Exhibit 99.1

Tri-State Generation and Transmission Association, Inc.

Rate Schedule for Contract Termination Payment Methodology and Procedures

Tri-State Generation and Transmission Association, Inc.’s (“Tri-State”) Utility Member1 Contract Termination Payment (“CTP”) is the amount of money a withdrawing Utility Member must pay to Tri-State so that remaining Utility Members are kept financially whole by the Utility Member’s exit from Tri-State. The CTP is designed to allow a Utility Member to terminate its wholesale electric service contract (“WESC”) with Tri-State, while leaving the remaining Utility Members financially unaffected. The following provisions set out the methodology that Tri-State will employ to calculate CTPs for its Utility Members (“CTP Methodology”) and certain procedural terms governing the provision of CTPs and Utility Member withdrawal from Tri-State.

I.    CTP METHODOLOGY PROCEDURES

A.    Contract Termination

In order to terminate a Utility Member’s WESC and its membership in Tri-State, a Utility Member must comply with the following requirements:

1.provide a two-year advance notice of its intent to withdraw from Tri-State and terminate its WESC; and

2.pay its CTP to Tri-State on the date of withdrawal, as calculated pursuant to the CTP Methodology.

Tri-State’s Board of Directors has no discretion to prevent a Utility Member from terminating its membership in Tri-State, so long as the withdrawing Utility Member complies with the above requirements.

B.    Annual CTP Calculations

Tri-State will provide CTP calculations to each of its Utility Members on or about April 1 of each year. A CTP calculation will remain valid through March 31 of the following year (“CTP Effective Period”). At any time during the CTP Effective Period, a Utility Member may provide written notice to Tri-State of its intent to terminate its WESC and withdraw from Tri-State at the then-effective CTP amount. Tri-State will not charge Utility Members for providing annual CTP calculations.

C.    Timing of Withdrawal

A Utility Member that has provided written notice of withdrawal to Tri-State will terminate its WESC and membership in Tri-State effective on the first day of the month

1The terms “Utility Member” and “Member” are used interchangeably in this rate schedule.

immediately following the second anniversary of its notice of withdrawal to Tri-State, or on such other date as Tri-State and the Utility Member agree (“Designated Withdrawal Date”).

D.    Data Inputs and Operating Assumptions

Tri-State will provide to each Utility Member the inputs used to calculate the Utility Member’s CTP. The inputs used in the CTP Methodology shall be obtained from readily available and updated data sources, including the Federal Energy Regulatory Commission’s (“FERC”) Electric Quarterly Reports (“EQR”), Department of Energy-Energy Information Administration (“EIA”) reports, Tri-State Eastern and Western Interconnect Open Access Transmission Tariff rates, Treasury Department and Federal Reserve Board data, and the Utility Member’s individual load and patronage capital account information.

II.    CTP METHODOLOGY

A.    CTP Methodology

Under the CTP Methodology, a departing Utility Member’s CTP shall be the greater of:

(1)    

(∑	n=L
	n=1

Revenue Stream Estimate/(1 + i)^(n − 0.5)), which is the net present value of Tri-State’s estimated lost revenues that result from the Utility Member’s departure prior to the expiration of its WESC. The Revenue Stream Estimate is equal to Gross Revenue Loss minus (i) the incremental revenues that Tri-State would receive from selling the withdrawing Utility Member’s load into the wholesale market, (ii) any subsequent revenue Tri-State would receive from the departing Utility Member if the Utility Member becomes an Open Access Transmission Tariff (“OATT”) customer, and (iii) the present value of the departing Utility Member’s accrued, unpaid patronage capital balance; or

(2)    the departing Utility Member’s Debt Covenant Obligation (“DCO”), which is the departing Utility Member’s pro rata share of Tri-State’s total debt and other obligations.

B.    Definitions of Terms

•L = expiration date of the withdrawing Utility Member’s WESC (12/31/2050) minus the date of the Utility Member’s withdrawal from Tri-State (measured in years).

