# Generation Adequacy Planning LOLE/LOLP Study Seminar by Gene Preston December 6, 2002.

## Presentation on theme: "Generation Adequacy Planning LOLE/LOLP Study Seminar by Gene Preston December 6, 2002."— Presentation transcript:

Generation Adequacy Planning LOLE/LOLP Study Seminar by Gene Preston g.preston@ieee.org December 6, 2002

Seminar Purpose Show the methodology for calculating the reliability indices using graphics and examples Define terms used in reliability studies such as LOLE, LOLP, EUE, FOR, PFOR, pdf, etc. Provide information to stakeholders concerning input data and interpretation of study results for single area and multi-area studies

Generation Adequacy Study Objectives Ensure installed generation reserve is sufficient Test the sensitivity of study parameters

pdf = probabilistic density function of a typical generator forced out of service f(x)f(x) x - megawatts (MW) total area = 1 0Pmax f(x) ~ Pmax time at each MW level See notes for each slide for more information.

Cumulative distribution function of the pdf   random variables x 1 f(x)f(x)F(x)F(x) expected value or mean value 1- area = value F(x) = 1 - Pr[generation MW ≤ x] = Pr[generation MW > x].5

Combination of two generator pdfs using convolution  

Representation of pdfs with discrete states x1x1 gen 1 Prx2x2 gen 2 Pr.125.25.125.1653.375.25.375.2123.625.25.625.2725.875.25.875.3499

Take all combinations of Pr’s and MW’s X Pr 0.25 0.0413250 0.50 0.0944000 0.75 0.1625250 1.00 0.2500000 1.25 0.2086750 1.50 0.1556000 1.75 0.0874750

Representation of pdfs with discrete states (one generator with states: 0, Derated, Pmax) f(x)f(x) x - MW 0Derated Pmax.8.1 PFOR.1 FOR

Generator failure as an exponential function of time probability of failure = 1 t = 0 probability of failure = 1/λ mean time to failure 1 – exp(–λt)

Steady state FOR (forced outage rate) derived from λ and µ up down λµ λ = failure rate µ = repair rate Pr[unit is up] = P 1 Pr[unit is down] = P 0 and P 0 + P 1 = 1 µP 0 = λP 1 gives P 0 = λ / (λ + µ) also FOR = P 0 = Pr[ down ] FOR = per unit down time

Markov representation of a 3-state generator P max MW 0 MW λ1λ1 µ1µ1 P1P1 P der MW P3P3 P2P2 µ2µ2 µ3µ3 λ2λ2 λ3λ3 λ 1 +λ 2 –µ 2 –µ 1 –λ 2 µ 2 +λ 3 –µ 3 1 1 1 P1P2P3P1P2P3 001001 FOR = per unit down time PFOR = per unit derated time (partial forced outage rate)

Use of the Markov process to represent three two-state generators U D 9 1 unit 1 FOR=.1 10 MW U D 4 1 unit 2 FOR=.2 15 MW U D 2.33 1 unit 3 FOR=.3 20 MW

Markov representation of three generators P 3 UDU P 2 UUD P 1 UUU P 5 DUU P 6 DUD P 4 UDD P 8 DDD P 7 DDU 2.33 9 9 9 4 4 4 4 1 1 1 1 1 1 1 1 1 9 1 1

Markov representation of three generators P1P2P3P4P5P6P7P8P1P2P3P4P5P6P7P8 0000000100000001 3 -2.3 -4 0 -9 0 0 0 -1 4.3 0 -4 0 -9 0 0 -1 0 6 -2.3 0 0 -9 0 0 -1 -1 7.3 0 0 0 -9 -1 0 0 0 11 -2.3 -4 0 0 -1 0 0 -1 12.3 0 -4 0 0 -1 0 -1 0 14 -2.3 1 1 1 1 1 1 1 1

Markov representation of three generators P1P2P3P4P5P6P7P8P1P2P3P4P5P6P7P8.504 45 MW.216 25 MW.126 30 MW.054 10 MW.056 35 MW.024 15 MW.014 20 MW.006 0 MW

Use of a binary tree for the three generators to perform the convolution process Individual States Cumulative Gen 1 Gen 2 Gen 3 MW Pr MW Pr ΣPr 20.7 -- 45.504 45.504.504 15.8 0.3 -- 25.216 35.056.560 10.9 0.2 20.7 -- 30.126 30.126.686 0.3 -- 10.054 sort 25.216.902 20.7 -- 35.056 20.014.916 0.1 15.8 0.3 -- 15.024 15.024.940 0.2 20.7 -- 20.014 10.054.994 0.3 -- 0.006 0.006 1.000

Graph of the 3 generator cumulative distribution for the probability that generation MW is > x) 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr.994.940.916.902.686.560.504.000 load not served generation

Unsuitability of the binary tree and Markov methods for large systems A system with 400 two-state generators has a total of: 400 120 2  10 states (combinations) This is greater than the number of atoms in the universe (~10 80 )!

