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?
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?
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?
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.?
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?
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?
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?
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?
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.


AEP Drops Carbon Storage Project On Lack Of Federal Carbon Limits –

AEP Drops Carbon Storage Project On Lack Of Federal Carbon Limits –

   By Cassandra Sweet

American Electric Power Co. (AEP) will stop work on a low-carbon coal-fired power plant as political support shrinks in the U.S. for regulating heat-trapping emissions linked to climate change.

The facility, which had been touted as a leading project to make the complex technology commercially viable, is the latest sign that the U.S. power industry is moving away from carbon dioxide emission-reduction technology. A lack of consensus in Washington over regulating carbon dioxide emissions, coupled with sluggish demand for power, has pressured AEP and other utilities to cut investment in so-called clean coal technology.

AEP Chairman and Chief Executive Michael G. Morris said the project to capture and store carbon emissions from an existing coal-fired plant in West Virginia doesn’t make economic sense while U.S. climate policy remains uncertain and the economy is weak.

West Virginia regulators had prohibited the company from passing on the project’s costs to utility customers until federal greenhouse-gas reduction rules are in place, further weakening the project, Morris said.

AEP designed the system to capture at least 90% of the carbon dioxide from a 235-megawatt piece of the company’s 1,300-MW Mountaineer coal plant in New Haven, W.Va.

The second part of the system would treat and compress about 1.5 million metric tons of CO2 from the plant per year, then inject the gas into rock formations about 1.5 miles (2.4 kilometers) below the surface, where it would be permanently stored.

The company said it would terminate an agreement with the U.S. Department of Energy, which had offered AEP $334 million to cover part of the costs of the carbon storage project. The project was to be completed in four phases and begin commercial operation in 2015.

A similar plant using different technology, proposed for Taylorville, Ill., by privately held power generator Tenaska, was scuttled in January after Illinois lawmakers defeated legislation that would have allowed the company to pass through the $3.5 billion cost of the project to utility customers. The Energy Department had offered the company up to $2.6 billion in loan guarantees and a $417 million tax credit to support construction of the plant.

Other low-carbon coal projects are moving ahead.

Southern Co.’s (SO) Mississippi Power utility is building a $2.4 billion, 580-megawatt low-emission coal-fired power plant in Kemper County, Miss. The plant, which was approved by state regulators, is designed to convert coal or lignite into a gas, which is then used to generate electricity, with lower emissions than a traditional coal plant. The company obtained a $270 million grant from the Department of Energy and $412 million in federal tax credits to support construction of the project.

Another low-carbon coal project is being developed by a coalition of utilities and coal companies called FutureGen. The $1.3 billion project would retrofit a 200-megawatt Ameren Corp. (AEE) coal plant in Meredosia, Ill., with so-called advanced oxy-combustion technology and build pipelines to ship captured CO2 to a nearby storage facility. A federal environmental review of the project, which has $1 billion in federal funding, is still pending.

AEP, one of the nation’s largest utilities and one of the largest coal-fired power generators, is still focused on cutting emissions. The company has estimated that it will likely to have to modify or shut down several of its older coal-fired power plants under pending federal limits on traditional pollution that could cost $6 billion to $8 billion over the next nine years.

Shares of AEP closed Thursday about 1% lower at $37.55.

-By Cassandra Sweet, Dow Jones Newswires; 415=269-4446;

No Limit to the Fees Passed Onto the People

Mississippi Power could not approve of this plant construction until there was unlimited funding to be passed along to us, the ratepayers.  2 out of 3 Public Service Commissioners suddenly changed their mind to lift the limit so building could proceed.

Mississippi Power Says Thanks But No Thanks

To Coal-Fired Plant

April 29, 2010

The three member Public Service Commission voted 2-1 today approving Mississippi Power’s plan to build a $2.4 billion coal-fired generating plant in Kemper County. However, the company, which has been fighting for over a year to win approval for the plant, says they will not build the plant.

The reason for this decision by Mississippi Power was the conditions put in force by the PSC. This includes a condition that put a $2.4 billion cap in the “amount of construction costs the company would be able to charge to rate payers.” The company said this restriction made it financially impossible to construct the plant.