•Revenue Stream Estimate (“RSE”) = Gross Revenue Loss – Competitive Market Value Estimate – OATT Revenue Estimate – Patronage Capital Credit, where:

◦Gross Revenue Loss (“GRL”):

▪For an all-requirements Utility Member served under the current WESC. GRL equals average annual Tri-State revenue as measured by the withdrawing Utility Member’s most recent three-year wholesale electric service purchases from Tri-State (the sum of revenues derived from the then applicable Schedule A (Class A) wholesale generation and

transmission rate, LDR (Load Development and Retention Rate or contracts), and Schedule S (Standby Service Rate)). The Class A revenue component for the years 2018-2020 will be reduced by four percent in recognition of the Stated Rate settlement agreement.

▪For Utility Members served under a Partial Requirements Electric Service Contract (“PRESC”) within the most recent three years. GRL equals the sum of Parts One and Two. Part One is the average Tri-State revenue from the withdrawing Utility Member’s most recent three-year purchases of transmission service under Schedule A, plus revenues from any LDR contract and Schedule S service. Part Two is the average annual revenue associated with PRESC generation service derived from Schedule A over the most recent three years, if applicable. If a Utility Member has been served under a PRESC for one full fiscal year (where a fiscal year coincides with Tri-State’s annual budgeting process), Part Two generation revenue shall be used from that year. If a Utility Member has been served under PRESC for two full fiscal years, Part Two generation revenue shall be the average of these two years. A withdrawing Utility Member must have been served under the PRESC for at least one full fiscal year to be eligible for treatment under this paragraph; otherwise, the Utility Member’s RSE will be the most recent three-year wholesale electric service purchases from Tri-State, as provided in the immediately preceding paragraph. The Class A revenue component for the years 2018-2020 will be reduced by four percent in recognition of the settlement agreement approved by the Federal Energy Regulatory Commission in Tri-State Generation and Transmission Ass’n, Inc., 176 FERC ¶ 61,068 (2021).

◦Competitive Market Value Estimate (“CMVE”): the estimated annual revenue Tri-State will receive by selling the withdrawing Utility Member’s load into the wholesale power market. A departing all-requirements Utility Member’s load is the average of the sum of energy in megawatt-hours (MWh) purchased from Tri-State during the most recent three-year period under Schedules A and S, and any LDR contracts. A departing partial requirements Utility Member’s load is the average amount of energy (MWh) purchased from Tri-State during the most recent three-year period under Schedule A (as adjusted for partial requirements consistent with the determination of GRL), Schedule S, and any LDR contracts. For each year of L, a withdrawing Utility Member’s load is multiplied by the applicable forecasted market price ($/MWh).

◦OATT Revenue Estimate (“ORE”): the estimated annual OATT revenue Tri- State will receive from the withdrawing Utility Member. A withdrawing Utility Member’s transmission demand (kW – TPP/MCP)2 equals the average of the sum of TPP/MCP billing units during the most recent three-year period under Schedule A, Schedule S, and any LDR contract sales. In each year of L, the

2TPP-MCP means the Utility Member coincident peak demand during the Tri-State peak period as defined in Schedule A.

withdrawing Utility Member’s demand billing units are multiplied by the forecasted OATT rate ($/kW-mo.). Unless otherwise agreed between Tri-State and a withdrawing Utility Member, the Utility Member is assumed to continue taking 100% of its transmission service from Tri-State through December 31, 2050. A withdrawing Utility Member taking less than 100% of its future transmission service from Tri-State will have a lower ORE and a higher CTP.

◦Patronage Capital Credit (“PCC”): the net present value of the departing Utility Member’s patronage capital balance, amortized over L or 20 years, whichever is greater.

◦Interest or Discount Rate (“i"): the average of the most recent three years’ Daily Yield Curve Rate on 30-year U.S. Treasury Bonds plus the option- adjusted spread on U.S. corporate bonds with a Standard & Poor (“S&P”) credit rating the same as Tri-State.

◦Year (“n”): full year, in sequence, beginning with “1” through “L”. For each year, this variable is reduced by one-half to conform with the half-year convention used in discounting. The half-year convention assumes that the annual RSE occurs evenly over the course of the year; therefore, the discount adjustment is applied at mid-year rather than year-end.

