1991 FERC-714 Diskette Master

Federal Energy Regulatory Commission FERC Form No. 714 (1999)		Annual Electric Control and Planning Area Report For the Year Ending December 31, 2002			Please Type: Utility Code 12825 Utility Name NorthWestern Energy
Part II - Schedule 1. Generating Plants Included in Reporting Control Area (Use continuation sheets if needed)
Under the name of its operating electric utility, list all generating plants (1) within the respondent's control area which are controlled, metered or for which the required information is otherwise available to control area operators and (2) dynamically scheduled plants or units outside the control area. Specifically identify dynamically scheduled plants. Report only plant totals with generators in an operating or standby status. Provide totals for columns (d) and (e) as a last line. The total in column (d) should equal the value in column (c) on Schedule 2 for the month of the annual peak demand. The total in column (e) should equal the value in column (f) on Schedule 3 for the month of the annual peak demand. Any differences must be explained in a note. For specific guidelines, please refer to the attached Schedule 1 Instructions on pages 14 and 15.
Line No. (a)	Electric Utility Name (b)		Plant Name (c)	Plant Available Capability at the Hour of the Annual Peak Demand Based on Net Energy for Load (MW) (d)		Integrated Net Load on the Plant at the Hour of the Annual Peak Demand Based on Net Energy for Load (MW) (e)
1.	NORTHWESTERN ENERGY		BLACK EAGLE	12		14
2.	NORTHWESTERN ENERGY		COCHRANE	54		24
3.	NORTHWESTERN ENERGY		COLSTRIP 1 & 2	300		273
4.	NORTHWESTERN ENERGY		COLSTRIP 3 & 4	216		208
5.	NORTHWESTERN ENERGY		CORETTE	160		152
6.	NORTHWESTERN ENERGY		HAUSER	11		10
7.	NORTHWESTERN ENERGY		HOLTER	24		22
8.	NORTHWESTERN ENERGY		KERR	185		186
9.	NORTHWESTERN ENERGY		MADISON	9		9
10.	NORTHWESTERN ENERGY		MILLTOWN	0		2
11.	NORTHWESTERN ENERGY		MORONY	48		23
12.	NORTHWESTERN ENERGY		MYSTIC LAKE	12		9
13	NORTHWESTERN ENERGY		RAINBOW	32		24
14	NORTHWESTERN ENERGY		RYAN	55		42
15	NORTHWESTERN ENERGY		THOMPSON FALLS	87		89
16	NORTHWESTERN ENERGY		YELLOWSTONE DIESELS	0		0
17	MT DEPT./NATURAL RESOURCES RESOURCES		BROADWAY	8		4
18	COLSTRIP ENERGY LTD. PARTNERSH		MONTANA 1	0		0
19	BILLINGS GENERATION INC.		BGI	52		24
20	US DEPT OF THE INTERIOR (USBR)		CANYON FERRY	26		33
21	VARIOUS SMALL POWER PROD			4		1
			TOTAL	1295		1149

Federal Energy Regulatory Commission FERC Form No. 714 (1999)				Annual Electric Control and Planning Area Report For the Year Ending December 31, 2002					Please Type: Utility Code Utility Name
Part II - Schedule 2. Control Area Monthly Capabilities at Time of Monthly Peak Demand
The peak demand and other terms used in this schedule are defined in the attached instructions for Schedule 2, pages 15 through 18. Please first read the instructions, then complete this Schedule. The value in column (c) for the month of the annual peak demand should equal the total in column (d) in Schedule 1. Any difference must be explained in a note.
		Net Capability at the Time of the Monthly Peak Demand, Based on Control Area Net Energy For Load (NEL)
		Net Capability from Plants Reported on Schedule II						External to the Control Area Net Unit or Firm Capability (MW)
			Unavailable Capability Due to:
Line No. (a)	Month (b)	Available Capability (MW) (c)	Planned Outage and Derating (MW) (d)		Unplanned Outage and Derating (MW) (e)	Other Outage and Derating* (MW) (f)	Total (c + d + e + f) (MW) (g)	Available (MW) (h)		Not Available (MW) (i)	Total Capability (g + h + i) (MW) (j)
1.	Jan	1167	16		385	0	1568	56			1625
2.	Feb	1416	21		103	0	1540	(6)			1534
3.	Mar	1342	16		182	0	1540	(13)			1527
4.	Apr	1425	43		63	0	1531	7			1538
5.	May	1366	10		38	0	1574	(154)			1420
6.	Jun	1000	10		409	0	1579	(25)			1554
7.	Jul	1295	10		257	0	1562	(34)			1528
8.	Aug	1454	13		92	0	1559	(169)			1390
9.	Sep	1363	13		166	0	1542	(169)			1373
10.	Oct	1286	19		254	0	1559	(94)			1465
11.	Nov	1029	23		508	0	1560	(94)			1466
12.	Dec	1460	29		68	0	1557	(50)			1507
* Reductions in capability due to fuel supply problems, environmental restrictions, lack of transmission availability at a generating plant, etc.