The member who voted against the proposal was Brandon Presley, a Democrat, from the northern district. The politics of this is interesting. Presley said rate payers were not protected by even the proposal put forth by the PSC so I imagine he will make a populist claim for opposition. Presley as you may know is thought of as a rising star in the Democratic Party. But while he may claim populism, he is also siding with groups like the Sierra Club and labor unions- not necessarily groups you want attached to your hip as a candidate in Mississippi.

Mississippi Power Says Thanks But No Thanks To Coal-Fired Plant « Majority In Mississippi.

Mississippi Will Have Regrets for Bottomless Bankroll

Georgia Power trashes regulatory staff’s financial proposal for Vogtle cost overruns

By Kristi E. Swartz

The Atlanta Journal-Constitution

4:36 p.m. Wednesday, July 6, 2011


Georgia Power officials told state regulators they never would have started to build a new multi-billion-dollar nuclear power plant if they knew the company might be on the hook for certain potential cost overruns.

The company, they said, would be building a natural gas plant instead.

Georgia Power, which is the largest stakeholder in a partnership building two new reactors at Plant Vogtle, is responsible for $6.1 billion of the $14 billion project. The Georgia Public Service Commission’s staff wants to cut into the utility’s allowed profit margin if the project runs more than $300 million over budget. Profits would similarly get a boost if the reactors come in under budget by the same amount.

At a PSC hearing Wednesday, company executives said the proposal could drive up financing costs of the project, potentially damage the ability to raise capital and eventually increase customer bills.

“As a member of the management team of the company, if this mechanism had been part of the original certification, we very likely would have not proceeded [with the project],” said Ann Daiss, Georgia Power’s comptroller.

Tom Newsome, a member of PSC’s staff, said Georgia Power earns a high profit if the cost of the project increases. The PSC proposal would continue to allow for that but would shield the company’s customers from having to pay for those cost overruns.

Should the costs grow to $7 billion, Georgia Power wouldn’t earn below a 10.25 percent return on its investment from this project. The current rate of return on investment is set at 11.15 percent.

“Even under the most adverse outcomes, the units remain highly profitable with very limited risk for investors,” Newsome said. “We’ve been talking a lot about investors in this hearing and I think we need to be talking about [customers].”

There are exceptions. Georgia Power would not be responsible for paying for overruns stemming from safety, efficiency or regulatory changes.

Newsome, who sparred with a Georgia Power attorney for most of the afternoon, said he thinks the company’s construction costs could come in under the “deadband” or threshold set in the proposal.

Still, company executives say that had the PSC staff’s risk-sharing mechanism been part of the plan years ago, Georgia Power would be building a natural gas plant instead.

Pete Ivey, an executive with the nuclear unit of Georgia Power’s parent company, Southern Co., told state regulators that a natural gas plant would have been most cost effective.

Ivey said the PSC’s plans would force the company to look at short-term financial decisions instead of long ones. It could impact maintenance decisions, for example, he said.

The PSC will vote on this issue in August.


Georgia Power trashes regulatory staff’s financial proposal for Vogtle cost overruns  |

Commissioners: Law allowing utility to hide rate impact unfair » Mississippi Business Journal



Two out of the three Mississippi Public Service Commissioners think a law that has allowed Mississippi Power Company to hide the rate impacts of its proposed $2.4 billion power plant is wrong.

By law, a utility is allowed to file with the Commission any information it wants to keep confidential.

To uncover the information, a third party must make a request through the Public Records Act. The utility then has 30 days to petition Hinds County Chancery Court to rule in its favor or turn over the documents if the court chooses not to rule in its favor.

The 190,000 customers of Mississippi Power Company have little idea what effect in real dollars the Kemper County clean coal plant would have on their monthly electric bills.

Outside Commission proceedings, MPC has said rates will go up “about a third” whether Kemper is built or a natural gas-fired alternative is used. `

Northern District Commissioner and Chairman Brandon Presley said he plans to file a motion to change the rule so that the Commission will have the authority to allow or disallow a utility to mark information as confidential.

“This rule does nothing but protect the utilities…and to heck with the consumer,” Presley said. “We (the commissioners) are the representatives for the public interest, but if a consumer comes to me and asks me what the addition of this power plant is going to do to his rates, I have to say, ‘I’m sorry. The utility told me I can’t tell you that,’” Presley said.

Likewise, Southern District Commissioner Leonard Bentz is unhappy with the law.

