Chapter 2

Transmission-Investment Increase on Horizon

Douglas M. Logan

Transmission constraints have become a matter of concern at the highest level of U.S. government. The National Energy Policy released by the White House in May 2001 observes that an antiquated and inadequate transmission grid prevents us from routing electricity over long distances and thereby avoiding regional blackouts, such as California's.” The document further notes, “The system is simply unequipped for large-scale swapping of power in the highly competitive market of the 21st century.” It declares, “we must greatly enhance our ability to transmit electric power between geographic regions.”

      In early 2001, inadequate transmission from Southern California to Northern California on Path 15 was indeed a cause of some of the rotating blackouts in Northern California. In 1998, transmission constraints were a factor in the Midwest price spikes. Curtailments of transactions across some interfaces in the Midwest and East, if not routine, occur repeatedly, but less dramatically: only money is lost, not load.

      Solutions to the problem are still on the drawing board. The North American Electric Reliability Council continues to refine transmission loading relief (TLR) procedures to determine and prioritize curtailments when constraints become binding. Independent system operators (ISOs) and regional transmission organizations (RTOs) wrestle with congestion management schemes. RTOs and transmission providers propose various financial incentive mechanisms to reward investment in system improvements.

      Clearly, there are inadequacies in America's existing transmission infrastructure. Clear, too, is that something needs to be done. However, not so clear is what. Nor is it clear what institutional arrangements, regulatory and commercial, are needed to attract the investments required to eliminate the inadequacies.

      Nevertheless, there is another way in which investment in transmission is likely to surge in the next few years in the buying and selling of transmission assets and in the restructuring of the transmission business. In 2001, the beginnings of this movement became visible as Trans-Elect, a new entrant, has acquired the transmission assets of two utilities. It may be that the dollar volume of such financial transactions rivals that of investment in new and upgraded facilities in the next three to five years.

      This paper considers the trends and prospects for both types of transmission investment.

Existing Transmission System

Figure 2–1 shows one indicator of a declining trend in transmission construction over the past decade. The bars show the net incremental transmission investment for investor-owned utilities (IOUs), while the line shows total U.S. electricity sales. Net incremental investment is calculated as the year-to-year change in transmission assets reported by utilities filing Federal Energy Regulatory Commission (FERC) Form 1 and reflects the net effect of new investment less depreciation. In 1999, new investment was insufficient even to keep up with depreciation. The North American transmission infrastructure has withstood the stresses of events in the past few years only because of heavy investments made in the years prior to those shown in the exhibit.

Figure 2–1—Transmission Investment TrendSource: RDI POWERdat

Over the decades the existing transmission system has evolved to meet the needs of the electric utilities within their own service territories. Transmission between service territories has generally been built only to accommodate shares of generating plants in one area owned by utilities elsewhere and to provide modest levels of generation reserve sharing between utilities and regions. Thus, today the transmission system can be characterized as a set of networks covering the service territories of the dominant utilities, separated by relatively weak.

Chapter 7

Distributed Energy Resources Show Promise Wellhead to Burnertip

David E. Dismukes, Ritchie D. Priddy, Martin J. Collette, and Jeffrey M. Burke

The changes in energy markets over the past ten years have created significant opportunities for end-user choice. One of the more exciting opportunities that has developed within the energy industry restructuring process has been associated with distributed energy resources (DER). In this current environment of energy uncertainty, DER offers end-users a physical hedcge against price volatility, outages, and power quality problems. Despite these opportunities, there is still widespread confusion about DER, its technologies, and operating performance characteristics.

      DER refers to the generation, storage, or demand-side management devices, measures, and/or technologies that are connected to or injected into the distribution level of the transmission and distribution (T&D) grid (i.e., “below” the bulk power transmission system). Micro-turbines, fuel cells, photovoltaics, wind turbines, and flywheels are some examples of DER technologies. Because these devices are more modular and flexible than a large central power station, they can be located at the customer’s premises on either the system side or the customer-side of the meter, or at other points in the distribution system such as a utility distribution company (UDC) substation. DER covers a wide range of technologies and is not limited to co-generation—commonly referred to as combined heat and power (CHP) for small power applications. Table 7-1 presents the cost and operating characteristics of a number of commercially available or developing DER technologies.

Table 7- 1—Costs of DER (Source: Gas Research Institute, "The Role of Distributed Generation in Competitive Energy Markets," Distributed Generation Forum (Chicago  1999), 9)

      While DER refers to a broad range of technologies and applications, most attention is being directed at those opportunities to generate electricity. Four major distributed generation technology categories include reciprocating engines, gas turbines, micro-turbines, and fuel cells. Currently, reciprocating engines are the most mature small-scale power generation technology on the market. Slightly larger gas turbines are equally important technologies that are commercially available for DER applications.

