"Anyone who assumes rural electric cooperatives will not be fully engaged in whatever system we have . . . if they assume the more competitive it becomes, the less we'll be engaged . . . they're very wrong."
(em Glenn English, CEO,
National Rural Electric
Ten terms as a U.S. Representative from Oklahoma's Sixth District taught Glenn English how to build consensus. Although his agenda and goals differ now, his mission at the National Rural Electric Cooperative Association (NRECA) shows all the signs of an election campaign.
NRECA's 900 cooperatives (em which include 60 generating and transmitting co-ops (G&Ts) (em have mixed opinions on retail wheeling and electric distribution. They expect the usual arguments from investor-owned utilities (IOUs) about their "favored" federal financing status. They plan to fight public power proponents on annexation. They anticipate more takeovers from IOUs eyeing co-ops with large, once-rural power loads that have become attractive suburbs. They recognize that their future lies with Congress: English believes universal service and deregulation conflict, and will until legislators weigh in.
It's a tough agenda. Winning consensus on leading issues won't be easy. But NRECA's CEO is up to the task. And English says co-ops are steeled to face the competitive forge, despite some small differences: "Anyone who assumes rural electric cooperatives will not be fully engaged in whatever system we have (em no matter how much regulation or deregulation (em if they assume the more competitive it becomes, the less we'll be engaged ... they're very wrong."
English took his post two years ago. Since then, he has led the development of a strategic plan aimed at NRECA member survival through "competitiveness, community, and competence." The plan attempts to reduce the risk of hostile takeovers, address municipal annexation, and support merger and acquisition efforts that "make sense." It also calls for new approaches to market-based wholesale and retail rates, and plans new ways to assess performance and to reduce regulation's impact.
NRECA's roadmap also encourages co-ops to add commercial and industrial load. Gaining industrial load would put co-ops on firmer ground and balance out retail rates. NRECA members generally have load factors of 50 percent. And retail rates in 70 percent of rural electric systems are higher than those of neighboring IOUs.
On the flip side, higher retail rates help fend off grazing IOUs seeking to expand service territories in border regions. Yet co-ops shouldn't think they're protected, as several recent cases have made clear. Sticking their heads in the sand over competition and forgoing sophisticated management practices only hurts co-ops' credit strength, says Marla Fox, utilities group director of Standard & Poor's (S&P) infrastructure group.
Fox says co-ops will need good management when open-access transmission hits and members begin to wonder "Why are we tied to a high-cost G&T when there's cheaper wholesale electric at hand?" Since co-ops are legally bound to their G&Ts and G&T stranded costs, it could become a legal debate.
Some G&T's are already making strides in lowering wholesale costs. In a recent assessment of the nine highest-rated G&Ts with combined debt over $9.7 billion, S&P noted that managers are competent, understand competitive issues, and have become more efficient by accelerating debt
payments and renegotiating fuel contracts. Most of these co-ops have coal generating systems. Excess capacity doesn't hurt their business position because the plants are efficient. Excess power can be sold at attractive rates. Least vulnerable to competition, these G&T's set a standard for the rest of the industry. Other G&T's aren't as appealing because of nuclear assets that hurt their rate base, Fox notes. Overall, she says S&P is comfortable with co-ops' market position.
English points to other areas where co-ops have parted with their past (em a past dotted with names like Cajun Electric and Wabash Valley Power Association, two bankrupt nuclear power G&Ts. NRECA's CEO blames the failed nuclear plants on government and misguided legislation like the Fuel Use Act, which prohibited the use of natural gas as a boiler fuel. Co-ops, in the past, were invited to share ownership in what turned out to be some of the most expensive electric generation anywhere. Some co-ops have filed cases against IOU partners, alleging fraudulent inducement to buy into plants they mismanaged.
"I'm not sure we have any nuclear power plants (em I don't care who's running them (em that are competitive," English says. "That, again, is impacted by government. ... You didn't have the natural process evolve to where the market price was allowed to work its will."
One area where the market is working its will is in the Rural Utilities Services (RUS), responsible for bringing universal service to rural areas and securing government loans. The federal budget cost of these loan programs for fiscal 1995 was $72.9 million, down from $169.1 million in 1993. Co-ops, fed up with the paperwork and able to get competitive private financing, are paying off their loans quicker, English says. According to NRECA, since 1986 co-ops and other RUS borrowers have prepaid 65 loans. Eighteen more have prepaid part of their debt, and 35 applications for prepayment were pending at the end of 1995.
