With cold weather and snow flurries expected this weekend, they just might. But Public Service Company of New Mexico has a little good news to offset the bad.

The company estimates more natural gas will be used this January than last, but expects the average residential bill to be less than last year’s.

That’s because January’s per-therm cost of natural gas dropped by 19 percent from last year for PNM customers.

This January’s average bill will likely come in around $116, according to PNM. Last January it was $129.

Company spokeswoman Susan Sponar said the drop was due to a warmer winter in other parts of the country driving down demand for gas, thus lowering its price.

The company also estimates that average bills in February and March will be less than what they were last year. They’ll still be in the $91 to $110 range.

PNM encourages its customers in numerous ways to cut down on their natural gas bills.

That includes weatherizing your home, sealing off unused rooms and lowering the heat during the night.

“Being more watchful” is how Benavidez describes it.

He keeps his home’s doors closed. At night, he puts his thermostat at 70 degrees, down from 75.

If those measures don’t cut it, there is help for families struggling with bills, as long as their household income meets certain requirements.

Last year, 5,100 households got assistance through PNM’s Good Neighbor Fund, which gives grants to households fighting high heating costs, Sponar said.

This year’s numbers aren’t yet in, but more than $700,000 has been raised.

Another option – the federally funded Low Income Home Energy Assistance Program – is creating some confusion.

That’s because the grants available through the program are far less than they were last year, said Betina Gonzales McCracken, communications director with the New Mexico Human Services Department.

Instead of households getting one-time grants of about $417 as they did last year, they can expect $127 this year, she explained.

Blame the funding.

Gonzales McCracken said that last year, the state added $23 million in emergency funds to the federal funding, which has held steady at about $10 million for the past four years.

This year, the Human Services Department might get $2 million in state help, she said.

“While the price of gas is going up on a regular basis,” she said, “they (the federal government) have not increased funding for this program.”

Last year, a record number of households received assistance through the program – 71,794, Gonzales McCracken said.

“We’re assuming we’re going to serve the same amount of people as last year,” she said. “With less money, the benefit is going to be a little bit less.”

The money, if approved, could be used to buy New Mexico Utilities Inc., a water and sewage company serving roughly 41,000 people in northwestern Albuquerque and northern Bernalillo County.

Citing concerns over the company’s management of water resources, the authority has long sought to buy New Mexico Utilities, a subsidiary of a California company, or make it comply with the authority’s expectations.

With negotiations stalling, the authority has threatened to condemn the company in order to force it to sell, said authority board Chairman Alan Armijo.

He said pursuing the $50 million bond – which would be up for approval at the authority’s Jan. 25 meeting – is one step to prepare for a purchase.

It is too soon to know whether the conflict might go to court, as negotiations are still possible, Armijo said.

If the two sides did go to court, that’s where they would argue the sale price for New Mexico Utilities.

The company puts its value at roughly $100 million, said Vice President and General Manager Bob Gay.

The authority puts the company’s value at $31.7 million. Armijo said the extra money in the bond request would allow for adjustments in the final price.

A court case and buyout could be avoided entirely if New Mexico Utilities managed its water in the way requested by the city-county water authority, Armijo said.

That could include the company doing the following:

Adopting more water-conservation measures, like those of the city’s.

Increasing what it charges customers for water.

Purchasing more water rights to make up for depletions to the supply.

Assuring it would take responsibility for any depletions to the water supply if the company were to leave the state.

Gay said the company has no plans to leave New Mexico.

New Mexico Utilities is restoring the water it is required to, he said, and increasing the price would be an unnecessary burden on customers.

He also says customers of New Mexico Utilities have reduced their per-capita water use more than customers on the city’s water system.

The city’s per-capita water use for residential customers dropped 26.1 percent between 1996 and 2005, according to the authority’s figures.

New Mexico Utilities’ per-capita water use for residential customers went down 30.1 percent in the same period, according to New Mexico Utilities.

However, from 1996 to 2005, the company’s total water use went up by 73.3 percent as its number of accounts grew by 253 percent.

