fuel the cheapest they possibly can do it,” he said.

It won’t be just the customers who feel the pinch. Bentz said, “I told Anthony (Topazi) the other day, ‘Y’all need to put these planes on the ground,'” referring to corporate aircraft.

Bentz added, “Profitmargins are not going to be what they were in the good years,” and he said, “I don’t believe bonuses are going to be paid to the amount that they’ve been paid.”

Webb said Mississippi Power has a hiring freeze and, “we are doing everything we can to control costs. We’re looking at the things we can do that won’t impact customerservice.”

If Bentz doesn’t sign the increase, he said, the Mississippi Supreme Court would most likely overturn that decision and grant it anyway, as the court has done in the past.

He can amortize the increase over 12 months or possibly two years. “When you do that, it’s just like putting it on a credit card,” he said, with the customers paying the carrying costs.

“It’s a crap shoot,” he said. “If prices keep going down it’s a great thing. But if they keep going up, you’re just compounding costs on top of each other.”

—–

To see more of The Sun Herald, or to subscribe to the newspaper, go to http://www.sunherald.com.

Copyright (c) 2009, The Sun Herald, Biloxi, Miss.

Distributed by McClatchy-Tribune Information Services.

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via PSC COMMISSIONER LEONARD BENTZ: Power’s High Cost Will Cost Coast Jobs.

Mississippi Coal Comments are in Red and added for commentary

CO2 BLOWOUTS: An Emerging Problem

January 2003 – CO2 blowouts: An emerging problem.

Vol. 224 No. 1

Well Control And Intervention

After thirty years of injecting CO2 for secondary recovery, corrosion and pressure change properties of CO2, and applications in aging wells, are creating conditions conducive to increasing blowouts during workovers / recompletions

Les Skinner, PE, Well Control Engineering Manager, Cudd Well Control, Houston

Blowouts on gas producers containing high concentrations of CO2 have occurred for years in the industry. Recently, however, there has been an increased frequency of CO2 blowouts in injection projects requiring intervention by well control companies. One company has responded to five such blowouts in the last three years, whereas the entire well-control industry only responded to two injection-related CO2 blowouts in the previous 27 years since injection began.

This article discusses several physical and chemical properties of CO2; blowout characteristics, unusual hazards, corrosion, preventive measures and methods for controlling wells in injection projects. Summaries of three of the five recent blowouts provide insight that will, hopefully, prevent the upswing in blowouts from becoming a long-term trend.

INTRODUCTION

Gas wells with high CO2 concentrations have been drilled throughout the world for several years. Some of these have suffered blowouts during drilling / production operations including well-control problems on CO2 source wells in New Mexico, Colorado and Wyoming. Producing wells with even moderate CO2 concentrations have also suffered corrosion-related problems. This so-called “sweet corrosion” has been well documented in the literature. Recently, blowouts in CO2 tertiary recovery floods have become problematic.

Continued injection has resulted in higher reservoir pressures in most projects, with CO2 now at or above its critical point. The extreme expansion of this fluid when surface pressure control is lost, and the resulting violence of the blowouts, is astounding. Blowouts have complications that other blowouts may not exhibit, due to the characteristics of supercritical CO2. Fighting a CO2 blowout requires a change in thinking to properly manage these unusual conditions, although most intervention techniques follow classical procedures.

Whether this increased frequency of blowouts represents a trend is unknown. However, recent experience tends to verify that blowouts in CO2 floods may, in fact, be an emerging problem.

CO2 PROPERTIES

CO2 is a stable oxide of carbon composed of two oxygen atoms, each double-bonded to a single carbon atom. CO2 is soluble in most crudes. When dissolved, it swells crude oil, slightly increases in-place volume and reduces viscosity. It can displace oil miscibly or immiscibly, depending on oil composition and reservoir pressure.

