BEFORE THE NEW MEXICO PUBLIC REGULATION COMMISSION

BEFORE THE NEW MEXICO PUBLIC REGULATION COMMISSION IN THE MATTER OF THE APPLICATION ) OF PUBLIC SERVICE COMPANY OF NEW ) MEXICO FOR APPROVAL TO ABANDON ) SAN JUAN GENERATING STATION UNITS ) 2 AND 3, ISSUANCE OF CERTIFICATES ) OF PUBLIC CONVENIENCE AND ) NECESSITY FOR REPLACEMENT POWER ) RESOURCES, ISSUANCE OF ACCOUNTING ) ORDERS AND DETERMINATION OF ) RELATED RATEMAKING PRINCIPLES AND) TREATMENT, ) PUBLIC SERVICE COMPANY OF NEW ) MEXICO, ) ) Applicant ) ) Case 13-00390-UT JULY 1 SUPPLEMENTAL TESTIMONY OF HENRY E. MONROY July 1,2014

JULY 1 SUPPLEMENTAL TESTIMONY OF HENRY E. MONROY NMPRC CASE NO. 13-00390-UT 1 Q- 2 A. 3 4 5 PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS. My name is Henry E. Monroy. I am the Director, Cost of Service and Corporate Budget for PNM Resources, Inc., and its subsidiaries, which includes Public Service Company of New Mexico ("PNM" or the "Company"). My address is 414 Silver Avenue, SW, Albuquerque, New Mexico 87102. 6 7 Q. HAVE YOU PREVIOUSLY FILED TESTIMONY IN THIS PROCEEDING? 8 A. Yes, I filed Direct Testimony in this proceeding on December 20,2013. 9 10 Q. 11 12 A. 13 14 15 16 17 WHAT IS THE PURPOSE OF YOUR JULY 1 SUPPLEMENTAL TESTIMONY? This testimony responds to the requirements for supplemental testimony set forth in Ordering Paragraph 3, parts (ii) and (iii) of the Order (1) Partially Granting PNM Motion, as Supplemented, for Leave to File Supplemental Testimony, to Extend Procedural Schedule and for Shortened Response Time and (2) Denying PNM Motion for Leave to File Reply in Support of Motion for Leave to File Supplemental Testimony that was issued by the Hearing Examiner on June 11,2014 ("June 11,2014 Order"). 18 19 Q. 20 21 A. 22 23 PLEASE ADDRESS THE REQUIREMENTS IN PARAGRAPH 3, PARTS (ii) AND (iii) OF THE JUNE 11,2014 ORDER. These provisioas of the June 11, 2014 Order require PNM to update Exhibits HEM-2, HEM-9 and HEM-11, filed December 20, 2013, for the Revised SIP with PV Unit 3 portfolio assuming 78 additional MW in SJGS Unit 4, and the Revised SIP with PV 1

JULY 1 SUPPLEMENTAL TESTIMONY OF HENRY E. MONROY NMPRC CASE NO. 13-00390-UT 1 2 Unit 3 portfolio assuming 132 additional MW in SJGS Unit 4, to reflect the updated modeling assumptions described in Mr. O'Connell's May 22, 2014 Supplemental 3 Testimony. 4 5 Q. HAVE YOU UPDATED YOUR EXHIBITS AS REQUIRED BY THE JUNK 11, 6 2014 ORDER? 7 A. Yes. In PNM Exhibit HEM-2 (July 1 Supplemental) 78 MW Scenario, I have updated 8 9 10 11 12 13 14 15 16 17 18 19 20 21 the estimated 2018 revenue requirements of the Revised SIP with PV Unit 3 portfolio. assuming the acquisition of 78 MW in SJGS Unit 4, to account for the impact of the updated load forecast. The updated load forecast resulted in changes to base fuel and fuel handling costs. In addition, the expiration of the City of Gallup wholesale contract resulted in a change in the generation demand allocator that apportions costs between the New Mexico retail jurisdiction and the FERC wholesale jurisdiction. This change in the generation demand allocator is the only update in PNM Exhibit HEM-9 (July 1 Supplemental) 78 MW scenario. In PNM Exhibit HEM-11 (July 1 Supplemental) Scenario, I have updated the estimated customer bill impacts in 2018 for the Revised SIP with PV Unit 3 portfolio, assuming the addition of 78 MW in Unit 4, as calculated in PNM Exhibit HEM-2 (July 1 Supplemental) 78 MW Scenario. I have also provided updated exhibits to reflect the effects of the same updated modeling assumptions but with the inclusion of 132 additional MW in SJGS Unit 4, instead of 78 MW. These exhibits are labeled as "132 MW Scenario". 22 2