In the same period, the city’s total water use went down 16.5 percent while the number of accounts went up 20.9 percent.

Gay said New Mexico Utilities will argue the company’s value in court if necessary.

“You always hope these things don’t happen, but they didn’t catch me completely off guard,” he said.
]]> http://flyingflashlight.com/2006/12/15/article-in-the-albuquerque-tribune-county-seeks-funds-to-buy-water-utility/feed/ 0 http://flyingflashlight.com/2006/09/20/article-in-the-albuquerque-tribune-city-new-mexico-utilities-square-off-over-water-usage/ http://flyingflashlight.com/2006/09/20/article-in-the-albuquerque-tribune-city-new-mexico-utilities-square-off-over-water-usage/#comments Wed, 20 Sep 2006 15:51:38 +0000 flyingflashlight http://flyingflashlight.com/?p=1221 Continue reading →]]> Concern over the Duke City’s future water supply has pitted the city against a private water utility company serving 55,000 people in northwestern Albuquerque and northern Bernalillo County.

“They continue pumping the same aquifer we’re trying to save,” said Alan Armijo, chairman of the Albuquerque Bernalillo County Water Utility Authority board. “There really isn’t any way to have any kind of oversight on it from our end.”

“They” is New Mexico Utilities Inc., a water and sewage company that has asked the State Engineer’s Office to approve an increase in the amount of water the company can annually use. A hearing is scheduled for June 2007.

The Water Authority is protesting the increase, and Armijo and other Authority officials cite several concerns:

• The amount of water being used by New Mexico Utilities.
• The rate at which the company is replenishing the water.
• Under an agreement signed with the company, if New Mexico Utilities left the state, the city would be held responsible for any water taken from the aquifer that the company had failed to replenish.
• The company’s commitment to water conservation.

New Mexico Utilities customers are not subject to the water-use restrictions adopted by the city in 1995.

Those were taken on after scientific studies showed the Middle Rio Grande Basin aquifer contained less water than previously thought.

“Bottom line . . . how do we all in this region save water for the future and keep that aquifer with the ability to continue to replenish itself?” Armijo said.

Replenishing

The State Engineer’s Office said New Mexico Utilities is replenishing aquifer water better than the rate required by its permit, but the city-county water authority said what’s being counted as replenished water needs a new definition.

The company’s permit requires water depletions to be made up when they are seen in the river, explained Jess Ward, district one supervisor with the state engineer’s office.

But with aquifer-fed wells sometimes miles away from the river, years can pass before any effect is seen.

That means used water could go for years without the consumer having to replenish it.

Even though the company returns more water than is required by its permit, that amount is about 35 percent of what the company uses annually, Ward said.

The rest of the consumption has yet to impact the river, and so does not need to be replenished yet.

If the same water was permitted under regulations adopted in 2000, Ward said the company would need to immediately buy more water rights to replenish the water it is using.

That’s because the new regulations require an entity to replenish water as it is used. Monthly measurements track the consumption.

He said the Water Authority has its water usage more or less covered, if the San Juan-Chama Drinking Water Project is taken into account.

In 2008, that project – diverting water from the San Juan-Chama River – is expected to begin supplying up to 70 percent of the metropolitan area’s water.

By the water authority’s calculations – which don’t allow for returned water accounted for by the company and the State Engineer’s Office – New Mexico Utilities is annually taking out 3,700 acre feet more than it is required to put back in. That’s about 1,600 Olympic-sized pools of water.

The Water Authority is concerned that amount could increase, increasingly straining Albuquerque’s and Rio Rancho’s water supply while neglecting the state’s larger, water-conservation needs.

“It’s very scary for our (New Mexico’s) long-term sustainability,” said Mark Sanchez, executive director of the Water Authority. “We all live in a desert and we all have to get better at conserving water.”

But Bob Gay, vice president and general manager of New Mexico Utilities, a subsidiary of a California company, said New Mexico Utilities’ customers have significantly reduced individual use in the past 10 years.