◦Debt Covenant Obligation (“DCO”): the withdrawing Utility Member’s pro rata portion (i.e., its percentage of Tri-State’s total Utility Member Revenues during the most recent calendar year) of Tri-State’s indebtedness and other obligations on an unconsolidated basis at the time of the Utility Member’s departure. Indebtedness and other obligations shall include all of Tri-State’s debt and liabilities (except regulatory liabilities).

C.    Summary of Key Inputs and Variables

Variable	Description	Calculation
L	WESC Termination Date (12/31/2050) less – Utility Member Departure Date (in years)	Example: Utility Member exits 1/1/2025 Round to full years [12/31/2050 – 1/1/2025= 26 years]
GRL	For, all-requirements Utility Members, the most recent three-year average Tri-State revenue derived from the sum of Schedule A, Schedule S, and any	For the most recent three full fiscal years, the sum of revenue associated with the departing Utility Member, divided by three.

Variable	Description	Calculation
	LDR contract services For the years 2018-2020, Class A revenue will be reduced by 4%.	3 ∑ Member Revenue /3 1
	For partial requirements Utility Members, the sum of Parts One and Two, where Part One is average Tri-State annual revenue derived from the transmission component of the most recent three years of Schedule A, Schedule S, and LDR contract revenues; and Part Two is the average of the most recent three years of generation revenue under PRESC, as applicable. Usage under PRESC will be based on historical actuals and averaged by the number of applicable years, up to three years. For the years 2018-2020, Class A revenue will be reduced by 4%.
CMVE - Year (n=0) – Initial Market Price Estimate (“IMPE”)	Most recent 3-year historical average of Tri- State and Public Service Company of Colorado wholesale market transactions as reported by FERC Electric Quarterly Reports.	See Explanatory Note 1
	FERC Tariff References:3
	–First Revised Rate Schedule, FERC No. 6

_____________

3 The FERC Tariff References described herein refer to the rate schedules in effect when a CTP is calculated pursuant to the CTP Methodology.

Variable	Description	Calculation
	–Rate Schedule for Power Sales Second Revised Volume No. 6 –Market-Based Rate Tariff, FERC Electric Tariff –NPU (Non-Public Utility)
CMVE - Escalation	EIA Annual Electric Power Projections by Electricity Market Module Region (WECC/Rockies) – Prices by Service Category (2020 cents per kilowatt-hour) – Generation.	See Explanatory Note 2
ORE – Year (n=0)- Current Weighted OATT Rate (“CWO”)	Current East/ West OATT rates weighted by applicable Utility Member Load in the eastern and western interconnects.	See Explanatory Note 3
ORE - Escalation	EIA Annual Electric Power Projections by Electricity Market Module Region (WECC/Rockies – Prices by Service Category (2020 cents per kilowatt-hour) – Transmission.	See Explanatory Note4
PCC	Amortized over L, but not less than 20 years	See Explanatory Note 5
“i”	Based on Tri-State’s current credit rating as reported by S&P, equal to the average Daily Treasury	See Explanatory Note 6

Variable	Description	Calculation
	Yield Curve Rates for 30- year bonds plus BBB-rated US Corporate Index Option
“n”	Sequential year of RSE	“n” = 1,2,3,4,5, etc. to L
DCO	Pro rata Share of Tri- State’s indebtedness and other obligations, excluding regulatory liabilities	The amount sufficient to avoid a Utility Member exit being included in the calculation of a “Member Termination Event” under Tri-State’s 2014 and 2017 Note Purchase Agreements

D.    Explanatory Notes

1. FERC EQR reports available athttps://eqrreportviewer.ferc.gov/(as may be modified by FERC). Analysis relies on the reported market transactions for “Tri-State Generation and Transmission Association, Inc.” and “Public Service Company of Colorado” initially over the calendar years 2018-2020. To reflect current market pricing, the data set used to calculate IMPE includes the following market-based tariffs identified in the field “FERC tariff reference”:

a.First Revised Rate Schedule, FERC No. 6;

b.Rate Schedule for Power Sales Second Revised Volume No. 6;

c.Market-Based Rate Tariff, FERC Electric Tariff; and

d.Non-Public Utility (“NPU”).