Due to its weakly bi-polar nature, CO2 is highly soluble in water, with which it reacts to form carbonic acid. Failures from CO2-related corrosion can cause the loss of well control. CO2 is not classified as a toxic material, i.e., it is not a poison. But breathing can cause severe negative health effects. CO2 is more dense than air, with a specific gravity of 1.55 (Air = 1.0). It can collect in high concentrations in low areas such as depressions, pits and cellars.

Pressure vs. phase changes. Of greatest significance is the tremendous expansion of supercritical CO2 when pressure containment is lost. Fig. 1 is a phase diagram showing its critical point at 1,071 psia and 88°F. Above this pressure and temperature, there is no distinction between liquid and vapor phases, and even small pressure drops can produce large volume increases, and vice versa. Minimum miscibility pressure for most CO2/crude systems exceeds critical pressure; and reservoir temperatures are greater than the critical temperature for most, if not all, injection projects. Thus, most floods in which injection has been underway for several years contain CO2 at conditions above the critical point.

Fig 1
Fig. 1. Phase diagram showing CO2 critical point.

When pressure containment is lost, two processes occur simultaneously. First, the CO2 (and a fraction of miscible products) converts from a supercritical “fluid” to a vapor, with significant expansion. This vapor continues to expand with decreasing confining pressure as it moves up the wellbore. Flow velocities increase accordingly. Any mud or other fluid in the well is expelled quickly, leaving little hydrostatic pressure to resist reservoir influx. The result is that more supercritical CO2 flows into the wellbore, expanding as it does.

The flowrate eventually stabilizes as an equilibrium is established between backpressure caused by fluid friction from the blowout and the pressure drop across the formation face. Often, the flowrate is controlled by the opening through which the plume escapes at the surface. Flow through small openings (holes in casing, leaks around pipe rams or in the wellhead, etc.) can reach sonic velocity, limiting flowrate and, consequentially, CO2 influx from reservoir to wellbore.

This flow behavior is almost explosive in its violence. And this is usually not expected by field workers. Often, only a small volume of supercritical “liquid” CO2 in the wellbore is enough to trigger the process, causing the well to blow out in a matter of seconds. Reaction time is minimal and some equipment, particularly manual BOPs and stab-in safety valves, cannot be installed and closed fast enough to avoid complete liquid expulsion from the well and total loss of pressure control.

Effects of expansion cooling. The second effect is rapid cooling of wellbore and fluid streams due to expansion. Once the CO2 stream falls below the triple point temperature and pressure of -63°F and 76 psi, respectively, solid dry ice particles can form quickly. Several special problems result from this unique phase behavior: 1) high flowrates complicate surface intervention work and expose workers to gas moving at high velocities; 2) CO2 and produced fluids from hydrates that can collect in BOPs, the wellhead and other surface equipment; 3) the cold CO2 condenses water in the atmosphere, resulting in reduced visibility in the white “cloud” around the wellbore, Fig. 2; and 4) free oil and condensed miscible fluids swept out of the near-wellbore area can collect on the surface, creating a ground-fire hazard, Fig. 3.

Fig 2
Fig. 2. Vapor cloud from water in the air condensed by cold CO2 reduces visibility near wellbore, hindering hand-signal communications.
Fig 3
Fig. 3. Injection well where oil swept out of the wellbore by CO2 blowout collected in pools on location.

Further, dry ice formation often results in pea- to marble-size projectiles expelled at very high velocities, sufficient to injure workers. Fig. 4 shows a large accumulation of ice around the front of the pumping unit skid and on the gearbox. The white area behind the pumping unit is a 1 to 2-in.-deep dry ice accumulation.

Fig 4
Fig. 4. Accumulation of dry ice and hydrates on the pump unit skid and gear box, plus 1 to 2 in. accumulation on the ground.

Corrosion. “Sweet” corrosion on metal goods results from formation of mild corrosives in CO2-water reactions. While not as rapid as “sour” corrosion caused by H2S or strong acid solutions it, over time, is just as insidious. Some wells in CO2 floods were drilled in the 1940s and 1950s, and cumulative corrosion is now becoming problematic.