JULY 1 SUPPLEMENTAL TESTIMONY OF HENRY E. MONROY NMPRC CASE NO. 13-00390-UT 1 Q. IS PNM ASKING THE COMMISSION TO APPROVE PNM'S UPDATED 2 GENERATION DEMAND ALLOCATOR IN THIS PROCEEDING? 3 A. Although I have adjusted the generation demand allocator used to estimate the 4 revenue requirements shown in my exhibits, PNM is not asking the Commission for 5 6 7 approval of the allocation factors in this filing. The revenue requirements presented in my exhibits are solely for the purpose of illustrating the potential impacts on revenue requirements of various resource portfolios. The Commission will review all of PNM's 8 allocation factors at the time PNM applies for a change in rates. 9 10 Q. ARE YOU PRESENTING ANY ADDITIONAL EXHIBITS WITH THIS 11 12 A, TESTIMONY? Yes. PNM has included additional exhibits to support the inputs to PNM Exhibit HEM- 13 2 (July 1 Supplemental) 78 MW Scenario and PNM Exhibit HEM-2 (July 1 14 Supplemental) 132 MW Scenario. PNM Exhibit HEM-4 (July 1 Supplemental) 78 MW 15 Scenario, PNM Exhibit HEM-4 (July 1 Supplemental) 132 MW Scenario, PNM Exhibit 16 HEM-5 (July 1 Supplemental), PNM Exhibit HEM-6 (July 1 Supplemental) 78 MW 17 18 Scenario, and PNM Exhibit HEM-7 (July 1 Supplemental) reflect the updated generation demand allocator to estimate the New Mexico retail share of revenue 19 requirements. PNM Exhibit HEM-6 (July 1 Supplemental) 132 MW Scenario reflects 20 an updated estimated revenue requirement for the SNCR with the balanced draft 21 conversion, consistent with PNM's proposed acquisition of 132 MW in SJGS Unit 4 22 and the updated generation demand allocator. 23 3

JULY 1 SUPPLEMENTAL TESTIMONY OF HENRY E. MONROY NMPRC CASE NO. 13-00390-UT 1 Q- 2 3 4 A- 5 6 7 8 9 10 11 12 13 14 15 16 IN YOUR SUPPLEMENTAL EXHIBITS, ARE THE REVENUE REQUIREMENTS FOR THE 40 MW SOLAR FACILITY HANDLED IN THE SAME MANNER AS IN PNM'S DECEMBER 20,2013 FILING? In PNM's original filing, the 40 MW solar facility was not identified as a resource in the Federal Implementation Plan ("FTP") portfolio. However, in the portfolios that reflect the impact of the updated modeling assumptions, identified by PNM Witness Mr. O'Connell, the proposed 40 MW solar facility is included in all portfolios, including the FIP. Because the 40 MW solar facility is included in all portfolios, it has no incremental cost impact in the comparison of revenue requirements from one portfolio to another and therefore the revenue requirements for the 40 MW solar facility have been excluded from the Summary of 2018 Estimated Revenue Requirements as provided on the July 1 Supplemental PNM Exhibit HEM-2. Nevertheless, I have provided PNM Exhibit HEM-8 (July 1 Supplemental) to reflect the updated estimated 2018 revenue requirement for the 40 MW solar facility based on the updated solar pricing. PNM has used the same assumptions for the 40 MW Solar Facilities as are included in the 2015 Renewable Energy Procurement Plan filing in NMPRC Case 14-00158-UT. 17 18 Q. HAVE YOU IDENTIFIED ANY OTHER CHANGES ON PNM EXHIBIT 19 HEM-7 (JULY 1 SUPPLEMENTAL) FOR THE 177 MW GAS PEAKER. 20 A. Yes. PNM has identified that the estimated revenue requirement in 2018 for the 177 21 MW gas peaker facility inadvertently excluded a portion of the estimated fixed 22 operating and maintenance expense in the original filing. PNM has included these 23 estimated O&M expeases in its updated estimated revenue requirements. These fixed 4