“Those numbers should be made available to the public,” Bentz has said. “The ratepayers need to know the impacts. When the bills go up, they’re not going to call (company CEO) Anthony Topazi. They’re going to call me … The whole story is not getting told.”

While Presley does not favor the Kemper plant, Bentz did vote for an April 29 order that conditionally approved the project. Bentz’ district comprises most of the citizens who will be paying for the plant if it goes forward.

“It is frustrating. I want to build this plant, but I want everybody to know exactly what is going to happen when we build this plant. I have to look Gulf Coast residents in the eye and tell them I did everything I could to get the information on the table,” Bentz said.

Under the Administrative Procedures Act, the Commission has the authority to amend its own rules, Presley said. A Commissioner can propose a rule change then allow utilities and other intervenors to submit their opinions. The Commissioners take comments into consideration and may then choose to alter a proposed rule before a final vote is taken.

Central District Commissioner Lynn Posey doesn’t have a strong opinion about the law.

Regarding the rule, Posey said, “I don’t know a reason why off the top of my head (rate impacts) would be confidential… I would not object to looking into it.” However, as the law is being interpreted now, the court has the ultimate authority, and “to some extent that’s probably not a bad thing,” he said.

Posey voted along with Bentz for the conditional approval of the Kemper plant.

Click here to read Rule 109 of the Commission’s Rules of Practice and Procedure which addresses confidential filing of documents.

MPC filed a request for a rehearing on the plant, saying the conditions put forth in the April 29 order make the project impossible to finance. The Commission has said it will likely rule on the motion on May 26.

Commissioners: Law allowing utility to hide rate impact unfair » Mississippi Business Journal.


Anthony Topazi, Barbour, BGR Group, Bloomberg News, Brandon Presley, Clean Coal Power Initiative, Construction Work in Progress, CWIP, Florida, Gov. Haley Barbour, Griffith & Rogers Inc., Interpublic Group of Companies Inc., Kemper County clean coal plant, Kemper County clean coal project, Kemper County Coal plant, Leonard Bentz, Lynn Posey, Mississippi Business Journal, Mississippi Power Company, Mississippi State Ethics Commission, Orlando Gasification Project, Public Service Commission, Southern Company, The New Republic, Todd Terrell, U.S. Department of Energy

Libs Recycle Warmed Over Tactic to Push Their Climate Change Hoax

Libs Recycle Warmed Over Tactic to Push Their Climate Change Hoax
                                                                         July 1, 2011
RUSH: Last night on PBS’ Charlie Rose Show, he interviewed Conservation International Cofounder and CEO Peter Seligmann. During a discussion about “climate change,” Charlie Rose said, “Why does the debate linger?”

SELIGMANN: Ah, it lingers because, um… as I say, science is partially ideology.

ROSE: Mitt Romney got in political trouble with some people — you know, with Rush Limbaugh and others — by suggesting that there’s a human contribution to global warming.

SELIGMANN: If there was a 1% chance (pause) that the plane you were getting into this morning (pause) to fly here (pause) was gonna crash (pause) would you get on that plane? (dramatic pause) The answer is always no.

ROSE: Right.

SELIGMANN: Okay. So let’s assume that there’s only a 20% chance that climate change science is right. (pause) Do you take the risk of not responding to it?

RUSH: You know, that’s the argument these people have been using for decades. I first heard this argument made by a Professor (what was it?) Oppenheimer. Some guy named Oppenheimer. It was on This Week with David Brinkley when I was in Sacramento, and I remember it was the summertime (it had to be 1985) and back then of global warming he said, “We can’t prove it. We can’t prove it,” and it was just five years earlier that Newsweek and TIME Magazine had their cover stories on global cooling and the coming of a new ice age. So these guys are out now with global warming, and we only had 20 years. We only had 20 years — and if we were wrong, then disaster was gonna happen and we would not be able to do anything about it.

And the argument was: “We can’t prove it, but what if we’re right? We had better get started now! There’s no harm even if we’re wrong,” and, of course, there would be tremendous harm because the solution to manmade global warming is communism. The solution to manmade global warming is socialism. That’s what it’s all about. So here comes this guy, “Conservation International” Cofounder Peter Seligmann: “Okay, let’s assume there’s only a 20% chance that climate change science is right. Do you take the risk of not responding to it?” We know it’s a hoax! It’s been established as a hoax — and, by the way, if there was a 1% chance that that plane you were getting into this morning was gonna fly here was gonna crash, would you get on it? People do every day. People get on every day. There is a percentage that an airplane is gonna crash, and people get on ’em every day. Make no mistake about it.

