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Reprint - PUC Interchange
IV. PLANNING CRITERIA
Page IV - 4
Unit costs for various types of primary distribution line improvements should include consideration
of several factors that could significantly affect unit prices. Distribution lines on the LEC system have
been maintained adequately and are generally in good condition. Usually, improvement of existing
facilities would not require complete reconstruction unless the improved facility requires adding
phases or is to use #4/0 ACSR or larger conductor. Table 4-4 indicates the costs for re-construction
of a facility is the same as the cost for a new facility of like design. Actually, removal cost for an
existing facility is usually more than the salvage value of the removed facility. When this is true, the
cost for re-construction of a facility is more than the cost for a new facility of like design.
TABLE 4-4: UNIT COST
(Primary Line Conversion)
Description
17
Cost per mile
Single-Phase to Three-Phase
to #1/0 ACSR
$
40,000
to #4/0 ACSR
$
50,000
7to 477 MCM ACSR
$
65,000
V-Phase to Three-Phase
to #1/0 ACSR
$
40,000
to #4/0 ACSR
$
50,000
to 477 MCM ACSR
$
65,000
Three-Phase to Three-Phase
to #1/0 ACSR
$
40,000
to #4/0 ACSR
$
50,000
to 477 MCM ACSR
$
65,000
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IV. PLANNING CRITERIA
b.
Page IV - 5
Primary Distribution Equipment
The following tabulation of unit prices lists major types of equipment normally itemized in system
planning. Minor distribution equipment costs are included in distribution line costs and are not
listed separately.
4-5: UNIT COST
(Primary Distribution Equipment)
Description
Cost
Voltage Regulator Banks
Three-Phase with Installation
100 Amp
$30,000
150 Amp
$36,000
200 Amp
$42,000
Capacitor Banks
300 kVAR
$12,000
c.
450 kVAR
$13,000
600 kVAR
$14,000
Substations
Presentations concerning substations are based on estimates furnished by the Engineer and
reviewed by LEC. Basic facets of substation costs are presented instead of itemizing individual
equipment costs.
TABLE 4-6: UNIT COST
(Substation)
Description
Cost
Single Transformer (4 circuits)
Substation Base Cost
$600,000
Individual Transfomer
10/12.5 MVA
12/16/20 MVA
Substation and 10 MVA Transformer
Transformer Relocation
$600,000
$800,000
$1,200,000
$20,000
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Page IV - 6
IV. PLANNING CRITERIA
d. Transmission
Presentations concerning transmission facilities are estimates furnished by the Engineer and are
based on recent experience.
TABLE 4-7: UNIT COST
(Transmission)
Description
Cost per mile
Three-Phase
2.
69 kV #4/0 ACSR
$195,000
69 kV #477 MCM ACSR
$210,000
115 kV #477 MCM ACSR
$275,000
138 kV #477 MCM ACSR
$295,000
Annual Fixed Expenses
A number of expenses are associated with ownership of each plant facility. Such expenses are
ongoing over the life of a facility, regardless of the capacity or effectiveness of that facility. Interest
is paid annually on funds borrowed to finance the original investment. Depreciation accounts for
the decreasing value of a facility over its useful life. Property taxes are based on the depreciated
value of a facility during its life.
Historical records of these expenses allow a ratio of annual
expenses to original plant investment to be derived. These ratios can then be used to estimate the
magnitude of these annual expenses that can be expected for any new facility. Expected LEC fixed
cost ratios used for planning purposes are derived below in Table 4-8.
Most ratios were derived
from past operating records. Interest rate is based on rates expected to prevail during the planning
period.
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IV. PLANNING CRITERIA
Page IV - 7
TABLE 4-8: ANNUAL FIXED EXPENSES
(2010 Expenses Relative to Plant Investment)
Total Plant Investment
RUS Form 7, Pg. 2, C-3
Item
Source
1 Blended Loan Funds
Cooperative Receives 0.00% of required funds from RUS @
Cooperative Receives 100.00% of required funds from CFC @
Cooperative Receives 0.00% of required funds from Others @
Blended Loan Funds =
2 Taxes/Property
Property Taxes & OthE ^r Taxes
Total
3 Depreciation
Total
RUS Form 7, Pg.1, A-12, Col. B
Depreciation / Plant
$135,200,217
Amount
Rate
0.00%
3.25%
0.00%
3.25%
0.90
0.90
0.90%
4,186,692.00
3.10%
7.25%
Plant facilities must be properly operated and adequately maintained on an ongoing basis in order
to minimize losses and maximize service reliability as well as promote safety. The Engineer has
concluded that operation and maintenance costs are much more nearly associated with line miles
than initial investment.
Costs for operation and maintenance are relatively the same per mile
regardless of conductor size and associated investment. Based on this conclusion, annual variable
expense ratios that treat operation and maintenance costs separately are shown below in Table 4-9.
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Page IV - 8
IV. PLANNING CRITERIA
TABLE 4-9: ANNUAL VARIABLE EXPENSES
(2010 Expenses Relative to Line Miles)
Cost/Mile
3.
Total Distribution Line Miles
RUS Form 7, Pg. 1, B-6, Col. B
Overhead
RUS Form 7, Pg. 1, B-7, Col. B
Underground
Total Distribution
5,122.0
1,708.0
6,830.0
Distribution Operation & Maintenance (O&M)
RUS Form 7, Pg. 1, A-5, Col. B
Operations
RUS Form 7, Pg. 1, A-6, Col. B
Maintenance
(Property
+ Other) / Plant
Total
3,250,450.00
3,455,937.00
6,706,387.00
TRANSMISSION
Total Transmission Line WE RUS Form 7, Pg. 1, B-5, Col. B
68.0
Transmission Operation & Maintenance (O&M)
RUS Form 7, Pg. 1, A-4, Col. B
Expense
(Property + Other) / Plant
Total
6,973.00
6,973.00
981.90
102.54
Economic Inflation
Most costs associated with the cooperative are affected, either directly or indirectly, by inflationary
economic trends. Investments in plant facilities are most rapidly and drastically affected. Other
expenses, such as purchased power, operation, maintenance, and interest are also affected. In
order for the Long-Range Plan to reflect budgetary needs as accurately as possible, inflation trends
are considered.
The time value of money relates to both interest rates and the rate of inflation. The effects of
inflation usually make a facility more expensive to construct when the project is deferred. However,
interest costs make the amount of money spent earlier worth more than the same amount of
money spent later.
The primary source used to obtain information concerning inflation is the Consumer Price Index
(CPI) which reflects national and regional trends in consumer prices.
Management, with the concurrence of the engineer expects that future interest rate of three
percent (3%) and inflation rate of three percent (3%). Based on historical trends, this ratio between
the two rates is appropriate. These rates are used herein for comparative present worth analysis of
plan options.
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IV. PLANNING CRITERIA
4.
Page IV - 9
Power Cost
In the past, wholesale power costs to LEC have accounted for about 60 percent (59%) of the total
cost of electric service
a.
Existing Power Costs
Lyntegar Electric Cooperative purchases all power requirements from both ONCOR Electric Delivery
Company LLC and Xcel Energy Inc. The average cost of power for LEC has increased and decreased
from 2006 through 2010.
Power Cost
Year
2006
2007
2008
2009
2010
¢ per kWh
6.99
7.71
8.33
5.17
6.35
Average
6.91
LEC purchases power from ONCOR and Xcel at a rate that consists of a number of components.
These components are related to membership, service, energy or demand. The largest components
are related to energy and demand.
b.
Future Power Costs
LEC believes that wholesale power costs will probably rise in the future. Much is dependent on the
market cost of fuel.
D. Other Criteria
Other factors and criteria have an impact on development of the long-range plan.
1.
Annual Load Factor
Table 4-10 below illustrates the LEC annual load factor for the last few years derived from LEC
operating reports.
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IV. PLANNING CRITERIA
Page IV - 10
TABLE 4-10: ANNUAL LOAD FACTOR
(Total System)
Y ear
Energy
NCP Peak Demand (kW)
Factor
( MWh)
Summer
2002
37.07%
545,837
168,108
65,962
2003
38.97%
581,361
170,309
79,366
2004
33.85%
503,686
169,866
81,279
2005
38.97%
576,127
168,750
80,978
2006
40.93%
649,038
181,022
94,637
2007
32.54%
494,571
173,525
74,375
2008
40.15%
652,550
185,557
93,635
2009
37.29%
712,381
218,100
102,182
37.47%
589,444
179,405
84,052
Average
2.
NCP Load
Winter
Power Factor
LEC routinely maintains a system-wide power factor above ninety percent at peak load. The
engineer usually considers a power factor above ninety-five percent (95%) during peak periods is
economically justified. A power factor of ninety-eight percent (98%) is used for the purposes of
long-range distribution system planning.
3.
Voltage Analysis Scenario
LEC substations are dependent on voltage delivered through ONCOR and Xcel transmission facilities.
Transmission systems other than those belonging to LEC are not analyzed in this study. Voltage
delivery to LEC substations is analyzed based on delivery of nominal transmission voltage using
maximum coincident LEC substation loading.
4.
Nominal Transmission Voltage
The ONCOR and Xcel bulk transmission system delivering power to the LEC system is comprised of
transmission facilities operating at a nominal voltage of 69 kV and 115 kV. ONCOR has two facilities
that operate at 138 kV. Therefore, the LEC transmission system is also designed and operated at 69
kV, 115 kV, and 138 kV.
Only 69 kV and 115 kV nominal transmission voltages were considered in this study for use on the
LEC system. Each voltage has inherent advantages and disadvantages. With a given conductor size,
approximately 1.7 times as much load can be delivered, and only thirty-six percent of the losses
incurred via a 115 kV facility over a 69 kV facility.
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IV. PLANNING CRITERIA
Page IV - 11
Re-construction of 69 kV facilities for 115 kV would be very expensive. Any 69 kV transmission
facility would have to be entirely replaced. Associated substation primary facilities would have to be
modified or replaced. Protective and some other equipment would be replaced.
5. Transmission System Configuration
The configuration of transmission systems serving LEC can potentially have a greater impact on
system reliability than most other parts of the system. Xcel and ONCOR should be able to serve peak
load if any single 69 kV, 115 kV (Xcel) or 138 kV (ONCOR) transmission segment were to become
inoperable. Since these transmission facilities serve loads in addition to LEC, load limitations that
night be imposed on LEC by these transmission facilities are not readily discernible.
A service interruption caused by malfunction of transmission facilities is less likely than with
distribution facilities because they are more regularly inspected and more extensively protected
than most distribution-voltage facilities. Radial transmission facilities warrant special consideration,
however. Service interruptions of a radial transmission facility will usually affect more consumers,
greater load and will be of longer duration than most distribution system malfunctions. Regardless
of the statistical probability that a malfunction of a transmission facility will cause a major service
interruption, special attention to the reliability of transmission facilities is warranted.
