MSR Public Power Agency · 2018. 11. 16. · Iberdrola Renewables BigHorn2 Power Mar-16 1,760,445.90$ LADWP Transmission Services A-V Mar-16 61,595.00$ PNM Monthly Invoice Mar-16

MSR Public Power Agency

MEETING OF THE COMMISSION

Wednesday, May 18, 2016, 12:00 p.m. Navigant Consulting, Inc.

35 Iron Point Circle, Suite 225 Folsom, CA 95630

AGENDA Distribution:

Commissioners & Alternate Commissioners Others Modesto:

James McFall Steve Gross Martin Caballero (Alt) Alan Hockenson Martin Hopper1 Scott Van Vuren Ed Oborn Ana Vigil Cindy Worley Toxie Buriss Santa Clara: Pat Kolstad, (President) John Roukema Teresa O’Neill1 (Alt) Alan Kuratori Joyce Kinnear1 Ann Hatcher Redding: Barry Tippin (V.P.) 1 Ann Czerwonka1 Paul Cummings (Alt)

1 Please post agenda.

M-S-R Public Power Agency

MEETING OF THE COMMISSION

Wednesday, May 18, 2016, 12:00 Noon Navigant Consulting, Inc.

35 Iron Point Circle, Suite 225 Folsom, California

AGENDA Any member of the public who desires to address the Commission on any item considered by the Commission at this meeting before or during the Commission’s consideration of that item shall so advise the Chair and shall thereupon be given an opportunity to do so.

CALL TO ORDER

ROLL CALL

CONSENT ITEMS 1 – 5 (All items are approved by a single action)

There will be no separate discussion of those items unless an item is removed at the request of any Commissioner or member of the public. Those items removed will be separately considered at the end of the consent agenda.

1. Minutes of April 20, 2016

2. Report of Summary invoices paid for April 2016 totaling $9,469,321.21

3. April 2016 Treasurer’s Report

4. May 2016 Outside Services Budget Versus Actual Report, (attached, Martin Hopper)

5. May 2016 WREGIS REC Status Report (attached, Martin Hopper)

END OF CONSENT ITEMS

ACTION ITEMS 6 - 7:

6. Status Reports (attached, Alan Hockenson)

a. San Juan Project Status Report

b. Southwest Transmission Projects Status Report

c. Pacific Northwest Projects Status Report

7. Discussion and possible action regarding M-S-R PPA’s 2015 Audited Financials for Year ending December 31, 2015 (attached, Bethany Ryers)

M-S-R Public Power Agency Commission Agenda Page 2 May 18, 2016

2016 MSR PPA Commission Meeting Agenda

CONVENE CLOSED SESSION:

a. Existing Litigation: Government Code §54956.9 (d)(1) – 7 Cases (10th US Circuit Court of Appeals 11-9557 et al, NM-PRC Case No. 13-00390-UT, Supreme Court of New Mexico Case No. 35-697; EL15-213, EL11-44 – BPA, EF13-7-000 et al, BP-18-BPA)

b. Conference with Real Property Negotiator Pursuant to Government Code Section §54956.8, Property: Transmission facilities and entitlement connecting the Westwing Substation, 11400 W. Hatfield Road, Peoria, Arizona, to the midpoint of the Victorville-Lugo transmission line. Agency Negotiator: Martin R. Hopper and/or Steven C. Gross. Under Negotiation: Purchase/Sale/Exchange/Lease of Real Property (provisions, price and terms of payment).

RECONVENE OPEN SESSION

ANNOUNCEMENTS FOLLOWING CLOSED SESSION

PUBLIC COMMENT

CONFIRM DATE AND TIME OF NEXT MEETING

ADJOURN

ALTERNATE FORMATS OF THIS AGENDA WILL BE MADE AVAILABLE UPON REQUEST TO QUALIFIED INDIVIDUALS WITH DISABILITIES.

M-S-R PUBLIC POWER AGENCY DRAFT MINUTES

MEETING OF THE COMMISSION APRIL 20, 2016

The Commission of the M-S-R Public Power Agency (M-S-R PPA) met April 20, 2016, at the

offices of Navigant Consulting, Inc. (NCI), 35 Iron Point Circle, Suite 225, Folsom, CA,

95630. Present from Modesto Irrigation District (MID) were James McFall, and Martin

Caballero; present from Santa Clara were Patrick Kolstad, and Alan Kurotori; and present

from Redding was Barry Tippin. Also present were Consultant Alan Hockenson; General

Counsel Steve Gross; and General Manager Martin R. Hopper.

Chair Kolstad called the meeting to order at 12:02 PM. A quorum was attained with the

voting representatives being Mr. McFall, Mr. Kolstad, and Mr. Tippin.

The Commission then considered approval of the Consent Calendar Items. It was moved by

Alternate Commissioner Caballero and seconded by Alternate Commissioner Cummings to

approve the Consent Calendar consisting of Items 1, 2, 3, and 4 as listed below. The motion

carried unanimously.

1. Minutes of March 16, 2016 – approved.

2. Report of Summary invoices paid for March 2016 totaling $9,050,317.87 –

noted and filed.

3. March 2016 Treasurer’s Report – accepted.

4. April 2016 Outside Services Budget Versus Actual Report – noted and filed.

Mr. Hockenson then briefly addressed the Commission regarding the San Juan Project,

Southwest Transmission Project, and Big Horn Project Status Reports and entertained

questions thereon. He additionally noted that there had been a number of transmission

curtailments pertaining to the Big Horn Projects concentrated on March 11 and 12, 2016 and

related to operations issues on the BPA transmission system.

Mr. Hopper addressed the Commission regarding his General Manager’s Report and

entertained questions thereon.

DRAFT Minutes M-S-R Public Power Agency Meeting of April 20, 2016 Page 2 of 4

Mr. Hopper then made a detailed presentation to the Commission regarding Recommended

Uses for Southwest Transmission Project sales Proceeds. The Staff Report was developed

through a collaborative process by the Financial Management Committee. He noted the

Financial Management Committee met eight times and consulted with the Agency’s Bond

Counsel and Financial Advisor to develop consensus recommendations. The eight major

sections of the report were reviewed for the Commission and the General Manager

recommended the Commission direct that the necessary documentation to implement the

recommendations be prepared for further review by the Commission. It was moved by

Commissioner McFall and seconded by Commissioner Tippin that the Commission direct the

General Manager and Financial Advisor to prepare for the Commission’s further

consideration implementing Resolutions and documents necessary to allow the Agency to

take the following actions:

1. Making findings that the Southwest Transmission Project Sales Proceeds

projected to be in an amount of approximately $60 million are surplus to the

needs of the San Juan Project and may be used for the following purposes

under the Indenture:

a. Payment of Debt Service

b. Defeasement of Debt

c. Establishment of Reserve or Revolving Funds, or

d. Pre-Funding San Juan Project Expenses; and

2. Preparing of the necessary documents for the defeasance of the Series 2011 O

Bonds on or about July 1, 2016; and

3. Preparing of a final defeasance plan based on Case 3 in the Staff Report

whereby the entire $60 million proceeds, less the cost of defeasing the Series

2011 O Bonds and allocating approximately $8.1 million of proceeds to the


Mine Reclamation and Plant Decommissioning Trusts, are used to defease

other remaining debt; and

4. Creating of a Debt Service Coverage Revolving Fund sufficient to provide debt

service coverage for the net resulting annual debt service after the above

described defeasances using moneys from the Agency’s Member Cash Call

Reserve Account sub-fund contained in the Operating Fund; and

5. Using Sales Proceeds to fund the Mine Reclamation Trust Fund in 2016 by an

amount of about $5.9 million, and placement of an expected contribution of

about $2.26 million for the Plant Decommissioning Trust into the Member

Cash Call Reserve Account in 2016 and subject to further direction of the

Commission subsequently transfer to the Plant Decommissioning Trust Fund

as required under the Plant Decommissioning and Trust Funds Agreement.

The motion carried unanimously.

The Commission then retired into Closed Session pursuant to Government Code Section

54956.9(d)(1) – Conference with Legal Counsel – Existing Litigation – 7 Cases (10th US

Circuit Court of Appeals 11-9557 et al, NM-PRC Case No. 13-00390-UT, Supreme Court of

New Mexico Case No. 35-697, EL15-213, EL11-44 - BPA, EF13-7-000 et al, and BP-18) at

1:00 P.M. Upon the conclusion of the Closed Session at 1:43 P.M., the Chair then reported for

the record, pursuant to the Government Code, that the Commission had taken no actions

which require public disclosure at this time.

The General Manager then revisited his General Manager’s Report to add that the M-S-R

Coordinator is working with his counter-part at LADWP to address the mechanics of handing

over transmission scheduling rights at the time of closing of the Southwest Transmission

Project transaction and the fact that the transfer of the assets will occur in the middle of a

scheduling day.


The Chair then called for Public Comment. There being none, the Chair announced that the

next regular meeting of the Commission will be held Wednesday, May 18, 2016, at 12:00

Noon, at Navigant’s offices in Folsom, CA. The meeting was then adjourned by the Chair at

1:46 P.M.

Martin R. Hopper Assistant Secretary Macintosh HD:Users:martinhopper:My Laptop Documents:M-S-R Public Power Agency:Administrative:Commission:Minutes:2016 Minutes:MSR PPA Minutes 0416.doc

April-16

Payee DescriptionPeriod

Covered Amount U.S. Bank Debt Service Series Apr-16 53,031.10$ MID Accounting & coordination Feb-16 62,072.00$ KBT Consulting Services Jan-16 25,946.95$ SRP M-P Betterments Feb-16 11,220.79$ U.S. Bank Series 1998 F&G Mar-16 294,969.30$ SRP M-P O&M Feb-16 26,946.27$ Flynn Resource SWTP Analysis Feb-16 637.50$ WAPA Firm Energy Losses Feb-16 18,075.99$ MID Ferguson Group Mar-16 1,755.00$ PNM Weekly RFF Mar-16 6,000.00$ Law Offices of Susie Berlin Legal Services Feb-16 9,918.20$ Duncan Weinberg Legal Services Feb-16 35,042.19$ Porter Simon Legal Services Mar-16 8,534.00$ Politico Group Legislative Services Mar-16 2,130.00$ Navigant Professional Services Feb-16 1,974.97$ Iberdrola Renewables Shaping Fee Mar-16 532,233.00$ Big Horn Wind Project Firm Energy Mar-16 2,946,961.02$ Martin Hopper Energy General Manager Services Mar-16 25,777.79$ PNM Weekly RFF Apr-16 253,000.00$ San Juan County Treasurer 2nd half of 2015 Property Taxes Apr-16 361,655.80$ Baker Tilly Audit Services Mar-16 32,048.00$ U.S. Bank Bond Series D Apr-16 1,100.00$ PNM Estimated Coal Apr-16 2,233,662.38$ Iberdrola Renewables BigHorn2 Power Mar-16 1,760,445.90$ LADWP Transmission Services A-V Mar-16 61,595.00$ PNM Monthly Invoice Mar-16 80,950.61$ PNM Demand Charge Mar-16 105,769.05$ U.S. Bank Series L, O, Q Apr-16 515,868.40$

9,469,321.21$

Report of Summary Invoices Paid

To Commission 5/18/16

Treasurer’s Report APRIL 2016

M-S-R Public Power Agency Treasurer’s Report

Index

i

Treasurer’s Report for the Month of April 2016

Investment Portfolio Pie Chart

MSR / LAIF / US Treasury 2-Year

Average Maturity Report

General Fund:

Portfolio Summary

Portfolio Details – Investments

Portfolio Details – Cash

Investment Status Report – Investments

Investment Status Report – Cash

Investment Activity by Type

Activity Report LAIF

Received Interest

Trust Funds:

Portfolio Summary

Portfolio Details – Investments

Portfolio Details – Cash

Investment Status Report – Investments

Investment Status Report – Cash

Investment Activity by Type

Received Interest

Realized Gains and Losses

Sales/Call Report

Purchases Report

MSR Treasurers Report Spreadsheet 2016

Corp Medium Term Notes16.46%

Federal Agency Issues6.38%

Managed Pool Accounts (LAIF)77.16%

M‐S‐R Public Power AgencyInvestment Portfolio April 2016

0.7290.69

0

0.5

1

1.5

2

2.5

3

Earnings Rate

MSR / LAIF / US Treasury 2‐YearApril 2016

MSR LAIF Treas Cons Matr 2Yr MSR Avg

0

100

200

300

400

500

600

Days

General Fund PortfolioAverage Maturity Report

Weighted Average Maturity

MSR Treasurers Report Spreadsheet 2016

M-S-R Public Power Agency Staff Report

Date: May 9, 2016 From: Martin R. Hopper, General Manager To: M-S-R PPA Commission Subject: May 2016 Outside Services Budget versus Actual Report Fiscal Year 2016: Major Legal Providers Reporting Are: Duncan, Weinberg, Genzer, and Pembroke: Through: March 31, 2016 Law Offices of Susie Berlin: Through: February 29, 2016 Porter Simon: Through: April 30, 2016 Major Consulting Providers Reporting Are: Navigant Consulting: Through: March 31, 2016 KBT LLC: Through: April 30, 2016 Flynn Resource Consultants: Through: April 30, 2016 Detailed charts of monthly budget versus actual cost comparisons for each provider are attached in their usual format. Recommendation: I recommend the Commission note and file this report.