JULY 1 SUPPLEMENTAL TESTIMONY OF HENRY E. MONROY NMPRC CASE NO. 13-00390-UT 1 2 O&M expenses were included in the Strategist modeling reflected in Mr. O'Connell's original and supplemental testimonies. 3 4 Q. 5 6 DO YOU PLAN TO UPDATE YOUR REVENUE REQUIREMENT AND CUSTOMER IMPACT EXHIBITS IN THE JULY 15 SUPPLEMENTAL TESTIMONY FILING. 7 A. Yes. I plan on updating my exhibits to reflect the changes associated with the 8 9 documents filed on July 1 in the Notice of Status of San Juan Generating Station Ownership Restructuring Negotiation and Filing of 'Term Sheet". 10 11 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL TESTIMONY? 12 A. Yes. 13 #518322 5

PNM Exhibit HEM-2 (July 1 Supplemental) 78 MW Scenario Summary of 2018 Estimated Revenue Requirements RSIP with PV Unit 3 78 MW to SJ4 Page 1 of 1 A Line Description Amount 1 Estimated Incremental Annual Revenue Requirement for Undepreciated Investment in SJGS Unit 2 and 3 2 Incremental Revenue Requirement 3 Subtotal 4 5 SNCR and Replacement Power Revenue Requirements 6 7 Estimated 2018 Palo Verde Unit 3 Revenue Requirement Estimated 2018 SNCR Revenue Requirement 8 Estimated 2018 Revenue Requirement for 177 MW Gas Peaker 9 10 Subtotal 104,771,808 n 12 Other Impacts of Revised SIP Compared to FIP 13 O&M and Fuel Handling Savings 14 Base Fuel Impacts 15 Subtotal 16 17 Total Revised SIP with PV3 78 MW to SJ4 Revenue Requirement B Reference 4,216,477 PNM Exhibit HEM-4(iulY 1 Supplemental) 78 MW Scenario, Page 1, Column A, Line 30 4,216,477 69,275,438 PNM Exhibit HEM-5 (July 1 Supplemental), Page 1, Column C, Line 49 12,970,056 PNM Exhibit HEM-6 (July 1 Supplemental) 78 MW Scenario, Page 1, Column A, Line 28 22,526,314 PNM Exhibit HEM-7 (July 1 Supplemental), Page 1, Column A, Line 47 (21,852,489) 1,447,288 (20,405,201) S 88,583,084

PNM Exhibit HEM-2 (July X Supplemental) 132 MW Scenario Summary of 2018 Estimated Revenue Requirements RSIP with PV Unit 3 132 MW to SJ4 Page 1 of 1 A B Line Description Amount Reference 1 Estimated Incremental Annual Revenue Requirement for Undepreciated Investment in SJGS Unit 2 and 3 2 Incremental Revenue Requirement 4,216,477 PNM Exhibit HEM-4 (July 1 Supplemental) 132 MW Scenario, Page 1, Column A, Line 30 3 Subtotal 4,216,477 4 5 SNCR and Replacement Power Revenue Requirements 6 7 8 Estimated 2018 Palo Verde Unit 3 Revenue Requirement Estimated 2018 SNCR Revenue Requirement Estimated 2018 Revenue Requirement for 177 MW Gas Peaker 69,275,438 14,214,387 22,526,314 9 10 Subtotal 106,016,138 11 12 Other impacts of Revised SIP Compared to FIP 13 O&M and Fuel Handling Savings (14,731,343) 14 Base fuel impacts (2,086,094) 15 Subtotal (16,817,436) 16 17 Total Revised SIP with PV3 132 MW to SJ4 Revenue Requirement 93,415,178 PNM Exhibit HEM-5 (July 1 Supplemental), Page 1, Column C, Line 49 PNM Exhibit HEM-6 (July 1 Supplemental) 132 MW Scenario, Page 1, Column A, Line 28 PNM Exhibit HEM-7 (July 1 Supplemental), Page 1, Column A, Line 47