6.
Maximum Substation Caoacit
A service interruption caused by malfunction of substation power transformers is less likely than
with most distribution facilities because they are more regularly inspected and more extensively
protected than most distribution-voltage facilities. Substation power transformers warrant special
consideration, however, based on the fact that service interruptions caused by malfunction of a
power transformer will usually affect more consumers, greater load and will be of longer duration
than most distribution system component malfunctions. Regardless of statistical probability that a
malfunction of a substation power transformer will cause a major service interruption, special
attention to the reliability of substation power transformers is warranted.
The engineer recommends that malfunction of a single substation power transformer should not
result in a greater-than-momentary interruption of service to load greater than ten megawatts (10
MW). More than just one substation power transformer should serve peak load greater than ten
megawatts that must be served by a single substation. If one substation power transformer should
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IV. PLANNING CRITERIA
Page IV - 12
malfunction, the remaining power transformer(s) should be of adequate capacity to provide
continued service.
Statistically, system reliability is most economically achieved if the system is designed so that length
of a possible service interruption is roughly inversely proportional to the magnitude of load that can
be interrupted by a single contingency.
Unless special service area, loading, or economic conditions prevail, future substation capacities will
be limited to capacity increments of standard power transformer and in maximum practical
capacity. The engineer would usually recommend that in strictly rural areas, substation capacity
served by a single power transformer will be limited to a capacity of 10/12.5/14 (OA/FA/65°C). In
most instances, the OA 55°C rating of the power transformer(s) will be dedicated to serve peak load
under normal operating conditions.
The OA/FA/65°C rating of the power transformer(s) will be
reserved for use only during emergency operating conditions or used in response to much-morerapid load growth than anticipated.
Rural substations serving more than 10.5 MVA load should be equipped with more than one power
transformer unless significant load can be transferred to another substation or a mobile transformer
can augment the capacity of the substation quickly. A substation power transformer should not be
exposed to load greater than one hundred percent (100%) of the OA/FA/65° rating of the power
transformer, even during emergency operating conditions.
7.
Primary Distribution Voltage
Only one primary distribution voltage was seriously considered for use on the LEC system.
a.
7.2/12.47 kV
The 7.2/12.47 kV distribution voltage is presently being utilized to serve 100% of load on the LEC
service area. Because of the abundance of nearby transmission systems serving the LEC system, the
proportion of this primary distribution system voltage will remain unchanged for the long-ranged
planning period.
b.
14.4/24.94 kV
The 14.4/24.94 kV distribution voltage is presently being utilized for three express feeders. One of
these is located at West Lamesa and is expected to be removed during the First Transition. The
other two are located at Seagraves, feeding the southwest portion of its service area, and Ackerly,
feeding West. The Seagraves and Ackerly express feeders will continue to be in service.
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IV. PLANNING CRITERIA
c.
Page IV - 13
Other Voltage
The most common uses of a distribution voltage higher than 7.2/12.47 kV is as an express feeder
into a remote area or as a sub-transmission system.
Unless special service area, loading, or economic conditions prevail, most primary distribution
facilities will ultimately operate at 7.2/12.47 W. Use of another distribution voltage would be a rare
exception.
E.
Assumptions
The engineer uses specific assumptions to develop the long-range plan.
The four percent (4.1%) interest rate used for economic evaluations is equal to the inflation rate of
four percent (4.1%) used to predict the costs of future investments. Regardless of future interest
rates or rates of inflation, the economic comparison of plans will remain valid so long as this ratio
does not change significantly.
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V. LONG RANGE PLAN
Page V - 1
A. The Recommended Plan
This section of the System Planning Report is designed to present the developed Long-Range Plan in
as much detail as necessary for implementation.
Most of the planned major system improvements to be accomplished during the planning period are
related to expected load growth but are dependent on the capacity and adequacy of existing
facilities. In most areas of the system, major system improvements included herein are deferred as
long as practical based on delivery of adequate voltage during emergency operating conditions that
occur coincident with peak load periods.
As normal load growth occurs throughout the system, some load transfers are appropriate between
substations to improve voltages, decrease losses, or defer premature investments. These load
transfers, when combined with normal load growth and system improvements, have an impact on
expected load served by each substation. In addition to these factors, emergency load transfers
between substations might be appropriate.
Three different approaches were completed by SGS Engineering, with the best and most economical
parts of each, were put together to comprise a single Long Range plan. One aspect, Exploratory A,
considered correcting problems but adding no new substations. This was accomplished by adding
additional or larger transformers at overloaded substations. Eight new 10 MVA transformers, and
four relocations of others, would have been needed. Exploratory B corrected expected problems by
adding new substations where it was most economical. Several possibilities were considered under
Exploratory B, but only those that proved as the best options were utilized in the Long Range Plan.
The last portion, Exploratory C, was focused on the southern service area of LEC, and tested several
different possibilities of new substations, eliminating the metering points within LEC. The possibility
of large-capacity substations (20 MVA) as well as several smaller ones were considered. Due to the
large geographical area served by LEC, the large substations were found to be less acceptable than
several smaller substations.
Based on the findings from the various exploratory options mentioned above, a Long Range Plan
was devised and is recommended by SGS engineering. The following two maps show the Long
Range Plan at the end of 2020. Each map illustrates the system showing recommended sources,
distribution changes, and interchange and substation facilities that should be in operation by the
end of the planning period.
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V. LONG RANGE PLAN
1.
Page V - 4
Voltage Regulation
The following two maps show the locations and coverage areas, in red, of voltage regulators at the
end of the Long Range Plan. Increasing conductor size can correct voltage drop, but the cost is much
higher than adding capacitors or regulators.
At the end of the Long Range Plan, there are no
cascading regulators.
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V. LONG RANGE PLAN
Page V - 7
Table 5-1 below lists the expected seasonal peak load for each service area at the end of the planning
period (after anticipated load transfers).
TABLE 5-1: SERVICE AREA LOAD SUMMARY
(2020 Long Range Plan)
Substation
Calculated
Load (kVA)
1. Ackerly
2. Ashmore
3. Brownfield
4. Central
5. Claudow
6. Clauene
7. Dixon
8. Doc Webber
9. Draw
10. Florey
11. Foster
12. Gail
13. Hackberry
14. Jess Smith
15. Key-Mesa
16. Lakeadow
7,689
5,219
7,403
3,614
9,557
9,676
7,358
7,683
4,849
4,880
7,260
2,829
6,386
6,778
9,138
7,316
17. Lakeview
7,102
18. Levelland
19. McConal
4,362
8,911
20. Meadow
9,318
Substation
21. New Home
22. New Moore
23. North Arvana
24. NW Lamesa
25. Patricia
26. Plains
27. Pleasant Hill
28. Punk-Welch
29. Sawyer Flat
30. Seagraves
31. Sea-Hill
32. Semino-Conal
33. Seminole
34. Sundown
35. Tokio
36. Tokio-Brown
37. Two Draw
38. Wellman
39. Wilson
F
TOTAL
Calculated
Load (kVA)
7,356
9,784
6,795
5,366
7,715
8,489
7,384
6,548
5,076
9,380
8,268
7,254
4,880
7,939
6,916
7,213
3,620
2,021
4,813
264,145
RED indicates a new substation
2.
Conclusions
Basic conclusions derived through long-range analysis of the system proved to be neither
revolutionary nor surprising.
Facilities outlined for construction or enhancement during the
planning period generally follow patterns that had been anticipated by the LEC staff and the
engineer.
a.
Power Supply
Twenty-nine out of thirty-one existing power supply locations are expected to remain in use for the
foreseeable future, with the exception of Ropes and the Prentice metering point. These are planned
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V. LONG RANGE PLAN
Page V - 8
to be eliminated in the first transition period. During the first transition, three new sources will be
placed into service from the 138 kV ONCOR line. One will be northwest of the current Key metering
point and one north and one south of the current West Lamesa/Dawson metering point.
Transmission line will be built to accommodate these new substations (Patricia and Northwest
Lamesa). Eventually this same tap will supply the Punk-Welsh and North Arvana Substations as well.
Table 5-2 shows the nominal voltage and capacity as well as the normal peak load conditions at each
recommended source location by the end of the planning period.
TABLE 5-2: FUTURE POWER SOURCES
(2020 Long Range Plan)
Voltage
Substation
Ackerly
(LL kV)
Voltage
(kVA)
Substation
(LL kV)
(kVA)
7,635
Arvana
69-7.2/12.47
MP
Ashmore
Brownfield
69-7.2/12.47
69-7.2/12.47
North Lamesa
Plains
Central
Clauene
69-7.2/12.47
115-7.2/12.47
5,828
7,414
3,618
Prentice
Dixon
69-7.2/12.47
9,676
7,372
Doc Webber
Draw
69-7.2/12.47
69-7.2/12.47
7,674
Punkin Center
Ropes
4,853
Sawyer Flat
69-7.2/12.47
69-7.2/12.47
0
4,865
Florey
69-7.2/12.47
3,317
Seagraves
69-7.2/12.47
Foster
69-7.2/12.47
7,354
Seminole
69-7.2/12.47
9,553
4,872
Gail
Hackberry
138-7.2/12.47
69-7.2/12.47
2,785
6,378
MP
69-7.2/12.47
Jess Smith
Key
69-7.2/12.47
6,778
South Lamesa
Sundown
Tokio
69-7.2/12.47
0
7,938
6,928
0
7,102
Two Draw
69-7.2/12.47
3,612
Lakeview
MP
69-7.2/12.47
Levelland
115-7.2/12.47
4,405
Wellman
69-7.2/12.47
2,018
McConal
Meadow
69-7.2/12.47
69-7.2/12.47
9,385
9,335
West Lamesa
Wilson
MP
69-7.2/12.47
0
4,816
New Subs (15t Transition)
Claudow
115-7.2/12.47
Key-Mesa
138-7.2/12.47
NW LaMesa
138-7.2/12.47
Patricia
138-7.2/12.47
9,553
9,190
5,418
7,716
New Subs (2"d Transition)
Lakeadow
69-7.2/12.47
North Arvana
138-7.2/12.47
Punk-Welch
138-7.2/12.47
Sea-Hill
69-7.2/12.47
6,795
6,667
8,289
Tokio-Brown
7,214
Semino Conal
6,804
69-7.2/12.47
0
New Home
New Moore
Pleasant Hill
Welch
69-7.2/12.47
69-7.2/12.47
MP
7,354
9,784
115-7.2/12.47
0
8,522
115-7.2/12.47
MP
7,383
0
MP
MP
69-7.2/12.47
0
0
7,318
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V. LONG RANGE PLAN
Page V - 9
b. Transmission
Table 5-3 summarizes the rated capacity of each future LEC transmission line segment in relation to
the maximum load that the line segment might experience during predicted peak load periods in
2020.
