Incremental transmission loss allocation under pool dispatch

Incremental transmission loss analysis has been used for decades, but recent interest in its application to loss allocation calls for new in-depth results. This paper demonstrates that, for incremental methods to be applied correctly in loss allocation, it is first necessary to specify the load distribution and loss supply strategies. Incremental loss allocation among bus power injections is shown to be arbitrary and, therefore, open to challenge as discriminatory. Loss allocation is possible among incremental loads and/or generators, but the proportion of the total losses assigned to either one is arbitrary. Unique, nonarbitrary incremental loss allocations are however possible among the "equivalent" incremental bilateral exchanges between generators and loads. From these basic components it is possible then to calculate the allocation among generators or loads in any specified proportion. The main results, although developed initially for small increments, are extended to large variations. Finally, a general incremental loss allocation algorithm is developed and tested     

Market-clearing with stochastic security-part I: formulation

The first of this two-paper series formulates a stochastic security-constrained multi-period electricity market-clearing problem with unit commitment. The stochastic security criterion accounts for a pre-selected set of random generator and line outages with known historical failure rates and involuntary load shedding as optimization variables. Unlike the classical deterministic reserve-constrained unit commitment, here the reserve services are determined by economically penalizing the operation of the market by the expected load not served. The proposed formulation is a stochastic programming problem that optimizes, concurrently with the pre-contingency social welfare, the expected operating costs associated with the deployment of the reserves following the contingencies. This stochastic programming formulation is solved in the second companion paper using mixed-integer linear programming methods. Two cases are presented: a small transmission-constrained three-bus network scheduled over a horizon of four hours and the IEEE Reliability Test System scheduled over 24 h. The impact on the resulting generation and reserve schedules of transmission constraints and generation ramp limits, of demand-side reserve, of the value of load not served, and of the constitution of the pre-selected set of contingencies are assessed.     

Surgical treatment of the acute cholecystitis in the laparoscopic age. A comparative study: laparoscopy against laparatomy

OBJECTIVE: The aim of this study was to assess the complications and results of the laparoscopic opposite to open treatment of the acute cholecystitis. METHODS: A retrospective randomized study with two groups of 30 patients each one. The parameters tested were age, sex, risk factors, surgical time, hospital stay, cholecystitis type, and early or late complications. RESULTS: In the two groups there were no significant differences in age, sex, risk factors, type of cholecystitis and surgical time. The average of hospital stay was significantly longer for open cholecystectomy (9.5) than for laparoscopic technique (2.30) (p < 0.001). The complication rate was higher (7.30%) in open cholecystectomy. CONCLUSIONS: The laparoscopic cholecystectomy should be the standard procedure for the treatment of the acute cholecystitis.     

An investigation of the solution to the optimal power flow problemincorporating continuation methods

The computation of the optimal power flow (OPF) remains a difficult nonlinear programming problem. An investigation is made of a solution methodology based on the continuation method, a parametric technique. In this algorithm, the continuation method is applied at various stages. The proposed algorithm uses the sequential quadratic programming strategy, but it replaces the standard subproblem module by a new parametric module. The varying-limits strategy used seems quite fast for solving the quadratic programs, and is formulated to be useful as a dispatching tool. In a second application of continuation methods, a load tracking outer loop is grafted to the nonlinear solver. This quickly produces (discrete) optimal solution trajectories when fed the forecasted system loads as input     

Comparison of 1D and 3D analysis of the front contact influence on GaAs concentrator solar cell performance

An extensive analysis of the front contact influence on concentrator GaAs solar cell performance has been carried out. The fill factor, open circuit voltage and efficiency have been calculated by varying the front contact specific resistance and the metal sheet resistance for 500X, 1000X and 2000X. An optimum front grid design has also been developed. The simulations have been carried out using a 3D model based on distributed circuit units, and by a classic lumped model, showing the need to use distributed models to achieve an accurate concentrator solar cell modeling as well as a precise front grid design.     

Pay-as-bid versus marginal pricing-part I:Strategic generator offers

As the arguments for and against the use of pay-as-bid (PAB) or marginal pricing (MP) in electricity pools tend to be qualitative, we compare the quantitative behavior of the two markets assuming that generators submit the best strategic offers that correspond to the specified pricing method. In Part I of this two-part study, assuming that the system marginal costs for PAB and MP are random with known probability density functions, we develop generator strategic offers by maximizing the corresponding expected values of the generator profits over the offer parameters. In Part II relations are established between the SMCs for each market type and a common random demand, thus allowing the two markets to be compared through the expected values and variances of the individual generation profits and of the consumer payments. This comparison demonstrates both theoretically and through simulation that: 1) the expected values of the individual generator profits as well as of the consumer payments are the same under MP and PAB and 2) the variances of the individual generator profits and of the consumer payments however are larger under MP than under PAB. The primary conclusion is then that although MP and PAB yield identical expected generator profits and consumer payments, the risk of not meeting these expected values is greater under MP than under PAB.     

Closure on "Equilibrium of auction markets with unit commitment: the need for augmented pricing"

The authors reply to the comments by M. Madrigal (see ibid., vol.18, no.2, p.961, 2003) on their original paper (see ibid., vol.17, p.798-805, 2002), answering the two questions he raised.     

Pay-as-bid versus marginal pricing-part II: market behavior under strategic Generator offers

As the arguments for and against the use of pay-as-bid (PAB) or marginal pricing (MP) in electricity pools tend to be qualitative, we compare the quantitative behavior of the two markets assuming that generators submit the best strategic offers that correspond to the specified pricing method. In Part I of this two-part study, assuming that the system marginal costs for PAB and MP are random with known probability density functions, we develop generator strategic offers by maximizing the corresponding expected values of the generator profits over the offer parameters. In Part II, relations are established between the system marginal costs for each market type and a common random demand, thus allowing the two markets to be compared through the expected values and variances of the individual generation profits and of the consumer payments. This comparison demonstrates both theoretically and through simulation that: 1) he expected values of the individual generator profits as well as of the consumer payments are the same under MP and PAB and 2) the variances of the individual generator profits and of the consumer payments however are larger under MP than under PAB. The primary conclusion is then that although MP and PAB yield identical expected generator profits and consumer payments, the risk of not meeting these expected values is greater under MP than under PAB.     

Energy and reserve pricing in security and network-constrained electricity markets

This paper analyzes some unresolved pricing issues in security-constrained electricity markets subject to transmission flow limits. Although the notion of separate reserve types as proposed by FERC can be precisely and unambiguously defined, when transmission constraints are active, the very existence of separate reserve prices and markets is open to question when the prices are based on marginal costs. Instead, we submit here that the only products whose marginal costs can be separately and uniquely defined and calculated are those of energy and security at each node. Thus, under marginal pricing, at any given network bus all scheduled reserve types should be priced not at separate rates but at a common rate equal to the marginal cost of security at that bus. Furthermore, we argue that nodal or area reserves cannot be prespecified but must be obtained as by-products of the market-clearing process. Simulations back up these conclusions.