PNM Exhibit HEM-4 (July 1 Supplemental) 78 MW Scenario Undepreciated Investment of SJGS Unit 2 and 3 after Acquisition of 78 MW in SJGS Unit 4 Page 1 of 3 Estimated Incremental Annual Revenue Requirement for Undepreciated Investment in SJGS Unit 2 and 3 A B Line No 2018 Revenue Requirement Reference 1 Regulatory Asset - Undepreciated Investment in Unit 2 & 3 204,995,787 Exhibit HEM-4 (July 1 Supplemental) 78 MW Scenario, Page 2, Column O, Line 36 2 3 Accumulated Amortization 4 5 Average Unamortized Regulatory Asset 6 (Line 1 + Line 3) 7 ADIT 8 9 Net Regulatory Asset 10 11 12 WACC (Line 5 + Line 7} 13 14 Carrying Charge on Regulatory Asset 15 16 (Line 9 * Line 12) (5,124,895) 199,870,892 (77,190,139) 122,680,754 S 10,035,286 17 Total Amortization Expense 10,249,789 18 19 Income Taxes 3,913,540 20 21 Total Non-Fuel Revenue Requirement 22 (Line 14 + Line 17+ Line 19) PNM Retaii Share of Non-Fuel revenue requirement 23 (Line 21* 95.42%) 24 Revenue Tax ( 0.508573% 25 Total PNM Non-Fuel Retail Revenue Requirement, Assuming 20 Year Recovery 26 (Line 23 + Line 24) 27 28 PNM Retail Revenue Requirement, Assuming 36 Year Recovery 29 30 Incremental Revenue Requirement for Undepreciated Investment of Unit 2 & Unit 3 31 (Line 25 - Line 28) 24,198,615 8.18% Exhibit HEM-3, Column E, Line 8 23,090,318 117,431 23,207,750 18,991,273 Exhibit HEM-4 (July 1 Supplemental) 78 MW Scenario, Page 3, Column A, Line 25 4,216,477 Exhibit HEM-2 (July 1 Supplementa!) 78 MW Scenario, Page 1, Column A, Line 2

PNM Exhibit HEM-4 (July 1 Supplemental) 78 MW Scenario Undepreciated investment of SJGS Unit 2 and 3 after Acquisition of 78 MW in SJGS Unit 4 Page 2 of 3 Estimated Undepreciated Investment in SJGS Unit 2 and 3 after Acquisition of 78 MW in SJGS Unit 4 A B C line Description 1 San Juan Unit 1 2 San Juan Unit 2 3 San Juan Unit 3 4 San Juan Unit 4 5 San Juan Common & Switchyard Net book value as of 06/30/13 S 95,095,936 112,640,507 170,124,725 120,485,000 95,478,709 Current kw Ownership 170,000 S 170,000 248,000 195,000 D = B / C per kw as of 06/30/13 559 663 686 618 E Estimated Capital Additions - 07/01/13-12/31/14 5,473,048 2,602,718 4,645,958 12,146,648 17,277,986 6 Total San Juan 593,824,878 783,000 758 42,146,358 7 8 9 F G = B + E +F H = G / C i Estimated Additional Accumulated Depreciation - Estimated Balance at 10 07/01/13-12/31/14 01/01/15 per kw as of 01/01/15 Acquisition of kw 11 San Juan Unit 1 (3,824,170) S 96,744,814 569 12 San Juan Unit 2 (4,420,751) 110,822,474 652 13 San Juan Unit 3 (7,866,054) 166,904,629 673 (78,000) 14 San Juan Unit 4 (5,971,609) 126,660,039 650 78,000 15 San Juan Common & Switchyard (3,724,030) 109,032,665 _ 16 Total San Juan (25,806,614) S 610,164,621 779 17 18 19 J K = G + J L M Estimated Additional Estimated Net Book Value at Estimated Capital Additions - Accumulated Depreciation - 20 Value of Acquired kw 01/01/15. after Transfer 01/01/15-12/31/17 01/01/15-12/31/17 21 San Juan Unit 1 S 96,744,814 19,046,786 (8,907,004) 22 San Juan Unit 2 110,822,474 (9,203,127) 23 San Juan Unit 3 (52,494,000) 114,410,629 (11,034,189) 24 San Juan Unit 4 52,494,000 179,154,039 8,752,098 (16,999,045) 25 San Juan Common & Switchyard 109,032,665 8,211,145 (7,390,328) 26 Total San Juan 610,164,621 36,010,029 (53,533,693) 27 28 29 N O Estimated Unrecovered Estimated Ending Net Book Investment in San Juan Unit 2 30 Value at 12/31/2017 and 3 31 San Juan Unit 1 S 106,884,596 32 San Juan Unit 2 101,619,347 101,619,347 33 San Juan Unit 3 103,376,440 103,376,440 34 San Juan Unit 4 170,907,093 35 San Juan Common & Switchyard 109,853,482 36 Total San Juan 592,640,957 204,995,787 Exhibit HEM-4 (Jufy 1 Supplemental) 78 MW Scenario, Page 1, Column A, Lirte 1 Exhibit HEM-4 {Jufy i Supplemental) 78 MW Scenario, Page 3, Column A, Line 1

