In tales of old, it was just a matter of finding the bottle, rubbing it the right way, and VOILA! (em out came the genie to grant our wishes. But that myth hasn't worked to fully open up transmission (em at least not to date. Some say the devil is in the details, but these details are truly devilish. They've proven more difficult to resolve than some of the real power-flow "bottlenecks" that can occur on the transmission system.
It might have been challenging enough to grow transmission access and usage if access was the only significant new entitlement granted by the 1992 Energy Policy Act (EPAct). However, EPAct also accelerated the growth of power marketers, brokers, and exempt wholesale generators, not to mention the multitude of public and private reform proposals (em including industry restructuring, retail wheeling, electricity futures contracts, and regional transmission groups. All are dependent in some way on transmission access.
Any proper evaluation of new industry features must involve an understanding of, and sensitivity to, the important technical factors implicit in implementing transmission access. First, there are choices to be made, concerning:
s market-driven pools
s bilateral contracts
s financial instruments
s wheeling charges.
These choices, in turn, include technical factors such as:
s power system planning
s real-time operations
s after-the-fact activities
s data on all of the above.
These technical factors suggest ways in which engineering-based solutions might relieve some of the decisionmaking bottlenecks and eventually increase potential benefits from transmission access and use.
One final qualifier. My intent is not to comment on pros and cons of specific industry concepts or proposals of others, or anticipate or presuppose their ultimate disposition. Many of these ideas have yet to be described with the level of detail necessary for full acceptance or implementation. In any case, actual practices will likely continue to vary (em sometimes significantly (em with time, and between jurisdictions.
That said, let's take a "business as usual" case as our point of departure.
Business as Usual
Historically, electric utilities planned and operated their transmission facilities to serve native load from fairly local generation sources. When generation was remotely located (mine-mouth plants, for example), longer-distance transmission was constructed (em sometimes owned by adjoining utilities if expedient. With the emergence of formal power pooling, or recognition of ad hoc coordinated planning and operations benefits in certain areas, some transmission facilities were jointly owned and/or used to minimize total cost for two or more utilities (em taking into account some anticipated level of power trading.
Regardless of the situation (em power pooling or ad hoc coordination (em the basic power system design criteria often dictated that utilities should, if possible, build and maintain enough transmission capacity to allow any reasonable combination of generating units (and economic wheeling transactions) to be dispatched for lowest cost at essentially any time. However, for a number of reasons (em such as rising cost pressures, transmission siting difficulties, and development of some nonutility plants not in the utility's own plan (em a growing number of physical transmission bottlenecks have surfaced, spawning congestion costs and foregone opportunities.
Nevertheless, before EPAct, most industry participants attained a reasonable familiarity with flow magnitudes, directions, and durations impressed on various components of power transmission systems. Of course, those actual patterns vary continually, and sometimes unpredictably (em especially as end-user demands vary daily, weekly, seasonally, and annually.
For example, heaviest loadings on some network parts do not necessarily occur contemporaneously with greatest end-user demand. Sometimes during high-load periods, the native utility may have to bring different generation on line than it usually uses (em perhaps some older, more costly to run, units located closer to urban loads for voltage support or other reasons. Such actions can actually decrease flows in parts of the grid that might otherwise have experienced greater flows (em or perhaps even cause flows in a different direction. These effects were generally handled with ease because the integrated power system "grew up" that way over a long period of time.
Hence, in the business-as-usual case, much of the benefit obtainable from transmission systems stems from a design tailored to serve historical sources and sinks economically, to maintain latent flexibility, and (em to the extent still present (em to sustain reserve capacity to prevent and ride through outages of various kinds. To these ends, power industry participants can lay claim to a large base of experience, with ready access to technical and economic information as well as data on actual and forecasted usage.
Such public domain disclosures currently include reports to organizations such as the Federal Energy Regulatory Commission, state regulators, and the financial community, covering hourly loads, size and composition of transmission lines, terms and conditions of wheeling contracts, and fuel-cost and operating efficiency of utility-owned generating plants. This material allows third parties to independently conduct investigations that range from detailed power flow and production cost analyses to simulation of future financial results via corporate models.