M-S-R PPAAll Legal Summary

5/9/16 2016 Legal Expenses.xlsx

Month of: Apr-2016

By FunctionBudget Current Month

Actual Current Month

Positive Variance

Actual v. Budget % By Function Budget Year

to DateActual Year to

DatePositive Variance

Actual v. Budget %

Generation 7,083 1,518 5,565 21% Generation 28,333 25,602 2,731 90%Gen - Other 2,500 0 2,500 0% Gen - Other 10,000 458 9,542 5%Transmission 30,833 2,376 28,457 8% Transmission 123,333 87,894 35,439 71%Trans - Other 833 0 833 0% Trans - Other 3,333 4,667 (1,333) 140%Renewables 4,750 0 4,750 0% Renewables 19,000 20,015 (1,015) 105%Rens - Other 25,000 0 25,000 0% Rens - Other 100,000 24,993 75,007 25%Administrative 2,083 3,190 (1,107) 153% Administrative 8,333 12,271 (3,938) 147%Total 73,083 7,084 65,999 10% Total 292,333 175,900 116,433 60%

By ProviderBudget Current Month


Positive Variance

Actual v. Budget % By Provider Budget Year



Actual v. Budget %

Duncan 58,750 0 58,750 0% Duncan 235,000 124,732 110,268 53%Berlin 5,000 0 5,000 0% Berlin 20,000 20,904 (904) 105%Porter Simon 6,833 7,084 (251) 104% Porter Simon 27,333 29,806 (2,473) 109%Others 2,500 0 2,500 0% Others 10,000 458 9,542 5%Total 73,083 7,084 65,999 10% Total 292,333 175,900 116,433 60%

CURRENT MONTH YEAR TO DATE

-

250,000

500,000

750,000

1,000,000

Jan-2016 Feb-2016 Mar-2016 Apr-2016 May-2016 Jun-2016 Jul-2016 Aug-2016 Sep-2016 Oct-2016 Nov-2016 Dec-2016

AllLegal-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

M-S-R PPADuncan Summary


Month of: Apr-2016

Budget Current Month


Positive Variance

Actual v. Budget %

Generation 1,667 0 1,667 0%Gen - Other 0 0 0 0%Transmission 29,167 0 29,167 0%Trans - Other 833 0 833 0%Renewables 2,083 0 2,083 0%Rens - Other 25,000 0 25,000 0%Administrative 0 0 0 0%Total 58,750 0 58,750 0%

Budget Year to Date

Actual Year to Date

Positive Variance

Actual v. Budget %

Generation 6,667 2,881 3,786 43%Gen - Other 0 0 0 0%Transmission 116,667 82,680 33,986 71%Trans - Other 3,333 4,667 (1,333) 140%Renewables 8,333 9,511 (1,178) 114%Rens - Other 100,000 24,993 75,007 25%Administrative 0 0 0 0%Total 235,000 124,732 110,268 53%

CURRENT MONTH

YEAR TO DATE

-100,000200,000300,000400,000500,000600,000700,000800,000

Jan-2016

Feb-2016

Mar-2016

Apr-2016

May-2016

Jun-2016

Jul-2

016

Aug-2016

Sep-2016

Oct-201

6

Nov-2016

Dec-201

6

Duncan-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

M-S-R PPABerlin Summary


Month of: Apr-2016



Positive Variance

Actual v. Budget %

Generation 2,083 0 2,083 0%Gen - Other 0 0 0 0%Transmission 0 0 0 0%Trans - Other 0 0 0 0%Renewables 2,500 0 2,500 0%Rens - Other 0 0 0 0%Administrative 417 0 417 0%Total 5,000 0 5,000 0%

Budget Year to Date

Actual Year to Date

Positive Variance

Actual v. Budget %

Generation 8,333 7,145 1,188 86%Gen - Other 0 0 0 0%Transmission 0 0 0 0%Trans - Other 0 0 0 0%Renewables 10,000 10,504 (504) 105%Rens - Other 0 0 0 0%Administrative 1,667 3,255 (1,588) 195%Total 20,000 20,904 (904) 105%

CURRENT MONTH

YEAR TO DATE

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Jan-2016

Feb-2016

Mar-2016

Apr-2016

May-2016

Jun-2016

Jul-2

016

Aug-2016

Sep-2016

Oct-201

6

Nov-2016

Dec-201

6

Berlin-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

M-S-R PPAMisc Legal Summary


Month of: Apr-2016



Positive Variance

Actual v. Budget %

Generation 0 0 0 0%Gen - Other 2,500 0 2,500 0%Transmission 0 0 0 0%Trans - Other 0 0 0 0%Renewables 0 0 0 0%Rens - Other 0 0 0 0%Administrative 0 0 0 0%Total 2,500 0 2,500 0%

Budget Year to Date

Actual Year to Date

Positive Variance

Actual v. Budget %

Generation 0 0 0 0%Gen - Other 10,000 458 9,542 5%Transmission 0 0 0 0%Trans - Other 0 0 0 0%Renewables 0 0 0 0%Rens - Other 0 0 0 0%Administrative 0 0 0 0%Total 10,000 458 9,542 5%

CURRENT MONTH

YEAR TO DATE

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Jan-2016

Feb-2016

Mar-2016

Apr-2016

May-2016

Jun-2016

Jul-2

016

Aug-2016

Sep-2016

Oct-201

6

Nov-2016

Dec-201

6

MiscLegal-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

M-S-R PPAPorter Simon Summary


Month of: Apr-2016



Positive Variance

Actual v. Budget %

Generation 3,333 1,518 1,815 46%Gen - Other 0 0 0 0%Transmission 1,667 2,376 (709) 143%Trans - Other 0 0 0 0%Renewables 167 0 167 0%Rens - Other 0 0 0 0%Administrative 1,667 3,190 (1,523) 191%Total 6,833 7,084 (251) 104%

Budget Year to Date

Actual Year to Date

Positive Variance

Actual v. Budget %

Generation 13,333 15,576 (2,243) 117%Gen - Other 0 0 0 0%Transmission 6,667 5,214 1,453 78%Trans - Other 0 0 0 0%Renewables 667 0 667 0%Rens - Other 0 0 0 0%Administrative 6,667 9,016 (2,349) 135%Total 27,333 29,806 (2,473) 109%

CURRENT MONTH

YEAR TO DATE

-10,00020,00030,00040,00050,00060,00070,00080,00090,000

Jan-2016

Feb-2016

Mar-2016

Apr-2016

May-2016

Jun-2016

Jul-2

016

Aug-2016

Sep-2016

Oct-201

6

Nov-2016

Dec-201

6

PorterSimon-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

5/9/16 2016 Input 2016 Legal Expenses.xlsx

Legal Costs - 2015 2016 Budget Reallocated Budget Jan-2016 Feb-2016 Mar-2016 Apr-2016 May-2016 Jun-2016 Jul-2016 Aug-2016 Sep-2016 Oct-2016 Nov-2016 Dec-2016 Total Average Year-End Notes

8.33% 16.67% 25.00% 33.33% 41.67% 50.00% 58.33% 66.67% 75.00% 83.33% 91.67% 100.00% Projection

DWG&P 30,583.70 Generation

SJGS Agreements 20,000 20,000 2,647 235 - 2,881 960 11,524 Transmission

FERC Gen'l 250,000 250,000 29,099 17,030 24,163.30 70,292 23,431 281,168 SCE 100,000 100,000 3,161 2,807 6,420.40 12,388 4,129 49,554 SCE Experts - - - - - -

Trans - OtherOther Trans - TRR 10,000 10,000 - - 4,666.80 4,667 1,556 18,667 CASIO Rate Case/SWTP

RenewablesBPA/PNW Gen'l 25,000 25,000 2,577 4,599 2,334.80 9,511 3,170 38,044

Rens - OtherOMP/BPA Rate Case 300,000 300,000 8,952 10,372 5,669.50 24,993 8,331 99,973

705,000 705,000 46,435 35,042 43,254.80 - - - - - - - - - 124,732 41,577 498,930 6.59% 11.56% 17.69% 17.69% 17.69% 17.69% 17.69% 17.69% 17.69% 17.69% 17.69% 17.69% 71%

Law Offices of Susie BerlinGeneration

AB32/Cap & Trade/SB136825,000 25,000 4,649 2,496 7,145 3,572 42,869 Renewables

RES/RPS 30,000 30,000 4,724 5,781 10,504 5,252 63,025 A&G 5,000 5,000 1,614 1,642 3,255 1,628 19,530

60,000 60,000 10,986 9,918 - - - - - - - - - - 20,904 10,452 125,424 18.31% 34.84% 34.84% 34.84% 34.84% 34.84% 34.84% 34.84% 34.84% 34.84% 34.84% 34.84% 209%

Others Italics = EstimatesGeneratiion - Other

Montgomery Andrews 30,000 30,000 317 70 70 458 153 1,830 30,000 30,000 317 70 70 - - - - - - - - - 458 153 1,830

1.06% 1.29% 1.53% 1.53% 1.53% 1.53% 1.53% 1.53% 1.53% 1.53% 1.53% 1.53% 6%- -

Sub Total 795,000 795,000 57,738 45,031 43,325 - - - - - - - - - 146,094 52,182 626,184 7.26% 12.93% 18.38% 18.38% 18.38% 18.38% 18.38% 18.38% 18.38% 18.38% 18.38% 18.38% 79%

Porter SimonM-S-R PPA

Generation 40,000 40,000 3,300 6,842 3,916 1,518.00 15,576 3,894 46,728 Transmission 20,000 20,000 88 220 2,530 2,376.00 5,214 1,304 15,642

Renewables 2,000 2,000 - - - - - - - A&G 20,000 20,000 3,606 132 2,088 3,189.97 9,016 2,254 27,048

82,000 82,000 6,994 7,194 8,534 7,083.97 - - - - - - - - 29,806 7,451 89,418 8.53% 17.30% 27.71% 36.35% 36.35% 36.35% 36.35% 36.35% 36.35% 36.35% 36.35% 36.35% 109%

GRAND TOTAL 877,000 877,000 64,732 52,225 51,859 7,084 - - - - - - - - 175,900 59,634 715,602 7.38% 13.34% 19.25% 20.06% 20.06% 20.06% 20.06% 20.06% 20.06% 20.06% 20.06% 20.06% 82%

2016 Budget Reallocated Budget

G 85,000 85,000 25,602 101,122 G - Other 30,000 30,000 458 1,830 T 370,000 370,000 87,894 346,364 T - Other 10,000 10,000 4,667 18,667 R 57,000 57,000 20,015 101,068 R - Other 300,000 300,000 24,993 99,973 A 25,000 25,000 12,271 46,578

877,000 877,000 175,900 715,602

50/35/15 490,000 490,000 Renew 57,000 57,000

M-S-R PPATotal Outside Consult Summary

5/9/16 2016 Consulting and Outside Service Expenses.xlsx

Month of: Apr-2016

By FunctionBudget Current Month


Positive Variance

Actual v. Budget % By Function Budget Year



Actual v. Budget %

Generation 9,750 16,513 (6,763) 169% Generation 39,000 57,364 (18,364) 147%Gen - Other 0 0 0 0% Gen - Other 0 0 0 0%Transmission 5,417 5,510 (93) 102% Transmission 21,667 24,270 (2,603) 112%Trans - Other 6,250 705 5,545 11% Trans - Other 25,000 3,330 21,670 13%Renewables 7,667 4,010 3,657 52% Renewables 30,667 23,918 6,748 78%Rens - Other 4,583 1,520 3,063 33% Rens - Other 18,333 12,000 6,333 65%Administrative 4,583 1,943 2,640 42% Administrative 18,333 10,447 7,886 57%Total 38,250 30,200 8,050 79% Total 153,000 131,330 21,670 86%

By ProviderBudget Current Month


Positive Variance

Actual v. Budget % By Provider Budget Year



Actual v. Budget %

Navigant 6,250 0 6,250 0% Navigant 25,000 6,511 18,489 26%KBT 25,000 26,036 (1,036) 104% KBT 100,000 109,772 (9,772) 110%Flynn RCI 4,167 705 3,462 17% Flynn RCI 16,667 3,330 13,337 20%Others 2,833 3,459 (626) 122% Others 11,333 11,718 (384) 103%Total 38,250 30,200 8,050 79% Total 153,000 131,330 21,670 86%

CURRENT MONTH YEAR TO DATE

-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

Jan-2016 Feb-2016 Mar-2016 Apr-2016 May-2016 Jun-2016 Jul-2016 Aug-2016 Sep-2016 Oct-2016 Nov-2016 Dec-2016

OutsideServicesConsultants-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

M-S-R PPANavigant Summary


Month of: Apr-2016



Positive Variance

Actual v. Budget %

Generation 417 0 417 0%Gen - Other 0 0 0 0%Transmission 2,917 0 2,917 0%Trans - Other 0 0 0 0%Renewables 2,083 0 2,083 0%Rens - Other 0 0 0 0%Administrative 833 0 833 0%Total 6,250 0 6,250 0%

Budget Year to Date

Actual Year to Date

Positive Variance

Actual v. Budget %

Generation 1,667 0 1,667 0%Gen - Other 0 0 0 0%Transmission 11,667 3,940 7,727 34%Trans - Other 0 0 0 0%Renewables 8,333 0 8,333 0%Rens - Other 0 0 0 0%Administrative 3,333 2,571 762 77%Total 25,000 6,511 18,489 26%

YEAR TO DATE

CURRENT MONTH

-10,00020,00030,00040,00050,00060,00070,00080,000

Jan-2016

Feb-2016

Mar-2016

Apr-2016

May-2016

Jun-2016

Jul-2

016

Aug-2016

Sep-2016

Oct-201

6

Nov-2016

Dec-201

6

Navigant-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

M-S-R PPAKBT Summary


Month of: Apr-2016



Positive Variance

Actual v. Budget %

Generation 7,917 14,783 (6,866) 187%Gen - Other 0 0 0 0%Transmission 2,500 5,510 (3,010) 220%Trans - Other 2,083 0 2,083 0%Renewables 4,167 2,280 1,887 55%Rens - Other 4,583 1,520 3,063 33%Administrative 3,750 1,943 1,807 52%Total 25,000 26,036 (1,036) 104%

Budget Year to Date

Actual Year to Date

Positive Variance

Actual v. Budget %

Generation 31,667 50,628 (18,961) 160%Gen - Other 0 0 0 0%Transmission 10,000 20,330 (10,330) 203%Trans - Other 8,333 0 8,333 0%Renewables 16,667 18,937 (2,270) 114%Rens - Other 18,333 12,000 6,333 65%Administrative 15,000 7,876 7,124 53%Total 100,000 109,772 (9,772) 110%