CO2-related corrosion is generally attributed to carbonic acid. Only a small fraction of the total CO2 volume dissolved in water reacts. The remainder of the gas remains in solution to supply a continuous CO2 source. The corrosion is localized, likely the result of small galvanic cells formed in specific areas. Other chemical reactions can also create scales that protect one area, while a nearby area is exposed to the acid.

Many reservoirs in which CO2 is injected also produce corrosive H2S and high chloride waters. Few older wells are equipped with corrosion-resistant casing and wellhead components, although some have been equipped in recent years with improved-metallurgy tubing / packers.

Two recent blowouts were the result of surface casing failure caused by corrosion. In both cases, a hole in the production casing allowed CO2 to internally corrode the surface casing, resulting in pipe failure and loss of well control.

Continued corrosion is expected on wells and tubular goods due to increasing CO2 partial pressure in most wells. The ratio of natural gas to recovered CO2 should decrease with time, unless the natural gas is re-injected, an unlikely scenario for commercial reasons.

Trends in corrosion-related problems are difficult to assess and predict. However, one operator reported that most holes in casing strings formerly occurred deep in the wellbore (+/- 6,000 ft) as a result of external corrosion. Recently, wells in this project are experiencing holes in the casing 200 to 300 ft from surface due to internal corrosion related to CO2 production. Also, in the past, a rig was needed occasionally to repair casing leaks. Now, two rigs are continually used for cement squeeze jobs, an indication that more corrosion pits are now penetrating the pipe.

PRE-BLOWOUT EVENTS

Four of the five recent blowouts occurred during remedial work. Workovers are routinely required on wells in CO2 floods, including cleanouts, conformance improvement jobs, stimulations, conversions and paraffin / asphaltene removal. Repairs to downhole tubulars, sensing equipment and production equipment are also required frequently.

Generally, the wells are killed with cut brine or low-density muds by bullheading down the tubing or annulus. Some wells die for a time after being bled down at surface. Once the well is dead, the head is nippled down and a BOP is installed. The BOP stack is often a 3,000-psi-rated manual with pipe and blind rams. Rarely is an annular preventer installed, due to height limitations under the rig floor.

Experience shows that much of this service rig blowout prevention equipment (BOPE) has aged and has not been maintained properly. The same ram blocks and stab-in safety valves are frequently used for several years without reconditioning. In many instances, the BOPs are not pressure-tested after installation, so there is often no sure way to confirm whether ram packers will seal and control the well.

Also, there is limited information available on the effect of CO2 on ram packers (some is available on its effects on other sealing components such as O-rings, however). Blistering due to rapid decompression of elastomers permeated by CO2 has been observed. Some reservoirs are now pressured to the point that the stack and other BOPE component ratings would be exceeded by shut-in surface pressures if a CO2 blowout occurs.

Crew training may need adjusting for working in CO2 injection projects. Some have worked in production operations, but they have no experience with the highly expansive nature of supercritical CO2, and the need to shut-in the well as quickly as possible after a flow is detected.

CASE STUDIES

The following are brief case studies of three of the five CO2 blowouts requiring well-control specialist intervention over the past three years:

Blowout No. 1. This well, in a miscible, West Texas CO2 displacement project, was an injector being serviced to replace corroded tubing joints and packer. The tapered 2 7/8 x 2 3/8-in. tubing was being pulled, and only a few joints of 2 3/8 in. and the packer were left in the hole. Air slips were chained to the top of the dual manual BOP.

The well began to flow unexpectedly, and the crew closed the manual BOPs, dressed with 2 7/8-in. ram blocks. An early report indicated at least one tubing joint was ejected and hung in the derrick. The well blew out within 30 sec and the crew evacuated. Fig. 4 shows the well upon arrival of the control team.