The same cumulative distribution can be created one generator at a time. The function is updated as each generator is added. 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr.994.940.916.902.686.560.504.000 load not served generation

Starting with a blank distribution 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr load not served

Cumulative distribution for generator 1 generator 1 = {10 MW, FOR=.1} Pr 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW).900 load not served.000 ∞

Adding generator 2 scales and shifts the initial distribution for Pr=.8 (up) and Pr=.2 (down) generator 2 = {15 MW, FOR=.2} 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr.900 x.2 =.18.900 x.8 =.72 1.00 x.8 =.80

Summing the two curves gives the combined generators 1 and 2 cumulative distribution 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr load not served.000.72.80+.18=.98.80 generation

Adding generator 3 scales and shifts the distribution for Pr=.7 (up) and Pr=.3 (down) generator 3 = {20 MW, FOR=.3} 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr.98x.3=.294.80x.3=.24.72x.3=.216.98x.7=.686.80x.7=.56.72x.7=.504 1.00x.7=.700

Summing the two curves gives the combined generators 1, 2, and 3 cumulative distribution (same curve as the one using a binary tree) 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr.294+.700=.994.24+.70=.940.216+.7=.916.686.560.504.000 load not served generation.216+.686=.902

Binary tree graph of the 3 generator cumulative distribution for the probability that generation is available at x MW 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr.994.940.916.902.686.560.504.000 load not served generation

Cumulative distribution Pr[generation is up] represented in discrete 1 MW steps 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr load not served generation

Flip the function over and backwards and the distribution represents Pr[generation out of svc] This is the COPT or Capacity Outage Probability Table 1.0.9.8.7.6.5.4.3.2.1 0 45 40 35 30 25 20 15 10 5 0 x (MW) Pr load not served.496.440.314.098.084.060.006.000

Representation of Pr[gen out of service] as piecewise linear increments 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr load not served

Representation of Pr[gen out of service] as piecewise quadratic increments 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 x (MW) Pr load not served for any 3 points, interpolate between the left two points

Relative per unit error introduced by numerous interpolations of piecewise linear (PL) and piecewise quadratic (PQ) distributions PL x=30% PQ x=30% PQ x=20%

LOLE – loss of load expectation EUE – expected unserved energy 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 MW x – MW (daily or hourly) Pr EUE = MWH not served (for each hour in the study) generation LOLE for one day = 1 - Pr[gen up] = Pr[load loss] = 1-.56 =.44 d/y.686.560.504.994.940.916.902

LOLP – loss of load probability 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 MW x – MW weekly peak demand Pr generation LOLP (for a week) = 1 - Pr[gen up] = Pr[load loss] = 1-.56 =.44.686.560.504.994.940.916.902 annual LOLP = 1-  i (Pr[gen up] i ) for all i weeks

Representing load uncertainty (each hour is a Normal distribution of MW values) 1.0.9.8.7.6.5.4.3.2.1 0 0 5 10 15 20 25 30 35 40 45 50 MW x – MW (daily or hourly) Pr generation.686.560.504.994.940.916.902

Generation scheduled maintenance 1 xxx 2 xxx 3 4 xxxxx 5 6 xxx 7 8 xxxx 9 xxx 10 xxxx 11 1 5 10 15 20 25 30 35 40 45 50 52 week # during the year generator # summer insufficient reserve?

Generation scheduled maintenance reduces available generation – increases LOLE 1 5 10 15 20 25 30 35 40 45 50 52 week # during the year generator installed MW before maintenance MW demand insufficient reserve planning reserve with maint

Generation scheduled maintenance to minimize overall LOLE 1 5 10 15 20 25 30 35 40 45 50 52 week # during the year generator installed MW before maintenance MW demand planning reserve with maint

Automatic scheduled maintenance methodology to minimize LOLE 1.Sort the MW unit sizes from largest to smallest. 2.Place the largest MW generator in a time slot with the greatest unused reserve margin. 3.Place the next largest generator in a time slot with the greatest unused reserve margin. 4.Repeat step 3 until all units are scheduled.