YEAR TO DATE

CURRENT MONTH

-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Jan-2016

Feb-2016

Mar-2016

Apr-2016

May-2016

Jun-2016

Jul-2

016

Aug-2016

Sep-2016

Oct-201

6

Nov-2016

Dec-201

6

KBT-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

M-S-R PPAFlynn RCI Summary


Month of: Apr-2016



Positive Variance

Actual v. Budget %

Generation 0 0 0 0%Gen - Other 0 0 0 0%Transmission 0 0 0 0%Trans - Other 4,167 705 3,462 17%Renewables 0 0 0 0%Rens - Other 0 0 0 0%Administrative 0 0 0 0%Total 4,167 705 3,462 17%

Budget Year to Date

Actual Year to Date

Positive Variance

Actual v. Budget %

Generation 0 0 0 0%Gen - Other 0 0 0 0%Transmission 0 0 0 0%Trans - Other 16,667 3,330 13,337 20%Renewables 0 0 0 0%Rens - Other 0 0 0 0%Administrative 0 0 0 0%Total 16,667 3,330 13,337 20%

CURRENT MONTH

YEAR TO DATE

-

5,000

10,000

15,000

20,000

25,000

30,000

Jan-2016

Feb-2016

Mar-2016

Apr-2016

May-2016

Jun-2016

Jul-2

016

Aug-2016

Sep-2016

Oct-201

6

Nov-2016

Dec-201

6

FlynnRCI-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

M-S-R PPAMisc Outside Services Summary


Month of: Apr-2016



Positive Variance

Actual v. Budget %

Generation 1,417 1,730 (313) 122%Gen - Other 0 0 0 0%Transmission 0 0 0 0%Trans - Other 0 0 0 0%Renewables 1,417 1,730 (313) 122%Rens - Other 0 0 0 0%Administrative 0 0 0 0%Total 2,833 3,459 (626) 122%

Budget Year to Date

Actual Year to Date

Positive Variance

Actual v. Budget %

Generation 5,667 6,736 (1,070) 119%Gen - Other 0 0 0 0%Transmission 0 0 0 0%Trans - Other 0 0 0 0%Renewables 5,667 4,981 685 88%Rens - Other 0 0 0 0%Administrative 0 0 0 0%Total 11,333 11,718 (384) 103%

YEAR TO DATE

CURRENT MONTH

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Jan-2016

Feb-2016

Mar-2016

Apr-2016

May-2016

Jun-2016

Jul-2

016

Aug-2016

Sep-2016

Oct-201

6

Nov-2016

Dec-201

6

OutsideServices-Total

CUMMULATIVEBUDGET

CUMMULATIVEACTUAL

5/9/16 2016 Input 2016 Consulting and Outside Service Expenses.xlsx

Consultant Costs - 2015

2016 Budget Revised Budget

Task Orders Jan-2016 Feb-2016 Mar-2016 Apr-2016 May-2016 Jun-2016 Jul-2016 Aug-2016 Sep-2016 Oct-2016 Nov-2016 Dec-2016 Total Average Year-End Notes

8.33% 16.67% 25.00% 33.33% 41.67% 50.00% 58.33% 66.67% 75.00% 83.33% 91.67% 100.00% Projection

NavigantGeneration

General 5,000 5,000 - - - - - - Transmission

SCE TO-6 et al 35,000 35,000 - 1,236 2,703.75 3,940 1,313 15,759 Other Trans

- - - - - - Renewables BPA 25,000 25,000 - - - - - BPA Cohen

Administrative 10,000 10,000 986 739 845.87 2,571 857 10,284 75,000 75,000 986 1,975 3,549.62 - - - - - - - - - 6,511 2,170 26,043

1.31% 3.95% 8.68% 8.68% 8.68% 8.68% 8.68% 8.68% 8.68% 8.68% 8.68% 8.68% 35%

KBTGeneration

General 95,000 95,000 15,705 9,120 11,020 14,782.79 50,628 12,657 151,884 Gen - Other

SJGS Disposition - - KBT 2016-xx - - - - - SJGS Restructuring Closing

- - - - Remaining -

TransmissionGeneral 30,000 30,000 2,470 6,270 6,080 5,510.00 20,330 5,083 60,990

Trans - OtherManagement 25,000 25,000 - - - - -

RenewablesGeneral 50,000 50,000 3,230 6,987 6,440 2,280.00 18,937 4,734 56,811

Rens - OtherBP-16 Rate Case 50,000 50,000 - BP-18 Rate Case

KBT 2016-01 9,600 2,240 5,520 7,760 3,880 7,760 Jan - FebKBT 2016-02 12,800 2,720 1,520.00 4,240 2,120 4,240 Mar - AprKBT 2016-xx - - - - - - May - JunKBT 2016-xx - - - - - - Jul - AugKBT 2016-xx - - - - - - Sep - OctKBT 2016-xx - - - - - - Nov - Dec

Sum 22,400 12,000 BPA - OMP/IRI Cases 5,000 5,000 BPA - OMP/IRI Cases

KBT 2016-01 - - - - - - Jan - FebKBT 2016-02 - - - - - - Mar - AprKBT 2016-xx - - - - - - May - JunKBT 2016-xx - - - - - - - Jul - AugKBT 2016-xx - - - - - - - Sep - OctKBT 2016-xx - - - - - - Nov - Dec

Sum - -

Administrative 45,000 45,000 2,302 1,151 2,481 1,943.20 7,876 1,969 23,629 300,000 300,000 25,947 29,048 28,741 26,035.99 - - - - - - - - 109,772 30,443 365,315

8.65% 18.33% 27.91% 36.59% 36.59% 36.59% 36.59% 36.59% 36.59% 36.59% 36.59% 36.59% 122%

Flynn RCIGeneration - - - -

Transmission - - - - Trans - Other

SWTP Negos 25,000 25,000 - 638 1,988 705 3,330 833 9,990 Renewables - - - - Rens - Other -

Administrative - - - 25,000 25,000 - 638 1,988 705 - - - - - - - - 3,330 833 9,990

0.00% 2.55% 10.50% 13.32% 13.32% 13.32% 13.32% 13.32% 13.32% 13.32% 13.32% 13.32% 40%

Misc (MID etc) - GenerationGen - Other - - - -

TransmissionTrans - Other - - - - - Renewables - - - - - - - - - - - - -

Administrative - - - - - - - - - - - - - 0 - - - - - - - - - - - - - - - -

0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% #DIV/0!109,772

SUBTOTAL 400,000 400,000 26,933 31,661 34,278 26,741 - - - - - - - - 119,612 33,446 401,347 6.73% 14.65% 23.22% 29.90% 29.90% 29.90% 29.90% 29.90% 29.90% 29.90% 29.90% 29.90% 100%

Outside Services Italics = EstimatesGeneration

Ferguson Group 5,000 5,000 - 1,755 1,755 878 10,530 Politico Group 12,000 12,000 1,000 1,187 1,065 1,730 4,981 1,245 14,944

TransmissionRenewables

Ferguson Group 5,000 5,000 - - - - Politico Group 12,000 12,000 1,000 1,187 1,065 1,730 4,981 1,245 14,944

Rens - OtherAdministrative - - - -

34,000 34,000 2,000 4,128 2,130 3,459 - - - - - - - - 11,718 3,368 40,418 5.88% 18.02% 24.29% 34.46% 34.46% 34.46% 34.46% 34.46% 34.46% 34.46% 34.46% 34.46% 119%

GRAND TOTAL 434,000 434,000 28,933 35,789 36,408 30,200 - - - - - - - - 131,330 36,814 441,765 6.67% 14.91% 23.30% 30.26% 30.26% 30.26% 30.26% 30.26% 30.26% 30.26% 30.26% 30.26% 102%

2016 Budget 2016 BudgetG 117,000 117,000 151,884 G - Other - - - T 65,000 65,000 76,749 T - Other 50,000 50,000 9,990 R 92,000 92,000 56,811 R - Other 55,000 55,000 12,000 A 55,000 55,000 33,913

434,000 434,000 341,347

50/35/15 287,000 Renew 147,000

Page 1 of 1

M-S-R Public Power Agency Staff Report

Date: May 3, 2016 From: Martin R. Hopper, General Manager To: M-S-R PPA Technical Committee Subject: May 2016 WREGIS REC Transfers Status Report In 2013, the General Manager met with Iberdrola Renewables, Inc regarding the status of its transfers of Western Renewable Energy Generation Information System (WREGIS) Renewable Energy Credits (RECs) for the Big Horn I and Big Horn II Wind Energy Projects to M-S-R PPA. Ideally, the WREGIS timelines would allow transfers of RECs to M-S-R PPA about 90-days after the close of a reporting month. At the time of that meeting, some transfers were as many as 215-days outstanding. Iberdrola has subsequently reviewed its internal procedures and has generally completed Big Horn I and Big Horn II transfers in a timely manner. The attached chart illustrates current and historic status of REC transfers. As requested by the Commission, this report will be updated and presented every other month. I recommend the Commission note and file the May 2016 WREGIS REC Transfers Status Report.

WREGIS Transfer Durations.xlsx 5/3/16

0

90

180

270

360

450

540

630

Jan-08 May-09 Oct-10 Feb-12 Jul-13 Nov-14 Apr-16

Elap

sedTime(Days)

Month

BigHornI&IIRECTransfers

BHIDuraDon

BHIIDuraDon

OpenTransfers

5/3/16 WREGIS Transfer Durations.xlsx

REC Transfer Timeliness

Month Ending

Date Transferred to Members

BH I DurationDate

Transferred to Members

BH II Duration Today's Date Open

Transfers

Jan-08 29-Jun-09 515Feb-08 29-Jun-09 486Mar-08 29-Jun-09 455Apr-08 29-Jun-09 425May-08 29-Jun-09 394Jun-08 29-Jun-09 364Jul-08 29-Jun-09 333Aug-08 8-Jun-09 281Sep-08 8-Jun-09 251Oct-08 29-Jun-09 241Nov-08 8-Jun-09 190Dec-08 8-Jun-09 159Jan-09 8-Jun-09 128Feb-09 29-Jun-09 121Mar-09 7-Jul-09 98Apr-09 2-Sep-09 125May-09 2-Sep-09 94Jun-09 5-Nov-09 128Jul-09 30-Nov-09 122Aug-09 15-Dec-09 106Sep-09 8-Jan-10 100Oct-09 8-Feb-10 100Nov-09 10-Mar-10 100Dec-09 9-Apr-10 99Jan-10 10-May-10 99Feb-10 10-Jun-10 102Mar-10 10-Aug-10 132Apr-10 10-Aug-10 102May-10 10-Sep-10 102Jun-10 13-Oct-10 105Jul-10 9-Nov-10 101Aug-10 10-Dec-10 101Sep-10 2-May-11 214Oct-10 2-May-11 183Nov-10 9-May-11 160 9-May-11 160Dec-10 3-Jun-11 154 3-Jun-11 154Jan-11 11-Jul-11 161 11-Jul-11 161Feb-11 11-Jul-11 133 11-Jul-11 133Mar-11 11-Jul-11 102 11-Jul-11 102Apr-11 29-Aug-11 121 31-Aug-11 123May-11 30-Aug-11 91 31-Aug-11 92Jun-11 8-Nov-11 131 8-Nov-11 131Jul-11 8-Nov-11 100 8-Nov-11 100Aug-11 30-Nov-11 91 30-Nov-11 91Sep-11 20-Jan-12 112 20-Jan-12 112Oct-11 15-Feb-12 107 15-Feb-12 107Nov-11 24-May-12 176 24-May-12 176Dec-11 24-May-12 145 24-May-12 145Jan-12 15-Aug-12 197 15-Aug-12 197Feb-12 15-Aug-12 168 15-Aug-12 168Mar-12 15-Aug-12 137 15-Aug-12 137Apr-12 15-Aug-12 107 15-Aug-12 107May-12 30-Aug-12 91 30-Aug-12 91Jun-12 1-Oct-12 93 1-Oct-12 93Jul-12 31-Oct-12 92 31-Oct-12 92Aug-12 30-Nov-12 91 30-Nov-12 91Sep-12 3-May-13 215 3-May-13 215Oct-12 3-May-13 184 3-May-13 184Nov-12 3-May-13 154 3-May-13 154Dec-12 3-May-13 123 3-May-13 123Jan-13 3-Jun-13 123 3-May-13 92Feb-13 3-Jun-13 95 3-Jun-13 95Mar-13 2-Jul-13 93 2-Jul-13 93Apr-13 31-Jul-13 92 31-Jul-13 92May-13 4-Sep-13 96 5-Sep-13 97Jun-13 1-Oct-13 93 1-Oct-13 93Jul-13 21-Nov-13 113 21-Nov-13 113Aug-13 5-Dec-13 96 5-Dec-13 96Sep-13 2-Jan-14 94 2-Jan-14 94Oct-13 3-Feb-14 95 3-Feb-14 95Nov-13 3-Mar-14 93 3-Mar-14 93Dec-13 3-Apr-14 93 4-Apr-14 94Jan-14 8-May-14 97 8-May-14 97Feb-14 3-Jun-14 95 3-Jun-14 95Mar-14 2-Jul-14 93 2-Jul-14 93Apr-14 31-Jul-14 92 31-Jul-14 92May-14 4-Sep-14 96 4-Sep-14 96Jun-14 20-Oct-14 112 20-Oct-14 112Jul-14 7-Nov-14 99 7-Nov-14 99Aug-14 2-Dec-14 93 2-Dec-14 93Sep-14 12-Jan-15 104 12-Jan-15 104Oct-14 23-Feb-15 115 23-Feb-15 115Nov-14 13-Apr-15 134 13-Apr-15 134 Note: Rec'd from IRI 3-Mar-15Dec-14 13-Apr-15 103 13-Apr-15 103 Note: Rec'd from IRI 1-Apr-15Jan-15 6-May-15 95 6-May-15 95Feb-15 2-Jun-15 94 2-Jun-15 94Mar-15 9-Jul-15 100 9-Jul-15 100Apr-15 5-Aug-15 97 5-Aug-15 97May-15 1-Sep-15 93 1-Sep-15 93Jun-15 2-Oct-15 94 2-Oct-15 94Jul-15 5-Nov-15 97 5-Nov-15 97Aug-15 2-Dec-15 93 2-Dec-15 93Sep-15 31-Dec-15 92 31-Dec-15 92Oct-15 12-Feb-16 104 12-Feb-16 104Nov-15 3-Mar-16 94 3-Mar-16 94Dec-15 4-Apr-16 95 4-Apr-16 95Jan-16 3-May-16 93 2-May-16 92Feb-16 3-May-16 64 Mar-16 3-May-16 33 Apr-16 3-May-16 3

Big Horn I Big Horn II

5/2/16

M-S-R PUBLIC POWER AGENCY SAN JUAN PROJECT

STATUS REPORT MAY 2016

SAN JUAN UNIT 4 OPERATIONS March 2016 Unit Net Generation (MWh) 272,066 Net Capacity Factor (%) 72.1 San Juan Generating Station (San Juan) Unit 4 was forced from service twice during March for a total of 35.5 hours. The outage on the 16th was due to the Induced Draft fans. The outage on the 20th was due to the loss of a boiler feed pump. SHUMWAY ARROYO SLURRY WALL PROJECT This slurry wall project was developed as part of a $10 Million settlement with the Sierra Club regarding water discharge issues at San Juan. This project has been delayed due for two years for land rights to be resolved. All such issues have been resolved and construction is estimated to begin in the fourth quarter of 2016. The new estimated cost has increased by almost $2.5 million. As a capital project, the Agency is not responsible for any of this cost. SAFETY ISSUES San Juan had experienced a continual improvement in its safety record through 2015. However, there were two accidents in the February 2016 that required hospitalization and set back this progress.