The air slips had apparently opened at some point allowing the tubing to drop into the BOP. The tubing was hanging on the partially closed pipe rams and the air slips had cocked sideways, spreading the plume horizontally around the wellhead; visibility was poor. The pipe rams were opened to drop the tubing and packer. An attempt was made to close the blind rams, but they were frozen in place. It was not possible to confirm whether the tubing had fallen downhole, due to ice buildup in the BOP. Fluid could not be pumped into the frozen wellhead. A hot-oil truck thawed the wellhead and BOP, and 242 bbl of water were pumped.

The next morning, the hot oiler again thawed pump lines, tubing head and BOP. The pump began injecting water down the annulus at about 0.5 bpd. Control specialists confirmed the tubing had dropped and the BOP stack was clear. Pump rate was increased to help load the well. Then blind rams were worked to break them free, and they were closed.

High-rate CO2 flow from the well had apparently damaged the ram packers and the BOP leaked badly, indicating it could fail at any time. The pump rate was increased to 20 bpd and the well was killed. The BOP was stripped off and a new stack was nippled up. The dropped tubing and packer were fished, and workover operations proceeded without further problems.

Blowout No. 2. This well was an active CO2 injector, being converted to reservoir pressure monitoring. Plans were to squeeze the top of a 4 1/2-in. liner and run new tubing with sensors and a packer. The well was killed, injection tubing was pulled and the old packer was removed.

A cement retainer was started in the hole on the old tubing. With the retainer at 6,300 ft, a pickup joint was made up on the injection tubing and run. Pipe rams were closed on the tubing, air slips were set and a stab-in safety valve was installed. Blind rams were left open.

Next morning, the crew found CO2 blowing from the BOP. Swept-out-oil had collected on location in pools and puddles. It was unlikely that the gas plume would ignite because of its high CO2 concentration, but oil on the ground was a serious fire hazard, so a foam blanket was applied. Then, the specialists approached the blowing well and confirmed that all flow was coming out the top of the BOP – it appeared that the pipe rams had failed. A line was laid and 177 bbl of brine were pumped down the annulus without affecting flow. The rig could not be started because of the fire hazard, so a winch truck was backed in to raise the blocks.

The tubing was raised, and a saddle was installed to hot tap the tubing with a 0.5-in. bit. About 300 bbl of brine was pumped down at 4 1/2 bpm to kill the blowout, but the well continued flowing. Pipe rams were closed on the tubing; flow stopped; and the well was finally killed by bullheading fluid down the annulus.

The pickup joint was backed off and laid down and was found to be flattened slightly on one side – an area only about 3/4-in. wide and about 1/16-in. deep, the length of the joint. It appeared that the joint had been pulled through a partially closed blind ram and the entire CO2 flow had exited the well between the flat spot and the closed pipe ram. When the rams were closed on the undamaged joint, the flow stopped.

Blowout No. 3. This well was also an injector in a miscible CO2 flood that required a workover to clean out fill. The well was killed and the packer was released. Injection tubing was pulled and stood back.

A small-diameter “stinger” made from 1 1/2-in. tubing was screwed onto the bottom of a joint of tubing, as had been used to clean out other wells. The crew elected not to install an annular preventer or change pipe rams before running the stinger.

Blind rams were opened and the crew lowered the stinger. Suddenly, the well began to flow. Pipe rams were closed, but they would not seal around the small-diameter stinger. An attempt was made to lower the stinger and tubing joint, but flow uplift would not let the tubing go down. The crew apparently attempted to drop the tubing but, instead of falling, the stinger bent and the joint fell over. Oil reached the surface a few seconds later and the crew evacuated Fig. 5. Oil collected on the location, and dirt berm was pushed around the site to contain it.

Fig 5
Fig. 5. Blowout No. 3 with oil on wellhead equipment and location, and bent stinger joint extending from BOP.