“I think we have shown that we are doing a very good job in water conservation, short term and long term,” he said. “We are complying with all the requirements of the state Engineer’s Office of the state of New Mexico.”

Enacting additional conservation measures similar to the city’s would cost the company more money, he said. Those measures include limiting watering to certain days and charging fines for heavy water use.

Such steps would mean a rate increase for New Mexico Utilities, which the New Mexico Public Regulation Commission would have to approve.

The last increase came in 1986, Gay said. That same year, the company proposed increasing rates according to how much water a customer used, thus making heavy users pay more and theoretically promoting conservation.

The PRC rejected the plan, Gay said.

“If conservation is working without all these extreme measures, it doesn’t make sense for me to make people pay more for something when they’re doing the right thing now,” he said. “I really do believe if you educate people, they’re going to do the right thing.”

He pointed out that the company’s profit levels are set by the PRC.

“It’s not like we’re going to make any more money if the rates go up,” he said. “All it’s going to do is make our customers pay more for something than they have to.”

The city charges $1.41 per 748 gallons of water used, according to the Water Authority Web site. New Mexico Utilities charges 96 cents for the same amount, according to company documents.

A consequence of leaving

Gay said the Water Authority’s fears about the company leaving the state are groundless; it plans on staying.

If it did leave, the city of Albuquerque would be responsible for any water depletions of New Mexico Utilities that go unreplenished.

That could mean the city would be left with buying water rights costing between $28 million and $37 million at current rates, Sanchez warned.

To cover such depletions, the Water Authority wants the company to buy more water rights.

Water rights allow their owner to use about two acre-feet of water per acre of land, said John Stomp, water resources manager with the Water Authority.

An acre-foot is how much water it takes to fill one acre of land one foot deep with water. It is 325,851 gallons, or about half the amount of water in an Olympic-sized swimming pool.

Water rights are typically bought from farmers who stop working their land, Stomp said. Sanchez estimated that a single acre-foot of water costs about $10,000.

Sanchez said New Mexico Utilities has failed, for the most part, to buy water rights for the past 15 years.

Gay countered that New Mexico Utilities went after three purchases of water rights this year. But the Water Authority itself stymied two of them, he said, by filing a petition with the state engineer’s office. The protests were eventually dropped.

Such protests caused one deal to fall through because they can prolong how long it takes to complete a sale, Gay said.

Another deal was successful and another is pending. Gay would not say how much water would be included in the purchases.

“Every water right we try to buy, they protest,” he said. “I’ve had several buyers who won’t talk to me because they know it’s going to be dragged out (because of the protests).”

When asked to explain why the Water Authority protested the purchase of water rights, Sanchez said it was in response to protests lodged by the company when the Water Authority tried to buy additional water rights.

A request for more

The Water Authority is also concerned about New Mexico Utilities’ application to increase how much water it can pump from the aquifer.

The company wants to increase its allotment from 10,000 acre-feet per year to 60,000. The application is pending with the state.

“It is a big leap,” Gay said. “It would be an ultimate amount ever to be needed.”

The increase is so the company would no longer have to go through the permitting process, which Gay said can take years.

The idea of New Mexico Utilities having access to more water has Sanchez worried, especially when he claims the company is not buying enough water rights to make up for its use.

In the past, the authority and Rio Rancho have made overtures to buy the company but that failed.

Sanchez said there is no clear timeline for resolving the disputes or completing a sale, but lawyers for both sides are in talks.

FACTBOX: City Water Use

Here’s a look at how much water the city uses annually for all its customers, as well its number of residential accounts – which can be made up of one or more people – and per-capita daily usage for residential accounts:

1996: Total: 39.3 billion gallons; Accounts: 122,861; Per capita: 115 gallons.

2000: Total: 37.5 billion gallons; Accounts: 132,819; Per capita: 107 gallons.

2005: Total: 32.8 billion gallons; Accounts: 148,480; Per capita: 85 gallons.

Percent change: Total: Down 16.5 percent; Accounts: Up 20.9 percent; Per capita: Down 26.1 percent.