Federal Energy Regulatory Commission FERC Form No. 714 (1999)				Annual Electric Control and Planning Area Report For the Year Ending December 31, 2002						Please Type: Utility Code Utility Name
Part II - Schedule 3. Control Area Net Energy for Load and Peak Demand Sources by Month
Enter the monthly "Net Energy for Load" which is the amount of energy that the control area requires internally including control area losses. The total in column (d) should equal the difference in the totals for columns (e) and (f) on Schedule 5. The value in column (f) for the month of the annual peak demand should equal the total in column (e) in Schedule 1. Any differences must be explained in a note. For detailed instructions and definitions, please refer to attached Schedule 3 Instructions on pages 19 and 20.
						Control Area Load Sources at Time of Control Area Monthly Peak Demand, Based on Net Energy For Load (NEL)
Line No. (a)	Month (b)	Control Area Net Generation (MWh) (c)	Net Actual Interchange (MWh) (d)		Net Energy for Load (MWh) (c + d) (e)	Output of Generating Plants (MW) (f)	Unit or Firm Purchases (MW) (g)	Unit or Firm Sales (MW) (h)	Net Non-Firm & Inadvertent (MW) (i)		Monthly Peak Demand (MW) (f+g-h+i) (j)	Monthly Minimum Demand (MW) (k)
1.	January	811587	11914		823501	1117	128	72	140		1313	811
2.	February	825162	109383		934545	1245	148	154	115		1354	830
3.	March	952528	155815		1108343	1235	98	111	117		1339	803
4.	April	897108	198519		1095627	1316	98	91	(65)		1258	738
5.	May	892366	180107		1072473	1319	0	154	16		1181	741
6.	June	651908	(85756)		566152	952	0	25	457		1384	785
7.	July	740620	(96196)		644424	1149	60	94	352		1467	825
8.	August	921557	162401		1083958	1301	0	169	124		1256	793
9.	September	816464	122091		938555	1244	0	169	162		1237	731
10.	October	801952	51363		853315	1178	0	94	262		1346	785
11.	November	857279	115231		972510	1167	0	94	183		1256	802
12.	December	872874	62118		934992	1147	0	50	237		1334	832
13.	Total	10041405	986990		11028395

Federal Energy Regulatory Commission FERC Form No. 714 (1999)		Annual Electric Control and Planning Area Report For the Year Ending December 31, 2002			Please Type: Utility Code Utility Name
Part II - Schedule 5. Control Area Scheduled and Actual Interchange
Identify on this schedule: each control area with which the respondent control area has actual or scheduled interchange of energy, in column (b); the total annual megawatthours (MWh) of the scheduled interchange that were received by the respondent control area through all interconnection points with each control area, in column (c); the MWh of scheduled interchange delivered to each control area, in column (d); the MWh of total annual actual interchange received and delivered within each adjacent control area, in columns (e) and (f). Provide totals for columns (c), (d), (e) and (f). The difference in the totals for columns (e) and (f) should equal the total in column (d) on Schedule 3. Any difference must be explained in a note. See Schedule 5 Instructions on page 21.
Line No.	Name of Control Area		Scheduled Interchange Between Control Areas (MWh)			Actual Interchange Between Adjacent Control Areas (MWh)
(a)	(b)		Received (c)	Delivered (d)		Received (e)	Delivered (f)
1.	BONNEVILLE POWER ADMINISTRATION		2,688,422	10,857,553		3,061,272	10,893,205
2.	PACIFICORP (EAST)		576,764	1,969,963		354,872	1,104,809
3.	PACIFICORP (WEST)		958,026	0		958,026	0
4.	PORTLAND GENERAL ELECTRIC		1,860,094	0		1,860,094	0
5.	PUGET SOUND POWER & LIGHT		4,509,167	0		4,509,167	0
6.	WASHINGTON WATER POWER		1,697,441	571,750		1,437,596	758,178
7.	WESTERN AREA POWER ADMINISTRATION (UPPER MISSOURI)		789,400	668,573		1,060,560	1,472,385
8.	WESTERN AREA POWER ADMINISTRATION (LOWER MISSOURI)		0	0		0	0
9.
10.	TOTAL		13,079,314	14,067,839		13,241,587	14,228,577