A single-jet abrasive cutter was rigged up on a boom and a line was run to a pump truck. Gelled fluid and an abrasive were mixed and pumped through the jet and the boom was telescoped to the correct position to cut the stinger off just above the BOP. The cut was made and the stinger fell into the hole, and blind rams were closed stopping the flow. The well was killed by bullheading brine down the casing, and the stinger was fished after the annular preventer was rigged up.

FUTURE OUTLOOK

CO2 injection is expected to increase. Several new floods have just begun in Cogdell Reef (Canyon) field, North Hobbs (San Andres) Unit, the Boyd Unit in the Slaughter (San Andres) field and others. CO2 injection is expected to increase in other projects now that better supplies are available.

Continuing corrosion is likely to be a problem in these projects as wellbore age and economic pressure precludes drilling replacement wells. Repairs and stimulation workovers will continue, with multiple opportunities for well-control problems.

Several sequestering projects have been proposed and are being studied to remove CO2 from the atmosphere, especially CO2 produced by fossil-fuel-fired power plants. Much of this work will involve personnel not familiar with the intricacies of CO2 injection, use of reconditioned, abandoned wells with inappropriate metallurgy for this service, and pressures that may exceed limits of existing equipment.

Continued exploration and development with high CO2 concentrations also provides the potential for well-control problems. With improved separation technology particularly in molecular sieves, many reserves that were formerly non-commercial will be developed. This includes areas such as the Norphlet in the U.S. Deep South, the Natuna Sea in Indonesia and the South China Sea, e.g., offsets to the Vicky well.

PREVENTIVE MEASURES

Several proactive procedures can be used to reduce probabilities of a CO2 blowout and mitigate adverse effects if one should occur. These include: wellbore integrity surveys on existing wells; improved BOPE maintenance; and installation of additional BOPE on suspect wells. Improved crew awareness and well control training, and aggressive blowout contingency planning and emergency response training for operator personnel are essential.

Every BOP stack used by service rigs in CO2 projects, whether manually or hydraulically-operated, should be performance and shell-tested at least annually. There is ample reason to recommend pressure testing blind rams, pipe rams and other BOPE components such as stab-in safety valves on each well when the stacks are nippled up. This BOPE should be tested to its rated pressures to ensure the stack can hold not only expected pressure from the well, but imposed pressures required during well kill operations, such as bullheading.

Annular BOPs are rarely used on well servicing units. At least two of the five blowouts mentioned above could have been prevented, or at least mitigated, by installation of an annular preventer.

The installation of profile nipples above packers in tubing strings would allow plugs or back-pressure valves to be set before running or pulling tubing. This would result in the crew pulling a wet string, but flow from the well would not come up the tubing requiring crews to install stab-in safety valves.

The importance of proper crew training and repetitive drills cannot be overstated. Many crew members have little or no well control training. Experienced crew members may have had no training in CO2 blowout control. The use of specialists familiar with CO2 blowouts to train and perform simulated incident drills may be justified.

In conclusion, response measures to safely handle CO2 blowouts require an awareness that these blowouts are not the same as gas-well or oil-well blowouts. With proper training and planning, and a firm knowledge about the peculiarities of supercritical CO2, the industry can respond to these events and, hopefully, prevent the recent increase in CO2 blowouts from becoming an epidemic.  WO

ACKNOWLEDGMENT

The author appreciates the permission and cooperation of Cudd Well Control in preparation of this article. Thanks are also extended for information provided by the well-control specialists and engineers who worked on these blowouts, including Steve Burrow, Mark Mazella, Eddie Goodman, Gabe Gibson and Chuck Roberts.

BIBLIOGRAPHY

Weeter, R. F. and Halstead, L. N.: “Production of CO2 From a Reservoir – A New Concept” paper SPE 10283, Journal of Petroleum Technology (September 1982), pp. 2144-2148.