ERCOT generation (MW) forced out of service and derated 0 2000 4000 6000 8000 10000 12000 ~5000 MW ~9000 MW ~6% ~11% 12.5% actual more generators

DC tie considerations probability of a DC tie failure is nearly 0 probability of generation supply being available in the other region is expected to be nearly 1 transmission constraints in the other region may reduce the probability of DC tie capability to less than 1 DC tie capacity can be included or excluded from the LOLP calculations (affects the LOLE) DC tie capacity may or may not be used to serve firm load in ERCOT (affects the reserve)

DC tie considerations DC tie with X MW firm generation DC tie with 0 MW firm generation DC tie in LOLP calculations Yes No LOLP:100% DC MW CDR : X MW gen 11% x=0 to 12.5% for x=all firm LOLP: X MW DC CDR : X MW gen 12.5% reserve LOLP:100% DC MW CDR : 0 MW gen 11% reserve LOLP: 0 MW DC CDR : 0 MW gen 12.5% reserve

Switchable generation considerations Switchable generation capability must be available to ERCOT when called upon. The same switchable MWs must be used in both the reserve calculation and the LOLP calculation.

Self-serve generation considerations Currently, both the self serve generation and self serve load (840 MW in the previous study) are omitted from the CDR and the LOLP calculations. Alternately, the self serve generation and load could be included with the CDR and LOLP calculations with a negligible effect on LOLE. Currently, self serve generation and load are included in the transmission load flow analysis as fixed MW values with 100% availability.

Interruptible load considerations The load can be modeled as two components, firm plus interruptible (i.e. two forecasts) The LOLE for serving firm load can be calculated by using only the forecast for firm load in the computer simulation. The LOLE for interruptible load can be calculated by using a forecast of firm load plus interruptible load in the computer simulation and then subtracting the LOLE results obtained for the firm load forecast.

Data needed to perform single-area LOLP studies hourly ERCOT loads for the (annual) study period (historical year hourly loads are scaled) the annual peak demand forecast and the percentage of interruptible load percentage of load forecast uncertainty each generator’s seasonal MW (Pmax) capability, fuel type, type of unit, and maintenance periods (by beginning and ending week numbers or by total weeks needed) FOR and DFOR of generator types such as gas, coal, nuclear, hydro, wind, etc. identification of self-serve MW by generator

Single Area Output Reports – Input Data SINGLE AREA GENERATOR DATA: SEASONAL CAPACITIES CDR FORCED PARTIAL-OUTAG SCHEDULED UNIT AREA WINT SPNG SUMM FALL CAP OUTAGE RATE DERATNG UNAVAILABLE NAME NAME MW MW MW MW % RATE % % % B1 D1 B2 D2 -------- -------- ---- ---- ---- ---- --- ------ ------ ------ -- -- -- -- STP1 ERCOT 1311 1311 1311 1311 100 6.90 2.30 5.50 5 4 0 0 STP2 ERCOT 1311 1311 1311 1311 100 6.90 2.30 5.50 4 4 0 0 CMPK 1 G ERCOT 1161 1161 1161 1161 100 6.90 2.30 5.50 11 4 0 0 CMPK 2 G ERCOT 1161 1161 1161 1161 100 6.90 2.30 5.50 3 12 0 0 DOW1 ERCOT 986 986 986 986 100 10.00 0.00 0.00 7 4 0 0 DOW2 ERCOT 917 917 917 917 100 10.00 0.00 0.00 3 12 0 0 DEC 1 G ERCOT 818 818 818 818 100 6.70 0.00 0.00 4 12 0 0 THSE 2 G ERCOT 818 818 818 818 100 6.70 0.00 0.00 48 4 0 0 LIM1 ERCOT 744 744 744 744 100 4.22 2.90 19.00 13 4 0 0 LIM2 ERCOT 744 744 744 744 100 4.22 2.90 19.00 3 12 0 0 MTNLK 1G ERCOT 727 727 727 727 100 4.22 2.90 19.00 43 4 0 0 MTNLK 2G ERCOT 727 727 727 727 100 4.22 2.90 19.00 48 4 0 0 MTNLK 3G ERCOT 727 727 727 727 100 4.22 2.90 19.00 49 4 1 8 MOSES3 G ERCOT 726 726 726 726 100 4.22 2.90 19.00 43 4 0 0 CB 3 ERCOT 703 703 703 703 100 6.70 0.00 0.00 13 4 0 0 DC-EAST ERCOT 700 700 700 700 0 0.01 0.00 0.00 3 12 0 0 Weeks 1-9 49-52 Weeks 10-21 Weeks 22-37 Weeks 38-48