So they’re back now to recycling the same old arguments.


RUSH: I want to go back, ladies and gentlemen, to this Peter Seligmann bite. A thought just struck me here. Peter Seligmann last night on Charlie Rose was talking about manmade global warming and Charlie Rose wondering why the debate’s still lingering. Here’s the bite again.

SELIGMANN: Ah, it lingers because, um… as I say, science is partially ideology.

RUSH: Wait a minute! Stop! Hold it just a second. Stop. Did you hear that? “[S]cience is partly ideology.” No, it is not, folks! That is a profound admission by this guy. He ought to be thrown out of the club for that. “[S]cience is in part ideology”? Ha! Tell that to Einstein. Anyway, that’s not what I wanted to focus on. Here’s the rest of the bite.

ROSE: Mitt Romney got in political trouble with some people — you know, with Rush Limbaugh and others — by suggesting that there’s a human contribution to global warming.

SELIGMANN: If there was a 1% chance (pause) —

RUSH: M’yeeez.

SELIGMANN: — that the plane you were getting into this morning (pause) —

RUSH: M’yeeez!

SELIGMANN: — to fly here (pause) —

RUSH: Yeees!

SELIGMANN: — was gonna crash (pause) would you get on that plane? (dramatic pause) The answer is always no.

ROSE: Right.

RUSH: Riiiiiiight.

SELIGMANN: Okay. So let’s assume that there’s only a 20% chance that climate change science is right. (pause)

RUSH: Right! Yeees. Right right right right.

SELIGMANN: Do you take the risk of not responding to it?

RUSH: Right. So for a 1% chance that these people are right, we are gonna fly our whole economy into a mountain? On a 1% chance — on a 1% chance that there is manmade global warming — we’re gonna go communist? We’re gonna go socialist?


via Libs Recycle Warmed Over Tactic to Push Their Climate Change Hoax.

Carbon Dioxide – Geologic Sequestration | Climate Change – Greenhouse Gas Emissions | U.S. EPA

Mississippians are told by their Elected Public Service Commissioners that the Kemper County Coal Plant will Capture CO2 then store, transport, and trade it.  So let’s learn more about this process:

Geologic Sequestration


According to scientists, atmospheric build-up of carbon dioxide (CO2) and other greenhouse gases as a result of human activities is changing the composition of the Earth’s atmosphere and tending to warm the planet. Scientific studies link these changes to shrinking glaciers, sea level rise, changes in plant and animal habitats, and other global impacts. One possible way to avoid the negative impacts of higher atmospheric concentrations of CO2 is to avoid emitting the CO2 into the air in the first place.

Carbon dioxide can be captured at stationary sources and injected underground for long-term storage in a process called geologic sequestration (GS) (Video – WMV, 8 min.). In its Special Report on Carbon Dioxide Capture and Storage Exit EPA Disclaimer, the Intergovernmental Panel on Climate Change (IPCC) identified CO2 capture and geologic sequestration as one of several options (including energy efficiency and renewable energy) that have the potential to reduce climate change mitigation costs and increase flexibility in achieving greenhouse gas emission reductions. The IPCC estimates that there is enough capacity worldwide to permanently store as much as 1,100 gigatons of CO2 underground (for reference, worldwide emissions of CO2 from large stationary sources is approximately 13 gigatons per year) (IPCC, 2005).

Confidence in this technology is supported by the knowledge that CO2 produced through natural processes has been retained in geologic formations for hundreds of millions of years (IPCC, 2005). The presence of multiple trapping mechanisms will reduce the mobility of CO2 underground over time, decreasing the risk of CO2 leaking to the surface (IPCC, 2005). It is likely that well-selected, well-designed, and well-managed GS sites can sequester CO2 for long periods of time.

Approximately 95% of the largest stationary sources of CO2 emissions (e.g., coal-fired power plants) in the United States are within 50 miles of a candidate GS site (GTSP, 2006). Considering the large storage capacity in the United States, GS has the potential to contribute significantly toward meeting the goals of the nation’s climate policy. To help realize these goals, the federal government is conducting a wide range of GS-related activities.