PNM Exhibit HEM-4 (July 1 Supplemental) 78 MW Scenario Undepreciated investment of SJGS Unit 2 and 3 after Acquisition of 78 MW in SJGS Unit 4 Page 3 of 3 Estimated Annual Revenue Requirement of SJGS Unit 2 & 3 Based on Remaining Life of SJGS Line No A 2018 Revenue Requirement B Reference 1 Regulatory Asset - Undepreciated investment in Unit 2 & 3 2 3 Accumulated Amortiiation (2,847,164) 4 5 Average Unamortiied Regulatory Asset 6 7 ADIT 8 (Line 1 + Line 3) 9 Net Regulatory Asset 10 11 {Line 5 + Line 7 j 204,995,787 Exhibit HEM-4 (July 1 Supplemental) 78 MW Scenario, Page 2, Column O, Line 36 202,148,623 (78,069,798) 124,078,825 12 WACC 8.18% Exhibit HEM-3, Column E, Line 8 13 14 Carrying Charge on Regulatory Asset 15 16 {Line 9 * line 12} S 10,149,648 17 Total Amortiiation Expense 5,694,327 18 19 Income Taxes 3,958,139 20 21 Total Non-Fuel Revenue Requirement 22 (Line 14 + Line 17 + Line 19) PNM Retail Share of Non-Fuel revenue requirement 23 (Line 21'95.42%) 24 Revenue Tax @ 0.508573% 25 Total PNM Non-Fuel Retail Revenue Requirement, Assuming 36 Year Recovery 26 (Line 23 * Line 24) 19,802,114 18,895,177 96,096 18,991,273 Exhibit HEM-4 (July 1 Supplemental) 78 MW Scenario, Page 1, Column A, Line 28

PNM Exhibit HEM-4 (Juiy 1 Supplemental) 132 MW Scenario Undepreciated Investment of SJGS Unit 2 and 3 after Acquisition of 132 MW in SJGS Unit 4 Page 1 of 3 Estimated Incremental Annual Revenue Requirement for Undepreciated Investment in SJGS Unit 2 and 3 Line No A 2018 Revenue Requirement B Reference 1 Regulatory Asset - Undepreciated Investment In Unit 2 & 3 204,995,787 Exhibit HEM-4 (July 1 Supplemental) 132 MW Scenario, Page 2, Column 0, Line 36 2 3 Accumulated Amortization (5,124,895) 4 5 Average Unamortized Regulatory Asset 6 (Line 1 + Line 3) 199,870,892 7 ADIT (77,190,139) 8 9 Net Regulatory Asset 10 11 (Line S + Line 7) S 122,680,754 12 WACC 8.18% Exhibit HEM-3, Column E, Line 8 13 14 Carrying Charge on Regulatory Asset 15 16 (Line 9 ' Line 12) s 10,035,286 17 Total Amortization Expense 10,249,789 18 19 Income Taxes 3,913,540 20 21 Total Non-Fuel Revenue Requirement 22 (Line 14 +Line 17* Line 19} PNM Retail Share of Non-Fuel revenue requirement 23 (Line 21' 95.42%) 23,090,318 24 Revenue Tax @ 0.508573% 25 Total PNM Non-Fuel Retail Revenue Requirement, Assuming 20 Year Recovery 26 (Line 23 + Line 24) 27 28 PNM Retail Revenue Requirement, Assuming 36 Year Recovery 29 30 Incremental Revenue Requirement for Undepreciated Investment of Unit 2 & Unit 3 31 (Une 25 - Line 28) 24,198,615 117,431 23,207,750 18,991,273 Exhibit HEM-4 (July 1 Supplemental) 132 MW Scenario, Page 3, Column A, Line 25 4,216,477 Exhibit HEM-2 (July 1 Supplemental) 132 MW Scenario, Page 1, Column A, Line 2