Single Area Output Reports – Maintenance AUTOMATIC MAINTENANCE OF 12 LONG & 4 SHORT WEEKS SCHEDULED UNAVAILABLE: -WINTER- ---SPRING--- ----SUMMER---- ----FALL--- WIN UNIT AREA JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC NAME NAME week: 1111111111222222222233333333334444444444555 -------- -------- 1234567890123456789012345678901234567890123456789012 PB 5 G ERCOT ooooooo........ ooooo PB 6 G ERCOT........ oooo. MRGN 6 G ERCOT........ oooo. MRGN 2 G ERCOT oo........ oooooooooo MRGN 4 G ERCOT....... oooo.. MRGN 5 G ERCOT........ oooo. MRGN 3 G ERCOT oo........ oooooooooo

Single Area Output Reports – CDR WEEK CAPACITY OUT-OF-SVC AVAILABLE PEAK LOAD RESERVE RESERVE WEEK MW MW MW MW MW % BEGINS ---- -------- -------- -------- -------- -------- ------- ------ 16 80223. 0. 80223. 0. 80223. 0.0 APR 18 17 80223. 0. 80223. 35344. 44879. 127.0 APR 25 18 80223. 0. 80223. 49251. 30972. 62.9 MAY 2 19 80223. 0. 80223. 52755. 27468. 52.1 MAY 9 20 80223. 0. 80223. 53323. 26900. 50.4 MAY 16 21 80223. 0. 80223. 54975. 25248. 45.9 MAY 23 22 80223. 0. 80223. 60222. 20001. 33.2 MAY 30 23 80223. 0. 80223. 57907. 22316. 38.5 JUN 6 24 80223. 0. 80223. 55546. 24676. 44.4 JUN 13 25 80223. 0. 80223. 57007. 23216. 40.7 JUN 20 26 80223. 0. 80223. 63446. 16777. 26.4 JUN 27 27 80223. 0. 80223. 62549. 17673. 28.3 JUL 4 28 80223. 0. 80223. 62641. 17582. 28.1 JUL 11 29 80223. 0. 80223. 64447. 15776. 24.5 JUL 18 30 80223. 0. 80223. 67662. 12561. 18.6 JUL 25 31 80223. 0. 80223. 67691. 12532. 18.5 AUG 1 32 80223. 0. 80223. 70378. 9845. 14.0 AUG 8 33 80223. 0. 80223. 69615. 10607. 15.2 AUG 15 34 80223. 0. 80223. 70535. 9688. 13.7 AUG 22 35 80223. 0. 80223. 67195. 13027. 19.4 AUG 29 36 80223. 0. 80223. 63388. 16835. 26.6 SEP 5 37 80223. 0. 80223. 58919. 21303. 36.2 SEP 12 38 80223. 0. 80223. 61987. 18236. 29.4 SEP 19 39 80223. 0. 80223. 59018. 21205. 35.9 SEP 26 40 80223. 0. 80223. 0. 80223. 0.0 OCT 3