EPA Roles and Responsibilities

EPA’s goal is to ensure that GS activities are conducted safely and effectively. EPA’s Underground Injection Control (UIC) program regulates underground injection of CO2 and other fluids under the Safe Drinking Water Act (SDWA). The UIC regulations were designed to help ensure that injected fluids do not endanger underground sources of drinking water. The regulations are implemented by state and federal regulators and well operators with expertise in relevant geological issues, well siting, well construction, well operation, and well closure. With over 800,000 regulated wells injecting a variety of fluids over the past 30 years, the UIC program is one of the largest and most experienced permit programs in the nation.

EPA’s primary responsibilities include:

Developing Greenhouse Gas Reporting Mechanisms for GS Under the Clean Air Act

Developing UIC Regulations Under the Safe Drinking Water Act (SDWA)

Evaluating Risks to Human Health and the Environment

EPA is working closely with the Department of Energy (DOE), state co-regulators and other stakeholders on all GS activities to leverage resources, clarify key questions and data gaps, and ensure that work is complementary and not duplicative. The following are examples of the products of these coordinated efforts:

EPA issued Class V Experimental Technology Well Guidance for Pilot Geologic Sequestration Projects in March, 2007 to assist in processing permit applications for near-term pilot projects.

EPA has been sponsoring and co-sponsoring workshops on Geologic Sequestration since 2005.

EPA’s GS-related activities support those that DOE is conducting. For more than a decade, DOE has led federal efforts on research, development, and deployment of GS technologies. DOE is currently directing seven regional carbon sequestration partnerships and overseeing the development of FutureGen Clean Coal Projects, an initiative to equip multiple new clean coal power plants with carbon capture and storage technology.


GTSP. 2006. Carbon Dioxide Capture and Geologic Storage: A Core Element of A Global Energy Technology Strategy to Address Climate Change. Global Energy Technology Strategy Program.

IPCC. 2005. Special Report on Carbon Dioxide Capture and Storage, Special Report of the Intergovernmental Panel on Climate Change.

via Carbon Dioxide – Geologic Sequestration | Climate Change – Greenhouse Gas Emissions | U.S. EPA.

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.


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 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.


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.


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.


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.


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


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.


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)


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.

Lignite looking more like the wrong horse to have bet on » Mississippi Business Journal

Lignite looking more like the wrong horse to have bet on » Mississippi Business Journal.

by For the MBJ

Published: June 19,2011

Tags: Kemper plant, Mississippi Power, natural gas, shale, view

While the world has been championing natural gas as the savior of the energy crisis, Mississippi Power has insisted that gas prices will be high and volatile — reminiscent of 2009 — for years to come.

The 2011 Energy Outlook from the U.S. Energy Information Administration (EIA) projects that natural gas prices will stay around $5 per million Btu through the year 2022.

Why? Advancements in technology have made it possible to get natural gas from a rock called shale.

TIME Magazine recently featured a chunk of shale on its cover with the headline: “This rock could power the world.”

These predictions are bad news for Mississippi Power Company customers who will pay for the $2.4-billion Kemper County clean coal plant.

Public records obtained by the Mississippi Business Journal show that in order for customers to see a cost benefit from the plant, gas prices will have to reach the $12 – $14 per million Btu range by 2020. That’s more than twice what they are predicted to be.

Where was this information in the spring of 2010, when the state Public Service Commission gave Mississippi Power the green light to build this expensive clean coal plant?

The answer is that it was available. A year ago the EIA was predicting that gas prices would be around $6 or $7 by 2020.

The Kemper Plant in a nutshell
A study said that the Mississippi Power service area in southeastern Mississippi would need more electric generation by 2014.

Mississippi Power asked the state Public Service Commission if it could build a $2.4-billion clean coal plant in Kemper County to meet that need. The company has to ask the state for permission to build the plant, because, as always, captive power company customers have to foot the bill for utility improvements — which are essentially public works projects, not economic development projects.

The company based its request on the fact that natural gas prices had been historically high and volatile. But, ignoring information from the EIA and numerous other entities, it predicted gas prices would continue to be high in the future.

Thus, the utility argued, the alternatives — buying natural gas-generated electricity from independent power producers or building a natural gas plant themselves — would not be in the best interest of Mississippi Power’s customers. Electricity from a lignite coal plant would be cheaper, they said.