For each transaction, the average market price expressed in dollars per megawatt hour ($/MWH) is calculated by dividing “total transaction charge” by the total of “transaction quantity” where “rate units” = “$/MWH” or “$/KWH”. Because transactions are expressed in $/MWH or $/KWH, a “rate units” adjustment is required so that all information is reported on a $/MWH basis. Total transaction costs include sales based on energy, capacity, or fixed fees. To simplify the calculation and produce an IMPE that reflects market pricing most accurately, revenues from all transactions are summed and divided by total reported energy quantities. For each year of the most recent three-year period that is used to determine the IMPE, the average rate is calculated by dividing “total transaction charge” by the total of “transaction quantity” where “rate units” = “$/MWH” to calculate an average $/MWH charge. The IMPE is the simple average of the market price for each year as follows:

IMPE=	Market Priceyr1+ Market Priceyr2+ Market Priceyr3
	3

Where:

	(Total Transaction Charges ($) − Total Transmission Charges ($))TriState yr (n) +
	(Total Transaction Charges ($) − Total Transmission Charges ($))PSCo yr (n)
Market Priceyr(n)=	TotalTransactionQuantities(MWH) TriStateyr(n)+
	TotalTransactionQuantities (MWH) PSCOyr (n)

Some transactions are fixed fee or capacity-related, and therefore do not have energy quantities. For these transactions, the dollar value is included in the IMPE calculation without billing units. This approach -- adding transaction revenue to the IMPE numerator while holding the denominator constant, increases the average market price ($/MWH) to include the value of capacity and fixed price transactions. The substantial majority of EQR transactions included in the IMPE calculation are based on energy billing units and include a price that reflects the value of demand and energy. Therefore, the market price as expressed in $/MWH, includes both capacity and energy components excluding transmission.

2. IMPE is escalated using the most recently published EIA Annual Energy Outlook 2021 Table 54: Electric Power Projections by Electricity Market Module Region, Reference case, Western Electricity Coordinating Council / Rockies, available online athttps://www.eia.gov/outlooks/aeo/data/browser/#/?id=62-AEO2021&region=5-24&cases=ref2021(as may be modified from time to time).

Escalation rate is determined by applying year-to-year change in electricity utility prices per “Prices by Service Category – Generation (2020 cents per kilowatt-hour)” to Initial Market Price Estimate.

Annual Escalation Rate (Year 1)=	Year1EIAGenerationPrice
	Year 0 EIAGenerationPrice
Annual Escalation Rate (Year 2) =	Year 2 EIAGenerationPrice
	Year1EIAGenerationPrice
Annual Escalation Rate (Year n)=	Year (n) EIAGeneration
	Year (n-1) EIAGeneration

For each forecast year, the annual market price estimate is equal to the IMPE times the applicable annual escalation rate as follows:

Year	Market Price	Annual Escalation Rate	Market Price Estimate
0	Initial Market Price Estimate	N/A	Initial Market Price Estimate
1	Market Price Estimate (Yr. 1)	Annual Escalation Rate (Year 1) = Year1 EIA Generation Price Year0 EIA Generation Price	Initial Market Price Estimate * Annual Escalation Rate (Yr. 1)

2	Market Price Estimate (Yr. 2.	Annual Escalation Rate (Year 2) = Year 2 EIA Generation Price Year 1 EIA Generation Price	(Yr. 1) Market Price Estimate * Annual Escalation Rate (Yr. 2)
n	Market Price Estimate (Yr. n)	Annual Escalation Rate (Year (n)) = Year (n) EIA Generation Price Year (n-1) EIA Generation Price	(Yr. n-1) Market Price Estimate * Annual Escalation Rate (Yr. (n))

Forecast market prices are applied to withdrawing Member’s load over the same three- year period that is used in the determination of GRL.