Single Area Output Reports – LOLE Results WEEK PEAK LOAD RESERVE WEEKLY PROBABILITY HOURLY UNSERVED WEEK MW % LOAD>GENR MWH BEGINS ---- -------- ------- -.--3--6--9-12-15- ----.--3--6--9- ------ 16 0. 0.0 0.0000000000000000 0.0000000000 APR 18 17 35344. 127.0 0.0000000000000000 0.0000000000 APR 25 18 49251. 62.9 0.0000000000000000 0.0000000000 MAY 2 19 52755. 52.1 0.0000000000000000 0.0000000000 MAY 9 20 53323. 50.4 0.0000000000000000 0.0000000000 MAY 16 21 54975. 45.9 0.0000000000000000 0.0000000000 MAY 23 22 60222. 33.2 0.0000000000000692 0.0000000000 MAY 30 23 57907. 38.5 0.0000000000000000 0.0000000000 JUN 6 24 55546. 44.4 0.0000000000000000 0.0000000000 JUN 13 25 57007. 40.7 0.0000000000000000 0.0000000000 JUN 20 26 63446. 26.4 0.0000000013815166 0.0000009830 JUN 27 27 62549. 28.3 0.0000000001051571 0.0000000560 JUL 4 28 62641. 28.1 0.0000000001375059 0.0000000719 JUL 11 29 64447. 24.5 0.0000000208146472 0.0000123400 JUL 18 30 67662. 18.6 0.0000393594360814 0.0782425020 JUL 25 31 67691. 18.5 0.0000418127666276 0.0886081361 AUG 1 32 70378. 14.0 0.0053711529435669 11.2483312958 AUG 8 33 69615. 15.2 0.0015578843676685 2.7090544949 AUG 15 34 70535. 13.7 0.0068264952639734 7.4071353617 AUG 22 35 67195. 19.4 0.0000147424748045 0.0100945754 AUG 29 36 63388. 26.6 0.0000000011738335 0.0000010857 SEP 5 37 58919. 36.2 0.0000000000000008 0.0000000000 SEP 12 38 61987. 29.4 0.0000000000194574 0.0000000072 SEP 19 39 59018. 35.9 0.0000000000000011 0.0000000000 SEP 26 40 0. 0.0 0.0000000000000000 0.0000000000 OCT 3 ANNUAL 70535. 13.7* 0.0137945421779943 21.5414809098 (* INSTALLED) LOSS OF LOAD EXPECTATION = 0.019290 DAYS/YR USING DAILY PEAK LOADS AND NO LOAD UNCERTAINTY LOSS OF LOAD EXPECTATION = 0.001565 DAYS/YR USING HOURLY LOADS AND NO LOAD UNCERTAINTY

Transmission model considerations Simplified transmission network (NARP) –requires the development of an equivalent –computationally fast –questionable circuit flow results Full transmission network (PLF) –eliminates the need to develop an equivalent –computationally fast if PDFs are used –results are in agreement with AC load flow

Transmission PDFs from AC load flows PDF = power distribution factor =  MW ckt flow /  MW power transfer  difference in two shift factors gen  flow load buses

Maximum Flows for Austrop-Sandow Ckts MAXIMUM +/- LINE FLOWS FROM SUMS OF INCREMENTAL GENERATOR FLOWS -------FROM------ -------TO-------- RATG BASE +MW -MW %ADJ 3429 SANDOW 345 7040 AUSTRO34 345 716 -356.0 2840.0 -3269.3 -2.2 3429 SANDOW 345 7040 AUSTRO34 345 789 -356.0 2840.0 -3269.3 -2.2 average weighted scale factor = 2.24 % sum of flows from helpers sum of flows from harmers

Maximum Flow Sources for Austrop-Sandow MAXIMUM CIRCUIT FLOWS WITH ALL CIRCUITS IN SERVICE -------FROM------ -------TO-------- ID RATG PCT -GENERATION-to-LOAD- DIST 3429 SANDOW 345 7040 AUSTRO34 345 1 716 -446 LOSTPN 2 18->NORTH.252 3429 SANDOW 345 7040 AUSTRO34 345 2 789 -405 LOSTPN 2 18->NORTH.252 3429 SANDOW 345 7040 AUSTRO34 345 1 716 397 SAND 4 G 22->SOUTH.232 3429 SANDOW 345 7040 AUSTRO34 345 2 789 360 SAND 4 G 22->SOUTH.232

0 MW Pr [ flow>x ] 0 1 ckt rating static base case flow overload Probabilistic flows on a circuit (in preparation to remove the overloaded portion)

Removing a transmission overload ckt overload states p p p Pr Pr[loss of gen>x] Pr[ckt MW>x] p = Pr[of an individual generation state] generation states one circuit’s flows MW shift a binary tree of generation states circuit rating

Correlating the removal of a transmission overload with the generation distribution line overload states F(x,y) surface as a set of discrete points 1 0 Pr F(x) generation distribution circuit distribution