TABLE 5-3: FUTURE TRANSMISSION CAPACITY
(2020 Long Range Plan)
Source Voltage
115 kV
115 kV
69 kV
69 kV
69 kV
69 kV
69 kV
69 kV
69 kV
69 kV
69 kV
69 kV
115 kV
115 kV
69 kV
69 kV
138 kV
Substation(s) on same line
Clauene
Claudow (future substation)
Meadow
Lakeadow (future substation)
Lakeview
New Home
Wilson
Draw
New Moore
McConal
Seminole
Semino-Conal ( future substation)
Sea-Hill (future substation)
Tokio-Brown (future substation)
Florey
Foster
South Source 5 new subs total *
Capacity
14.20%
14.00%
60.10%
17.90%
25.80%
48.30%
17.30%
17.40%
35.40%
51.60%
12.00%
17.80%
12.10%
10.60%
8.10%
17.80%
22.90%
Analysis
Size
Adequate
Adequate
Inadequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
1/0 ACSR
4/0 ACSR
1/0 ACSR
4/0 ACSR
1/0 ACSR
1/0 ACSR
1/0 ACSR
1/0 ACSR
1/0 ACSR
4/0 ACSR
4/0 ACSR
4/0 ACSR
4/0 ACSR
4/0 ACSR
4/0 ACSR
4/0 ACSR
4/0 ACSR
'3 on one line, 1 each on others
Analysis of LEC transmission system voltage is based on delivery of at least nominal voltage (listed
above) at each source point. One concern is the 1/0 ACSR line leading to Meadow, should the new
Lakeadow substation be constructed in series on the existing 1/0 ACSR radial line.
At the end of the long range plan, should the 1/0 ACSR segment be connected to the Meadow
substation, it is expected to reach near 60% capacity, culminating is significantly higher losses. For
this reason, it is recommended that the line segment leading into Meadow be converted from 1/0
ACSR to 477 MCM ACSR at the time that the Lakeadow substation is constructed.
However, if Lakeadow were to be connected to Lakeview instead of Meadow, the 1/0 ACSR leading
to Lakeview could reach an estimated 52% capacity at the end of the Long Range Plan and face
fewer losses. Should Lakeadow be connected to both Meadow and Lakeview, creating a looped
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V. LONG RANGE PLAN
Page V-10
system, then conversion of both feeder lines would not be necessary as each line segment in
question would reach an estimated 40% capacity.
Therefore, at the end of the first transition period, the capacity of the Meadow and Lakeview
substations, and their growth, should be re-evaluated in order to determine which supply feeder has
the least capacity and the most economical way to connect the new Lakeadow substation to that
supply line.
By the end of the long range plan, the radial 1/0 ACSR, feeding both Wilson and New Home, will be
close to the point of needing to be converted due to loading approaching 50%.
Below Table 5-4 summarizes the results of analysis of the long-range LEC system based on expected
peak load levels of 2020. Delivered voltage is indicated on the primary side of power transformers
(before correction by no-load taps or voltage-regulators). These values do not address loss of power
to a substation because a radial transmission facility becomes inoperable.
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Page V-11
V. LONG RANGE PLAN
TABLE 5-4: FUTURE TRANSMISSION VOLTAGE ADEQUACY
(2020 Long Range Plan)
Substation(s) on same line
voltage Analysis
Per Unit
Meadow
Foster
Lakeview
New Home, Wilson
New Home
Wilson
Florey
Draw
New Moore
Seminole
Claudow
Semino-Conal
Patricia
NW Lamesa, Punk-Welch, N. Arvana
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
Adequate
98.4%
99.7%
98.6%
98.0%
97.7%
97.2%
99.9%
98.8%
97.6%
98.9%
99.8%
98.9%
99.8%
99.7%
Punk-Welch, North Arvana
Adequate
99.6%
Adequate
Adequate
Adequate
Adequate
Adequate
Items in red indicate new facilities
99.5%
99.5%
99.8%
97.0%
96.6%
Punk-Welch
North Arvana
Sea-Hill
Meadow, Lakeadow
Lakeadow
Table 5-4 illustrates that the future transmission system should be capable of delivering adequate
voltage to all substations during periods of peak load without supplying excessive voltage during
minimum load periods. Substation voltage regulators should be capable of raising delivered voltage
to a level five percent above nominal.
c.
Interchanges
LEC owns no transmission-voltage interchanges. ONCOR and Xcel are expected to provide adequate
interchange capacity to serve LEC loads throughout the planning period.
d.
Substations
The following table lists the operating and future substations and the number of feeders each
station utilizes. During the long range planning period, ten new substations are added while eight
meeting points are removed. By the end of the second transition, a total of 17 additional circuits
will be in operation.
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Page V - 12
V. LONG RANGE PLAN
TABLE 5-5: SUBSTATIONS AND FEEDERS
(Relative to Growing Load)
Number of Circuits
Number of Circuits
Substation Name
Existing
Ackerly
4
1st Transition
Substation Name
Existing
2nd Transition
1st Transition
2nd Transition
3
3
Sundown
3
3
3
Tokio
5
5
5
Ashmore
3
3
3
Brownfield
4
4
4
Two Draw
2
2
2
Central
2
2
2
Wellman
2
2
2
6
6
Wilson
3
3
3
Clauene
6
Dixon
3
3
3
Arvana
2
2
0
Doc Webber
4
4
4
Key
4
0
0
3
4
North Lamesa
2
0
0
Draw
3
Florey
2
2
2
Prentice
1
0
0
Foster
4
4
4
Punkin Center
3
3
0
South Lamesa
2
0
0
1
Gail
1
1
Hackberry
4
4
5
Welch
2
2
0
Jess Smith
4
4
4
West Lamesa
5
0
0
Lakeview
4
4
4
Claudow
0
4
4
Levelland
4
4
4
Key-Mesa
0
4
4
McConal
4
4
4
Lakeadow
0
0
3
4
Meadow
4
4
5
N. Arvana
0
0
New Home
4
4
4
NW LaMesa
0
3
3
New Moore
3
3
3
Patricia
0
4
4
Plains
4
4
4
Punk-Welch
0
0
3
Pleasant Hill
3
3
3
Sea-Hill
0
0
4
Sawyer Flat
3
3
3
Semino-Conal
0
0
3
Seagraves
5
5
5
Tokio-Brown
Seminole
3
3
3
Total:
0
4
4
121
125
138
Circuit changes shown in red
A table of future LEC substations follows. The rated capacity and the highest predicted peak load of
each substation are listed to illustrate the adequacy of future power transformers.
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V. LONG RANGE PLAN
Page V-13
TABLE 5-6: FUTURE SUBSTATION ADEQUACY
(2020 Long Range Plan)
Capacity (kVA)
55° C Rise
Substation
Ackerly
Arvana
Ashmore
Brownfield
Central
Clauene
Dixon
Doc Webber
Draw
Florey
Foster
Gail
Hackberry
Jess Smith
Key
Lakeview
Levelland
McConal
Meadow
New Home
New Moore
North Lamesa
Plains
Pleasant Hill
Prentice
Punkin Center
Ropes
Sawyer Flat
Seagraves
Seminole
Voltage
(LL
kV)
69-7.2/12.47
MP
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
115-7.2/12.47
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
138-7.2/12.47
69-7.2/12.47
69-7.2/12.47
MP
69-7.2/12.47
115-7.2/12.47
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
MP
115-7.2/12.47
115-7.2/12.47
MP
MP
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
South Lamesa
MP
Sundown
Tokio
Two Draw
Welch
Wellman
West Lamesa
Wilson
69-7.2/12.47
69-7.2/12.47
69-7.2/12.47
MP
69-7.2/12.47
MP
69-7.2/12.47
Base OA
7,500
MP
10,000
7,500
5,000
10,000
7,500
7,500
5,000
5,000
10,000
7,500
7,500
7,500
MP
7,500
10,000
10,000
10,000
7,500
10,000
MP
10,000
10,000
MP
MP
1,000
7,500
10,000
7,500
MP
Maximum
with Fans
9,375
MP
12,500
9,375
6,250
12,500
9,375
9,375
6,250
6,250
12,500
9,375
9,375
9,375
MP
9,375
12,500
12,500
12,500
9,375
12,500
MP
12,500
12,500
MP
MP
1,250
9,375
12,500
9,375
MP
Peak Load
Maximum
@ 65° C
Rise
10,500
MP
14,000
10,500
7,000
14,000
10,500
10,500
7,000
7,000
14,000
10,500
10,500
10,500
MP
10,500
14,000
14,000
14,000
10,500
14,000
MP
14,000
14,000
MP
MP
1,400
10,500
14,000
10,500
MP
(kVA)
7,635
0
4,042
7,414
3,618
9,676
7,372
7,674
4,852
3,317
7,355
2,828
6,378
6,778
0
7,102
4,405
9,385
9,336
7,354
8,179
0
8,484
7,382
0
0
0
4,865
9,553
4,872
0
10,000
12,500
14,000
7,938
10,000
12,500
14,000
6,927
5,250
6,563
7,350
3,612
MP
MP
MP
0
5,000
6,250
7,000
2,018
MP
MP
MP
0
7,500
9,375
10,500
4,816
items snown in red indicate new or modified facilities.