But business isn't "usual" any more.
Today there exist many alternative power production and delivery "worlds," and they can change technical transmission access and usage characteristics in six different ways:
s generation siting
s generation dispatch
s transmission system physical makeup
s transmission component deployment
s wheeling patterns
s transmission investment, usage measurement, accounting, and payment.
Let's start with market-driven pools.
This idea implies arrangements that go beyond current power pooling practices. Market-driven pools allow virtually all "power sources" (that is, providers of generation, wheeling, and load modification) to compete to serve the load as an aggregate. The lowest-priced sources are then selected to participate at any one time. Of course, bilateral contracts can also be allowed to proceed simultaneously (em creating conditions somewhere between complete pooling and a bilateral contracts-only situation.
That blended possibility aside, one can say that in general, for short-term time horizons, there are no significant unsolved technical problems to stymie market-driven pools. Moreover, because of the system's built-in flexibility, changes in technical deployment of existing controllable transmission components will not likely restrict this market-based pool scenario. Rather, future developmental challenges could arise.
Historical industry goals have centered on optimal planning of both the generation and transmission systems as a unit, recognizing inherent tradeoffs of losses, congestion, and reliability, and so on. That objective may not work as well for market-driven pools.
A key to transmission planning lies in "flow forecasting." The term is somewhat analogous to load forecasting but inherently more difficult to achieve because of the highly nonlinear relationship between properties of the transmission system as it interacts with various combinations of siting and dispatch of generation and load modification resources, as well as wheeling requests.
One possible solution might come from encouraging market players to supply some minimum amount of advance information for longer-term overall system planning. For example, those players not choosing to collaborate might be assessed (higher) transmission charges. Such differentiated pricing is technically feasible and only awaits regulatory sanction. There should be no significant technical problems in tracking transmission cost-causers in a world of market-driven pools. However, the task could prove somewhat more difficult with bilateral contracts.
Any seller(s) and buyer(s) can pair up and strike their own power deal, whether at wholesale or retail. Depending on the number of parties and their characteristics, these bilateral contracts may create more technical difficulty than market-driven pooling, because overall system-use patterns and hence forecasted flows for transmission planning could become even less predictable (em especially in the long term. Why? Confidentiality plays a part, of course. But bilateral contracts may also increase uncertainty for suppliers (em and end users (em who may delay decisions as long as possible in hope of getting a better deal, further frustrating joint efforts in advance planning.
Technological advances may have shrunk the optimal size of new generating units, but transmission's economy-of-scale benefits have endured and will likely persist. In fact, as bottlenecks continue to appear, it may become desirable (valuable) to build reserve transmission capability into new installations whenever possible. Hence, if bilateral contracts become predominant (em instead of wholly market-based pools (em traders may need to work together to encourage joint system planning for generation, load modification, and transmission.
For example, overall transmission system capabilities could be periodically "trued-up" by updating the potential needs of market participants any time a significant new power source prompts system expansion. Thus, if some existing power sources were already aware they were subject to congestion charges or foregone opportunities, such constraints could be at least partially relaxed to their benefit by allowing pro-rata contributions to construction costs if new transmission facilities also help cost-effectively relax known bottlenecks. Of course, adopting this sort of process also could help accelerate construction in general, by reducing incremental charges for new power sources that actually precipitate transmission expansion.
Continuing "transparency" would also help. For example, the system "administrator" could commission and make available certain generic types of transmission planning documents intended to target a variety of broad categories of potential usage. These documents could include a plan to adequately serve new cycling generation in an urban area, or one to handle base-load wheeling throughout the system. With reference to these sorts of plans on file, and by comparing time and costs of implementation to operationally constrained alternatives, power sources could buy in to the plan without necessarily disclosing sensitive information in advance.
And what about transmission capacity trading?