PNM Exhibit HEM-4 (July 1 Supplemental) 132 MW Scenario Undepreciated Investment of SJGS Unit 2 and 3 after Acquisition of 132 MW In SJGS Unit 4 Page 2 of 3 Estimated Undepreciated Investment in SJGS Unit 2 and 3 after Acquisition of 78 MW in SJGS Unit 4 A B C D = B/C E Estimated Capital Additions - Line Description Net book value as of 06/30/13 Current kw Ownership per kw as of 06/30/13 07/01/13-12/31/14 1 2 3 4 San Juan Unit 1 San Juan Unit 2 San Juan Unit 3 San Juan Unit 4 S 95,095,936 112,640,507 170,124,725 120,485,000 170,000 170,000 248,000 195,000 S 559 663 686 618 5,473,048 2,602,718 4,645,958 12,146,648 5 San Juan Common & Switchyard 95,478,709 6 Total San Juan 593,824,878 783,000 758 7 8 9 F G = B + E +F H-G/C Estimated Additional Accumulated Depreciation - 10 07/01/13-12/31/14 Estimated Balance at 01/01/15 oerkw as of 01/01/15 11 San Juan Unit 1 S (3,824,170) 96,744,814 569 12 San Juan Unit 2 (4,420,751) 110,822,474 652 13 San Juan Unit 3 14 San Juan Unit 4 15 San Juan Common & Switchyard (7,866,054) (5,971,609) (3,724,030) 166,904,629 126,660,039 109,032,665 673 650 I Acquisition of KW 17,277,986 42,146,358 16 Total San Juan (25,806,614) S 610,164,621 779 17 18 19 J K«=G +J L M Estimated Additional Estimated Net Book Value at Estimated Capital Additions - Accvmyiate^ Dgpr^cigtion - 20 (i) Value of Acquired kw 01/01/15. after Transfer 01/01/15-12/31/17 01/01/15-12/31/17 21 San Juan Unit 1 S S 96,744,814 19,046,786 S (8,907,004) 22 San Juan Unit 2 110,822,474 (9,203,127) 23 San Juan Unit 3 24 San Juan Unit 4 (52,494,000) 114,410,629 52,494,000 179,154,039 8,752,098 25 San Juan Common & Switchyard 109,032,665 _ 8,211,145 26 Total San Juan S 610,164,621 36,010,029 27 28 29 N O Estimated Unrecovered Estimated Ending Net Book Investment in San Juan Unit 2 30 Value at 12/31/2017 and 3 31 San Juan Unit 1 106,884,596 32 San Juan Unit 2 101,619,347 101,619,347 33 San Juan Unit 3 103,376.440 103,376,440 34 San Juan Unit 4 170,907,093 35 San Juan Common & Switchyard 109.853,482 _ 36 Total San Juan 592,640,957 204,995,787 Exhibit HEM-4 (Juty 1 Supplemental) 132 MW Scenario, Page 1, Column A, Line 1 37 Exhibit HEM-4 (Juty 1 Supplemental! 132 MW Scenario, Page 3, Column A, Line 1 38 (1) Value pursuant to May 22 Supplemental Testimony as described by PNM Witness Sategna (132,000) 132,000 (11,034,189) (16,999,045) (7,390,328) (53,533,693)

PNM Exhibit HEM-4 (July 1 Supplemental) 132 MW Scenario Undepreciated Investment of SJGS Unit 2 and 3 after Acquisition of 132 MW in SJGS Unit 4 Page 3 of 3 Estimated Annual Revenue Requirement of SJGS Unit 2 & 3 Based on Remaining Life of SJGS Line No A 2018 Revenue Requirement B Reference 1 Regulatory Asset - Undepreciated Investment in Unit 2 & 3 2 3 Accumulated Amortization (2,847,164) 4 5 Average Unamortized Regulatory Asset 6 7 ADIT 8 (Line 1 ' Line 3) 9 Net Regulatory Asset 10 11 12 WACC 13 (Line 5 + Line 7) 14 Carrying Charge on Regulatory Asset 15 16 (Line 9 * tine U) 204,995,787 Exhibit HEM-4 (July 1 Supplemental) 132 MW Scenario, Page 2, Column 0, Line 36 202,148,623 (78,069,798) S 124,078,825 10,149,648 17 Total Amortization Expense 5,694,327 18 19 Income Taxes 3,958,139 20 21 Total Non-Fuel Revenue Requirement 22 (Line It + Line 17 * Line 19) PNM Retail Share of Non-Fuel revenue requirement 23 (Line 21* 95.42%) 18,895,177 24 Revenue Tax @ 0.508573% 25 Total PNM Non-Fuel Retail Revenue Requirement, Assuming 36 Year Recovery 26 (Line 23 + Line 24} 19,802,114 8.18% Exhibit HEM-3, Column E, Line 8 96,096 18,991,273 Exhibit HEM-4 (July 1 Supplemental) 132 MW Scenario, Page 1, Column A, Line 28