Normal %
of
Capacity
101.80%
MP
40.42%
98.85%
72.36%
96.76%
98.29%
102.32%
97.04%
66.34%
73.55%
37.71%
85.04%
90.37%
MP
94.69%
44.05%
93.85%
93.36%
98.05%
81.79%
MP
84.84%
73.82%
MP
MP
0.00%
64.87%
95.53%
64.96%
Emergency
% of
Capacity
72.71%
MP
28.87%
70.61%
51.69%
69.11%
70.21%
73.09%
69.31%
47.39%
52.54%
26.94%
60.74%
64.55%
MP
67.64%
31.46%
67.04%
66.69%
70.04%
58.42%
MP
60.60%
52.73%
MP
MP
0.00%
46.33%
68.24%
46.40%
MP
MP
79.38%
69.27%
68.80%
MP
40.36%
MP
64.21%
56.70%
49.48%
49.14%
MP
28.83%
MP
45.87%
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V. LONG RANGE PLAN
Page V-14
Capacity (kVA)
Peak Load
55° C Rise
Voltage
(LL
Maximum
Normal %
Emergency
Maximum
@ 65° C
of
% of
Capacity
Capacity
kV)
Base OA
with Fans
Rise
(kVA)
Claudow
115-7.2/12.47
10,000
12,500
14,000
9,551
95.51%
68.22%
Key-Mesa
138-7.2/12.47
10,000
12,500
14,000
9,190
91.90%
65.64%
Lakeadow
69-7.2/12.47
10,000
12,500
14,000
7,318
73.18%
52.27%
North Arvana
138-7.2/12.47
10,000
12,500
14,000
6,795
67.95%
48.54%
NW LaMesa
138-7.2/12.47
10,000
12,500
14,000
5,418
54.18%
38.70%
Punk-Welch
138-7.2/12.47
10,000
12,500
14,000
6,667
66.67%
47.62%
Sea-Hill
115-7.2/12.47
10,000
12,500
14,000
8,288
82.88%
59.20%
Semino-Conal
69-7.2/12.47
10,000
12,500
14,000
6,805
68.05%
48.61%
Patricia
138-7.2/12.47
10,000
12,500
14,000
7,715
77.15%
55.11%
Tokio-Brown
115-7.2/12.47
72.18%
51.56%
Substation
e.
10,000
12,500
14,000
7,218
erns snown in rea rnaicate new or moaned tacilities.
New Substations
Ten new LEC substations are to be constructed during the planning period. Five new substations are
to be constructed during the first transition of the planning period, including one new 115-7.2/12.47
kV 10 MVA substation named Claudow. Depending on the availability, reliability, and associated
costs, Claudow could be connected to a 69 kV or 115 kV line as both are equal distance from the
estimated site location.
Other substations include one new 115-7.2/12.47 10 MVA substation
termed Tokio-Brownfield, and three new 138-7.2/12.47 kV 10 MVA substations, currently being
called Key-Mesa, Northwest Lamesa, and Patricia. During the second transition of the planning
period, five more new substations are to be constructed, including two new 69-7.2/12.47 kV 10
MVA substations termed Lakeadow and Semino-Conal; one new 115-7.2/12.47 kV 10 MVA
substation called Sea-Hill, and two new 138-7.2/12.47 kV 10 MVA substations currently termed
North Arvana and Punk-Welch.
The cooperative plans to construct a new 138 kV transmission line to reach three of the substations.
To reach NW Lamesa, North Arvana, and Punk-Welch, approximately 11.5 miles of new 477 MCM
ACSR 138 kV Transmission Line will be built as a requirement for these Substation's operation. Two
future substations are expected to connect to this line, one running north and one east, adding an
additional 15.7 miles. Existing substations are expected to continue to provide power to this region
until the new substations are constructed.
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V. LONG RANGE PLAN
f.
Page V-15
Substation Modifications
The Engineer does not expect that any substation will be modified to change voltage during the
plan. Several LEC substations will undergo an increase in capacity.
Currently, Seminole is awaiting a 7.5 MVA transformer to replace the existing 5.25 MVA
configuration once loads decrease so loads can be back-fed from other substations during the
transition. In the North-Central (Meadow) and South-Central (New Moore) portions of the system,
two substations are expected to require a 10 MVA transformer due to anticipated load growth
and/or possible oil field expansions, replacing the existing 7.5 MVA on site. Once the 7.5 MVA
transformers are replaced, they can then be moved and placed into service at Hackberry and
Wilson, removing the 5 MVA's currently in operation. These can then be moved to Central and
Draw, replacing the 3.75 MVA transformer on site.
At the end of the Long Range Plan, it will be necessary to replace the 7.5 MVA transformer at
Ackerly with a 10 MVA, depending on load growth in the area over the Second Transition period.
g.
Distribution
A number of situations can provide an inducement for modification of the distribution system.
Improvements are usually prompted by losses, delivered voltage or thermal capacity. Only rarely do
thermal capacity considerations affect rural distribution lines.
considerations affect urban distribution lines.
More usually, thermal capacity
Modifications are sometimes prompted by the
condition of facilities. As systems age, their useful life is sometimes approached or exceeded. These
facilities are simply replaced with similar facilities or improved to address other concerns at the
same time.
Seven types of distribution system modifications are planned either to forestall or defer other
investments if possible, or improve the system in the most economic manner commensurate with
providing quality service. These types of modifications include 1) replacing existing facilities, 2)
shifting load between substations or feeders, 3) installing capacitor banks, 4) installing voltage
regulators, 5) increasing conductor size of existing facilities, 6) increasing nominal voltage of
distribution lines and 7) construction of new facilities.
Facilities with foreseen problems are
presented below along with the most justifiable system modification required to forestall problems.
Each substation service area is addressed in alphabetical order.
When capacitor banks are added to maintain proper voltage levels, the proper size and placement
location(s) will need to be verified on an annual basis.
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V. LONG RANGE PLAN
Page V-16
Ackerly Service Area
Other than capacitor and regulator placement, the only improvement for this service area is
anticipated to be the extension of a 1/0 ACSR line eastward to feed the area between Ackerly and
Gail for this Long Range Plan. However, due to the expectation of a new substation to the north, the
service area and load is reduced below the current transformer's OA base rating. The elimination of
one underground circuit is anticipated during the first transition time period. The 25 kV express
feeder to the west will continue to be used.
Over the next ten years, 1,500 kVAR of switched capacitor banks will need to be added to this
service area.
Arvana Service Area
The Arvana metering point is to be eliminated in the second transition of this long range plan.
During the first transition, a new 1/0 tie line is suggested to maintain voltage levels and in
preparation for the second transition. By the second transition period, the cooperative should
construct 0.35 miles of 30 #1/0 ACSR to the southeast to insure better reliability and voltage values
for the region.
Over the next ten years, over 1,300 kVAR of switched capacitor banks will need to be added to this
service area.
Ashmore Service Area
We anticipate that the Ashmore service area will need to be extended eastward slightly in
anticipation of oil load growth in other areas and the future elimination of the Welch metering
point. There are no anticipated line upgrades for this area for this long range plan.
Over the next ten years, 1,600 kVAR of switched capacitor banks will need to be added to this
service area.
Brownfield Service Area
Due to the predicted load growth in the Brownfield service area, it is recommended that LEC
construct a new 115-7.2/12.47 kV, 10 MVA, (Tokio-Brown) substation early in the first transition in
order to solve major load and voltage problems, accommodating current and new load growth in
this area. The Tokio-Brown Substation will relieve load off of the existing 7.5 MVA Brownfield
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V. LONG RANGE PLAN
Page V-17
Substation over 10 miles to the east. (See Tokio-Brown Service Area). Because of the anticipated
new substation, there are no conductor improvements for this area.
During the next ten years, over 1,600 kVAR of switched capacitor banks needs to be added to this
service area.
Central Service Area
Central's service area will need to be extended northward slightly to relieve load from Hackberry.
Due to the characteristics of the load area, it is not expected to experience voltage problems during
this Long Range Planning Period.
We are recommending that 900 kVAR of switched capacitor banks be added in this service area over
the next 10 years.
Clauene Service Area
Because of current load and anticipated load, Clauene is expected to exceed the FA/FA rating of its
transformer.
Because of this, the construction of a new 115-7.2/12.47 kV, 10 MVA substation is
recommended (Claudow) during the first transition period. Due to the new substation relieving load
from Clauene, there are no line upgraded recommended during this long range planning period.
We are recommending that 2,700 kVAR of switched capacitor banks be added in this service area.
Dixon Service Area
Over the next ten years, it is expected that the Dixon service area will not change during this Long
Range Planning Period. The conversion of 1.5 miles of #4 ACSR to 4/0 in the southern region is
suggested to support future load and reduce losses. We are recommending that 1,200 kVAR of
switched capacitor banks be added in this service area.
Doc Webber Service Area
The Doc Webber service area is not expected to grow beyond the capacity of the current
transformer so no changes are recommended for this area. However, to better facilitate the
location of load growth, a new 0.27 mile, 1/0 ACSR tie line is suggested at the end of line to maintain
proper voltage and provide equal division of delivered power from the west and south circuits
during this Long Range Planning Period.
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V. LONG RANGE PLAN
Page V-18
We are recommending that approximately 2,400 kVAR of switched capacitor banks be added in this
service area.
Draw Service Area
Due to anticipated load growth over the next ten years, it is suggested that Hackberry's 5 MVA
transformer be moved to the Draw substation during the first transition period. It is also suggested
that another circuit (south) be added. This new 4.14 mile circuit will be 4/0 ACSR and added to feed
the southwest portion of the service area.
The current south feeder is expected to experience voltage and load problems during this Long
Range Planning Period. Approximately 4 miles of 10 #4 ACSR will need to be converted to 30 477
MCM ACSR and a new 0.52 mile 477 MCM ACSR tie line added.
We are recommending that 2,900 kVAR of switched capacitor banks be added in this service area.
Florey Service Area
Load growth in the Florey service area will facilitate the need for a larger transformer near the end
of the long range planning period. (The transformer from either Wilson or Hackberry is suggested.)
During the second transition period, a substation is suggested to be added northeast of Florey. This
new 69-7.2/12.47 kV, 10 MVA substation (Semio-Conal) will relieve some of the growing load by the
reduction in service area served by Florey.
We are recommending that 900 kVAR of switched capacitor banks be added in this service area over
the next ten years.
Foster Service Area
Few changes are anticipated for the Foster service area. To the north, it is suggested that Foster
expand its service area and relieve Jess Smith of approximately 500 kW during this Long Range
Planning Period. We are recommending that 750 kVAR of switched capacitor banks be added.
Gail Service Area
Over the next ten years, it is anticipated that only the relocation of a regulator and one 600 kVAR
capacitor be performed for the Gail service area during this Long Range Planning Period.
We are recommending that 300 kVAR of switched capacitor banks should be added.
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V. LONG RANGE PLAN
Page V-19
Hackberry Service Area
For the Hackberry service area, load is expected to exceed the OA base rating by the end of the first
transition time period, even after the reduction in area served. Both Central and Two Draw will
assume some of the service area from Hackberry to keep from exceeding the FA rating and possibly
damaging the transformer. By the end of the first transition period, a 7.5 MVA transformer (from
either New Moore or Meadow) will need to replace the existing 5 MVA transformer. It is also
recommended that a fifth circuit be added. This 4/0 ACSR circuit is dedicated to the plant located
0.25 miles west of the substation.
No conductor upgrades are anticipated for this service area.
We are recommending that 1,500
kVAR of switched capacitor banks be added. A single 1,800 kVAR capacitor is suggested to be placed
at the plant when the new circuit is added.