1. An operator took on the task of cleaning behind a large piece of equipment that had not been moved for a while. Although there were wheels, one was flat. The operator decided to use a small overhead crane available to move the equipment. As the operator was moving the equipment the load shifted. His middle finger was pinched resulting in amputation at the cuticle.

2. Two employees were inspecting the penthouse section of the Unit 2 boiler. Ash covered the floor and had not completely cooled. One employee stepped into a hole and hot ash entered the top of his safety boot. The result was second degree burns at the ankle. Poor maintenance of the wound subsequent to initial care resulted in an infection that ultimately required hospitalization.

3. A third incident happened in March that was also significant. A new welder was

welding/grinding in the shop during his first week on the job. He was using his personal safety equipment as plant-issued fitted equipment was being readied. He managed to get a piece of slag in his left eye and failed to report in a timely manner.

5/2/16

M-S-R PUBLIC POWER AGENCY

SOUTHWEST TRANSMISSION PROJECTS STATUS REPORT

MAY 2016 Engineering and Operating (E&O) Committee Meetings

The semi-annual meetings of the Mead-Phoenix Transmission Project (Mead-Phoenix) and Mead-Adelanto Transmission Project (Mead-Adelanto) were held on April 7, 2016 in Phoenix, AZ. Resolutions 2016-1 (for both projects) were presented at the meeting and were the subject of an in-meeting conference call of the Management and Coordinating Committees. The subject of the resolutions was to relieve the Agency of liabilities when the divestiture to the Southern California Public Power Authority (SCPPA) occurs. All signatures have now been received by the Operating Agents.

Perkins Capacitor Voltage Transformer (CCVT)

A series of CCVTs at Perkins have failed and have been replaced. In June 2013, a CCVT failed on the Perkins-Westwing line. A second failed in August 2013. In November 2013, another CCVT failed in Perkins Station. All three CCVT were replaced. In October 2015, yet another CCVT failed, this time on the Perkins-Mead line. An original CBI was approved in 2013 and a revision to the CBI as well. Now, after more work has been completed, a second CBI revision has been approved. It is likely that all if these costs will be invoiced before the end of May.

5/2/16

M-S-R PUBLIC POWER AGENCY PACIFIC NORTHWEST PROJECT

STATUS REPORT MAY 2016

BIG HORN I OPERATION MWH % of 5-Year Average March 2016 54,698 106.0 2016 Total 121,070 90.6 Project Life (since October 2006) 4,868,781 92.4 BIG HORN II OPERATION MWH % of 5-Year Average March 2016 14,632 116.4 2016 Total 32,722 95.5 Project Life (since November 2010) 640,730 91.5 Energy curtailments for the four month period November 2015-February 2016 totaled only 55 MW. Curtailments in March 2016 were 58 MW during peak hours and 91 MW during off peak hours. Total energy production for both projects was stronger during the peak periods compared to off-peak periods. At first look this may seem odd but March had the maximum number of peak hours possible (432 compared to 311 off-peak hours). This compares to 421 peak and 321 off-peak hours for an average month in 2016.

Baker Tilly refers to Baker Tilly Virchow Krause, LLP,an independently owned and managed member of Baker Tilly International. © Baker Tilly Virchow Krause, LLP

M-S-R Public Power AgencyCommission PresentationReport on M-S-R Public Power Agency Financial Audit – December 31, 2015

Audit presentation topics

Audit overview

Internal control communication

Auditor’s communication with Those Charged with Governance

Questions

2

Audit overview

Audit was conducted smoothly with no major snags or difficulties.

Management and staff were cooperative and readily available.

Audit schedule was maintained and communication between management and auditors was good.

Last day of fieldwork was March 25, 2016.

3

Audit overview

Audit performed in accordance with Generally Accepted Auditing Standards.

Audit objective - reasonable assurance that financial statements are free from material misstatement.

Financial statements received an Unmodified Opinion.

4

5

GASB Statement No. 53 (Derivatives)Investments

Revenue recognition

Purchased power

Assets under construction and plant in service

Debt

Analytical review of balance sheet and statement of revenues, expenses and changes in net position

Sensitive estimates

Transmission rights

Restructuring agreement

Audit is based on assessment of control risk in key business process areas. Below are several key areas of review:

Audit overview

5

Internal control communication

Statement on Auditing Standards: Clarification and Recodification (AU-C) No. 325 Communication of Internal Control Related Matters Identified in an Audit

Internal Control Over Financial Reporting

6

Auditor’s Communication with ThoseCharged with Governance

Significant findings from the audit

7

Area to be Communicated Auditor’s Response

Auditor’s View on Qualitative Aspects of Significant Accounting Policies

The significant accounting policies used in the preparation of your financial statements are discussed in Note 2 to the financial statements.

Accounting estimates are an integral part of the financial statements prepared by management's knowledge and experience about past and current events and assumptions about future events. Significant estimates include:

Coal mine obligations

Asset retirement obligations

We feel that all estimates made by management are in accordance with generally accepted accounting principles.

8


Significant Difficulties Encountered in Performing the Audit

We encountered no difficulties in performing our audit.

Uncorrected Misstatements/Adjusting Entries

By Professional Auditing Standards, uncorrected misstatements refer to immaterial passed audit adjustments –there were no such proposed adjustments as part of this year’s audit.



9


Disagreements with Management Professional standards define a disagreement with management as a matter, whether or not resolved to our satisfaction, concerning a financial accounting, reporting, or auditing matter that could be significant to the financial statements or the auditor’s report. We are pleased to report that no such disagreements were encountered during the course of the audit.

Other Findings or Issues There are no other issues to disclose as part of the audit in connection with these Professional Auditing Standards.



10


Material Corrected Misstatements Professional standards define an audit adjustment as a proposed correction of the financial statements that, in our judgment, may not have been detected except through our auditing procedures.

There were no adjustments as part of this year’s audit.



11


Management Representations We have requested certain representations from management that are included in the management representation letter. A copy of this letter is included with our management letter.


Other required communications

12


Management’s Consultations with Other Accountants

To the best of our knowledge, management has not consulted with or obtained opinions from other independent accountants on auditing and or the application of accounting principles during the past year.

Professional standards require the consulting accountant to discuss any such contacts with the current auditor to determine that the consultant has all the relevant facts. To our knowledge, there were no such consultations with other accountants.



13


Auditor Independence We are not aware of any relationships between Baker Tilly Virchow Krause, LLP and M-S-R Public Power Agency that, in our professional judgment, may reasonably be thought to bear on our independence.

Significant Issues We generally discuss a variety of matters, including the application of accounting principles and auditing standards, with management each year prior to the audit.

These discussions occurred in the normal course of our professional relationship and our responses were not a condition to our retention as the Agency’s auditors.



Closing

We appreciate the work done by M-S-R Public Power Agency accounting staff and management in preparing for and assisting in the audit!

Questions?

14


FINANCIAL STATEMENTS

Including Independent Auditors’ Report

As of and for the Years Ended December 31, 2015 and 2014


TABLE OF CONTENTS

As of and for the Years Ended December 31, 2015 and 2014

Independent Auditors’ Report 1 – 2

Management’s Discussion and Analysis 3 – 8

Balance Sheets 9 – 10

Statements of Revenues, Expenses and Changes in Net Position 11

Statements of Cash Flows 12 – 13

Notes to Financial Statements 14 – 34

Page 1

INDEPENDENT AUDITORS' REPORT To the Commissioners M-S-R Public Power Agency Modesto, CA Report on the Financial Statements We have audited the accompanying financial statements of M-S-R Public Power Agency (the Agency), as of and for the years ended December 31, 2015 and 2014, and the related notes to the financial statements, which collectively comprise the Agency's basic financial statements as listed in the table of contents. Management’s Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error. Auditors’ Responsibility Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Agency’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Agency's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Agency as of December 31, 2015 and 2014, and the respective changes in financial position and cash flows thereof for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Baker Tilly Virchow Krause, LLP Ten Terrace Ct, PO Box 7398 Madison, WI 53707-7398 tel 608 249 6622 fax 608 249 8532 bakertilly.com


Management's Discussion and AnalysisDecember 31, 2015 and 2014 - Unaudited

Overview:

Background:

Financial Reporting:

The Agency’s financial statements include the Balance Sheets, Statements of Revenues, Expenses and Changes in Net Position, and Statements of Cash Flows. The Balance Sheet provides information about assets and obligations of the Agency at a specific point in time. The Statements of Revenues, Expenses and Changes in Net Position provide information regarding the Agency’s operations during the fiscal years indicated. The Statements of Cash Flows report cash sources and uses for operations, capital and related financing and investing activities.

The following management discussion and analysis of the M-S-R Public Power Agency (the “Agency”) provides an overview of the financial activities and transactions for the years ended December 31, 2015 and 2014 in the context of the requirements of the Governmental Accounting Standards Board (GASB) Statement No. 34, Basic Financial Statements – and Management’s Discussion and Analysis – for State and Local Governments, as amended . This discussion and analysis should be read in conjunction with the Agency’s audited financial statements and accompanying notes.

The Agency’s accounting records are maintained in accordance with generally accepted accounting principles (GAAP) as prescribed by the Governmental Accounting Standards Board (GASB).

Overview of Financial Statements:

The Agency is a joint power agency (JPA) composed of the Modesto Irrigation District, and the California Cities of Santa Clara (Silicon Valley Power) and Redding (Members). The purpose of M-S-R is to manage electric power generation and transmission resources for the benefit of its members. The Agency has a 28.8% ownership interest in a 507 megawatt coal fired electric generating facility located in New Mexico (“San Juan Project”). Additionally, the Agency is a participant in the Southwest Transmission Project (“Transmission Project”). The Project is a 500-kilovolt alternating current transmission project spanning between Central Arizona and Southern California. The Agency also has two long term power purchase agreements for the Big Horn I and Big Horn II Wind Energy Projects located in Washington State.

Agency Highlights

M-S-R Public Power Agency has been in negotiations for the transfer of its ownership and interest in the 507 megawatt coal fired electric generation plant (San Juan Project) located in Farmington New Mexico. The exit date is scheduled for December 31, 2017.

The agency is also negotiating the sale of Southwest Transmission Project (Transmission Project). The project is a 500-kilovot alternating current transmission project spanning from Central Arizona to Southern California. Additional information for both projects can be found under Footnote 10 – Contingencies.

Page 3



Financial Summary

Balance Sheet($ in millions) December 31, December 31, December 31, Change from

2015 2014 2013 2014 to 2015Assets and Deferred Outflows

Capital Assets 119.1$ 129.0$ 138.6$ (9.9)$ Other assets and investments 44.2 43.6 48.4 0.6$ Current assets 62.8$ 62.2$ 55.3$ 0.6$ Deferred outflows of resources 7.4$ 9.9$ 12.7$ (2.5)$

Total Assets and DeferredOutflows 233.5$ 244.7$ 255.0$ (11.2)$

Liabilities and Net PositionLong-term debt (net of current) 206.5$ 234.3$ 263.9$ (27.8)$ Noncurrent liabilities 34.4$ 36.5$ 37.0$ (2.1)$ Current liabilities 40.8$ 44.2$ 42.3$ (3.4)$

Total Liabilities 281.7$ 315.0$ 343.2$ (33.3)$

Net positionInvestment in capital, net (88.6)$ (109.7)$ (122.6)$ 21.1$ Restricted for debt service 27.6$ 14.4$ 12.8$ 13.2$ Restricted for coal mine obligation 2.7$ -$ -$ 2.7$ Unrestricted 10.1$ 25.0$ 21.6$ (14.9)$

Total Net Position (48.2)$ (70.3)$ (88.2)$ 22.1$

Total Liabilities and Net Position 233.5$ 244.7$ 255.0$ (11.2)$

($ in millions) December 31, December 31, December 31, Change from

2015 2014 2013 2014 to 2015

Operating revenues 139.3$ 149.6$ 156.6$ (10.3)$ Operating expenses (104.9)$ (117.2)$ (112.2)$ 12.3$

Operating income (loss) 34.4$ 32.4$ 44.4$ 2.0$

Investment income 0.3$ 0.2$ 0.1$ 0.1$ Interest expense (10.8)$ (11.8)$ (14.4)$ 1.0$ Other expense (1.8)$ (2.9)$ (2.4)$ 1.1$

Non-operating income (expense) (12.3)$ (14.5)$ (16.7)$ 2.2$

Change in net position 22.1$ 17.9$ 27.7$ 4.2$

Net position, beginning of year (70.3)$ (88.2)$ (115.9)$ 17.9$

Net Position, End of Year (48.2)$ (70.3)$ (88.2)$ 22.1$

Statement of Revenues, Expenses, and Changes in Net Position

Non-Operating Income (Expenses)

Operating Revenues and Expenses

Page 4



BALANCE SHEET

Assets

Capital Assets

Other Assets and Investments

Current Assets

Deferred outflow of Resources

Capital assets decreased by $9.9 million in 2015 when compared to 2014 due to slight increases in plant in service for the San Juan Generation Plant offset by increases in depreciation and reductions in construction in progress.