Source: Albuquerque Bernalillo County Water Utility Dept.

FACTBOX: New Mexico Utilities Use

Here’s a look at how much water New Mexico Utilities is using annually for all its customers, as well its number of residential accounts – which can be made up of one or more people – and per-capita daily usage for residential accounts:

1996: Total: 1.5 billion gallons; Accounts: 3,975; Per capita: 146 gallons.

2000: Total: 2.1 billion gallons; Accounts: 7,590; Per capita: 121 gallons.

2005: Total: 2.6 billion gallons; Accounts: 14,017; Per capita: 102 gallons.

Percent change: Total: Up 73.3 percent; Accounts: Up 252.6 percent; Per capita: Down 30.1 percent.

Source: New Mexico Utilities

People in cities on the oceans’ edges, such as New Orleans and New York, would be forced to move as their homes and businesses flooded.

“There will be literally millions of people on the move in the United States,” said Ed Mazria, founder of the architecture firm Mazria Inc. Odems Dzurec and expert on energy-efficient building design. “Today we have a choice. . . . We can continue on our present course or we can choose another path.”

Possible paths to a future powered by sustainable and environmentally friendly energy sources were discussed Thursday at the two-day conference attended by political, business and scientific leaders from around the state and country.

New Mexico can lead the way, Mazria said, and the journey can start with building design.

The problem is buildings’ appetite for fossil fuels. Nationwide, buildings make up 48 percent of energy consumption, according to U.S. Energy Information Administration statistics cited by Mazria.

“Heating, lighting and cooling are the big three,” he said. “Globally, the percentage is even greater.”

That makes buildings powered by fossil fuels one of the greatest contributors of greenhouse gas emissions, Mazria said. Many scientific studies have shown the gases contribute to global warming.

Cutting back on buildings’ energy consumption, he said, can be as simple as designing them to better use the heat and light of the sun. Other technologies, such as solar power panels, can help, too.

“But you start first with the low hanging fruit, which is design out as much as you can,” he said.

By the year 2030, he and Architecture 2030, a movement sponsored by the nonprofit New Energy Economy out of Santa Fe, hope to see buildings consume zero fossil fuels.

“There are lots of ways to do it,” he said. “Albuquerque can take a leadership role.”

As a guiding philosophy for energy use, Mazria said any decision should be judged by how it will impact people seven generations into the future.

“If your action is good for that generation, then do it,” he said. “If your action is not good for that generation, then don’t take that action.”

But he warned other cities have to join in the effort to redefine energy consumption, or it will be for naught.

Kurtis Helvie, a 15-year-old freshman at High Tech High School in Albuquerque who attended the conference with several of his classmates, said the country needs to change its approach to energy use.

“I think if we don’t start changing our ways, it’s going to be deadly,” he said, and in comparison to problems caused by fossil fuels, “we’ll think Katrina was nothing.”

Conference attendee Cory Johnson, 14, said some of his peers lack knowledge about the environmental issues surrounding global warming.

“I don’t think they even really understand the full consequences of it,” he said. “They know that global warming is going on, but they’re just sort of fine with it. They’re like, `Oh, one degree celsius, what is that?’ ”

Education about energy – where it comes from, its costs and consequences of its use – will be an important part of Albuquerque’s future, according to one conference panel that brainstormed how the Duke City could evolve into a sustainability leader by 2015.

A classroom for such lessons could be stores, according to Bruce Milne, professor of biology at the University of New Mexico and director of the UNM Sustainability Program.

He proposed adding information to product labels that describe how much energy it took to make and transport a product.

It’s called embodied energy. It accounts for factors such as the fuel consumed to ship a product, and the energy expended assembling and refining the product’s raw materials.

“When you go to the shopping mall, you don’t have any clue as to which products embody a lot of energy and which don’t,” he said. “You can’t make choices based on the environmental impact that particular product has.”

Other changes are simpler to make.

As Milne left the empty panel room for a lunch break with two others, he stopped and, with a laugh, headed back.

“We should turn off the lights,” he said.