PNM Exhibit HEM-5 (July 1 Supplemental) Estimated 20X8 Palo Verde Unit 3 Revenue Requirement Page 1 ofl Line No A 2018 Revenue Requirement Before Adjustment B C 0 Adjustment 2018 to 2,500/kW Revenue Requirement Reference 1 Gross Want 2 Production Plant 3 Transmission Plant 4 Total Gross Plant 5 6 Accumulated Reserve 7 Production Plant 8 Transmisskm Want 9 Total Accumulated Reserve 10 11 Average NBV 12 Production Went 13 Transmission Went 14 Total Average NBV 15 (tine 4 ' Line 9} 16 ADIT 17 Working Capital 18 19 Rate Base 20 (Line 14 * Line 16 + Line 1?} 21 22 WACC 23 24 Return on Rate Base 25 (Line 19'Line 22} 26 27 Depredation Expense 28 Production Plant 29 Transmission Plant 30 Total Depreciation Expense 231,461,843 8,207,876 239,669,719 (90,952,527) (5,315,079) (96,267,606) 140,509,316 2,892,797 143,402,113 (57,366,268) 31,909,139 117,944,985 8.18% 9,647,900 31 32 Decommissioning Expense 1,300,000 33 34 Income Taxes 3,762,468 35 36 Property Taxes 37 Production Plant 38 Transmission Plant 39 Total Property Tax 191,552,217 191,552,217 (3,302,624) (3,302,624) 188,249,593 188,249,593 (72,701,993) 115,547,600 M 8.18% 423,014,060 8,207,876 431,221,936 (94,255,151) (5,315,079) (99,570,230) 328,758,909 2,892,797 331,651,706 (130,068,260) 31,909,139 233,492,585 9,451,794 19,099,693 5,876,933 6,605,249 12,482,182 167,160 167,160 6,044,093 6,605,249 12,649,342 1,545,602 31,821 1,577,423 8.18% Exhibit HEM-3, Column E, Line 8 1,300,000 3,685,991 7,448,459 2,070,746 2,070,746 40 41 O&M 22,933,006 42 43 Third Party Transmission Expense 5,154,516 44 45 Total Non-fuel Revenue Requirement 50,419,405 21,813,779 46 (Une 24 * Line 30 * Line 32 * Line 34 + Une 39 * Line 41 * Line 43) PNM Retail Share of Non-Fuel revenue requirement 47 (Une 21'95 42%} 48 Revenue Tax @0.508573% 49 Total PNM Non-fuel Retail Revenue Requirement 50 (Line 47 + Line 48} 48,110,197 20,814,708 244,675 105,858 48,354,872 20,920,566 3,616,348 31,821 3,648,169 22,933,006 5,154,516 72,233,184 68,924,905 350,533 69/275,438 Exhibit HEM-2 (July 1 Supplemental) 78 MW Scenario, Page 1, Column A, Line 6 Exhibit HEM-2 (July 1 Supplemental) 132 MW Scenario, Page 1, Column A, Une 6