Current assets increased by approximately $0.6 million in 2015 when compared to 2014. The change is primarily due to a decrease in both cash and cash equivalents – unrestricted and member receivables offset by an increase in cash and cash equivalents – restricted.

Capital assets decreased by $9.6 million in 2014 when compared to 2013 due to increases in plant in service for the San Juan Generation Plant offset by increases in depreciation and reductions in construction in progress.

Other assets and investments increase in 2015 by $0.6 million when compared to 2014. The change reflects an increase in cash and investments – restricted for the San Juan Reclamation Trust of approximately $3.1 million offset by changes in transmission rights, financial derivatives, unamortized debt issuance expenses of $2.5 million.

Other assets and investments decreased in 2014 by $4.8 million when compared to 2013. The change reflects a reduction in cash and investments – restricted due to the 2007K bonds being paid off. Other additional changes include market adjustment for financial derivatives and decrease in unamortized debt issuance expenses.

Current assets increased by $6.9 million in 2014 when compared to 2013. The change is primarily due to an increase in cash and cash equivalents – unrestricted, cash and cash equivalents – restricted, and member receivables offset by reductions in accounts receivables due from the San Juan Generation Plant.

Deferred outflow of Resources - Unamortized loss on refunding decreased by $2.5 million in 2015 when compared to 2014 and $2.8 million in 2014 when compared to 2013. Changes reflect amounts being charged as current year non-operating expenses, amortization of premium. Reductions will continue until the unamortized loss on refunding as been fully amortized.

Page 5



Liabilities and Net Position

Long-Term Debt

Non-Current Liabilities

Current Liabilities

Net Position

Current liabilities increased by $1.9 million in 2014 when compared to 2013 due to increases in the current portion of long-term debt offset by reductions in accounts payable and interest payable.

Net position is classified into four components – net investment in capital assets, restricted for debt service, restricted for coal mine obligations, and unrestricted. The largest portion of the Agency’s net position each year represents its net investment in capital assets (e.g., the San Juan Generation Plant). The Agency’s deficit net investment in capital assets improved by $21.1 million moving from a deficit of $109.7 million in 2014 to a deficit of $88.6 million in 2015.

The Agency’s net position represents resources that have use restrictions under the Agency bond resolutions. The restricted for debt services increased in 2015 by $13.2 million when compared to 2014. Restricted for debt services increased in 2014 by $1.6 million when compared to 2013. The changes are the result of increases in restricted cash for scheduled bond payments.

Unrestricted net position may be used to meet any of the Agency’s ongoing obligations. Unrestricted net position decreased by $14.9 million in 2015 when compared to 2014 as a result of the changes mentioned previously. Unrestricted net position increased in 2014 when compared to 2013 by approximately $3.4 million.

Long-term debt decreased by $27.8 million in 2015 when compared to 2014 and by $29.6 million in 2014 when compared to 2013. In 2013, the Agency initiated a direct purchase of the 1997D Bonds with Wells Fargo reducing long-term debt by $8.0 million. The remaining decrease for both years is the result of the Agency paying scheduled debt service payments.

Non-current liabilities decreased by $2.1 million in 2015 when compared to 2014. The change reflects reductions in unamortized premium and coal obligations and market adjustments of the liability related to financial derivatives.

Non-current liabilities decreased by $0.5 million in 2014 when compared to 2013. The change reflects a reduction in unamortized premium and coal obligations offset by changes in market adjustments of the liability related to financial derivatives and asset retirement obligations.

Current liabilities decreased by $3.4 million in 2015 when compared to 2014 due to decreases in the accounts payable, current portion of long-term debt, interest payable, and the current portion of the coal mine obligations.

Page 6



Operating Revenue

Operating Expenses

Investment Income

Interest Expense

STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION

Investment income increased in 2015 by $0.1 million and increased in 2014 by $0.1 million respectively, due to market conditions.

Operating expenses increased by $5.0 million for 2014 as compared to 2013. This was due primarily to an increase in purchase power of $3.4 million and transmission of $1.8 million offset by a decrease in power generation of $0.25 million.

Operating expenses decreased by $12.3 million for 2015 as compared to 2014. This was primarily due to decreases in purchase power of $7.6 million, power generation of $1.4 million, and transmission of $3.5 million offset by increases in administration and general, depreciation and amortization, and renewables of $0.2 million.

Operating revenues for 2015 decreased $10.3 million when compared to 2014. The decrease was primarily due to MSR members not being billed for San Juan capital projects in the amount of approximately $2.4 million and decreases in purchase power of renewables from Big Horn I & II of approximately $7.9 million. Operating revenues were $139.3 million and $149.6 million in 2015 and 2014, respectively.

Operating revenues for 2014 decreased $7.0 million when compared to 2013. The decrease was primarily due to MSR members not being billed for San Juan capital projects in the amount of approximately $10.7 million and decreases in purchased power of approximately $3.4 million. Operating revenues were $149.6 million and $156.6 million in 2014 and 2013, respectively.

Operating Revenues and Expenses

Non-Operating Revenue (Expenses)

Interest expense decreased by $1.0 million in 2015 compared to 2014 and by $2.6 million in 2014 compared to 2013. Both decreases were due to principal payments lowering the amount of debt outstanding at year end.

Other expense has continued to remain relatively unchanged for 2014 as compared to 2013.

Operating revenues for the Agency include billings to its members for power received and their respective portions of administrative and operating expenses.

Other non-operating revenue (expense) has continued to remain relatively unchanged with approximately $1.1 million decrease for 2015 as compared to 2014. The decrease was due to changes in the regulatory costs collected through rates, amortization of loss on refunding, and loss of disposal of assets offset by reductions in amortization of premium.

Other Non-operating Revenue (Expense)

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Distribution to Members

This financial report is designed to provide our customers, investors, and creditors with a general overview of the Agency's finances. If you have questions about this report or need additional information, please contact the Controller's Office at P.O. Box 4060, Modesto, CA 95352

Contacting the M-S-R Public Power Agency

The Agency made no distributions to members in 2015, 2014, and 2013.

Page 8


BALANCE SHEETSAs of December 31, 2015 and 2014

ASSETS AND DEFERRED OUTFLOWS 2015 2014

CAPITAL ASSETSPlant in service 354,734$ 354,365$ Less: Accumulated depreciation (239,295) (229,076)

Plant in Service - Net 115,439 125,289 Construction work in progress 3,646 3,734

Total Capital Assets 119,085 129,023

OTHER ASSETS AND INVESTMENTS Cash and investments - restricted 21,689 18,616 Investments - unrestricted 2,647 2,699 Interest receivable - restricted 88 10 Transmission rights 3,892 4,448 Regulatory costs for future recovery 15,877 17,843

Total Other Assets and Investments 44,193 43,616

CURRENT ASSETS Cash and cash equivalents - unrestricted 13,928 25,990 Cash and cash equivalents - restricted 30,992 18,268 Interest receivable - unrestricted 72 73 Member receivables 14,267 14,374 Prepayments 344 335 Other current assets 3,185 3,204

Total Current Assets 62,788 62,244

DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding 7,415 9,868

TOTAL ASSETS AND DEFERRED OUTFLOWS 233,481$ 244,751$

(Dollars in Thousands)

Page 9

LIABILITIES AND NET POSITION 2015 2014

NONCURRENT LIABILITIES Long-term debt, net of current portion 206,465$ 234,335$ Unamortized premium 2,455 3,322 Asset retirement obligations 15,533 14,783 Coal mine obligations, net of current portion 1,721 1,878 Derivative financial instruments 14,705 16,445 Other noncurrent liabilities 57 56

Total Noncurrent Liabilities 240,936 270,819

CURRENT LIABILITIES Accounts payable and other accruals 8,895 10,028 Current liabilities payable from restricted assets

Current portion of long-term debt 27,870 29,560 Interest payable 3,491 3,844 Current portion of coal mine obligations 520 769

Total Current Liabilities 40,776 44,201

NET POSITION Net investment in capital assets (88,601) (109,710) Restricted for debt service 27,589 14,434 Restricted for coal mine obligation 2,717 - Unrestricted 10,064 25,007

Total Net Position (48,231) (70,269)

TOTAL LIABILITIES AND NET POSITION 233,481$ 244,751$


See accompanying notes to financial statementsPage 10


STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITIONFor the Years Ended December 31, 2015 and 2014

2015 2014

OPERATING REVENUES Sales of electric energy 139,299$ 149,637$

OPERATING EXPENSES Purchased power 43,791 51,360 Generation 43,992 45,383 Transmission 3,978 7,516 Renewable 850 844 Administrative and general 578 537 Depreciation and amortization 11,736 11,594

Total Operating Expenses 104,925 117,234

Operating Income 34,374 32,403

NONOPERATING INCOME (EXPENSE) Investment income 304 230 Interest expense (10,784) (11,845) Regulatory costs collected through rates (226) (523) Amortization of premium 866 1,057 Amortization of loss on refunding (2,453) (2,943) Loss on disposal of assets (43) (469)

Total Nonoperating Expenses (12,336) (14,493)

CHANGE IN NET POSITION 22,038 17,910

NET POSITION - Beginning of Year (70,269) (88,179)

NET POSITION - END OF YEAR (48,231)$ (70,269)$


See accompanying notes to financial statements.Page 11


STATEMENTS OF CASH FLOWSFor the Years Ended December 31, 2015 and 2014

2015 2014

CASH FLOWS FROM OPERATING ACTIVITIES Receipts from electric customers 139,407$ 150,803$ Paid to suppliers for goods and services (94,321) (106,729) Payments for coal mine obligations (545) (354)

Net Cash Flows Provided by Operating Activities 44,541 43,720

CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES Repayment of long-term debt (29,560) (26,435) Debt issuance costs - (140) Construction expenditures (388) (680) Interest paid (11,137) (12,336)

Net Cash Flows Used in Capital and Related Financing Activities (41,085) (39,591)

CASH FLOWS FROM INVESTING ACTIVITIES Purchases of investments (58,786) (49,509) Sales of investments 57,099 49,908 Interest received 386 184

Net Cash Flows Provided by (Used in) Investing Activities (1,301) 583

Net Change in Cash and Cash Equivalents 2,155 4,712

CASH AND CASH EQUIVALENTS - Beginning of Year 42,753 38,041

CASH AND CASH EQUIVALENTS - END OF YEAR 44,908$ 42,753$

SUPPLEMENTAL DISCLOSURE OF NONCASH ACTIVITIES Change in derivative valuation 1,740$ (367)$

Loss on disposal of assets (43)$ (469)$

Amortization (1,813)$ (2,409)$ Long-term debt advance refunded -$ 55,600$

Unrealized gain (loss) on investments (159)$ (50)$



2015 2014

RECONCILIATION OF OPERATING INCOME TO NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES Operating income 34,374$ 32,403$ Adjustments to reconcile operating income to net cash flows provided by operating activities Depreciation and amortization 11,736 11,594 Change in operating assets and liabilities Member receivables 107 (1,488) Other accounts receivable - 2,624 Prepayments 4 (7) Other current assets 6 (80) Accounts payable and other accruals (1,141) (1,002) Other noncurrent liabilities 1 30 Coal mine obligations (546) (354)

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 44,541$ 43,720$

RECONCILIATION OF CASH AND CASH EQUIVALENTS TO BALANCE SHEET ACCOUNTS Cash and cash equivalents - unrestricted 13,928$ 25,990$ Cash and cash equivalents - restricted 30,992 18,268 Cash and investments - restricted 21,689 18,616 Investments - unrestricted 2,647 2,699

Total Cash and Investments 69,256 65,573 Less: Noncash equivalents 24,348 22,820

CASH AND CASH EQUIVALENTS 44,908$ 42,753$




NOTES TO FINANCIAL STATEMENTS As of and for the Years Ended December 31, 2015 and 2014


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NOTE 1 – ORGANIZATION AND DESCRIPTION OF BUSINESS M-S-R Public Power Agency (the Agency) is a California joint powers agency composed of the Modesto Irrigation District, and the Cities of Santa Clara (Silicon Valley Power) and Redding, California (Members). The Agency manages electric power generation and transmission resources for the benefit of its Members. The personnel of its Members and professional staff contracted by the Agency perform the administrative and management functions of the Agency. The Agency is managed by a Commission made up of personnel from the individual Members. The Agency is exempt from payment of federal and state income taxes. The Members pay for the costs associated with the operation of the Agency in the following percentages: Modesto Irrigation District - 50%; Silicon Valley Power - 35%; and City of Redding - 15%. The activities of the Agency consist principally of a 28.8% ownership interest in the 507-megawatt unit No. 4 of a coal-fired electricity generating plant, located in New Mexico (the San Juan plant). The San Juan plant is jointly owned by the Public Service Company of New Mexico (PNM) (38.5%), the Agency (28.8%) and other municipal power entities (32.7%). The Agency is also a participant in the Southwest Transmission Project, a 500-kilovolt alternating current transmission project between Central Arizona and Southern California, which provides firm transmission from the San Juan plant into California. The Agency has transmission contracts to complete the path to bring power to the Members’ distribution systems. The Members share in the income and expense of the San Juan Plant and the Southwest Transmission Project in the ratio of the Agency ownership percentages. In 2006, the Agency entered into a Wholesale Purchase and Sale Agreement and a Shaping and Firming Agreement with Iberdrola Renewables, Inc. to provide renewable wind energy to the Members from the Big Horn Wind Project (Big Horn). The Member income and expense sharing ratio for Big Horn is as follows: Modesto Irrigation District - 12.5%; Silicon Valley Power - 52.5%; and City of Redding - 35.0%. In 2009, the Agency entered into a Power Purchase Agreement and Redelivery Agreement with Iberdrola Renewables, Inc. to provide renewable wind energy to the Members from the Big Horn II Wind Project (Big Horn II). The Member income and expense sharing ratio for Big Horn II is as follows: Modesto Irrigation District – 65.0%; Silicon Valley Power – 35.0%; and City of Redding – 0.0%. NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The financial statements of the Agency have been prepared in conformity with accounting principles generally accepted in the United States of America. The Governmental Accounting Standards Board (GASB) is the accepted standard-setting body for establishing governmental accounting and financial reporting principles. The significant accounting principles and policies utilized by the Agency are described below. METHOD OF ACCOUNTING The financial statements are reported using the economic resources measurement focus and the accrual basis of accounting. Under the accrual basis of accounting, revenues are recognized when earned and expenses are recorded when the liability is incurred or economic asset used. Revenues, expenses, gains, losses, assets and liabilities resulting from exchange and exchange-like transactions are recognized when the exchange takes place.