According to the North American Electric Reliability Council (NERC), a not-for-profit corporation of power industry members that oversees the grid’s reliability, for every gigawatt of new power generation capability installed in 1972, there was roughly $200 million in year-2000 dollars invested in the transmission grid. That’s $6 billion spent on the lines supporting 30 gigawatts of new power plants.

But in 2001, 41.8 gigawatts of new power plants got only $3.9 billion — or about $90 million per gigawatt, less than half the 1972 level — invested in the transmission grid. And in 2002, 57.7 gigawatts of new power plants came online and only $3.5 billion was invested in the grid. That’s $60 million per gigawatt. NERC estimates about 53.8 gigawatts of new power plants were added in 2003, accompanied by about $3.8 billion in grid investment –- or $70 million invested per new gigawatt.

“It doesn’t seem this blackout is attracting the financing activity it should have,” said Richard Stavros, executive editor of Public Utilities Fortnightly, a magazine covering the power and gas industry.

Investment in the grid is being held up in part by a complicated power struggle between state and federal authorities.

In 2003, the Federal Energy Regulatory Commission (FERC) tried to encourage grid investment by allowing companies to charge up to 3 percent more for transporting power though their lines if they joined a regional transmission organization (RTO). RTOs are not-for-profit companies responsible for directing power across the grid in the same sense that air traffic controllers direct flights in and out of airports. In joining an RTO, a company gives it control of the company’s transmission lines.

“Everybody thought last year that would create a huge investment wave,” Stavros said.

But some states, concerned that the higher rates allowed by FERC would raise electricity prices for their constituents and undermine their regulatory authority, temporarily barred companies in their states from joining RTOs, or instituted approval processes for joining an RTO.

FERC has proposed ordering companies to give control over their transmission lines to RTOs, but the stalled federal energy bill, if passed, would forbid it until 2007, said Bryan Lee, spokesperson for FERC. However, a court case underway between FERC and American Electric Power Co. Inc., a utility holding company, may help resolve whether FERC or the states have authority over companies in regard to joining RTOs.

And there’s another debilitating tussle between the federal and state governments, over which should control siting, the process by which a new site is chosen and approved for the installation of new power lines.

States currently have siting authority, and it can take years to get approval from all the different entities involved in a siting decision, especially troublesome when power lines in today’s partially deregulated electricity market need to cross the nation.

Deregulation — initiated by the Energy Policy Act in 1992 — revved up in 1996 with an order from the Federal Energy Regulatory Commission. It required any company owning electricity transmission lines to let other companies send their power through those lines. As a result, consumers could pick and choose their power supplier from around the nation, birthing a national, competitive market for power.

But the essential backbone of that national power market — the nation’s transmission grid — was built to handle local, intrastate transfers of power. It was never intended to cope with the massive movement of power across the nation that has pushed the power lines toward their limits.

“The existing interconnection transmission systems in this country are today being used in ways for which they, frankly, weren’t designed,” said Brant Eldridge, executive manager of the East Central Area Reliability Council, one of 10 regional members of NERC. “You don’t have as much margin if something goes wrong as you used to have.”

Richard Bulley, executive director of Mid-America Interconnected Network, another regional member of NERC, said the power lines are currently operating closer to their limits, subsequently requiring closer scrutiny of the lines than in the past.

Providing that scrutiny in the Midwest is the Midwest Independent Transmission System Operator Inc. (MISO), a non-profit organization located in Carmel, Ind. MISO, founded in 1996, was the first regional transmission organization (RTO) approved by the Federal Energy Regulatory Commission.

MISO’s reliability coordinators watch over the transmission grid stretching from eastern Montana to Indiana and Michigan. If they spot a problem, they tell local control-area operators — working for utility companies — who then fix it by altering the flow of power across their utility’s section of MISO’s portion of the national grid.

In its investigation of last summer’s blackout, NERC found MISO partially responsible and asked it to improve a host of its operational aspects by June 30.