Jess Smith Service Area
There is little in way of improvements for the Jess Smith service area other than a slight reduction in
service area to Foster during this Long Range Planning Period.
We are recommending that 1,200 kVAR of switched capacitor banks be added in this service area
over the next ten years.
Key Service Area
This metering point is planned to be eliminated during the first transition time period and replaced
by the Key-Mesa, 10 MVA substation. (See Key-Mesa below)
Lakeview Service Area
The Lakeview service area is expected to exceed the FA rating on the in-place (7.5 MVA) transformer
by the end of the ten-year, long range planning period. However, a new 69-7.2/12.47 kV, 10 MVA
substation (Lakeadow) is suggested during the second transition period. This new substation will
reduce the load on the Lakeview transformer to under the OA base rating.
We are recommending that 1,500 kVAR of switched capacitor banks be added in this service area.
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V. LONG RANGE PLAN
Page V - 20
Levelland Service Area
The Levelland service area is not expected to experience any load or distribution difficulties over the
long range planning period. However, to maintain proper voltage and improve the power factor, we
are recommending the addition of 900 kVAR of switched capacitor banks be added.
McConal Service Area
No significant upgrades are suggested for the McConal service area for this long range plan. It is
anticipated that the load will exceed the FA rating of the on-site transformer nearing the end of the
long range plan. However, a new 69-7.2/12.47 kV, 10 MVA substation (Semino-Conal) is anticipated
during the second transition period, absorbing a significant amount of the McConal load and some
load from both Seminole and Florey to help maintain their voltage levels and eliminate necessary
upgrades, should the new substation not be constructed.
We are recommending that 1,200 kVAR of switched capacitor banks be added in this service area.
Meadow Service Area
Because of significant load growth in and around the Meadow service area, several changes are
planned. During the end of the First Transition period, line conversions are expected as the Ropes
substation will be eliminated and picked up by Meadow. These conversions consist of adding a
three mile 1/0 ACSR circuit to the north to carry load to the north west service area, converting a #2
ACSR to 4/0 ACSR to aid in load distribution to the Ropes area, and upgrading from 1/0 ACSR to 477
MCM ACSR for 1.7 miles to the west to maintain voltage levels and significantly reduce losses on this
circuit.
Once the new 69-7.2/12.47 kV, 10 MVA substation (Lakeadow) is constructed during the second
transition, Meadow's service area will reduce slightly but will still need to be increased to a 10 MVA
transformer due to anticipated load growth.
We are recommending that 1,600 kVAR of switched capacitor banks be added in this service area.
New Home Service Area
There are few expected changes to the New Home service area other than a slight increase to the
southeast, absorbing load from Wilson.
We are recommending that 2,100 kVAR of switched capacitor banks be added.
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V. LONG RANGE PLAN
Page V - 21
New Moore Service Area
Due to the large capacity on the east circuit from the New More service area, 5.15 miles of 1/0 ACSR
will need to be converted to 477 MCM ACSR to reduce losses and maintain voltage. From the east
circuit, there is a 10 #4 ACSR line to the north that will need to be converted to 30 1/0 ACSR for 3.8
miles to maintain proper voltage. There is also an expected oil load growth potential on the
southern part of this circuit that could exceed 2.0 MVA. Should this oil load develop, two other
conversions will be necessary to maintain proper power delivery. A 10 #4 ACSR line to the south
will need to be upgraded to 30 1/0 ACSR, and a 1/0 ACSR tie line will need to be constructed to the
west to divide the load more evenly.
Due to its large area, we are recommending that 2,200 kVAR of switched capacitor banks be added
in this service area.
North Lamesa Service Area
This metering point is planned to be eliminated during the second transition time period and
replaced by the North Arvana, 10 MVA substation. (See North Arvana below). Until that time, we
are recommending that 600 kVAR of switched capacitor banks be added.
Plains Service Area
Load in the southwest region of the Plains service area is expected to cause voltage problems in the
long range planning period. To alleviate this, 2 miles of 4/0 ACSR, built from an existing western
circuit, will run south to meet existing lines. From there, 4 miles of #2 ACSR will need to be
converted to 4/0 ACSR to meet and carry load to the southern service area.
We are recommending that 2,800 kVAR of switched capacitor banks be added.
Pleasant Hill Service Area
The only conductor conversion for the Pleasant Hill service area during the first transition period, is
converting a 10 #4 ACSR to 30 1/0 ACSR to help balance load on the western circuit, and better
maintain proper voltage. During the second transition, a new 115-7.2/12.47 kV, 10 MVA substation
(Sea-Hill) is to be constructed to the west of Pleasant Hill and redirect some of the increasing load.
We are recommending that 2,600 kVAR of switched capacitor banks be added in this service area.
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V. LONG RANGE PLAN
Page V - 22
Prentice Service Area
Due to its small size, the Prentice metering point will be absorbed by the Tokio substation during the
first transition period.
Punkin Center Service Area
This metering point is planned to be eliminated during the second transition time period and
replaced by the Punk-Welch, 138-7.2/12.47 kV, 10 MVA, substation. (See Punk-Welch below). Until
that time, we are recommending that 300 kVAR of switched capacitor banks be added in this service
area.
Ropes Service Area
This 1 MVA substation is planned to be eliminated during the first transition period of the long range
plan and its load absorbed by the Meadow service area. (See Meadow above). Until then, we are
recommending that 300 kVAR of switched capacitor banks be added.
Sawyer Flat Service Area
The only estimated changes to the Sawyer Flat service area during the long range plan is a slight
increase in service area to the north.
We are recommending that 600 kVAR of switched capacitor banks be added.
Seagraves Service Area
For the Seagraves service area, the expected load of the long range plan will exceed the FA rating on
the transformer. For this reason, a new substation (Sea-Hill) will be constructed to the north during
the second transition period. This new 10 MVA substation causes the service area of Seagraves to
diminish in the north. The existing 25 kV express feeder to the south will continue to be utilized, as
nearly 30% of the total load is served by this line. One underground circuit to the west can be taken
out of service.
During the long range planning period, we are recommending that 1,200 kVAR of switched capacitor
banks be added.
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V. LONG RANGE PLAN
Page V - 23
Seminole Service Area
A 7.5 MVA transformer will replace Seminole's existing 3-1.75 MVA (5.25 MVA total) transformers
once the summer peak loading has diminished. Even with this larger transformer, no line
conversions are recommended in this long range plan. To improve the service area even more, a
new substation is expected (Semino-Conal) during the second transition period.
We are recommending that 2,400 kVAR of switched capacitor banks be added.
South Lamesa Service Area
This metering point is planned to be eliminated during the first transition time period of the long
range plan and replaced by the Key-Mesa, 138-7.2/12.47 kV, 10 MVA, substation. (See Key-Mesa
below).
Sundown Service Area
The Sundown service area is expected to experience voltage problems on the north circuit during
this Long Range Planning Period. To alleviate this, 0.78 miles of the 1/0 ACSR line to the north is to
be converted to 477 MCM ACSR during the second transition period as over 35% of the total
estimated load will be served by this circuit.
We recommend that 1,200 kVAR of switched capacitor banks be added.
Tokio Service Area
Due to the predicted load growth in the Tokio service area, it is recommended that LEC construct a
new 115-7.2/12.47 kV, 10 MVA, (Tokio-Brown) substation early in the first transition in order to
solve major load and voltage problems, based on current and new load growth in this area. The
Tokio-Brown Substation will relieve load off of the existing 10 MVA transformer over 8 miles to the
west. (See Tokio-Brown Service Area). Because of the anticipated new substation, there are no
conductor improvements for this area. However, the load on circuit 2 (west and northwest) will
need to be switched over to circuit 5 (4/0 ACSR line) at the point of intersection to alleviate voltage
issues. This can be done at the start of the second transition period.
We are recommending that 2,200 kVAR of switched capacitor banks be added in this service area.
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V. LONG RANGE PLAN
Page V - 24
Two DrawService Area
There are few changes to the Two Draw service area over the duration of the current long range
plan.
We are recommending that 900 kVAR of switched capacitor banks be added in this service area.
Welch Service Area
This metering point is planned to be eliminated during the second transition time period and
replaced by the Punk-Welch, 138-7.2/12.47 kV, 10 MVA, substation. (See Punk-Welch below). Until
that time, we are recommending that 600 kVAR of switched capacitor banks be added in this service
area.
Wellman Service Area
There are few changes to the Wellman service area over the duration of the current long range plan.
We are recommending that 600 kVAR of switched capacitor banks be added in this service area.
Wilson Service Area
There are few changes to the Wellman service area over the duration of the current long range plan.
This service area will increase slightly in the northeast as load is taken from Hackberry to facilitate
the change-out of its transformer at the end of the first transition period.
We are recommending that 900 kVAR of switched capacitor banks be added in this service area y.
NEW SUBSTATION SERVICE AREAS
Claudow Service Area
During the first transition period, it is recommended that a substation between Clauene and
Meadow be constructed to alleviate the rapidly increasing load. This new 115-7.2/12.47 kV, 10
MVA, substation should be located to the northeast of Clauene and tap into an existing 115 kV line
that is 4.8 miles to the west. Because of the location of this new substation, conductors to the
north, east, and south will need to be converted to enable better power delivery.
To the north, 1.26 miles of #2 ACSR will need to be converted to 4/0 ACSR out of the substation.
The east circuit will need to be converted from #2 ACSR to 477 MCM ACSR for 1.45 miles starting at
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V. LONG RANGE PLAN
Page V - 25
the substation. The last change to the new Claudow service area is a new 1/0 tie line to the south to
better divide and deliver power to the southern area.
We are recommending that 3,100 kVAR of switched capacitor banks be added in this new service
area over the next ten years.
Key-Mesa Service Area
During the first transition period, it is recommended that a new 138-7.2/12.47 kV, 10 MVA,
substation be constructed to eliminate two metering points. This new substation will be located
between Key and South Lamesa, just 0.25 miles south of an existing 138 kV transmission line.
Line conversions to the east and west must also be done with the new substation to service this
large area. The first conversion will be 3.43 miles west, changing from 1/0 ACSR to 477 MCM ACSR,
from the substation. The second conversion will be on the southeast circuit, 4.45 miles east out of
the substation, changing #2 ACSR and #4 ACSR to 4/0 ACSR.
We are recommending that 2,700 kVAR of switched capacitor banks be added in this service area.
Lakeadow Service Area
During the second transition period, it is recommended that a new 69-7.2/12.47 kV, 10 MVA,
substation be constructed to eliminate the increasing loads at Lakeview and Meadow. This new
Ladeadow substation will be located 5 miles east of Meadow. To do this, 5.1 miles of 69 kV
transmission line will need to be constructed out of Meadow. Along with this new substation, 2.56
miles of #4 ACSR will need to be converted to 477 MCM ACSR, south out of the substation. Another
0.65 miles of #4 ACSR will need to be converted to 4/0 ACSR and 0.3 miles of new 4/0 ACSR tie line,
extending south from the 477 line.