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NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont.)

METHOD OF ACCOUNTING (cont.) Presentation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. CASH AND CASH EQUIVALENTS Cash equivalents include all debt instruments with maturity dates of 90 days or less from the date of purchase and all investments in the Local Agency Investment Fund (LAIF), and money market mutual funds. LAIF has an equity interest in the State of California Pooled Money Investment Account (PMIA). PMIA funds are on deposit with the State’s Centralized Treasury System and are managed in compliance with the California Government Code, according to a statement of investment policy which sets forth permitted investment vehicles, liquidity parameters and maximum maturity of investments. The PMIA cash and investments are recorded at amortized cost which approximates market. The Agency’s deposits with LAIF are generally available for withdrawal on demand. INVESTMENTS Generally, all investments are carried at their fair market value. Market values may have changed significantly after year-end. MEMBER RECEIVABLES Member receivables include charges to the Members for power sales, transmission and operational charges. RESTRICTED ASSETS Mandatory segregations of assets are presented as restricted assets. Such segregations are required by bond agreements and other external parties. Current liabilities payable from these restricted assets are so classified. PREPAYMENTS The balance represents payments to vendors for costs applicable to future accounting periods. OTHER CURRENT ASSETS Other current assets include the Agency’s ownership interest in coal, supplies and other items associated with the operation of the San Juan plant, which are stated at cost, determined using the average cost method.




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PRELIMINARY SURVEY AND INVESTIGATION The balance represented initial project engineering costs related to plant construction. The balance was written off to expense in 2014 as the Agency will not be participating in the project. REGULATORY COSTS FOR FUTURE RECOVERY As a regulated entity, the Agency’s financial statements are prepared in accordance with GASB Statement No. 62, Codification of Accounting and Financial Reporting Guidance Contained in Pre - November 30, 1989 FASB and AICPA pronouncements, which require that the effects of the rate-making process be recorded in the financial statements. Accordingly, certain expenses and credits, normally reflected in the Change in Net Position as incurred, are recognized when included in rates and recovered from, or refunded to, the member communities. The Agency records regulatory assets and credits to reflect rate-making actions of the Commission. The account includes the fair value of ineffective investment derivatives held by the Agency and unamortized debt issuance costs of previously issued bonds. CAPITAL ASSETS Capital assets represent the Agency’s ownership portion of the San Juan plant and Southwest Transmission Project. Utility plant is stated at cost, net of accumulated depreciation. Costs and related accumulated depreciation of assets sold or otherwise disposed of are eliminated from the accounts and related gains or losses are included in the statements of revenues, expenses and changes in net position. The costs of replacement assets are charged to utility plant. Repair and maintenance costs are charged to expense in the period incurred. Interest costs incurred, plus amortization of deferred debt issue costs and related bond discounts/premiums, less any related interest earned during periods of construction of utility plant assets, are capitalized at a rate based on the Agency’s tax-exempt borrowings related to that construction. No interest was capitalized in 2015 or 2014. Depreciation is computed using the straight-line method over the useful lives of the assets, which generally range from 15 to 35 years. TRANSMISSION RIGHTS In accordance with an agreement with the Tucson Electric Power Company, the Agency has the right to certain levels of power exchange without charge and without transmission losses between the San Juan plant in New Mexico and the Palo Verde, Moenkopi, and Westwing substations located in Arizona through 2025. These rights are being utilized in connection with the delivery of power from the San Juan plant to the Members or third party purchasers and are being amortized on a straight-line basis over the life of the agreement. DEFERRED OUTFLOWS OF RESOURCES A deferred outflow of resources represents a consumption of net position that applies to a future period and will not be recognized as an outflow of resources (expense/expenditure) until that future time.




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OTHER NONCURRENT LIABILITIES Other noncurrent liabilities include the Agency’s ownership interest in the emission and groundwater reserve associated with the operation of the San Juan plant. ASSET RETIREMENT OBLIGATIONS The Agency follows the Accounting Standards Codification (ASC) of the Financial Accounting Standards Board related to asset retirement obligations (ARO). An ARO is recorded only when legally binding retirement obligations exist under enacted laws, statutes, written contracts or oral contracts, including obligations arising under the doctrine of promissory estoppel. Fair value is determined based on quoted prices or discounted cash flows using the probability-weighted future cash flows for the associated retirement costs, and a credit-adjusted risk-free discount rate. Upon initial recognition, an ARO is recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Annual accretions of ARO liabilities are recorded as operating expenses and the capitalized costs are depreciated over the useful life of the related long-lived assets. Upon settlement of the liability, a gain or loss is recorded. ARO amounts recorded are subject to various assumptions and determinations, such as determining whether an obligation exists to remove assets, estimating the fair value of the costs of removal and estimating when final removal will occur. Changes that may arise over time with regard to these assumptions and determinations will change such amounts recorded for asset retirement obligations. The Agency’s ARO liabilities are generally associated with the San Juan facility. The Agency recognized accretion expenses associated with these ARO liabilities totaling $750 and $713 for the years ended December 31, 2015 and 2014, respectively. In 2013 the Agency was informed that PNM had begun the process of again updating its ARO valuation studies related to the San Juan facility. The San Juan Decommissioning and Trust Funds Agreement, further identified in Note 10, provides that a projected decommissioning costs review be performed during the year 2022 and every five years thereafter. The Agency expects the range of alternative decommissioning scenarios contained in these new studies to be inclusive of the values identified in the 2012 study. The ARO could be materially different once these studies are complete and finalized. The Agency has identified potential asset retirement obligations related to its ownership interest in the Southwest Transmission Project located on properties that do not have perpetual lease rights. The Agency’s non-perpetual leased land rights generally are renewed continuously because the Agency intends to utilize these facilities indefinitely. Since the timing and extent of any potential asset retirements are unknown, the fair value of any obligations associated with these facilities cannot be reasonably estimated. Accordingly, a liability has not been recorded at December 31, 2015 and 2014. The Agency has no other potential asset retirement obligations that represent a material ARO.




Page 18


COAL MINE RECLAMATION OBLIGATIONS The Agency’s Early Purchase and Participation Agreement obligate the Agency to pay for mine reclamation costs. Similar to the Agency’s accounting for ARO obligations, contract related liabilities associated with the San Juan mine reclamation activities are recognized at their fair value. The Agency currently estimates that reclamation activities will likely extend through to at least 2053 at which time all mines may be fully reclaimed and the Agency’s obligations under the contracts will be terminated. Payments for coal mine reclamation obligations were $545 and $354 for the years ended December 31, 2015 and 2014, respectively. Annual accretions of ARO liabilities are recorded as operating expenses. The Agency recognized accretion expenses associated with these liabilities totaling $139 and $140 for the years ended December 31, 2015 and 2014, respectively. LONG-TERM DEBT Long-term debt and other obligations are reported as liabilities. Bond premiums and discounts are amortized over the life of the bonds using the effective interest rate method. Gains or losses on prior refundings are amortized over the remaining life of the old debt or the life of the new debt, whichever is shorter. The balance at year end for premiums and discounts is shown as an increase or decrease in the liability section of the balance sheet. The balance at year end for the loss on refunding is shown as a deferred outflow in the balance sheet. NET POSITION GASB Statement No. 34 requires the classification of net position into three components — net investment in capital assets; restricted; and unrestricted. These classifications are defined as follows:

Net investment in capital assets — This component of net position consists of capital assets, net of accumulated depreciation and reduced by the outstanding balances of any bonds, mortgages, notes, or other borrowings that are attributable to the acquisition, construction, or improvement of those assets. If there are significant unspent related debt proceeds at year-end, the portion of the debt attributable to the unspent proceeds is not included in the calculation of net investment in capital assets. Rather, that portion of the debt is included in the same net position component as the unspent proceeds. Restricted – This component of net position consists of constraints placed on net asset use through external constraints imposed by creditors (such as through debt covenants), grantors, contributors, or laws or regulations of other governments or constraints imposed by law through constitutional provisions or enabling legislation. Unrestricted – This component of net position consists of net position that does not meet the definition of “restricted” or “net investment in capital assets.”

When both restricted and unrestricted resources are available for use, it is the Agency’s policy to use restricted resources first, then unrestricted resources as they are needed.




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REVENUES AND EXPENSES The Agency distinguishes operating revenues and expenses from nonoperating items. Operating revenue is comprised of billings to its Members for the cost of the power received from the Agency. Operating expenses include the cost of sales and services, administrative expenses, and depreciation on capital assets. The Members are billed for actual costs and the associated revenue is recognized as these costs are incurred. All revenues and expenses not meeting this definition are reported as nonoperating revenues and expenses. NOTE 3 – CASH AND INVESTMENTS The Agency’s investment policies are governed by the California Government Codes and its bond Indenture, which restricts the Agency’s investment securities to obligations which are unconditionally guaranteed by the U.S. Government or its agencies or instrumentalities; direct and general obligations of the State of California (State) or any local agency within the State; bankers’ acceptances; commercial paper; certificates of deposit; interest bearing time deposits in California banks; repurchase agreements; medium-term corporate notes; shares of beneficial interest; mortgage pass-through securities; financial futures and financial option contracts; and deposits with the Local Agency Investment Fund (LAIF). Investments in LAIF are unregistered, pooled funds. LAIF is a component of the Pooled Money Investment Account Portfolio managed by the State Treasurer, in accordance with Government Code Sections 16430 and 16480. The fair value of the Agency’s Investments in LAIF approximates the value of its pool shares. The Agency’s investment policy includes restrictions for investments relating to maximum amounts invested as a percentage of total portfolio and with a single Issuer, maximum maturities, and minimum credit ratings; except for investments in U.S. and Federal agency securities, which are not limited. In addition, the investment policy requires all securities to be held in safekeeping by a third party custodian, acting as agent for the Agency under the terms of a custody agreement. Deposits in each local and area bank are insured by the FDIC in the amount of $250 for time and savings accounts (including NOW accounts), and $250 for demand deposit accounts (interest bearing and noninterest bearing). In addition, if deposits are held in an institution outside of the state in which the government is located, insured amounts are further limited to a total of $250 for the combined amount of all deposit accounts. Custodial Credit Risk Deposits Custodial credit risk is the risk that in the event of a financial institution failure, the Agency’s deposits may not be returned to the Agency. The Agency does not have any deposits exposed to custodial credit risk. The Agency’s investment policy addresses this risk.




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NOTE 3 – CASH AND INVESTMENTS (cont.)

Custodial Credit Risk (cont.) Investments For an investment, custodial credit risk is the risk that, in the event of the failure of the custodian, the Agency will not be able to recover the value of its investments or collateral securities that are in the possession of an outside party. As of December 31, 2015 and 2014, the Agency’s investments were exposed to custodial credit risk as follows: Neither Insured nor Registered and Held by the Custodian’s Trust Department or Agent in the Agency’s Name 2015 2014 US Agencies Explicitly Guaranteed $ 16,724 $ 3,256Corporate Medium Term Notes 5,041 5,094U.S. Treasury Notes 1,479 1,511 Totals $ 23,244 $ 9,861 The Agency’s investment policy addresses this risk. Credit Risk Credit risk is the risk an issuer or other counterparty to an investment will not fulfill its obligations. As of December 31, 2015 and 2014, the Agency’s investments were rated as follows:

Investment Type Standard & Poors

2015 Standard & Poors

2014 Local Agency Investment Fund NR NR Money Market Mutual Funds AAAm AAAm Corporate Medium Term Notes AA+, A AA+, A+ The Agency’s investment policy addresses this risk. To mitigate the risk that an issuer of an investment will not fulfill its obligation to the holder of the investment, the Agency limits investments to those rated, at a minimum, “A” for medium-term notes and “A1” for commercial paper, or equivalent, by a nationally recognized rating agency.




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Concentration of Credit Risk Concentration of credit risk is the risk of loss attributed to the magnitude of an entity’s investment in a single issuer. At December 31, 2015 and 2014, the Agency’s investment portfolio was concentrated as follows:

Percentage of Portfolio Investment Type 2015 2014

GE Capital Corporation Notes 4.44% 5.10% The Agency’s investment policy addresses this risk. The Agency will diversify its investments by security type, issuer and maturity. With the exception of U.S. Treasury Securities, U.S. Agency and U.S. Government-sponsored enterprises, no more than 40% of the total investment portfolio will be invested in a single security type or with a single financial institution and no more than 15% of the total investment portfolio will be placed with any one issuer. Interest Rate Risk Interest rate risk is the risk changes in interest rates will adversely affect the fair value of an investment. As of December 31, 2015, the Agency’s investments were as follows: Maturity (In Years)

Investment Type

Fair Value Less than 1

Year 1 to 5 Years Greater than

5 Years Local Agency Investment Fund $ 8,698 $ 8,698 $ - $ -Money Market Mutual Fund 36,757 36,757 - -U.S. Agencies Explicitly Guaranteed 16,724 - 1,997 14,727Corporate Medium Term Notes 5,041 - 5,041 -U.S. Treasury Notes 1,479 - 1,479 - Totals $ 68,699 $ 45,455 $ 8,517 $ 14,727

As of December 31, 2014, the Agency’s investments were as follows: Maturity (In Years)

Investment Type

Fair Value Less than 1

Year 1 to 5 Years Greater than

5 Years Local Agency Investment Fund $ 16,642 $ 16,642 $ - $ -Money Market Mutual Fund 34,395 34,395 - -U.S. Agencies Explicitly Guaranteed 3,256 - 3,256 -Corporate Medium Term Notes 5,094 - 5,094 -U.S. Treasury Notes 1,511 - 1,511 - Totals $ 60,898 $ 51,037 $ 9,861 $ -




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Interest Rate Risk (cont.) Though the Agency has restrictions as to the maturities of some of the investments, it does not have a formal policy that limits investment maturities as a means of managing its exposure to fair value losses arising from increase interest rates. NOTE 4 – RESTRICTED ASSETS DEBT RELATED ACCOUNTS Certain proceeds of the Agency’s debt, as well as certain resources set aside for their repayment, are classified as restricted assets on the balance sheet because their use is limited. The following accounts are reported as restricted assets:

Redemption - Used to segregate resources accumulated for debt service payments over the next twelve months.