Side-stepping government financing gives a co-op a slight competitive edge: It no longer would need to file an environmental impact statement on new construction. However, in some cases, co-ops, by forgoing RUS financing, could become regulated by the Federal Energy Regulatory Commission (FERC). (The FERC doesn't have authority over G&T wholesale transactions and distributive cooperatives that borrow from the RUS.) Systems in 16 of the 46 states where co-ops do business are subject to rate regulation by state commissions. And the FERC can order rural electric systems to offer wholesale transmission service. Furthermore, FERC regulation of IOU power-supply sales to co-ops is quite significant.
Federal subsidies or loan programs are delicate areas for NRECA. English contrasts the $12 billion in outstanding RUS loans with the $75 billion IOUs charge ratepayers, portions of which they hold back due to investment tax credits and accelerated depreciation. He puts the annual cost of this IOU "subsidy" at around $5 billion.
"What's the difference?" English asks. "We've got $12 billion, they've got $75 billion. We're paying interest on ours. They're not paying a blooming dime on theirs.
"Everybody knows that we have subsidies. What they don't know is they have subsidies."
English says a single case provides the strongest argument. "Pull out Consolidated Edison and see what they paid in ... 1993. ... Not a dime. In fact, they got a $25-million tax break. They had $5 billion in revenue. Five billion dollars. And those guys are getting $25 million back from the federal government?"
English says that NRECA could be more vocal on the subsidy issue, but that legislators haven't called for an emphatic response. "We have not seen Congress, Republicans in Congress, Democrats in Congress, attack us on these issues," he says. "What we've seen is IOUs raising these issues before the Congress."
Not all the issues facing NRECA are external. For instance, while most of its members oppose retail wheeling, some favor it. English says residential users are vulnerable and will likely subsidize competition with big loads: "We don't like that." Yet, he adds that, like the Edison Electric Institute, which is funded largely by IOUs, "we have members who it doesn't scare a bit. [But] we think consumers are going to get burned. They're going to get burned bad."
Regardless of what NRECA and its members face, the primary issue will always be to keep rates low. "That's one that I think the Congress is going to have to come to grips with," English says. "The enthusiasm seems to be cooling just a tad out there as regulators finally become aware of the fact that 'Hey, somebody's bills have got to go up as the bills for the big users are going to go down.'"
English says we can't have universal service and total deregulation. "You'll probably have some hybrid system that does not work well, and then raises real questions: Why are we doing this? Are we changing so we can say we changed something? Is this in response to the fad of the times? We used to have bell-bottom pants, but I don't know that everybody wants to go to bell-bottom pants. This might be one of those passing fads."
One facet of keeping rates low are mergers. Mergers among co-ops or co-ops and IOUs are being strongly and widely considered. The National Rural Utilities Cooperative Finance Corp. was assessing 65 deals, in various stages, in 1995.
English says most mergers that have come through have been in service areas big power companies don't want; co-ops are only taking over or merging with territories on the periphery of larger service grids. He says mergers don't conflict with the original mission of association members to provide power to consumers and those who own a cooperative. "There was never ... anything along the lines that you should only have so many people in cooperatives," English says. "You've got people who say, 'We can be more efficient if we do this.'
"If there are savings to be gotten by merging, that is very attractive to the consumers out there, because it means they will be able to hold down the rates or even reduce the cost of their rates."
Buyouts of co-ops by IOUs are another story. And they can have a win-or-lose outcome. Last year, the Washington-St. Tammany Electric Cooperative staved off an attempt by Central Louisiana Electric Co. (CLECO) to take over its more than 14,000 member service area, even though CLECO spent as much as $2 million on a takeover campaign. "And they were offered substantial cash inducements to do that," English adds. "'If you sell out to us, why, we'll give you lower electric rates and so much cash' (em making all these promises."
By contrast, CLECO appears to have been successful in the buyout of the Teche Electric Cooperative. The $22.4-million deal must be approved by state and federal agencies and an all-requirements contract must be worked out with Cajun Electric, the bankrupt G&T. Some 85 percent of the 7,400-member co-op voted for the merger. Members now can expect a five-year freeze on rates that could be 20 percent less than the co-op's, along with capital credits that NRECA reports could average $800 per residence. The utility hopes the matter will be resolved with Cajun this month, says Christy Frederic, CLECO spokeswoman.