We are recommending that 1,800 kVAR of switched capacitor banks be added.
North Arvana Service Area
During the second transition period, it is recommended that a new 138-7.2/12.47 kV, 10 MVA,
substation be constructed to eliminate two metering points. This new substation will be located
between North Lamesa and Arvana, approximately 1.32 miles east of the existing North Lamesa
substation. To get power to this location, 5.6 miles of 138 kV (or 10.9 miles of 115 kV) transmission
will need to be constructed. Because of its central location to the service area, 3.2 miles of 4/0 ACSR
will need to be constructed to the west to better serve the load previously served by the Arvana
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V. LONG RANGE PLAN
Page V - 26
metering point. There would also be an additional 0.6 miles of conversion from #4 ACSR to 4/0
ACSR on this same circuit.
Once the substation is constructed, we recommend that 900 kVAR of switched capacitor banks be
added.
Northwest Lamesa Service Area
During the first transition period, it is recommended that two new 138-7.2/12.47 kV, 10 MVA,
substations be constructed to eliminate the West Lamesa metering point. The northern substation
will be located 1.96 miles northwest of the existing West Lamesa metering point. To supply power
to this substation, 4.62 miles of 138 kV transmission line will need to be constructed from a tap
point located 2.63 miles south of the existing West Lamesa metering point. The previous 25 kV
express feeder will no longer be needed for this service area.
We are recommending that 2,700 kVAR of switched capacitor banks be added in this service area.
Punk-Welch Service Area
During the second transition period, it is recommended that a new 138-7.2/12.47 kV, 10 MVA,
substation be constructed to eliminate two metering points. This new substation will be located
between Punkin Center and Welch, approximately 5 miles south of the existing Welch substation.
To get power to this location, 9.1 miles of 138 kV (or 8.2 miles of 115 kV) transmission line will need
to be constructed. Because of its central location to the service area, 3.2 miles of 4/0 ACSR will need
to be constructed to the west to better serve the load previously served by the Arvana metering
point. There would also be an additional 0.6 miles of conversion from #4 ACSR to 4/0 ACSR on this
same circuit.
Once the new substation is constructed, we are recommending that 900 kVAR of switched capacitor
banks be added in this service area.
Sea-Hill Service Area
During the second transition period, it is recommended that a new 115-7.2/12.47 kV, 10 MVA,
substation be constructed to reduce the load at two other substations. This new substation will be
located between Seagraves and Pleasant Hill, approximately 5 miles west of the existing Pleasant
Hill substation. To get power to this location, approximately 3.2 miles of 115 kV transmission line
will need to be constructed. Because of its central location to this new service area, there are two
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V. LONG RANGE PLAN
Page V - 27
recommended line conversions that need to be completed. The first conversion begins at the new
substation and proceeds 2.12 miles west; # 4 ACSR will need to be converted to 477 MCM ACSR. At
the end of the previous conversion, the continued #4 ACSR will need to be changed to 4/0 ACSR
south and west for 3.0 miles.
During the first transition period, we are recommending that 1,200 kVAR of switched capacitor
banks be added. During the second transition period, after the completion of Sea-Hill substation,
we are recommending that an additional 1,600 kVAR of switched capacitor banks be added in this
new service area.
Semino-Conal Service Area
During the second transition period, it is recommended that a new 169-7.2/12.47 kV, 10 MVA,
substation be constructed to reduce the load at two other substations. This new substation will be
located between Seminole and McConal, approximately 3.2 miles southwest of the existing McConal
substation. To get power to this location, approximately 6 miles of 69 kV transmission line (3 miles
west and 3 miles south from McConal) will need to be constructed.
There are three recommended line conversions that need to be completed. The first conversion
begins at the new substation and proceeds 2.55 miles west; the existing # 4 ACSR will need to be
converted to 477 MCM ACSR to accommodate a large load to the west. At the end of the previous
conversion, the continued #4 ACSR will need to be changed to 4/0 ACSR farther west for another 2.5
miles. The third conversion is located south of the new substation and begins at the end of the 1/0
ACSR line. 1.33 miles of #4 ACSR will need to be converted to 4/0 ACSR because of load and low
voltage issues.
During the first transition period, we are recommending that 900 kVAR of switched capacitor banks
be added in this service area and an additional 600 kVAR of switched capacitor banks during the
second transition period.
Patricia Service Area
During the first transition period, it is recommended that two new 138-7.2/12.47 kV, 10 MVA,
substations be constructed to eliminate the West Lamesa metering point. Patricia, the southern
substation, will be located 4.12 miles south of the existing West Lamesa metering point. To supply
power to this substation, 6.85 miles of 138 kV transmission line will need to be constructed from a
single tap point located 2.63 miles south of the existing West Lamesa metering point.
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V. LONG RANGE PLAN
There are two line upgrades that must also be completed.
Page V - 28
The first is converting the existing #2
ACSR to 477 MCM ACSR starting at the Patricia substation and proceeding 7.11 miles west. The
second conversion begins at the end of the 477 line, converting the #2 ACSR to 4/0 ACSR for another
2.05 miles.
During the first transition period, we are recommending that 3,300 kVAR of switched capacitor
banks be added with an additional 2,500 kVAR be added over the second transition period.
Tokio-Brownfield Service Area
During the first transition period, it is recommended that a substation between Tokio and
Brownfield be constructed to alleviate the rapidly increasing load in the area. This new 1157.2/12.47 kV, 10 MVA, substation should be located 10 miles to the west of Brownfield and tap into
an existing 115 kV line that is 0.5 miles to the north. Conductors to the south will need to be
converted to enable better power delivery to the southeast.
The first change is the conversion of the #4 ACSR line to 477 MCM ACSR, south out of the substation
for 1.25 miles. Beginning from there, the #4 ACSR should be converted to 4/0 ACSR for another 4
miles. At that point, a new 4/0 ACSR tie line should run south, 0.55 miles, to meet an existing line.
During the first transition period, we are recommending that 1,900 kVAR of switched capacitor
banks be added and an additional 1,100 kVAR of switched capacitor banks be added later.
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VI. TRANSITION PLANS
Page VI - I
The information presented herein is provided as a recapitulation of the system improvements
presented previously. Transition plans are used to illustrate major steps in system improvement.
Planned development of the system is separated into three transition periods. Each improvement,
although designated by time frame (years), should be treated as facility development related to
peak load.
Improvements and associated investments indicated herein are usually deferred.
However, deferring system improvements beyond the magnitude of load with which the
improvement is correlated will cause an increase in system losses and cause a compromise of
system reliability.
As time passes, load growth rates different from those projected will become apparent in various
parts of the system. Improvements planned for a particular area will become necessary earlier than
foreseen if unexpected growth occurs. Conversely, improvements planned for a particular area can
be deferred longer than anticipated if growth does not occur as rapidly as expected. As stated
above, the transition plans and facilities indicated therein should be construed as viable under
actual load conditions, not necessarily by reference time frames.
A.
First Transition 2011 - 2015
The First Transition was developed to address system requirements during the four-year period,
2011 through 2014. Table 6-1, below, indicates annual investments expected during the First
Transition period.
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Page VI - 2
TABLE 6-1: PROJECTED ANNUAL INVESTMENTS
First Transition 2011 - 2014
Investment Description
Distribution Facilities
New Member Line Extensions
Total
$10,618,272
System Improvements
New Tie Lines
Line Conv. & Changes
$307,500
$2,204,800
Substations
New Stations
Power Transformers
$6,000,000
$640,000
Subtotal (Substations)
$6,640,000
Misc. Distr. Equipment
Transformers/Meters
Service Wire Sets
Security Lights
Sectionalizing Equip.
SCADA
Voltage Regulators
Capacitors
Subtotal (Misc. Distr. Equip.)
Ordinary Replacements
Subtotal Distribution
$13,899,318
$345,094
$318,548
$1,061,827
$1,061,827
$546,000
$895,000
$18,127,614
$4,884,405
$42,782,590
Transmission Facilities
New Line
New Station
Ordinary Replacements
$1,349,400
$2,000,000
$318,548
Subtotal Transmission
$3,667,948
Grand Total
$46,450,539
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VI. TRANSITION PLANS
1.
Page VI - 3
Transmission System
Several improvement to the transmission system serving the LEC system is scheduled for completion
during the First Transition period. The cooperative plans to construct five new substations. Two
new 115-7.2/12.47 kV 10 MVA substations named Claudow and Tokio-Brown, and three new 1387.2/12.47 kV 10 MVA substations, titled Key-Mesa, Northwest Lamesa, and Patricia (2013) in order
to solve major voltage problems and accommodate new growth in these areas.
The Claudow substation will relieve load off of two existing substations, Clauene (115-24.94/14.4 kV
10 MVA) and Meadow (69-24.94/14.4 kV 7.5 MVA). To accomplish this, approximately 4.8 miles of
new 477 MCM ACSR 115 kV Transmission Line, from the Clauene substation, will be built as a
requirement for this Substation's construction.
The Tokio-Brown substation will relieve load off of two existing substations, Tokio (69-24.94/14.4 kV
10 MVA) and Brownfield (69-24.94/14.4 kV 7.5 MVA). To accomplish this, approximately 0.5 miles
of new 477 MCM ACSR 115 kV Transmission Line will be built as a requirement for this Substation's
construction.
A third substation, Key-Mesa (138-24.94/14.4 kV 10 MVA), eliminating two metering points, will be
located within close proximity to an existing 138 kV transmission line, and need less than 0.25 miles
of 477 MCM ASCR tap line. This substation will relieve load off of two existing metering points, Key
and South Lamesa The new 477 MCM ACSR 115 kV Transmission Line will be built as a requirement
for this Substation's construction.
The final transmission improvement during the Frist Transition, is located in the southern portion of
the LEC service area. A single tap from a 138 kV transmission line will feed two new 10 MVA
substations eliminating the West Lamesa metering point. Patricia (138-24.94/14.4 kV 10 MVA) and
Northwest Lamesa (138-24.94/14.4 kV 10 MVA) will be powered from this new line. To accomplish
this, approximately 4.62 miles of new 477 MCM ACSR 138 kV Transmission Line will be built north to
reach Northwest Lamesa, and approximately 6.85 miles of new 477 MCM ACSR 138 kV Transmission
Line will be built south to reach Patricia, as a requirement for these Substation's construction.