Load shedding to remove Austrop- Sandow circuit overloads LINE-GENERATOR-AREA LOAD SHEDDING REPORT: BUS# BUS NAME BUS# BUS NAME ID MW MWH GENERATOR > LOAD AREA PDF 3429 SANDOW 345 - 7040 AUSTRO34 345 1 167. 0.114381 LOSTPN 2 NORTH 0.25209 3429 SANDOW 345 - 7040 AUSTRO34 345 1 167. 0.043348 LOSTPN 3 NORTH 0.25209 3429 SANDOW 345 - 7040 AUSTRO34 345 1 167. 0.016571 LOSTPN 1 NORTH 0.25209 3429 SANDOW 345 - 7040 AUSTRO34 345 1 167. 0.006372 BEP GT2 NORTH 0.24760 3429 SANDOW 345 - 7040 AUSTRO34 345 1 167. 0.002422 BEP GT1 NORTH 0.24760 3429 SANDOW 345 - 7040 AUSTRO34 345 1 166. 0.000880 BEP ST1 NORTH 0.24760 3429 SANDOW 345 - 7040 AUSTRO34 345 1 584. 0.000473 FPP G1 NORTH 0.22876 3429 SANDOW 345 - 7040 AUSTRO34 345 1 584. 0.000009 FPP G2 NORTH 0.22875 3429 SANDOW 345 - 7040 AUSTRO34 345 2 167. 0.022171 LOSTPN 2 NORTH 0.25209 3429 SANDOW 345 - 7040 AUSTRO34 345 2 167. 0.010692 LOSTPN 3 NORTH 0.25209 3429 SANDOW 345 - 7040 AUSTRO34 345 2 167. 0.004809 LOSTPN 1 NORTH 0.25209 3429 SANDOW 345 - 7040 AUSTRO34 345 2 167. 0.002008 BEP GT2 NORTH 0.24760 3429 SANDOW 345 - 7040 AUSTRO34 345 2 167. 0.000778 BEP GT1 NORTH 0.24760 3429 SANDOW 345 - 7040 AUSTRO34 345 2 166. 0.000277 BEP ST1 NORTH 0.24760 3429 SANDOW 345 - 7040 AUSTRO34 345 2 584. 0.000138 FPP G1 NORTH 0.22876 3429 SANDOW 345 - 7040 AUSTRO34 345 2 584. 0.000002 FPP G2 NORTH 0.22875 0.225331 MWH for one hour (with all gens at Pmax)

Load shedding to remove Austrop-Sandow circuit overloads AREA 2 NORTH AREA 2 TOTAL SYS RESV% LOAD-MW LOLP TLOP EUE-MWh TEUE-MWh TEUE-MWh 26.8 24556.70 0.0000000 0.0000000 0.000000 0.000001 0.000000 25.8 24747.19 0.0000000 0.0000000 0.000000 0.000002 0.000000 24.9 24937.68 0.0000000 0.0000000 0.000001 0.000003 0.000000 23.9 25128.17 0.0000000 0.0000000 0.000005 0.000006 0.000000 23.0 25318.67 0.0000001 0.0000001 0.000017 0.000011 0.000000 22.1 25509.16 0.0000004 0.0000001 0.000060 0.000019 0.000000 21.2 25699.65 0.0000012 0.0000002 0.000200 0.000033 0.000000 20.3 25890.14 0.0000039 0.0000004 0.000642 0.000057 0.000000 19.4 26080.63 0.0000115 0.0000006 0.001982 0.000095 0.000000 18.5 26271.13 0.0000328 0.0000010 0.005868 0.000157 0.000000 17.7 26461.62 0.0000894 0.0000017 0.016656 0.000254 0.000000 16.9 26652.11 0.0002330 0.0000026 0.045318 0.000408 0.000000 16.0 26842.60 0.0005806 0.0000041 0.118123 0.000646 0.000001 15.2 27033.09 0.0013812 0.0000062 0.294801 0.001011 0.000002 14.4 27223.58 0.0031339 0.0000093 0.703970 0.001559 0.000007 13.6 27414.08 0.0067733 0.0000139 1.607262 0.002374 0.000019 12.8 27604.57 0.0139248 0.0000203 3.505661 0.003567 0.000049 12.0 27795.06 0.0271876 0.0000293 7.298278 0.005290 0.000123 11.3 27985.55 0.0503270 0.0000418 14.489008 0.007744 0.000297 10.5 28176.04 0.0881587 0.0000588 27.404648 0.011197 0.000684 9.8 28366.54 0.1458544 0.0000817 49.340149 0.016000 0.001510 9.1 28557.03 0.2274701 0.0001123 84.498868 0.022601 0.003175 8.3 28747.52 0.3338294 0.0001524 137.585140 0.031555 0.006356 7.6 28938.01 0.4604444 0.0002029 212.981405 0.043481 0.012050 6.9 29128.50 0.5966979 0.0002636 313.627661 0.058973 0.021579 6.2 29319.00 0.7275037 0.0003300 439.966399 0.078365 0.036333 5.5 29509.49 0.8376617 0.0003927 589.470300 0.101443 0.057332 4.9 29699.98 0.9172952 0.0004368 757.143111 0.127114 0.084476 4.2 29890.47 0.9653328 0.0004466 936.921174 0.153360 0.116035 3.5 30080.96 0.9886289 0.0004117 1123.342538 0.177556 0.148519 2.9 30271.46 0.9972702 0.0003356 1312.648220 0.197277 0.177645 2.2 30461.95 0.9995617 0.0002363 1502.893099 0.211163 0.199933 1.6 30652.44 0.9999568 0.0001397 1693.351411 0.219370 0.214090 1.0 30842.93 0.9999959 0.0000674 1883.840375 0.223328 0.221365 0.4 31033.42 0.9999987 0.0000254 2074.331880 0.224820 0.224271 note the differences in TEUE area and system load levels --------------- warning - load sheds can appear to occur at different % load levels generation Pr [out of svc] transmission constraints