One improvement includes MISO giving its reliability coordinators five more days of training dealing with emergency power situations. NERC also asked MISO to improve its ability to monitor the power grid, a task primarily accomplished by the grid overview — a screen showing all the different points on MISO’s grid area and the amount of power flowing through those points. The overview did not cover all of MISO’s territory until October 2003, over a month after the blackout, said Roger Harszy, vice president of engineering at MISO. But in December, MISO launched an upgraded computer system that increased its ability to track the flow of power across the grid.

“The full deployment of our set of tools that we have now would certainly been very beneficial in August last year,” he said.

Additionally, NERC asked MISO to report any grid disturbances it observes — even if the meaning of the disturbances is unclear to MISO — to other reliability coordinators and control-area operators, Harszy said. Before the blackout, MISO would analyze disturbances and report its findings rather than each disturbance, he said.

NERC also initiated a new, tri-annual inspection of the nation’s control-area operators and RTO reliability coordinators. Reports of all of the new inspections will be made public, whereas only the inspections of reliability coordinators were made public in the past, said Michehl Gent, president and chief executive officer of NERC, during a press conference.

The reports NERC receives will also offer more thorough information — identifying specifically who made a violation and the exact nature of the violation. Past reports sent to NERC listed the quantity of violations, but did not identify the violators or details of the violation, Gent said.

Stavros said NERC’s recommendations were a good sign, but they fell short of addressing the real problem because NERC, a voluntary organization, lacks regulatory authority. If it had approval from Congress to enforce its recommendations, he said, it could set standards that would require utilities to invest in the transmission grid.

“If the money’s not going into upgrading the transmission infrastructure, how are you going to be able to adequately tell the American public that you’ve been able to improve reliability?” he said.
————————————————–
*This is the full version of the article; The Times of Northwest Indiana published a shortened version in its Sunday business section (February 29, 2004).

*The Medill News Service published this article in February 2004. It is archived here.

In January the state’s first large-scale wind farm — 63, 213-foot tall turbines turning wind into electricity –- got its finishing touches from Navitas Energy Inc., a Minneapolis-based wind farm developer and subsidiary of Spain-based Gamesa Energia S.A.

Near Compton, Ill., the wind farm totals 50.4 megawatts in capacity and spreads over roughly 3,000 acres. Those who own the land the turbines sit upon will receive $2,000 to $4,000 a year for each turbine. With an annual power output estimated to be 126 million kilowatt-hours, the farm could power about 12,000 homes.

“The Great Plains, especially in the winter, is like a vast ocean of wind,” said Greg Jaunich, chief executive officer of Navitas. “There will be a lot of renewable energy installed in the U.S. over the upcoming years.”

He may be right. Wind energy capacity grew in the nation by an average of 24.5 percent a year from 1998 to 2003, when it reached 6,374 megawatts, according to the American Wind Energy Association (AWEA).

Iowa held 471.2 megawatts of that total and Wisconsin held 53 megawatts. Indiana has no wind farms, but in Illinois, two stalled wind farm projects — totaling about 100 megawatts — will begin construction when Congress passes the long-stalled federal energy bill with its wind energy production tax credit.

Jaunich said the declining cost of producing wind energy — which is beginning to make it competitive with fossil fuels — is one reason interest in wind energy has grown from a breeze to gale.

In the 1980s wind energy cost between 38 cents and 40 cents per kilowatt-hour to produce, said Stefan Noe, president of Illinois Wind Energy LLC, another developer of wind farms. He said the cost is now around 3 cents to 4 cents per kilowatt-hour.

In comparison, energy produced by natural gas — before the recent price jumps — costs about 3 cents to 4 cents per kilowatt-hour, said James Johnson, senior mechanical engineer at the National Renewable Energy Laboratory (NREL) in Golden, Colo., by e-mail. He added that power from paid-off coal plants costs about 2 cents per kilowatt hour, and from new coal plants, about 4 cents per kilowatt-hour.

Much of the drop in wind energy production costs can be attributed to the turbine’s blade size.