      The popularity of reciprocating engines and gas turbines is based upon availability, low capital cost, modest exhaust emissions, extended service intervals, long service lives, and well-developed sales and marketing infrastructure. Industry sources estimate that recent sales of reciprocating engines amount to approximately 35 gigawatts. The installed capital costs of these technologies range from $300 a kilowatt for a 200-kilowatt unit to $724 a kilowatt for a 12.5-kilowatt unit. Gas turbine costs are equally competitive $350 a kilowatt to $1,000 a kilowatt range (Table 7–1).

      Two emerging technologies that are attempting to challenge the reciprocating engine market are microturbines and fuel cells. Microturbines are essentially mini-jet aircraft engines that are based upon the same aerospace technologies that revolutionized the larger combustion turbine market of the electric power industry over the past twenty years. On the other hand, fuel cells facilitate a...

Mexico: Good Start, Great Regulators, but Mixed Results for Participants

Dana Contratto

Throughout 1995 and early 1996 the Mexican government and its newly enhanced energy regulatory commission, the Comision Reguladora de Energia (CRE) created the legal and regulatory infrastructure to open the natural gas industry downstream of production to private investment and ownership. Until then, as a legal and practical matter, the Mexican government had exercised almost sixty years of strict state ownership and control over that sector of the economy. This dramatic departure from state to private sector has now had a full five years of operating experience. This chapter assesses the results of the Mexican natural gas initiative and provides some observations about its pros and cons from several different perspectives.

     The specifics of the opening of the downstream natural gas industry have been written about extensively.^[1] It is not the purpose of this chapter to review the regulatory and legal minutiae of that exercise. Rather, the purposes here are to summarize the developments in the “opened” downstream industry, to provide an assessment of the successes, or lack of successes, of that initiative, and to postulate some future implications for the Mexican energy sector. One section of this chapter includes a candid assessment from the perspective of Mexican gas industry participants themselves and is based upon confidential responses to a primary data collection survey.

SCOPE OF THE MEXICAN GAS INDUSTRY INITIATIVE

For decades, the Mexican oil and gas industry has been generally reserved for exploitation by the Mexican state through its wholly owned governmental unit known as Petroleos Mexicanos (Pemex). Within the Pemex organizational structure, natural gas matters downstream of production are in the province of Pemex Gas and Basic Petrochemicals. It is important to understand the scope of the Mexican government's natural gas initiatives in 1995 and 1996. They were not a privatization of Pemex or Pemex Gas, nor did they legally restrict the activities of Pemex in the sector. Rather, the private sector was simply permitted to compete against Pemex in areas otherwise legally or practically reserved to Pemex, that is, natural gas storage, transportation, distribution, and marketing.

For sake of clarification and further understanding, it should also be noted that as a legal matter, natural gas distribution was previously and technically not “off limits” to private investment and ownership. Indeed, as discussed below, at the time of the government initiatives in the sector there were a number of privately owned natural gas distribution systems in Mexico. However, the economic viability of those systems was tied to a regulatory structure that seriously discouraged private investment in distribution.

GAS INDUSTRY SEGMENTS AND THE RESULTS OF OPENING THE INDUSTRY

The results have thus far been generally positive.

Storage

Natural gas storage projects in Mexico were not necessary during the first years of the opening of the downstream industry. This was because the Pemex Gas pipeline system, which was and is extensive nationwide, operated at the time with a utilization rate of about 50 percent of capacity on a systemwide basis. Thus, the Pemex Gas transmission system itself was able to serve a supply/demand balancing function, which has been largely sufficient, especially given the near absence of heating load in Mexico and attendant absence of peak demands. Thus, storage projects and permits for such were not present during this period.

Marketing

Unfortunately, marketing, i.e., buying and selling the commodity natural gas, has not developed as a business sector since the opening of the industry. All natural gas in Mexico is owned by Pemex, transferred from the Pemex exploration subsidiary, and marketed virtually exclusively by Pemex Gas on a bundled with transportation service basis or sold separately as a pure commodity sale. Further, all so-called first hand sales—that is first sales of domestic Mexican gas by Pemex Gas to a nonaffiliated Pemex entity—are subject to a maximum lawful price regime set concerning a defined Houston Ship Channel commodity price in the United States.