Load shedding to remove Austrop-Sandow circuit overloads RESV% LOAD-MW LOLP TLOP GLOL-D/Y TLOL-D/Y TOTL-D/Y 22.1 66956.00 0.0000004 0.0000001 0.000001 0.000000 0.000001 21.2 67456.00 0.0000012 0.0000001 0.000003 0.000001 0.000004 20.3 67956.00 0.0000039 0.0000002 0.000010 0.000001 0.000011 19.4 68456.00 0.0000115 0.0000004 0.000029 0.000002 0.000031 18.5 68956.00 0.0000328 0.0000006 0.000084 0.000003 0.000086 17.7 69456.00 0.0000894 0.0000010 0.000232 0.000004 0.000236 16.9 69956.00 0.0002330 0.0000015 0.000615 0.000007 0.000622 16.0 70456.00 0.0005806 0.0000024 0.001563 0.000011 0.001574 15.2 70956.00 0.0013812 0.0000036 0.003799 0.000017 0.003816 14.4 71456.00 0.0031339 0.0000055 0.008833 0.000027 0.008860 13.6 71956.00 0.0067733 0.0000082 0.019635 0.000041 0.019676 12.8 72456.00 0.0139248 0.0000120 0.041690 0.000062 0.041752 12.0 72956.00 0.0271876 0.0000173 0.084488 0.000092 0.084580 11.3 73456.00 0.0503270 0.0000246 0.163376 0.000135 0.163511 10.5 73956.00 0.0881587 0.0000345 0.301211 0.000195 0.301406 9.8 74456.00 0.1458544 0.0000472 0.529378 0.000277 0.529655 9.1 74956.00 0.2274701 0.0000641 0.886719 0.000390 0.887109 8.3 75456.00 0.3338294 0.0000847 1.416075 0.000539 1.416615 7.6 75956.00 0.4604444 0.0001094 2.158461 0.000733 2.159193 6.9 76456.00 0.5966979 0.0001386 3.146670 0.000982 3.147652 6.2 76956.00 0.7275037 0.0001670 4.400033 0.001284 4.401317 5.5 77456.00 0.8376617 0.0001914 5.922297 0.001641 5.923937 4.9 77956.00 0.9172952 0.0002067 7.703882 0.002040 7.705923 4.2 78456.00 0.9653328 0.0002070 9.723858 0.002472 9.726330 3.5 78956.00 0.9886289 0.0001889 11.947046 0.002903 11.949949 2.9 79456.00 0.9972702 0.0001498 14.317933 0.003325 14.321258 2.2 79956.00 0.9995617 0.0001027 16.754972 0.003700 16.758673 1.6 80456.00 0.9999568 0.0000594 19.161745 0.004023 19.165768 1.0 80956.00 0.9999959 0.0000280 21.463148 0.004293 21.467442 0.4 81456.00 0.9999987 0.0000104 23.621519 0.004478 23.625998 generation transmission LOLE LOLE

Overall effect of removing all transmission overloads on the LOLE single area unserved load 0 0 1 x MW load additional unserved load due to a transmission constraint Pr [gen is in service]

Overall effect of removing all transmission overloads on the LOLE Pr [gen is out of service] 0 1 Generation MW 0 Capability  increasing load single area unserved load additional unserved load due to a transmission constraint

See my dissertation on egpreston.com for more details. The End