In the 1980s, wind turbine blades were 15 to 18 meters long, Johnson said. The blades got bigger — the longest today being 75 meters for 7-megawatt offshore wind turbines — as manufacturers better understood their aerodynamic and structural properties. Bigger blades mean cheaper energy because manufacturing costs grow only slightly when the blade gets slightly bigger, but the megawatt capacity increases exponentially, he said.

But the blades probably won’t get any bigger due to the cost of transporting and installing such behemoths, Johnson said. Further cuts in wind energy cost will have to come from improved manufacturing processes or by increasing the quantity of turbines being manufactured in order to hit even better economies of scale.

Even with the huge, cost-efficient turbines, Illinois Wind Energy’s 51-megawatt wind farm in Bureau County — about 120 miles southwest of Chicago — won’t be built until Congress passes the energy bill, which includes the renewal of a wind energy production tax credit.

The credit is 1.5 cents per kilowatt-hour of renewable energy produced. It is adjusted for inflation and was at 1.8 cents per kilowatt-hour before expiring on Dec. 31, 2003, after a two-year extension in 2001. The AWEA has pushed for a five-year extension.

The credit began as independent legislation supported by both political parties, said Kathy Belyeu, a spokesperson for the AWEA. However, it was attached to the energy bill for political reasons and the AWEA’s attempts to detach it and have it passed separately have failed.

The lack of a production tax credit is also holding up construction of Forever Power & Construction Services Inc.’s 44.5 megawatt, $60 million wind farm near West Brooklyn, about 100 miles west of Chicago. The farm’s 27 turbines could be running in eight months once the credit is revived.

The key to the rise of Forever Power’s wind farm — and many others — was the deregulation of electric utilities, said Joyce Papiech, president of Forever Power.

Deregulation, initiated nationwide by an order from the Federal Energy Regulatory Commission in 1996, allows electricity buyers to choose who generates their power. It forced utilities to consider alternative energy sources to keep environmentally-conscious customers who began shopping elsewhere for their power.

“There has been an opening up, a start of changing in the attitudes of some of the electric companies,” Papiech said.

Noe agreed. “You started to see utilities getting more and more comfortable with the idea of wind power and adding wind power to their production mix,” he said.

While all of the power from Forever Power’s wind farm will be bought by Commonwealth Edison, the Chicago-based subsidiary of Exelon Corp., other wind projects weren’t so lucky.

Florida-based FPL Energy LLC, a subsidiary of FPL Group Inc., dropped plans for a wind farm in Illinois when it couldn’t find a utility to buy the power at an acceptable price, a contract typically called a power purchase agreement, said Steve Stengel, spokesperson for FPL Energy.

Had a utility entered a power purchase agreement with FPL Energy, it, unlike some renewable energy producers, would have included the wind farm’s green tags in the sale.

Green tags are certificates that producers of renewable energy get for the renewable energy they produce. The tags, first used around the year 2000, represent the reduction in pollution that occurs when renewable energy is used instead of energy from fossil fuels.

The tags can be bought and sold on an informal, nationwide market. In states with renewable portfolio standards — regulations first appearing in 2000 that required utilities to use a certain percentage of renewable energy — utility companies often buy the tags rather than invest directly in renewable energy facilities, to demonstrate they’ve met those required renewable levels.

Even with green tag revenues, wind farms typically need some sort of power purchase agreement. Renewable portfolio standards, slowly catching on around the nation, would make such agreements easier to secure.

Illinois adopted a voluntary standard in 2001 that is pushing for 5 percent of total energy to come from renewable sources by 2010, and 15 percent to be renewable by 2020. Hawaii also has a voluntary standard and 13 states have mandated standards. In Chicago, Mayor Richard Daley announced that 20 percent of the city government’s power usage will come from renewable energy sources by 2006. But wind energy is still not the cheapest energy supply — and utilities are still businesses trying to make a profit.

“It’s a matter of time before there will be (wind) opportunities here in Illinois that make sense economically,” said Gabriela Martin, manager of Environmental Commitment at Commonwealth Edison. “I think that’s the bottom line. It’s got to make sense for the business.”