Distribution also will factor in keeping rates low. If a co-op can bail out of a G&T, it guts the G&T and makes it a stranded investment. "I think we have distribution co-ops that in the short term may feel that they could get better rates, and we have a lot of different groups that are dangling that promise in front of some of our distribution cooperatives," English says. "But I think the real question and what we have to address is, 'What happens in the long term? Is it really in your best interest to do this?'" He adds: "It's probably the uncertainty that makes it more attractive to listen to offers from groups making promises they may or may not be able to fulfill."
A break in the distribution impasse could happen sooner than he or others suspect. Four County Electric Power Association of Columbus, MS, filed suit in federal court on November 21, 1995, against the TVA after the authority refused to let it participate in an economic development program that gave credit against power bills for new and expanding business. This followed an earlier request by Four County to be released from TVA's power-supply contract. The co-op estimated it could save as much as $70 million over 10 years by going to a cheaper supplier. "They won't release us from the contract we have, but won't include us in the benefits other distributors are getting," says Harold Knight of Four County. TVA says it would lose millions of dollars from the 200-megawatt load.
Opting out of TVA is "the unthinkable," English says. "That's true not just of cooperatives but of other customers of TVA. They're looking around, no question about it.
"We don't want our membership, well, split [on this issue], but we don't want to see any surprises. And we want them to have as long a period as possible to do their planning, to make their decisions and make sure those decisions are the proper ones and also, to make sure all the different possibilities are explored."
In other words, it could be a tough "election year." t
Joseph F. Schuler is associate editor of PUBLIC UTILITIES FORTNIGHTLY.
. About 900 electric cooperatives serve 12 million commercial, industrial, and residential customers in 46 states, excluding Hawaii, Rhode Island, Massachusetts, and Connecticut. Co-ops account for 7.4 percent of the kilowatt-hours sold and 5 percent of the electricity generated.
. Most co-ops provide electric distribution. Some generate and transmit electricity (G&Ts). There are 60 G&Ts. Rural systems generate 41 perdent of the electricity they sell and buy 34 percent from federal sources. About 25 percent comes from IOUs.
. Co-ops maintain nearly half the electric distribution lines in the United States. Yet, they average only 5.8 consumers per mile of line and collect annual revenue of about $7,000 per mile of line. IOUs, by contrast, average 34 customers and $59,000 per mile of line; publicly owned utilities average 46 customers and $71,000 per mile of line.
Source: The National Rural Electric Cooperative Association
Largest G&T Regroups to Serve Members
Oglethorpe Power Corp.'s 39 cooperatives may soon be free to buy wholesale power from the marketer of their choice.
Freedom doesn't come without its price, however. The plan would leave each cooperative with a share of Oglethorpe's stranded investment.
Even so, those pro rata costs enable the cooperatives to be more profitable, according to Dwight Brown of Cobb Electric Membership Corp., the largest cooperative in the Oglethorpe fold. In the first deal of its kind, an agreement between Oglethorpe and its members would be modified for incremental needs. The new pact is part of a restructuring of the $1-billion G&T, prompted by a planned "defection" about two years ago of six of its cooperatives.
A solution to the impasse came in July 1995, when both parties agreed on the assignment of stranded costs. December 1995 brought the reorganization announcement, plus an interim agreement that carries Oglethorpe members through March 31. Oglethorpe has agreed to supply power up until that date through Enron Power Marketing, Inc.
The interim agreement will reduce co-ops' wholesale power costs by several million dollars, according to Stan Hill, an Oglethorpe v.p. The cost savings vary by member. Oglethorpe will sell energy from its owned generation, then buy it back at a fixed price, which is where the savings come in. Enron's purchase arrangement includes an option to buy excess energy. The cooperatives still will deal directly with oglethorpe, but that could change as the reorganization takes shape and the contract evolves.
Oglethorpe hopes to have the principles of its reorganization established by the time the Enron deal ends. At that time the G&T would be split into separate generating, transmission, and systems operations companies. "What we're seeking to do is to change the setup so that the generation company will still be regulated by RUS," Hill says.
The other two companies, while they may be cooperatives initially, we'll look at making those private corporations ... We can move rapidly to take advantage of deals we see out there, and not get caught up and lose them because of the time involved to get something approved."
Oglethorpe has a letter from RUS supporting the reorganization concepts. However, once the power marketing relationship develops, what's to prevent cooperatives from going direct to Enron, or to a similar marketer?
"I think we will," Brown predicts. "Sure. But we've still got to pay our share of Oglethorpe's stranded investment."
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