In short, the commercial basis for competing against Pemex Gas for marketing was, and is, generally not present. All domestic natural gas is initially

Chapter 16

MMS, Interior in Center of Debate about Production Activity, Regulation

Cynthia L. Quarterman

This is the first-ever chapter about the regulation of exploration for and production and development of natural gas on the Outer Continental Shelf (OCS) and the collection of associated revenues in the Natural Gas and Electric Power Industries Analysis series. Therefore, some introductory information is offered here. The Department of the Interior is widely recognized as one of the largest land managers in the United States government. It is responsible for overseeing the nation’s sprawling park and federal land holdings. Those lands are assumed by many to be primarily concentrated in the Western United States. However, the department’s largest federal land management responsibility is over the OCS, which covers 1.76 billion acres. Since 1982, the department’s Minerals Management Service (MMS) has been responsible for managing the mineral resources on those lands.

Creditors, judge will determine fate of enron bankruptcy, like others

Anthony M. Sabino

A dark shadow has fallen over the landscape of the energy industry, and its hopes for continued deregulation. The shadow has a name, and it is “Enron.”  With the downfall of that once mighty corporation, the hue and cry has gone up, not only that deregulation has failed, but that reregulation is now imperative. It is not enough that Enron represents the largest corporate Chapter 11 of all time.[1]  In addition, it is the sense of common dread that the energy industry may be relegated back to the dark ages of overt government regulation and interference.

     However, enough doom and gloom for the moment. No sane person can doubt the gravity of the Enron bankruptcy, least of all the energy industry participants so directly affected. The purpose of this writing is to studiously avoid the hyperbole and the melodrama. The developing story at Enron is much too important for talking heads and ten-second sound bites. Rather, our stated purpose here is to calmly dissect the legal and business implications of this record breaking bankruptcy filing, what is and what will exactly happen in the corridors of the bankruptcy court, and conclude with some broad observations as for what this all means for the energy industry. What matters to you, and thus this writer, is how this affects the conduct of your business, and that is what we will stick to.  

DOORS can stay OPEN

We know that Enron is still in business, operating under Chapter 11 of the Bankruptcy Code.[2]  By now, American businesses are generally familiar with broad contours of bankruptcy. It is common knowledge that a bankruptcy case filed under Chapter 7 is a liquidation, causing the appointment of a trustee, and the forced sale of all the debtor’s assets, with the concomitant customary lower return and mere morsels paid out to creditors. Enron is not there—at least, not yet.

     Enron is merely the latest and largest of U.S. corporate titans to file for reorganization of their businesses under Chapter 11 of the Bankruptcy Code. To be sure, this path has already been well traveled by the likes of blue chips such as Johns-Manville, Texaco, Federated Stores, Macy’s, and Continental Airlines. None of these firms were insignificant in terms of size, market share, or by any measure. Enron merely trumps them for the moment because, measured in today's dollars, it is the largest bankruptcy filing ever recorded.

     Notably, each of the aforementioned titans that fell from Wall Street’s good graces were restored to past glories. Enron's ultimate goal is the same; to reorganize its business, restructure its finances, and then reemerge from the bankruptcy process as a viable, going concern. In the energy sector, Texaco skillfully negotiated its way through Chapter 11 (not without a few close calls, however), settled its difference with industry rival Pennzoil, and reemerged a healthy company, so healthy in fact that it is now one-half of the newly christened “super major” ChevronTexaco. Enron would like to do the same.

     However, just how does a troubled company stay in business while in bankruptcy?  Key to Enron and any debtor is the privilege to stay in possession of its assets and continue to operate its business.[3]   All attempts to repossess, reclaim, or assert jurisdiction over Enron's assets by the usual means in state courts are specifically prevented by the automatic stay of the Bankruptcy Code, the statute that stays (read: stops) all litigation.[4]  All claims are centralized and all creditors confined to being heard within the walls of the bankruptcy court. This avoids the piecemeal dismemberment of the debtor. Enron, like any Chapter 11 debtor large or small, enjoys such protection while it travels the path of reorganization.

     Interestingly, litigation against related parties, such as investor lawsuits against Enron's directors and officers or its accounting firm, is another matter entirely. Those individuals or entities are not in bankruptcy, and therefore the automatic stay does not protect them. Only if such a lawsuit might ultimately impact on an Enron asset, such as an insurance policy that protects the firm, would it be held in abeyance while the company continues in bankruptcy. This is why numerous lawsuits are continuing unabated in places other than the New York bankruptcy court hearing Enron's Chapter 11.

     Finally, the automatic stay makes a key exception for police or regulatory enforcement actions. Any action by a governmental agency pursuant to its