What was the rush?

Why couldn’t Mississippi Power have waited to build the plant? Say five years, even, and let customers benefit from cheap gas prices and put off paying for a multi-billion-dollar plant?

The power company stressed that its grant from the U.S. Department of Energy had a time limit. But the grant was only for $270 million, which is not that large of a chunk when you’re looking at a $2.4-billion price tag.

Rate increases that customers will bear as a result of the plant are still unknown, by the way. The Mississippi Public Utilities Staff allowed Mississippi Power to conceal them from the public.

We at least know how plant costs will affect chicken farmers in Southeast Mississippi. According to information released by the Mississippi Poultry Association, Mississippi Power informed its poultry farmer customers in September that their electric rates would be rising by more than 30 percent due to the Kemper plant.

ISS – Mississippi coal plant taken to court

ISS – Mississippi coal plant taken to court.

Mississippi coal plant taken to court

kemper_coal_plant_press_conf.jpgBy Ada McMahon, Bridge the Gulf

On Monday, Feb. 14, the Sierra Club took Mississippi Power’s proposed lignite coalmine and power plant to court, as part of its ongoing attempt to stop the project from being built.

In a morning press conference, the environmental group and a diverse range of residents and advocates voiced their opposition to the project, calling it “dirty, expensive, and unnecessary.” They said residents of south Mississippi simply cannot afford the $2.4 billion project, which is expected to bring a 48% rate increase to Mississippi Power’s residential consumers.

Rose Johnson, founder of the North Gulfport Community Land Trust and former head of the Sierra Club’s Mississippi Chapter, spoke about the impact the project would have on the African American community of North Gulfport. “My opposition arises from the numbing and debilitating effect that a 48% rate hike would have on my community and its citizens. Many are struggling to make ends meet. The last thing they need … is an unnecessary, expensive, $3 billion coal plant.”

Byron Johnson spoke to the impact such a dramatic rate hike would have on local business. “We will not be able to survive a [rate] increase,” he said of the two Gulfport restaurants he owns.

The project, slated for Kemper County, was initially rejected by Mississippi’s Public Service Commission, which cited its “unprecedented risk” and expense to ratepayers. But then the Commission reversed its decision, granting a certificate the project needs to move forward.

Sierra Club through its attorney Robert Wiygul argued that this “flip-flop” decision is arbitrary and not supported by the Commission’s own findings. They say that the Commission must justify its decision with more substantial evidence that the project is in the public interest, or stick with its earlier decision and not grant the certificate at all.

Many of Wiygul’s arguments came from the Commission’s earlier decision to reject the project. He cited the Commission’s comments that it would be “too big to fail,” and create “unprecedented risk” and “unprecedented cost” for ratepayers in Southern Mississippi.

Wiygul said that the Commission failed to explain how these, and a total of 11 risks it initially identified, were no longer of concern. 

Through his questioning, Chancery Court Judge Jim Persons appeared to have similar concerns, saying that the Commission did not address whether ratepayers will be able to afford a 48% increase in energy bills. The Judge said he will make his decision within two weeks.

Mississippi Power’s attorney Ben Stone argued that diversifying Mississippi’s energy sources with lignite coal would be cheaper for the ratepayer, pointing to the volatility of natural gas prices. But he failed to offer specifics to counter the claim that rates would rise by nearly half for Mississippi Power customers.

Passing this “unprecedented cost” off on ratepayers is enabled by a 2008 Mississippi law, which allows power companies to pay for plants before they are built through rate increases, rather than paying for upfront costs themselves or through private investors.

In addition to rate increases, which would begin in 2014, opponents have concerns about the environmental and human health impacts of lignite coal mining. The Sierra Club says the Kemper County project would displace hundreds of residents, strip mine 45 square miles, create a 500 acre dump for toxic ash, and emit mercury into streams, wetlands and neighboring communities.

No matter the environmental impacts, Sierra Club calls building any new power plant in Mississippi “unnecessary” because current plants and new energy efficiency projects can easily meet the state’s energy needs for decades to come.

(In the photo by Ada McMahon, Rose Johnson and other residents, business owners, advocates and elected officials from the Mississippi Gulf Coast speak out against the Kemper County power plant at the Harrison County Courthouse on Feb. 14, 2011.)

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