Lynch, R. D., McBride, E. J., Perkins, T. K.  and Wiley, M. E.: “Dynamic Kill of an Uncontrolled CO2 Well,” paper SPE 11378, JPT (July, 1985), pp. 1267 – 1275.

Norman, C.: “CO2 for EOR is Plentiful but Tied to Oil Price,” Oil & Gas Journal (February 7, 1994).

Newton, L. E., Jr. and McClay, R. A.: “Corrosion and Operational Problems, CO2 Project, Sacroc Unit,” paper SPE 6391, presented at the 1977 SPE Permian Basin Oil and Gas Recovery Conference, Midland, TX, 10-11 March, 1977.

Gair, D. J. and Moulds, T. P.: “Tubular Corrosion in the West Sole Gas Field,” paper SPE 11879, SPE Production Engineering (May, 1988), pp. 147-152.

Gunaltun, Y.: “Carbon Dioxide Corrosion in Oil Wells,” paper SPE 21330, presented at the SPE Middle East Oil Show, Bahrain, 16-19 November, 1991.

Palacios, C. A. and Chaudary, V.: “Corrosion Control in the Oil and Gas Industry Using Nodal Analysis and Two-Phase Flow Modeling Techniques,” paper SPE 36127, presented at the Fourth Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad & Tobago, 23-26 April, 1996.

Sienko, M. J. and Plane, R. A.: Chemistry, 3rd Edition, McGraw-Hill Book Company, p. 87.

Farshad, R. R., Garber, J. D. and Polaki, V.: “Comprehensive Model for Predicting Corrosion Rates in Gas Wells Containing CO2,” paper SPE 65070, SPE Production & Facilities, 15 (3) (August, 2000) p. 186.

Shakhashiri, B. Z.: “Carbon Dioxide,” (handout) Chemistry 104, University of Wisconsin-Madison (March 18, 2002).

Ormiston, R. M. and Luce, M. C.: “Surface Processing of Carbon Dioxide in EOR Projects,” paper SPE 15916, JPT (August, 1986), pp. 823-828.

Holm, L. W.: “Evolution of the Carbon Dioxide Flooding Process,” paper SPE 17134, JPT (November, 1987), pp. 1337-1342.

Crolet, J. L.: “Acid Corrosion in Wells (CO2, H2S): Metallurgical Aspects,” paper SPE 10045, JPT (August, 1983), pp. 1553-1558.

Stone, P. C., Steinberg, B. G. and Goodson, J. E.: “Completion Design for Waterfloods and CO2 Floods,” paper SPE 15006, SPE Production Engineering (November, 1989), pp. 365-370.

Personal interview, Kerry Shoemake, Kinder Morgan (October 1, 2002)

Moritis, G.: “Future of EOR & IOR: new Companies, infrastructure, projects reshape landscape for CO2 EOR in US,” Oil & Gas Journal, (May 14, 2001)

Moritis, G.: “California steam EOR produces less; other EOR continues,” Oil & Gas Journal, (April 15, 2002)

Schempf, J.: “Future Looks Good for CO2,” Hart’s E&P, (June, 2001)

Schempf, J.: “CO2 injection grows in Gulf states,” Hart’s E&P, (September, 2001)


THE AUTHOR

Skinner Les Skinner, PE, Well Control Engineering Manager for Cudd Well Control, a division of Cudd Pressure Control, earned a BS in chemical engineering from Texas Tech University in 1972. He has 20 years’ oilfield experience with major / independent operators as a drilling / production engineer, plus 11 years with well-control companies, covering 14 U.S. states and 13 international countries. He has designed / supervised drilling / completion programs for deep and horizontal wells. He has worked on several major blowouts, including those in Kuwait during the Gulf War. Mr. Skinner is a licensed professional engineer in Texas. He has published several technical papers and holds three patents. He is a member of SPE, TSPE, NSPE and AIChE.