Nicor earned $35.1 million for the quarter ended Dec. 31, or 80 cents per share, compared with $39.3 million, or 89 cents per share, for the same period a year earlier. The consensus earnings estimate from analysts polled by Zacks.com was 85 cents per share for the quarter ended Dec. 31.

For 2003, Naperville-based Nicor earned $105.2 million, or $2.38 per diluted share, compared with $128 million, or $2.88 per diluted share, earned in 2002. The consensus earnings estimate from analysts polled by Zacks.com was $2.07 per share for 2003.

“The big driver in the reduction of earnings was lower gas distribution results,” said Richard Hawley, chief financial officer of Nicor, during a conference call. A sluggish national economy and high natural gas prices contributed to those results, he added. On top of that, increasing maintenance and operation expenses — including health insurance and compliance costs –- also whittled away earnings.

Industrial deliveries, one component of the gas distribution business, were down about 6 percent, noted Mark Knox, assistant secretary and director of investor relations at Nicor, during a conference call.

The drop in industrial demand would be slow to recover, and could be permanent, said Thomas Fisher, chairman and chief executive officer of Nicor, during a conference call. In response, Nicor plans to enact tight cost control and to request a raise in the rates the company is allowed to charge its customers, he added. Rates are regulated by the Illinois Commerce Commission, and it would review any proposed rate changes.

Another factor contributing to the drop in 2003 earnings was a change in accounting rules, according to a company press release.

Revenues for the quarter ended Dec. 31 were $743.9 million, 5.6 percent higher than the $704.7 million reported for the same period a year earlier. For 2003, Nicor reported revenues of $2.66 billion, a whopping 40 percent higher than the $1.90 billion in revenues reported for 2002.

”An overwhelming amount of that will be the much higher gas prices,” said Craig Shere, a utility analyst with Standard & Poor’s Equity Research Services. “In addition, the first quarter of ’03 was colder.”

In 2003, natural gas prices reached record highs. Nicor bought more expensive natural gas and that gas was sold to customers –- at the price the utility paid for it– thus creating leaps in revenues but not earnings, Shere said. Utilities, by regulation, are allowed to profit from its natural gas distribution services, but not the sale of natural gas. Whatever the utility pays for gas is what the customer pays.

Due to lowered expectations for the performance of Nicor’s gas distribution segment and continued increasing operations costs, the company has set earnings estimates at $2.10 to $2.30 per diluted share in 2004.

Nicor Inc. is the holding company for Northern Illinois Gas, a natural gas utility company doing business as Nicor Gas. Nicor Gas serves about two million customers in Illinois. Nicor Inc. also owns Tropical Shipping, a freight shipping business based in the Caribbean.

The stock’s price was $33.59 during late afternoon trading, up 79 cents.

“They took a beating on what they sold,” said Jim Halloren, an analyst with NatCity Investments.

NiSource earned $139.8 million, or 54 cents per share, for the quarter ended Dec. 31. That was up 70 percent from the $82.1 million, or 36 cents per share, earned in the same period a year ago.

The consensus earnings estimate of analysts polled by Zacks.com was 56 cents per share for the quarter, 2 cents above the actual earnings per share.

Revenues hit $1.7 billion for the quarter, compared with $1.7 billion.

NiSource earned $85.2 million, or 33 cents per share, for the year ended Dec. 31, down 77 percent from the $372.5 million, or $1.77 per share, earned in 2002.

Revenues rose to $6.2 billion for the year compared with $5.3 billion.

“They did a good job on paying down debts and holding the line on costs,” said Michael C. Heim, an equity analyst with A.G. Edwards & Sons. “It’s been a good turnaround story as a whole.”

Earnings per share for 2004 are estimated to be $1.65 to $1.70, said Gary Neale, chairman, president and chief executive officer of NiSource, during a conference call with analysts.

“January has been a cold month with strong natural gas sales,” Neale added. “This gives us a good start for the year.”

NiSource is an Indiana-based holding company with natural gas and electricity transmission, storage and distribution businesses serving about 3.7 million customers.