Tokio-Brown
Claudow
Key-Mesa
Northwest LaMesa
Patricia
115 kV
115 kV
138 kV
138 kV
138 kV
0.5 miles
4.8 miles
0.2 miles
4.6 miles
6.9 miles
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VI. TRANSITION PLANS
Page VI - 4
Substations
A number of LEC substation investments are expected during the First Transition period to provide
power to the distribution system. During the first five years, it is expected that five new substations
are to be constructed. Also at this time, New Moore and Meadow will need to have their current
7.5 MVA transformer increased to 10 MVA. Once that is completed, the 7.5 MVA transformers can
be placed at Wilson and Hackberry.
Distribution System
During the First Transition period, line voltage regulators are to be installed at selected locations
throughout the system to defer premature investments.
Capacitor banks are to be installed
throughout the system to improve voltage and decrease losses. Eleven major improvement projects
are planned for the distribution system in the First Transition period. The following table lists each
foreseen major distribution line project.
During the First Transition, Hackberry will construct a new 4/0 ACSR circuit to provide power solely
to the industry plant located 0.22 miles to the west of the substation. The Ackerly and Seagraves
substations will each remove one circuit, an underground line, from use during this transition phase.
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Page VI - 5
TABLE 6-2: SYSTEM IMPROVEMENT COST DETAIL
First Transition 2011 - 2014
Project
Circuit
1
Changes/Description
cost
substation
$1,200,000
convert 1.45 miles of #4 to 477
$93,600
2
3
convert 1.26 miles of #2 to 4/0
build 0.75 miles new 1/0 tie
$63,000
$45,000
Meadow
1
convert 0.9 miles of #2 to 4/0
$67,500
Plains
3
convert 3.98 miles of #2 to 4/0
$199,000
build 2.03 miles new 4/0
$101,500
Claudow
substation
Tokio-Brown
Pleasant hill
3
1
1
New Moore
1
$1,200,000
convert 1.24 miles of #4 to 477
$81,200
convert 3.98 miles of #4 to 4/0
$200,000
build 0.55 miles new 4.0
$34,400
convert 2.46 miles of #4 1^ to 1/0 30
$98,400
build 1.03 miles new 1/0 tie
$41,200
new 10 MVA transformer
$600,000
convert 5.15 miles of 1/0 to 477
$334,100
convert 3.5 miles of #4 10 to 1/0 30
$140,000
build 1.81 miles new 1/0 tie*
$72,400
convert 3.8 miles of #4 10 to 1/0 30*
$152,000
substation
Patricia
4
$1,200,000
convert 7.11 miles of 1/0 to 477
$225,000
convert 2.05 miles of 1/0 to 4/0
$102,500
substation
Key-Mesa
Hackberr y
$1,200,000
3
convert 4.45 miles #2 & #4 to 4/0
$225,000
4
convert 3.43 miles of 1/0 to 477
$223,500
5
build 0.13 miles new 4/0 circuit
$13,000
relocation of 7.5 MVA transformer
$20,000
Wilson
relocation of 7.5 MVA transformer
$20,000
NW LaMesa
substation
* oil load dependance; could be done in 2nd transition
$1,200,000
1
$9,152,300 1
Distribution system improvements are prompted by thermal capacity or delivered voltage
considerations. Each improvement has been scheduled based on expected load. The following two
maps illustrate the above system improvements.
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VI. TRANSITION PLANS
Page VI - 8
Ackerly Service Area
During the First Transition period, only the application of capacitors and regulators are expected.
The removal of two 600 kVAR capacitors (Feeder 1 and 4) with one 300 kVAR capacitor being turned
on (Feeder 1). Feeder 3 will need two 300 kVAR capacitors added to it along with the relocation of
the regulator.
Feeder 4 will need two 450 kVAR capacitors placed on it.
No major line
improvements are anticipated to be needed in the Ackerly Service area for this duration of the Long
Range Plan. Capacitor size and proper placement will need to be verified annually.
Arvana Service Area
The Arvana metering point is expected to be eliminated during the Second Transition period, but
during the First Transition, a new 0.35 mile 1/0 ACSR tie line will need to be constructed. This new
line will help to more evenly distribute the current load as well as when the metering point is
eliminated and a new substation is built. It will also help maintain proper power flow and insure
better reliability on the circuit as 750 kVAR and one voltage regulator are added during this time
period.
Ashmore Service Area
During the First Transition period, 450 kVAR of capacitance will need to be added (Feeder 1) and 300
kVAR relocated (from Feeder 1 to Feeder 2) along with the addition of one regulator to Feeder 2 to
maintain proper voltage levels.
Brownfield Service Area
During the First Transition period, two 300 kVAR in capacitors (Feeders 1 and 3) will need to be
added and one 600 kVAR removed (Feeder 3) while one regulator is added to Feeder 1 to maintain
proper voltage levels.
Central Service Area
During the First Transition period, one 300 kVAR capacitor will need to be added and one regulator
relocated to maintain proper voltage levels.
Clauene Service Area
During the First Transition time period, the removal of four large (600 kVAR) capacitors from
Feeders 1, 3, 5, and 6, will precede the application of four 300 kVAR (Feeders 1, 3, 4, and 5) and one
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VI. TRANSITION PLANS
Page VI - 9
450 kVAR capacitor (Feeder 2). Circuits 1 and 5 will also need voltage regulators to maintain proper
voltage levels.
Dixon Service Area
Feeder 1 is not expected to experience voltage problems during this First Transition Period. Feeder 2
will need one 300 kVAR capacitor and one regulator placed. Feeder 3 will need one 600 kVAR capacitor
removed.
Doc Webber Service Area
Feeder 1 is not expected to experience voltage problems during this First Transition Period. However,
one 600 kVAR capacitor will need to be relocated and one 300 kVAR capacitor added. Feeder 2 should
not experience any problems. Feeder 3 will need one 300 kVAR capacitor relocated and a 450 kVAR
capacitor added. Feeder 4 will need a 600 kVAR capacitor removed but a 300 kVAR capacitor added.
Draw Service Area
Feeder 1 is not expected to experience voltage problems during this First Transition Period and would
only require the application of one 150 kVAR capacitor. Feeder 2 will need 750 kVAR added and one
regulator. Circuit three can have both regulators removed. Circuit 4 (new) will need one 300 kVAR
capacitance added to it.
Florey Service Area
Feeder 1 will need to have its regulator relocated and upgraded to 100 Amps along with 300 kVAR
added. Feeder 2 will only need a regulator added during this First Transition Period.
Foster Service Area
Feeders 2, 3, and 4 are not expected to experience voltage problems during this First Transition Period.
Feeder 1 will need one 300 kVAR added.
Gail Service Area
The Gail service area will only need one 600 kVAR capacitor removed or turned off and the current 100
Amp regulator relocated during this First Transition Period.
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Page VI -10
Hackberry Service Area
During this First Transition Period, a fifth feeder, if possible, will need to be added and run exclusively to
the plant 0.13 miles west of the substation. This Feeder will need a 1800 kVAR capacitor placed just
outside the plant. Feeder 1 will only need a 600 kVAR capacitor removed, while Feeders 2 and 4 have
no anticipated changes. Feeder 3 will need a 300 kVAR capacitor added.
Jess Smith Service Area
There are no expected changes to Feeders 1 or 2 during this First Transition Period. Feeder 3 will
need a 600 kVAR capacitor relocated. Feeder 4 will need a 600 kVAR capacitor removed and a 300
kVAR capacitor added to it.
Key Service Area
It is anticipated that the Key metering point will be removed from service during this First Transition
period. Until it's removal, two 600 kVAR and one 300 kVAR capacitor are to be removed and two
450 kVAR capacitors added to it.
Lakeview Service Area
Feeder 1 is expected to experience voltage problems during this First Transition Period, so a 300
kVAR capacitor and a regulator will need to be added. Feeder 2 will need a 600 kVAR capacitor
turned ON with a large regulator being added. Feeder 3 will only need a 300 kVAR capacitor, and
Feeder 4 should experience no problems.
Levelland Service Area
Feeder 1 is not expected to experience voltage problems during this First Transition Period, but will
need to have a 600 kVAR capacitor removed or turned OFF. Feeder 2 will need to relocate a 600
kVAR capacitor, while Feeder 3 will need a voltage regulator added. Feeder 4 should have a 600
kVAR capacitor removed and a 450 put in its place.
McConal Service Area
Feeder 1 is not expected to experience voltage problems during this First Transition Period, but will
require a 300 kVAR capacitor being added. Feeder 2 should not experience and voltage problems,
but Feeder 3 should have a 600 kVAR capacitor relocated. Feeder 4 could have a 600 kVAR
capacitor removed or turned OFF and the current regulator could be removed.
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Page VI -11
Meadow Service Area
Because of increased load, Feeder 1 will need to have 1 mile of #4 ACSR converted to 4/0 ACSR
during this First Transition Period. A single 300 kVAR capacitor will also need to be added. Feeder 2
is not expected to need any changes made to it. Feeder 3 should have a 600 kVAR capacitor
removed and a 300 kVAR put in its place. Feeder 4 will need two 300 kVAR capacitors.
New Home Service Area
During this First Transition Period, Feeder 1 could have a 450 kVAR capacitor placed at the location
of a 600 kVAR capacitor. Feeder 2 should have a 450 kVAR capacitor replace a 300 kVAR currently in
place. Feeder 3 will need a voltage regulator, while Feeder 4 will require one 300 kVAR capacitor.
New Moore Service Area
Feeder 1 is expected to experience significant voltage problems during this First Transition Period,
so a 600 kVAR capacitor will be added along with 5.14 miles of 1/0 ACSR being converted to 477
MCM ACSR directly out of the substation, going east. Should an oil field load increase to the south
during this time period, the conversion of a 10 #4 ACSR to 30 4/0 ACSR segment and construction of
a new tie line would be necessary.
Feeder 2 should have a 600 kVAR capacitor relocated along with one being removed. Feeder 3 has
no anticipated changes.
North Lamesa Service Area
The North Lamesa metering point is expected to be eliminated during the Second Transition period,
but during the First Transition, the relocation of a 300 kVAR capacitor is all that will be needed.
Plains Service Area
Feeder 1 is not expected to experience significant voltage problems during this First Transition
Period, so only the application of one 450 kVAR capacitor is recommended. Feeder 2 is currently
experiencing voltage problems prompting the addition of a 600 kVAR capacitor and changes to
Feeder 3. To reduce load one Feeder 2 and increase voltage levels to the southeast portion of the
Plains service area, a 2 mile 4/0 ACSR line will need to be constructed south out of the substation,
meeting existing #4 ACSR lines. These lines will need to be converted to 4/0 ACSR for 3.98 miles to
reach the south line. There are no changes needed at this point for Feeder 4.