Energy Partners Plans for Mississippi

Mississippi Lignite Coal Plant

Transport Inergrated Gasification Art

America eagerly seeks new energy technologies to make us independent.  The Southern Company, the parent company of Mississippi Power, in cooperation with the Department of Energy have been trying to develop a cleaner, possibly less expensive, and more dependable methods of producing power from coal.  The result of some of this research is gasification. According to the Mississippi power website this technology was developed at the Power Systems Development Facility (PSDF) in Alabama.

The gasification of coal breaks down coal into chemical components which can be burned and used to fuel power plants using a fancy term called, ” Integrated Gasification Combined Cycle technology (IGCC) “ unfortunately there is an undesirable environmental impact.

Southern Company partnered with KBR (much more on this company later) and further developed the technology to use a low quality mushy coal called lignite.  It is said that Lignite is abundant in Kemper County, Mississippi so construction has begun taking advantage of the geographically close fuel source, Lignite, to reduce logistic transportation costs.  That’s prudent.

  • (T R I G ™) Transport Integrated Gasification utilizes a low grade lignite coal burning method that will be used at the IGCC facility in Kemper County Mississippi.  We understand they will be testing the effectiveness of the cleaning of emissions of nitrogen oxides, sulfur dioxide, mercury, and other dangerous elements some of which may be unexpected.

The Kemper County Coal Power Plant project appears to be in full cooperation with and DEPENDANT  upon the Al Gore global warming agenda, the Environmental Protection Agency (EPA), Cap and Trade, and the redistribution of wealth.  A carbon dioxide capturing device was incorporated into the lignite coal burning process. Carbon dioxide is the gas that sustains human lives and is required in the process of photosynthesis to maintain the life of plants. The EPA determined carbon dioxide is poisonous needing regulation.  Is it ridiculous for Mississippi to jump into compliance to these progressive money grabbing scams?  Does someone believe we are getting into the bottom floor of a pyramid scheme?

The Kemper County Plant is fully preparing for carbon dioxide to be regulated by government entities by investing rate payers monies (that means most of you in Mississippi)  into this brand-new energy plant utilizing brand-new never used to scale technology.   The risk of budgeting failure  without costly changes is certain and it is reasonable to expect the new technology will need costly adjustments following the testing in China, 2012. Risk is clearly documented, noted, and white-washed for the trusting silent Mississippians.

It has also come to our attention that some of the current coal burning plants in Mississippi will be fitted with scrubbers to improve the removal process of harmful toxins and to meet or exceed environmental standards. That seems reasonable and efficient but what you have not been told is some plants may be closed as a result of Kemper Power plant.  That equals lost jobs in Mississippi.

Americans optimistically look to the future for environmentally safer and economically sound methods of producing electricity.  Developing and correcting these new technologies directly out of pockets of unsuspecting Mississippians labeled as a power bill is unethical.

SOUTHERN COMPANY 2010 SUMMARY ANNUAL REPORT

SOUTHERN COMPANY 2010 SUMMARY ANNUAL REPORT.

“Our research and development team – the nation’s most comprehensive in-house function of its kind among regulated utilities – has spent years developing a process called Transport Integrated Gasification (TRIG), which produces energy by converting low-grade coals, such as lignite, into a synthesis gas. In 2012, that technology is set to make its commercial debut in China, a nation better known for exporting, rather than importing, innovation.”

The Technology for the Kemper County Coal plant is not fully proven and has never been utilized in a commercial setting.  Our concern is that the cost of unpredictable expenditures could be endless passing the cost onto ratepayers will cripple Mississippi.  A request to expand the costs with an explanation can be sent to the PSC for approval.  Simple procedure.  The caps of 2.2 billion expanded to 2.88 billion have been quoted to the public as being a cap.  These quotes are not firm and appear to give a false sense of security.   There is no final cap to the cost the ratepayers will be responsible for so far as we have read in the legal documents.

 

http://bcove.me/hbq7nisu

 

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