Reserve - Used to report resources set aside to make up potential future deficiencies in the redemption account.

RESERVE AND CONTINGENCY The bond resolution establishes a reserve and contingency fund equal to 10% of the amount required to be deposited in the redemption fund for the next ensuing twelve months. SAN JUAN COAL MINE RECLAMATION RESERVE In 2012 the Agency entered into the Mine Reclamation and Trust Funds agreement among the San Juan project participants whereby each participant establish a trust funded according to a funding curve schedule in order to ensure funds available to pay its proportionate share of reclamation costs. The Mine Reclamation and Trust Funds Agreement was superseded by the Amended and Restated Mine Reclamation and Trust Funds Agreement which became effective January 31, 2016.

Carrying Value as of

December 31, 2015

Carrying Value as of

December 31, 2014

Restricted Accounts Reserve fund $ 12,340 $ 12,277 Redemption fund 30,992 18,268 San Juan coal mine reclamation reserve fund

4,958

1,948

Reserve and contingency fund 4,391 4,391 Total Restricted Accounts $ 52,681 $ 36,884




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NOTE 5 – UTILITY PLANT A summary of changes in capital assets for 2015 follows: Balance Balance 1/1/15 Increases Decreases 12/31/15 Capital assets being depreciated

San Juan plant in service $ 276,114 $ 367 $ 115 $ 276,366 Southwest transmission project 78,251 117 - 78,368

Total Capital Assets Being Depreciated 354,365 484 115 354,734

Less: Accumulated depreciation (229,076) (10,292) (73) (239,295) Construction in progress 3,734 396 484 3,646 Net Capital Assets $ 129,023 $ 119,085 A summary of changes in capital assets for 2014 follows: Balance Balance 1/1/14 Increases Decreases 12/31/14 Capital assets being depreciated

San Juan plant in service $ 275,114 $ 2,466 $ 1,466 $ 276,114 Southwest transmission project 78,201 50 - 78,251

Total Capital Assets Being Depreciated 353,315 2,516 1,466 354,365

Less: Accumulated depreciation (219,889) (10,184) (997) (229,076) Construction in progress 5,141 1,109 2,516 3,734 Net Capital Assets $ 138,567 $ 129,023




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NOTE 6 – LONG-TERM DEBT As of December 31, 2015 the following bonds are outstanding.

Date Purpose Final

Maturity Interest

Rate Original Amount

Outstanding Amount 12/31/15

3/30/04 Series 1997D 7/1/18 3.88 – 4.30% $ 65,000 $ -

Subordinate Lien Bonds 12/4/07 Series 2007K 7/1/14 4.00 – 5.00 48,305 -

Subordinate Lien Bonds 7/24/08 Series 2008L 7/21/22 4.00 – 5.00 118,865 103,655

Subordinate Lien Bonds 7/24/08 Series 2008M 7/21/22 Variable 62,500 62,500

Subordinate Lien Bonds 7/24/08 Series 2008N 7/21/20 Variable 17,000 17,000

Subordinate Lien Bonds 4/26/11 Series 2011O 7/1/18 2.93 – 4.35 34,050 11,970

Subordinate Lien Bonds 9/20/13 Series 2013P 7/1/18 1.20 – 1.70 57,485 -

Subordinate Lien Bonds 4/2/2014 Series 2014Q 7/1/18 1.20 55,600 39,210

Subordinate Lien Bonds In 2014, the Series D and Series K Subordinate Lien Bonds were paid off. Also during 2014, Series 2013P bonds were partially refunded by Series 2014Q bonds. In 2015, the Series 2013P Subordinate Lien Bonds were paid off. Revenue bonds debt service requirements to maturity follows: Year Ending December 31 Principal Interest Total

2016 $ 27,870 $ 10,386 $ 38,256 2017 28,540 8,714 37,2542018 27,880 8,984 36,8642019 28,555 7,695 36,2502020 29,985 6,268 36,2532021 - 2022 91,505 6,672 98,177

Totals $ 234,335 $ 48,719 $ 283,054 All Agency revenues net of specified operating expenses are pledged as security of the above revenue bonds until the bonds are defeased. Principal and interest paid for 2015 and 2014 was $40,697 and $38,771, respectively. Total customer gross revenues as defined for the same period were $139,762 and $149,958, respectively. Annual principal and interest payments are expected to require 29% of gross revenues on average.




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NOTE 6 – LONG-TERM DEBT (cont.)

Interest payments for variable rate debt include the effects of the payments related to the interest rate swaps. For the Agency’s other variable rate debt, interest payments are computed using the rate in effect as of December 31. PLEDGE OF MEMBERS The net electric revenue of the Agency is pledged for repayment of Revenue Bonds, supported by take-or-pay commitments of the Members. GENERAL TERMS The Subordinated Lien Revenue Bonds are subordinate to all future and existing Senior Lien Bonds. Currently, the only senior lien bonds were the Series F San Juan Project Revenue Bonds, which were paid off in 2014. All series of bonds paying interest at a fixed rate are payable on January 1 and July 1. Variable rate bonds pay interest on a monthly basis. The variable-rate demand bonds (VRDB’s) had variable rates of 0.57% and 0.52% for the Series 2008M bonds and 0.82% and 0.75% for the Series 2008N bonds at December 31, 2015 and 2014, respectively. Prior to a fixed rate conversion date or refunding which is determinable by the Agency, the VRDB’s are subject to tender for purchase at the option of the bondholder. The Agency has the ability to refinance, on a long-term basis, the outstanding VRDB’s upon tender. The portion that would be due in the subsequent fiscal year in the event that the VRDB’s were tendered and not remarketed was $79,500 at December 31, 2015 and 2014. The bonds are currently held by Wells Fargo Bank, National Association, as a participant holder under the Depository Trust Company Corporation (DTCC). The Agency is in compliance with required bond covenants. The Agency has outstanding debt obligations totaling $61,595 and $67,020 at December 31, 2015 and 2014, respectively, which are defeased and excluded from the Agency’s long-term debt. CURRENT REFUNDING On April 2, 2014, bonds in the amount of $55,600, the 2014Q bonds, were issued with an average interest rate of 1.70% to refund $55,600 of the outstanding 2013P bonds with an average interest rate of 1.30%. The net proceeds were used to prepay the outstanding debt service requirements on the old bonds. The cash flow requirements on the old bonds prior to the current refunding was $57,851 from 2014 through 2018. The cash flow requirements on the new bonds are $57,189 from 2014 through 2018. The current refunding resulted in an economic gain of $585.




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NOTE 6 – LONG-TERM DEBT (cont.)

LONG-TERM OBLIGATIONS SUMMARY Long-term obligation activity for the year ended December 31, 2015 is as follows:

1/1/15 12/31/15 Due Within Balance Additions Reductions Balance One Year

Long-term debt $ 263,895 $ - $ 29,560 $ 234,335 $ 27,870Unamortized premium 3,322 - 867 2,455 -Asset retirement obligations 14,783 750 - 15,533 -Coal mine obligations 2,647 140 546 2,241 520Derivative financial

instrument 16,445 - 1,740 14,705 -Other noncurrent liabilities 56 1 - 57 - Totals $ 301,148 $ 891 $ 32,713 $ 269,326 $ 28,390 Long-term obligation activity for the year ended December 31, 2014 is as follows:

1/1/14 12/31/14 Due Within Balance Additions Reductions Balance One Year

Long-term debt $ 290,330 $ 55,600 $ 82,035 $ 263,895 $ 29,560Unamortized premium 4,379 - 1,057 3,322 -Asset retirement obligations 14,070 713 - 14,783 -Coal mine obligations 2,861 140 354 2,647 769Derivative financial

instrument 16,078 367 - 16,445 -Other noncurrent liabilities 26 30 - 56 - Totals $ 327,744 $ 56,850 $ 83,446 $ 301,148 $ 30,329 FAIR VALUE The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Agency for debt of similar maturities. The recorded and estimated fair value of the Agency’s long-term debt at December 31, 2015 and 2014 is as follows:

2015 2014

Carrying amount $ 234,335 $ 263,895Fair value 244,119 278,317




Page 27

NOTE 7 – DERIVATIVE INSTRUMENTS

SUMMARY OF NOTIONAL AMOUNTS AND FAIR VALUES The Agency enters into financial derivative transactions to hedge its exposure to fluctuating interest rates. These agreements are evaluated pursuant to GASB Statement No. 53, Accounting and Financial Reporting for Derivative Instruments, to determine whether they meet the definition of derivative instruments, and, if so, whether they effectively hedge the interest rate exposures. For derivatives deemed ineffective hedges, the Agency applies investment derivative accounting. Under investment derivative accounting, the increase (decrease) in the fair value of derivative instruments is considered revenue (expense) to the Agency. However, Agency has adopted GASB Statement No. 62, Codification of Accounting and Financial Reporting Guidance Contained in Pre-November 30, 1989 FASB and AICPA Pronouncements, under which these revenues (expenses) are deferred as regulatory liabilities (assets). For the reporting period, none of the Agency’s derivatives met the effectiveness tests; therefore, all are considered investment derivatives. Fair values are obtained from the Agency’s counterparties. The Agency verifies these values using a financial information service. The following is a summary of the fair values and notional amounts of derivative instruments outstanding as of December 31, 2015 (amounts in thousands; gains shown as positive amounts, losses as negative).

2015 Change in Fair Value Fair Value, End of 2015 Notional Classification Amount Classification Amount (Thousands)Investment Derivative Instruments:

Pay-fixed swaps, interest rate

Regulatory asset

$ 1,740 Derivatives $ (14,705) $ 79,500

The following is a summary of the fair values and notional amounts of derivative instruments outstanding as of December 31, 2014 (amounts in thousands; gains shown as positive amounts, losses as negative).

2014 Change in Fair Value Fair Value, End of 2014 Notional Classification Amount Classification Amount (Thousands)Investment Derivative Instruments:


Regulatory asset

$ (367) Derivatives $ (16,445 ) $ 79,500




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NOTE 7 – DERIVATIVE INSTRUMENTS (cont.)

OBJECTIVES AND TERMS OF DERIVATIVE INSTRUMENTS

The objectives and terms of the Agency’s derivative instruments that were outstanding at December 31, 2015 are summarized in the table below (if a counterparty has multiple ratings, the rating indicating the greatest risk is shown using the Standard & Poor’s scale). The interest rate swaps were originally designed to synthetically fix the cash flows associated with the Agency’s 1998F and 1998G bonds. The 1998F and 1998G bonds were refunded in 2008 and replaced with 2008M and 2008N bonds. The Agency left the swaps in place after the refunding because the notional amounts and maturities match the new bonds. However, the interest rate indices are not an exact match, giving rise to the ineffectiveness classification. The Agency pays a daily interest rate on the 2008M bonds while receiving 70% of one-month LIBOR on the associated swap. On the 2008N bonds, the Agency pays a weekly interest rate while receiving 100% of one-month LIBOR. Netting the swaps and bonds, the Agency pays 4.48% on the 2008M series plus or minus any mismatch between daily rates and 70% of one-month LIBOR, and 5.97% on the 2008N series plus or minus any mismatch between weekly rates and one-month LIBOR.

Type

Objective

Notional

(Thousands)Effective

Date Maturity

Date Terms

Counterparty

Rating Pay-fixed swaps, interest rate

Hedge cash flows on the 2008M bonds

$ 62,500

Nov-98

July-22

Pay 4.48%; Receive 70% of 1-month LIBOR

A


Hedge cash flows on the 2008N bonds

17,000

Nov-98

July-20

Pay 5.97%; Receive 1-

month LIBOR

A

RISKS OF DERIVATIVE INSTRUMENTS Credit risk – Credit risk is the risk of loss due to a counterparty defaulting on its obligations. The Agency seeks to minimize credit risk by transacting only with high credit counterparties. The Agency has the same counterparty on both of the interest rate swaps. As of December 31, 2015 and 2014, the mark-to-market value of the swaps is in the counterparty’s favor; therefore, the Agency would not experience a credit loss if the counterparty failed to perform. The Agency uses industry standard agreements to document derivative transactions. These agreements include netting clauses whereby, if the Agency and the counterparty owe each other payment, the party owing the greater amount pays the net. The Agency can also demand the counterparty to post collateral if the mark-to-market value is in the Agency’s favor and the counterparty has had its credit ratings downgraded below a threshold level. These conditions not being met, the Agency held no collateral on the derivatives as of December 31, 2015 and 2014. The Agency is not required to post collateral if the mark-to-market value is in the counterparty’s favor. Termination risk – Termination risk is the risk that a derivative will terminate prior to its scheduled maturity due to a contractual event. Contractual events include bankruptcy, illegality, default, mergers in which the successor entity does not meet credit criteria, and severe rating downgrades. One aspect of termination risk is that the Agency would lose the hedging benefit of a derivative that becomes subject to a termination event. Another aspect of termination risk is that, if at the time of termination the mark-to-market value of the derivative was a liability to the Agency, the Agency could be required to pay that amount to the counterparty. Termination risk is associated with all of the Agency’s derivatives.