Federal Energy Regulatory Commission FERC Form No. 714 (1999)	Annual Control Area and Electric System Report For the Year Ending December 31, 2002		Please Type: Utility Code Utility Name
Part II - Schedule 6. Control Area System Lambda Data
Submit on a 3.5 inch diskette formatted for the DOS operating system the following data file in ASCII format: the control area's system lambda for each hour of the year starting with 1 a.m., January 1, 1999. Identify clearly the time zone in which this time series is made. The file should have 8760 records (8784 for leap years). Each record is to contain the system lambda value at the clock hour in dollars per megawatthour (mills per kilowatthour) or an "NA" for those hours when system lambda was not calculated. Control Area Hourly System Lambda. For control areas where demand following is primarily performed by thermal generating units, the system lambda is derived from the economic dispatch function associated with automatic generation control performed at the controlling utility or pool control center. Excluding transmission losses, the fuel cost ($/hr) for a set of on-line and loaded thermal generating units (steam and gas turbines) is minimum [1] when each unit is loaded and operating at the same incremental fuel cost ($/MWh) [2] with the sum of the unit loadings (MW) equal to the system demand plus the net of interchange with other control areas. This single incremental cost of energy is the system lambda. System lambdas are likely recalculated many times in one clock hour. However, the indicated system lambda occurring on each clock hour would be sufficient for reporting purposes.		Provide, as a note in Part IV, an explanation describing the reason for the unavailability of system lambda information and a definite plan for reporting the information with a target date. The Commission expects that all Energy Management Systems, with proper instructions, can record the system lambda being used for economic dispatch of the control area's thermal units. Respondents should be able to report system lambda, along with the other information reported on a control area basis, that describe the operation of such areas from information that should be readily available. The Commission is not requesting Respondents to develop incremental or marginal cost (either short or long term) according to any formula. Nor is the Commission requesting "avoided cost rates" that, pursuant to PURPA 210, electric utilities file with state commissions or otherwise make available for prospective qualified facilities. Description of Economic Dispatch. Also, provide in writing a detailed description of how Respondent calculates system lambda. For those systems that do not use an economic dispatch algorithm and do not have a system lambda, provide in writing a detailed description of how control area resources are efficiently dispatched.

Federal Energy Regulatory Commission FERC Form No. 714 (1999)		Annual Electric Control and Planning Area Report For the Year Ending December 31, 2002	Please Type: Utility Code Utility Name
Part III - Schedule 1. Electric Utilities That Compose the Planning Area (Use continuation sheets if needed)
Enter the name of each entity, including the respondent, that forms the planning area for which this report is being prepared and their coincident summer and winter peak demands in megawatts. Please refer to Instructions on pages 23 and 24 .
				Electric Utility Coincident Peak Demand (MW)
Line No. (a)	Electric Utility Name (b)			Summer (c)	Winter (d)
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2.
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4.
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6.
7.
8.
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Federal Energy Regulatory Commission

FERC Form No. 714 (1999)

Annual Electric Control and Planning Area Report

For the Year Ending December 31, 2002

Please Type:

Utility Code

Utility Name

Part III - Schedule 2.

Planning Area Hourly Demand and Forecast Summer and Winter Peak Demand and Annual Net Energy for Load

PLANNING AREA HOURLY DEMAND

(1) Respondents must submit hourly demand data in electronic form to the Commission. Additionally, Respondents that participate in a national, regional or subregional process for consolidating and ensuring the consistency and accuracy of actual hourly and forecast demand information, may instead authorize the national, regional or subregional organization to release that information to the Commission, and to the public at the cost of reproduction, in an easily accessible electronic format, such as the EEI format.

(2) If the Respondent does not participate in the development of national, regional or subregional actual and forecast demand information, it must submit its own, equivalent, demand information directly to the Commission along with this report, as follows.

Respondents must submit on a 3.5 inch diskette formatted for the DOS operating system the following data file in ASCII format: the planning area's actual hourly demand, in megawatts, for each hour of the year starting with 1 a.m, January 1, 1999. Indicate the time zone and the period for which daylight savings time was used. The file should have 8760 records (8784 for leap years). For hours when this information is not available, enter "NA."

PLANNING AREA FORECAST SUMMER AND WINTER PEAK DEMAND

Provide on the diskette a file containing the planning area's forecast summer and winter peak demand, in megawatts, and annual net energy for load, in megawatthours, for the next ten years.

[1] Some utilities may also include variable operation and maintenance costs that they consider "dispatchable." Therefore the costs to be minimized could include a variable O&M component as well as the fuel costs.

[2] Because unit heat rates and fuel costs vary, some units may not be able to operate at the same incremental fuel cost as the other units and, thus, those units may be loaded differently.

Federal Energy Regulatory Commission FERC Form No. 714 (1999)				Annual Electric Control and Planning Area Report For the Year Ending December 31, 2002	Please Type: Utility Code Utility Name
Part IV. Notes
Indicate a note by placing an asterisk (*) next to the entry on Schedules 1 through 6 of Part II and Schedules 1 and 2 of Part III, and then provide the note below. For each note, enter the page number in Column (a), the line number in Column (b), the column letter in Column (c), and the Note in Column (d). Use more than one line if needed.
Page No. (a)	Line No. (b)	Column Letter (c)	Notes (d)
			NorthWestern Energy (NWE) does not compute system lambda as described in the instructions for this report. NWE”S dispatchable resources are hydroelectric plants and coal-fired thermal plants. Automatic generation control (AGC) is provided by NWE”S hydro plants or by contracts with neighboring utilities. Because of their low fuel costs, NWE’s thermal plants are not included in the AGC algorithm and typically loaded to their maximum capabilities with any resulting surplus energy sold to other utilities. During some months of the year (generally May and June), regional hydroelectric production may make it economic for NWE to reduce thermal generation during off-peak hours. If this occurs, thermal generation is dispatched on a merit-order basis, but ACG continues to be provided by hydro plants or by contracts.