	(	∑	3	Member’s Load (GRL) (MWH)	)
Departing Member’s Load=			1
				3

For each year (n) over period L, annual CMVEs associated with wholesale power market sales equal withdrawing Member’s Load multiplied by the Market Price Estimate in Year (n) as follows:

Departing Member’s Load (MWH) (Year (n)) X Market Price Estimate (Year (n))

3. Eastern and Western Interconnect OATT rates currently in effect are weighted by withdrawing Member Load in each region as follows:

[(Current Western Interconnect Effective OATT Rate X Member Load in Western Interconnect (MWH)) + (Current Eastern Interconnect Effective OATT Rate X Member Load in Eastern Interconnect (MWH))] / Total Member Load (MWH)

Where:

Member Load in Western Interconnect (MWH) =

∑	3	Member Load inWesternInterconnect (MWH) overthethesameperiodasGRL
	1	3

Member Load in Eastern Interconnect (MWH) =

∑	3	Member Load in EasternInterconnect (MWH) overthethesameperiodasGRL
	1	3

Total Member Load (MWH) =

∑	3	Total Member Load (MWH) overthethesameperiodasGRL
	1	3

Note that for each Utility Member, total load is categorized as either eastern or western based on the region where the majority of load is served.

4. CWO is escalated using the most recently published EIA Annual Energy Outlook 2021 Table 54: Electric Power Projections by Electricity Market Module Region, Reference case, Western Electricity Coordinating Council / Rockies, available online at https://www.eia.gov/outlooks/aeo/data/browser/#/?id=62-AEO2021&region=5-24&cases=ref2021(as may be modified from time to time).

Escalation rate is determined by applying year-to-year change in electricity utility prices per “Prices by Service Category – Transmission (2020 cents per kilowatt hour)” to initial weighted OATT rate.

Annual Escalation Rate (Year 1)=	Year1EIA TransmissionPrice
	Year 0 EIA TransmissionPrice
Annual Escalation Rate (Year 2) =	Year 2 EIA TransmissionPrice
	Year1EIA TransmissionPrice
Annual Escalation Rate (Year n)=	Year (n) EIA Transmission
	Year (n-1) EIA Transmission

For each forecast year, the OATT rate is equal to the initial weighted OATT rate times the applicable annual escalation rate as follows:

Year	Market Price	Annual Escalation Rate	Market Price Estimate
0	CWO	N/A	CWO
1	Forecasted OATT (Yr. 1)	Annual Escalation Rate (Year 1) = Year1 EIA Transmission Price Year0 EIA Transmission Price	CWO * Annual Escalation Rate (Yr. 1)
2	Forecasted OATT (Yr. 2)	Annual Escalation Rate (Year 2) = Year 2 EIA Transmission Price Year 1 EIA Transmission Price	(Yr. 1) OATT * Annual Escalation Rate (Yr. 2)
n	Forecasted OATT (Yr. n)	Annual Escalation Rate (Year (n)) = Year n EIA Transmission Price Year (n-1) EIA Transmission Price	(Yr. (n-1)) OATT * Annual Escalation Rate (Yr. (n))

Forecast OATT rates are applied to withdrawing Utility Member’s load over the same three-year period that is used in the GRL and the percentage of Utility Member load to be served by Tri-State’s transmission system over L.

Departing Member’s Transmission Load =

[	(	∑	3	Member’s Load (GRL) (kW-mo.(TPP-MPC))	)	]	X % of Member Load to be Served by
			1
				3

Tri-State’s Transmission System over L

For each year (n) over period L, annual ORE associated with OATT revenues equal Departing Member’s Load multiplied by the OATT Rate Estimate in Year (n) as follows:

Departing Member’s Transmission Load (kW −mo. (TPP −

MPC) (Year (n)) X OATT Rate Estimate (Year (n))

5. A departing Member’s accrued by unpaid Patronage Capital as of departure date will be amortized over L as follows:

Annual Patonage Capital Amortization Amount =

Current Patronage Capital Balance (from Tri-State’s most recent financial statements

L or 20 (whichever is greater)

6. Interest or Discount Rate (i) used in present value calculations equals Daily Treasury Yield Curve Rates plus the simple average BBB US Corporate Index Option-Adjusted Spread (for

Tri-State’s current credit rating from S&P), with both components averaged over the same period as the RES.

Daily Treasury Yield Curve Rates are available at https://www.treasury.gov/resource-center/data-chart-center/interest-rates/Pages/TextView.aspx?data=yield(as may be modified from time to time).

BBB US Corporate Index Option-Adjusted Spread available from “Economic Research Federal Reserve Bank of St. Louis” at https://fred.stlouisfed.org/series/BAMLC0A4CBBB#0(as may be modified from time to time).