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NOTE 7 – DERIVATIVE INSTRUMENTS (cont.)

RISKS OF DERIVATIVE INSTRUMENTS (cont.) Interest rate basis risk – Basis risk is the risk that arises when a hedged item and a derivative intended to hedge that item are based on different indices. As discussed above in Objectives and Terms of Derivative Instruments, the Agency uses interest rate swaps to reduce its exposure to fluctuating interest rates. However, the floating leg payments that the Agency receives on the swaps are based on different indices than the variable rates the Agency pays on the associated bonds. This results in a basis risk that would negatively impact the Agency if the daily and weekly rates on the bonds were to increase relative to the one-month LIBOR rate on the swaps. NOTE 8 – SAN JUAN PLANT AGREEMENTS The Agency’s cost sharing arrangements with PNM and the other owners of the San Juan plant are governed by the San Juan Project Participation Agreement, as amended (the Agreement). In connection with the Agreement, the Agency is financially committed to its proportional interest in various contractual commitments between PNM, the plant operator, and the entities that provide operations and maintenance services to the San Juan plant. The San Juan plant owners, through PNM, have a long-term agreement with San Juan Coal Company (the Company) for underground mining. Pursuant to the Restructuring Agreement, the Agency purchases its coal requirements from PNM through 2017 with specified annual minimum take amounts at a fixed price of $50.00 per ton. At the specified minimum dispatch requirements as based on expected San Juan plant performance, this represents a minimum future commitment of the Agency of approximately $62,000 and $87,000 at December 31, 2015 and 2014, respectively, which is generally expected to be paid ratably over the remaining term of the Restructuring Agreement. NOTE 9 – TRANSACTIONS WITH SIGNIFICANT CUSTOMERS Sales of electric energy consist primarily of sales to its Members, as summarized below for the year ended December 31, 2015 and 2014:

2015 2014 Modesto Irrigation District $ 61,302 $ 65,185 City of Santa Clara 53,495 57,029City of Redding 24,502 27,423 Totals $ 139,299 $ 149,637




Page 30

NOTE 10 – CONTINGENCIES CLEAN AIR ACT - REGIONAL HAZE PROCEEDINGS The U.S. Environmental Protection Agency (the “EPA”) has established rules addressing regional haze (i.e., visibility impairment caused by cumulative air pollutant emissions from numerous sources over a wide geographic area). The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. The rules require Best Available Retrofit Technology (“BART”) to be considered as a control measure on specific categories of certain major stationary sources of haze-producing pollutants in existence prior to the enactment in 1977 of the Clean Air Act amendments addressing regional haze. If a source is found to be BART-eligible, a determination of the source’s contribution to visibility impairment and the resulting emission reductions from the application of BART is conducted. The San Juan Generating Station is a source that is subject to the statutory obligations of the Clean Air Act to reduce visibility impacts. The State of New Mexico submitted a State Implementation Plan (“SIP”) on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from the San Juan Generating Station is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, the EPA published its Federal Implementation Plan (“FIP”), stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the Clean Air Act. The FIP included a regional haze BART determination for the San Juan Generating Station that required installation of selective catalytic reduction technology (“SCR”) with stringent NOx emission limits on all four units by September 21, 2016. PNM, the Governor of New Mexico, and the New Mexico Environment Department (the “NMED”) petitioned the Tenth Circuit to review the EPA’s decision and requested the EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule on March 1, 2012. These parties also formally asked the EPA to stay the effective date of the rule. Several environmental groups intervened in support of the EPA. WildEarth Guardians, an environmental group, also filed an action to challenge the EPA’s rule in the Tenth Circuit, seeking to shorten the rule’s compliance period from five years to three years and PNM intervened in that action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court’s order, the parties filed supplemental information. In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required the EPA to issue a final rulemaking on New Mexico’s regional haze SIP by November 15, 2012. The EPA approved all components of the SIP, except for the NOx BART determination for the San Juan Generating Station. With respect to that element of the SIP, the EPA determined that with the FIP in place, it had met its obligation under the consent decree. Because the then unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at the San Juan Generating Station, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the San Juan Generating Station owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, was suspended through November 1, 2015 and has not been reactivated. At the time of execution of the contract, PNM estimated the total cost to install SCRs on all four units of the San Juan Generating Station to be between approximately $824 million and $910 million, although final costs would be refined through an “open book” subcontractor bidding process.




Page 31

NOTE 10 – CONTINGENCIES (cont.)

CLEAN AIR ACT - REGIONAL HAZE PROCEEDINGS (cont.) During 2012 and early 2013, PNM, as the operating agent for the San Juan Generating Station, engaged in discussions with the NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other San Juan Generating Station owners, PNM, the NMED and the EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at the San Juan Generating Station, subject to approval by the New Mexico Environmental Improvement Board (the “EIB”) and the EPA. The terms of the non-binding agreement would result in the retirement of the San Juan Generating Station Unit Nos. 2 and 3 by the end of 2017 and the installation of SNCRs on Unit Nos. 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP. PNM has estimated the cost of SNCRs along with certain additional equipment (primarily balanced draft conversions) required to be installed to meet certain federal air quality standards to total approximately $149 million for the two remaining units of the San Juan Generating Station. The State of New Mexico submitted SIP revisions on October 7, 2013 and November 5, 2013, pursuant to this agreement. The revised SIP reflects the terms of the nonbinding agreement among PNM, the NMED and the EPA to address the regional haze requirements applicable to the San Juan Generating Station. Following that action, on May 12, 2014, the EPA filed in the Federal Register its proposal to withdraw the FIP that addresses the NOx BART and visibility transport requirements for the San Juan Generating Station and to approve the State of New Mexico’s SIP as revised in 2013, based upon a determination that it adequately addresses the “good neighbor” provisions of the haze regulation. Parties were given 30 days to comment (i.e., by June 11, 2014). On September 26, 2014, the EPA finally approved the revised SIP and withdrew its FIP requiring installation of SCRs on all four units of the San Juan Generating Station by September 21, 2016. Due to the long lead times on certain equipment purchases, PNM began taking steps to prepare for the potential installation of SNCRs on Unit Nos. 1 and 4 as contemplated by the revised plan. In April 2013, PNM issued a request for proposals for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider, but has not yet entered into a construction and procurement contract. PNM, as operating agent, presented the SNCR project to the participants in San Juan Unit Nos. 1 and 4 for approval in late October 2013. The project was approved for Unit No. 1, but the Unit No. 4 project did not obtain the required percentage of votes for approval. Other capital projects related to Unit No. 4 were also not approved by the participants. The San Juan Project Participation Agreement provides that PNM is authorized and obligated to take reasonable and prudent actions, consistent with Prudent Utility Practice, necessary for the successful and proper operation of the San Juan Generating Station pending resolution by the participants. PNM invoked “Prudent Utility Practice” by notices issued March 10, 2015 and July 14, 2015 to fund the Unit 4 Revised SIP Compliance Project through May 1, 2015. Most recently on March 20, 2015, PNM informed the participants that pursuant to said standard, it must complete the Unit 4 Revised SIP Compliance Project notwithstanding the continued failure of the participants to reach agreement. The Unit 4 Revised SIP Compliance Project was completed in December 2015.




Page 32


CLEAN AIR ACT - REGIONAL HAZE PROCEEDINGS (cont.) In connection with the implementation of the revised plan and retirement of the San Juan Generating Station Unit Nos. 2 and 3, certain San Juan Generating Station participants have expressed a desire to exit their ownership in the plant. On June 20, 2014, representatives of the nine San Juan Generating Station owners reached a non-binding agreement in principle on the ownership restructuring of the San Juan Generating Station predicated on the proposed retirement of Unit Nos. 2 and 3 by December 31, 2017 as necessary to implement the revised SIP (as now approved). The participants’ non-binding agreement on the restructuring of the ownership of the San Juan Generating Station has been memorialized in the form of (i) a Resolution of the San Juan Generating Station Coordination Committee Regarding San Juan Project Restructuring (the “Restructuring Resolution”) and (ii) the San Juan Generating Station Restructuring Non-Binding Term Sheet of Remaining Participants (the “Remaining Participants’ Term Sheet”). Under the Restructuring Resolution, the owners that would exit active participation in the San Juan Generating Station effective December 31, 2017 (the “exiting participants”) would include, in San Juan Unit No. 4, M-S-R PPA and Anaheim. The ownership interests of M-S-R PPA and Anaheim were proposed to be acquired by PNM and Farmington. The Restructuring Resolution was unanimously approved by the San Juan Coordination Committee on June 26, 2014. The Remaining Participants’ Term Sheet was also approved on June 26, 2014 by the San Juan Generating Station owners that are expected to retain an interest in the ongoing operation of one or more units of the San Juan Generating Station (the “remaining participants”). Certain elements of the proposed restructuring arrangements, including details as to the allocation of ongoing responsibility for decommissioning costs and any environmental liabilities among the exiting participants and the remaining participants, were identified in the San Juan Resolution as remaining to be addressed at a later date. On September 2, 2014, the San Juan Coordination Committee approved a Supplement to the Restructuring Resolution (the “Supplement to Restructuring Resolution”) setting forth the non-binding agreement in principle of the San Juan Generating Station owners with respect to ongoing responsibilities of the participants for decommissioning costs and environmental liabilities. The Supplement to Restructuring Resolution is intended to provide a framework for liability, indemnity and defense provisions to be contained in final agreements (if any) pertaining to environmental and general liability consistent with the guiding principle set forth in the Restructuring Resolution that in allocating any related costs responsibility between the exiting participants and the remaining participants, the exiting participants are not financially responsible for events taking place at the San Juan Generating Station after their exit date from participation in the project, and that all participants in the project are financially responsible for events taking place at the San Juan Generating Station before the exit date. The Supplement to Restructuring Resolution further sets forth a proposed methodology and schedule for addressing decommissioning issues among the exiting participants and the remaining participants.




Page 33


CLEAN AIR ACT - REGIONAL HAZE PROCEEDINGS (cont.) A number of regulatory approvals were required in order to implement the proposed ownership restructuring of the San Juan Generating Station as contemplated by the Restructuring Resolution (and Supplement thereto) and the Remaining Participants’ Term Sheet. These regulatory approvals, which have now been obtained, included those of the New Mexico Public Regulation Commission, the Federal Energy Regulatory Commission and the governing bodies of the publicly-owned utility San Juan Project Participants. The proposed ownership restructuring was also contingent on the effectiveness of the closing of a sale of the San Juan Coal Company from BHP Billiton New Mexico Coal, Inc. to Westmoreland Coal Company and the effectiveness of a new Coal Sales Agreement with the San Juan Coal Company, both of which occurred on January 31, 2016. The necessary approvals were obtained in January 2016 which allowed the restructuring agreements to become effective in 2016. On July 31, 2015, the San Juan Project Participants executed the Restructuring Agreements comprising the San Juan Project Restructuring Agreement, the Amended and Restated Mine Reclamation and Trust Funds Agreement, the San Juan Decommissioning and Trusts Funds Agreement, the Restructuring Amendment to Amended and Restated San Juan Project Participation Agreement, and the Exit Date Amendment to the Amended and Restated San Juan Project Participation Agreement. These agreements were to become effective once all conditions precedent were completed. These agreements provide for the Agency to:

> Exit its interest in San Juan Unit Four effective December 31, 2017 (“Exit Date”); > Be relieved of its obligation to pay for Capital Improvements at the San Juan Project effective

July 1, 2014 and pay a monthly Demand Charge through the Exit Date in lieu thereof, a demand charge relating to this period of $1,269 was paid and recorded in March 2016;

> Sell its share of the fuels inventory to PNM, a payment of $8,385 was made to the Agency in March 2016 for its share of inventory;

> Pay a restructuring fee to the remaining San Juan Project Participants, a payment of $2,835 was made in March 2016;

> Pay a fixed price for fuel through the Exit Date; and > Retain certain liabilities for Mine Reclamation and Plant Decommissioning.

The San Juan Project Restructuring Agreement, the Amended and Restated Mine Reclamation and Trust Funds Agreement, and the Restructuring Amendment to Amended and Restated San Juan Project Participation Agreement became effective, once all final approvals and conditions precedent were obtained, on January 31, 2016. The San Juan Decommissioning and Trusts Funds Agreement and the Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement will become effective on the Exit Date. At December 31, 2015, the net book value of total construction work in progress and plant in service recorded in MSR PPA’s financial statements related to the San Juan Generating Station was $78,328. The Agency will continue to be liable on the balance owed on the bonds related to the San Juan project after the ownership interest in the project is turned over as of December 31, 2017. The balance of the bonds outstanding at December 31, 2015 related to the San Juan project is $222,365.




Page 34


GENERAL CONTINGENCIES The Agency is financially dependent upon its Members and their ability to provide continuing revenues to the Agency sufficient to cover all of its operating and debt service costs in connection with its take-or-pay agreement with its Members. While all of the Agency’s Members are California utilities and are affected by the uncertainties associated with the industry changes, Agency management believes the Members will be able to continue to fully satisfy their take-or-pay obligations to the Agency. In the normal operations of its business, the Agency is party to various claims, legal actions and complaints. However, the Agency’s legal counsel and management believe that the ultimate resolution of these matters will not have a significant adverse effect on the financial position or results of operations of the Agency. NOTE 11 – RISK MANAGEMENT

The Agency is exposed to various risks of loss related to torts; theft of, damage to, or destruction of assets; and errors and omissions. These risks are covered through the purchase of commercial insurance, with minimal deductibles. Settled claims have not exceeded the commercial liability in any of the past three years. There were no significant reductions in coverage compared to the prior year. NOTE 12 – SUBSEQUENT EVENT

The Agency has entered into a purchase and sale agreement dated August 31, 2015 for the sale of its interest in the Southwest Transmission Project at a purchase price of $60,000. The closing date of the sale is expected to be May 25, 2016. The net book value of the Southwest Transmission Project was $40,757 at December 31, 2015. The balance on the bonds outstanding related to the Southwest Transmission Project as of December 31, 2015 was $11,970.