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Page VI - 12
Pleasant Hill Service Area
The eastern feeder, Feeder 1, is expected to experience voltage and capacity problems in the First
Transition period. To redirect some of the load flow and increase voltage levels, a 10 #4 ACSR line
will need to be converted to 30 1/0 ACSR for 2.5 miles, then continued north as a 1.03 mile tie line.
The redirected flow will make it possible that only one 300 kVAR capacitor will be needed. Feeder 2
and Feeder 3 will each need one 300 kVAR capacitor added during this First transition period.
Prentice Service Area
The Prentice metering point load will be assumed into the Tokio service area eliminating it from
service during the First Transition period.
Punkin Center Service Area
It is anticipated that the Punkin Center metering point will be removed from service during the
Second Transition period. Until it's removal, one 600 kVAR and one 300 kVAR capacitor are to be
relocated be facilitate better voltage values.
Ropes Service Area
It is anticipated that the Ropes substation will be removed from service during this Long Range
Planning period. This could be done during either the first or second transition period. No changes
to this system are needed to the Ropes service area at this time.
Sawyer Flat Service Area
Feeders 1 and 2 are not expected to experience voltage problems during this First Transition Period,
so no, changes are suggested. Feeder 3 will need one 600 kVAR and one 300 kVAR capacitor are to
be relocated be facilitate better voltage values.
Seagraves Service Area
Feeder 1 will need a 300 kVAR capacitor added to this circuit while no changes for Feeder 2 are
expected. Feeder 3 will need one 600 kVAR capacitor removed and one relocated while a 300 kVAR
capacitor will need to be added. Feeder 4, an underground line, can be removed from service and
free a location for future growth. Feeder 5 can have one 600 kVAR capacitor removed or turned
OFF.
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VI. TRANSITION PLANS
Page VI -13
Seminole Service Area
Feeder 1 and 2 will each need a 600 kVAR capacitor added to the circuit. Feeder 3 will need the
voltage regulator relocated and increased during this First Transition Period.
South Lamesa Service Area
It is anticipated that the South Lamesa metering point will be removed from service during the
Second Transition period. Until it's removal, two 600 kVAR and one 300 kVAR capacitor are to be
removed while two 450 kVAR capacitors will need to be placed, to maintain better voltage values.
Sundown Service Area
Feeder 1 can have one 600 kVAR capacitor turned OFF or removed and a 300 kVAR capacitor added
during this First Transition Period. Feeder 2 will only need one 600 kVAR capacitor relocated.
Feeder 3 will need one 600 kVAR capacitor turned ON while another can be removed.
Tokio Service Area
Feeder 1 is not expected to experience voltage problems during this First Transition Period. Feeder
2 can have one 600 kVAR capacitor removed and a 300 kVAR capacitor installed. Feeder 3 can also
have one 600 kVAR capacitor removed and a 450 kVAR put in its place. Feeder 4 will only need one
300 kVAR capacitor added to it while Feeder 5 is not expected to need any changes.
Two Draw Service Area
Feeder 1 will require one 300 kVAR capacitor during this First Transition Period. Feeder 2 is not
expected to experience voltage problems and requires no changes.
Welch Service Area
It is anticipated that the Welch metering point will be removed from service during the Second
Transition period. Until it's removal, two 600 kVAR capacitors can be removed and one 300 kVAR
capacitor added. The regulator will need to be relocated.
Wellman Service Area
Feeder 1 will need the application of one 600 kVAR capacitor and 100 Amp voltage regulator during
this First Transition Period. Feeder 2 will only require the relocation of one 300 kVAR capacitor.
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VI. TRANSITION PLANS
Page VI -14
Wilson Service Area
Feeder 1 should have a 600 kVAR capacitor removed or turned OFF along with adding a voltage
regulator. Feeder 2 will not need any changes, however a regulator should be added to Feeder 3.
NEW SUBSTATIONS
Claudow Service Area
The Claudow substation should be constructed during the First Transition period to relieve high load
from both Cluene and Meadow. Once constructed, Feeder 1 to the east will need 1.44 miles of #4
ACSR converted to 477 MCM ACSR and the addition of one 600 kVAR capacitor. Feeder 2, going
north, will need to convert 1.26 miles of #2 ACSR to 4/0 ACSR and the addition of one 450 kVAR.
Feeder 3 serving the south will need the addition of a 1/0 tie line to add in proper power delivery. A
600 kVAR capacitor can be removed from this circuit and a voltage regulator added to insure proper
voltage levels. Feeder 4 will need the relocation of one 600 kVAR capacitor.
Key-Mesa Service Area
The Key-Mesa 138 kV substation should be constructed during the First Transition period to
eliminate two metering points, Key and South Lamesa. Feeder 1 (north) changes will be done prior
to construction completion and according to the Key recommendations above. Feeder 2 (northeast)
changes will be completed prior to substation construction according to the South Lamesa
guidelines above.
Feeder 3 which will serve the southeast area will require 4.45 miles of #4 and #2 ACSR to be
converted to 4/0 ACSR immediately east out of the substation. Feeder 4, to the west, will need
conversion of 1/0 ACSR to 477 MCM ACSR for 3.43 miles out of the substation. Because of these
conversions, no additional capacitors or voltage regulators are needed to maintain proper voltage
levels.
Northwest Lamesa Service Area
The Northwest Lamesa substation is suggested to be completed during the First Transition period
and will split the West Lamesa metering point load into two 10 MVA substations. Feeder 1 (north)
will require one 600 kVAR capacitor and one 300 kVAR capacitor to be removed or turned OFF. One
600 kVAR capacitor will have to be relocated and a voltage regulator is suggested.
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Page VI -15
VI. TRANSITION PLANS
Feeder 2 (southeast) will need four 600 kVAR capacitors removed or turned OFF, the relocation of
one 300 kVAR capacitor, and the addition of two 450 kVAR capacitors.
Feeder
3
to
the
southwest will only need a larger, relocated voltage regulator.
Patricia Service Area
Patricia is the second substation that will split the West Lamesa metering point load into two 10
MVA substations. The 25 kV express feeder will no longer be needed. However, Feeder 4 to the
west will require conversion of the 1/0 ACSR to 477 MCM ACSR for 7.11 miles starting from the new
substation. At the end of the new 477 MCM line, an addition 2.05 miles of conversion to 4/0 is
needed as well as the addition of two 450 kVAR capacitors and the relocation of one 600 kVAR
capacitor. This feeder will also require a voltage regulator.
Feeder 1 (north) will only require adding one 300 kVAR capacitor and a voltage regulator. Feeder 2
(south) is estimated needing two 450 kVAR capacitors, the relocation of one 300 kVAR capacitor,
and a new voltage regulator. Feeder 3 (southeast) can have one voltage regulator removed and
adding one 300 kVAR capacitor.
Tokio-Brown Service Area
The Tokio-Brown substation should be constructed during the First Transition period to relieve the
increasingly high load from both Tokio and Brownfield. Once constructed, Feeder 1 to the east will
need one 600 kVAR capacitor added to it to maintain proper voltage levels. Feeder 2 (north) will
need one 600 kVAR capacitor turned OFF. Feeder 4 (west) can have one 600 kVAR capacitor
removed along with the voltage regulator.
Feeder 3 (south) will need the #4 ACSR out of the substation converted to 477 MCM ACSR for 1.24
miles. Then the next 3.98 miles of the #4 ACSR will need to be converted to 4/0 ACSR. At the end of
the above conversions, a 0.55 mile 4/0 ACSR tie line will need to be constructed to maintain proper
load balance and voltage levels. On this feeder, one 300 kVAR capacitor will need to be relocated
and one 600 kVAR capacitor added.
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VI. TRANSITION PLANS
Page VI -16
B. Second Transition 2016 - 2020
The Second Transition was developed to address system requirements during the five-year period of
2016 through 2020.
Table 6-3 below indicates annual investments expected during the Second Transition period.
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Page VI -17
VI. TRANSITION PLANS
TABLE 6-3: PROJECTED ANNUAL INVESTMENTS
Second Transition 2016-2020
Investment Description
Distribution Facilities
New Member Line Extensions
Total
$12,309,487
System Improvements
New Tie Lines
Line Conv. & Changes
$652,500
$2,118,700
Substations
New Stations
Power Transformers
Subtotal (Substations)
$6,000,000
$640,000
$6,640,000
Misc. Distr. Equipment
Transformers/Meters
Service Wire Sets
Security Lights
Sectionalizing Equip.
SCADA
Voltage Regulators
Capacitors
Subtotal (Misc. Distr. Equip.)
Ordinary Replacements
Subtotal Distribution
$16,113,118
$400,058
$369,285
$1,230,949
$1,230,949
$1,092,000
$1,017,500
$21,453,859
$5,662,364
$48,836,910
Transmission Facilities
New Line
New Station
Ordinary Replacements
Subtotal Transmission
Grand Total
$5,228,500
$0
$369,285
$5,597,785
$54,434,694
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Page VI - 18
VI. TRANSITION PLANS
1.
Transmission System
Some improvements will need to be made to the transmission system during the Second Transition
period to allocate power to the new substations.
Lakeadow
Sea-Hill
Semino-Conal
Punk-Welch
North Arvana
115 kV
115 kV
69 kV
138 kV
138 kV
5.1 miles
3.0 miles
6.0 miles
9.1 miles
7.6 miles
Substations
The cooperative plans to construct five new substations during this transition period, listed above.
Two new 69-7.2/12.47 kV 10 MVA substations, including Lakeadow and Semino-Conal, one new
115-7.2/12.47 kV 10 MVA substation named Sea-Hill, and two new 138-7.2/12.47 kV 10 MVA
substation, including North Arvana and Punk-Welch, will be added during this second transition
period.
During the Second Transition, the three 5 MVA transformers (Seminole, Wilson, Hackberry) can be
placed at Central, Florey, and Wellman according to time of need. LEC will then have three 3.75
MVA transformers available for future use.
During the Second Transition, the Draw substation will need to add a 4`h circuit, leading south, to
supply power to the southwest portion of the service area due to increasing load in the southern
region. An additional circuit will also need to be added to Meadow when the Ropes substation load
is moved onto Meadow. Proceeding north out of the Meadow substation, a new circuit will be
constructed to deliver power to the northwest service area.
Distribution System
During the Second Transition period, line voltage regulators are to be installed at selected locations
throughout the system to defer premature investments. Capacitor banks are also to be installed
throughout the system to improve voltage and decrease losses. Fourteen major improvement
projects are planned for the distribution system in the Second Transition period. The following table
lists each foreseen major distribution line project.
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299

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