Sanction of marketable ownership rights in electric transmission would also provide a useful adjunct to collaborative planning (em especially when the power source's plans change, creating a need to sell the rights. However, existing jurisdictional issues might become a cause for concern, particularly with respect to entire transmission lines. Thus a path of lower resistance (so to speak) might start out by allowing any firms to invest in FACTS (flexible A-C transmission systems) devices. FACTS, a relatively new technology, involves placing discrete controllable elements at key locations to improve various aspects of the grid's power-carrying capabilities. In the usual case, no new line construction is required.
Futures? Options? Swaps? Some are in limited use now, but much more activity looms over the horizon. The key here lies in emphasizing the special technical properties of electric power in contrast to those of other commodities (em some of which exhibit tantalizingly similar, yet different, characteristics. However, analogies between electricity and gas, or whatever, don't matter. Simply identify and retain the necessary linkage between paper contracts (em for power or money (em and physical electrons in wires.
If no "delivery" is ever required by the structure of the financial instrument, then any affected parties should be concerned primarily with evaluating the mathematical correctness and related risk factors of the deal. Of course, it might seem logical that a deal's potential power deliverability should always remain at least conceptually possible (em if not a contractual requirement. However, in an industry that still sanctions fictitious "contract path" wheeling arrangements it remains, by extension, plausible to let the mind float free and imagine a world wherein physical delivery might be completely disconnected from financial payoffs.
Nevertheless, let's discuss situations in which the parties have evidently assumed that physical delivery is desirable (em if not a necessary precursor to financial viability and liquidity. From a technical standpoint, this condition shouldn't cause any problems (em in deployment patterns
of existing generation or
transmission (em as long as more parties haven't subscribed to a delivery situation than can happen in real-time. Frequent monitoring of historical and actual system conditions, coupled with judicious forecasting over the time horizon of interest, should serve to compare actual possibilities to amounts specified in financial instruments (em and then limit subscriptions if necessary.
In addition, markets may demand definition and use of some financial instruments dealing with power deliveries projected to be large enough, and far enough out in future time, that power system expansion might be needed and feasible. In such cases, mechanisms will probably have to be developed to solicit enough input from players to identify specific characteristics of generation and transmission needed to allow for prospective delivery (and determine related costs).
Other considerations may apply (em both for short- and long-term financial instruments. For example, even though some "delivery" locations may be physically realizable, redispatch and wheeling changes necessary to bring about proper amounts and timing of flows to that location may so alter the actual costs of making and getting power there as to create disconnects between the promised (or expected) and delivered prices. However, traders can surmount this obstacle by judiciously choosing the definition of how price indices are calculated and selecting a sufficient number and diversity of alternative delivery points, while carefully checking that none are oversold on paper.
Wheeling rate possibilities run the gamut. Just pick your poison (see sidebar below).
Proper technical analyses are required to evaluate all alternatives before selecting the best choice for the situation at hand (em or even meaningfully narrowing down potential selections. Many aspects must be considered, such as:
s Physical cost components
s System-condition effects on costs
s Modeling power system costs and configurations
s Practicality of pricing methods
s Billing and reconciliation activities.
Thus, it is fair to say that substantial technical work remains before selecting and implementing preferred new wheeling charge methodologies in various jurisdictions. Choosing the best approach means a lot. For example, in an area with existing and increasing transmission bottlenecks, it should be paramount to use a long-run incremental cost-based wheeling charge approach that appropriately encourages timely and optimal construction of new facilities.
Richard P. Felak, of Schenectady, NY, has worked in the power industry for 30 years. His areas of expertise include wheeling analysis, power marketing, least-cost planning, project development, and regulatory strategy. Mr. Felak currently is adjunct consultant to Charles River Associates. He is a Registered Professional Engineer, a panelist of the American Arbitration Association, a senior member of the Institute of Electrical and Electronics Engineers, and a member of IEEE's Task Force on Transmission Access and Nonutility Generation. Mr. Felak holds an M.S.E.E. in Power Systems from Rensselaer Polytechnic Institute.
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