PNM Exhibit HEM-6 {July 1 Supplemental) 78 MW Scenario Estimated 2018 SNCR Revenue Requirement Page 1 of 1 Line No A 2018 Revenue Requirement B Reference 1 Gross Plant 2 3 Accumulated Reserve 4 5 Total Average NBV 6 (Line 1 + Line 3) 7 ADIT 8 9 Rate Base 10 (Line 5 + Line 7) 11 12 WACO 13 14 Return on Rate Base 15 (Line 9 * Line 12) 16 Depreciation Expense 17 18 Income Taxes 19 20 Property Taxes 21 81,937,374 (6,059,401) 75,877,973 (8,633,241) 67,244,732 5,500,619 8.18% Exhibit HEM-3, Column E, Line 8 2,156,247 2,145,120 608,976 22 OSiM 3,112,857 23 24 Total Non-Fuel Revenue Requirement 13,523,819 25 (Line 14 + Line 16 + Line 18 + Line 20 + Line 22) PNM Retail Share of Non-Fuel revenue requirement 26 (Line 21 * 95.42%; 12,904,428 27 28 29 Revenue Tax @ 0.508573% Total PNM Non-Fuel Retail Revenue Requirement (Line 26 + Line 27) 65,628 S 12,970,056 Exhibit HEM-2 (July 1 Supplemental) 78 MW Scenario, Page 1, Column A, Line 7

PNM Exhibit HEM-6 (July 1 Supplemental) 132 MW Scenario Estimated 2018 SNCR Revenue Requirement Page 1 of 1 Line No A 2018 Revenue Requirement B Reference 1 Gross Plant 2 3 Accumulated Reserve 4 5 Total Average NBV 6 (Line 1 + Line 3} 7 ADIT 8 9 Rate Base 10 (Line 5 + Line 7) 11 12 WACC 13 14 Return on Rate Base 15 (Line 9 * Line 12) 16 Depreciation Expense 17 18 Income Taxes 19 20 Property Taxes 21 22 OStlVI 23 24 Total Non-Fuel Revenue Requirement 25 26 (Line 14 + Line 16 + Line 18 + Line 20 + Line 22) PNM Retail Share of Non-Fuel revenue requirement (Line 24*95.42%) 27 Revenue Tax @ 0.508573% 28 Total PNM Non-Fuel Retail Revenue Requirement 29 (Line 26 + Line 27) 90,614,570 (6,616,520) 83,998,050 (10,823,369) S 73,174,681 8.18% Exhibit HEM-3, Column E, Line 8 5,985,689 2,384,594 2,334,287 680,915 3,435,792 S 14,821,276 14,142,462 71,925 14,214,387 Exhibit HEM-2 (July 1 Supplemental) 132 MW Scenario, Page 1, Column A, line 7

PNM Exhibit HEM-7 (July 1 Supplemental) Estimated 2018 Revenue Requirement for 177 MW Gas Pesker Page 1 of 1 Lme No A 2018 Revenue Requirement B Reference 1 Gross PUnt 2 Gas Peaker Gas Pipeline 4 Total Gross Plant 5 6 Accumulated Reserve 7 Gas Peaker 8 Gas Pipeline 9 Total Accumulated Reserve 10 11 Average NBV 12 Gas Peaker 13 Gas Pipeline 14 Total Average NBV 15 (Line 4 + Ltne 9} 16 ADIT 17 18 Rate Base 178,162,744 10,934,184 189,096,928 (1,670,276) (136,677) (1,806,953) 176,492,468 10,797,507 187,289,975 (3,318,099) 183,971,876 19 (Line 14 * Line 161 20 21 WACC 22 23 Return on Rate Base 24 25 fii (Line 18 " Line 21) 26 Depreciation Expense 27 Gas Peaker 28 Gas PtpeHne Ui 29 Total Depredation Expense 30 31 Income Taxes 32 33 Property Taxes 34 35 Gas Peaker Gas Pipeline 36 Total Property Tax si! 37 38 O&M 39 40 Gas Peaker Gas Pipeline 11,286,675 8.18% Exhibit HEM-3, Column E, Line 8 3,340,551 273,355 3,613,906 4,401,554 1,069,715 86,976 1,156,692 2,779,258 250,000 M 41 Total O&M 3,029,258 42 43 Total Non-Fuel Revenue Requirement 44 45 (Line 23 * Line 29 + Line 31 + Line 36 * Line 41} PNM Retail Share of Non-Fuel revenue requirement (line 21 95.42%; 46 Revenue Tax @ 0,508573% 47 Total PNM Non-Fuel Retail Revenue Requirement 48 (Line 45 Lme 46) al Reflects 9 months, based on In-service date of 4/1/2018 23,488,085 22,412,330 113,983 22,526,314 Exhibit HEM-2 (July 1 Supplemental) 78 MW Scenario, Page 1, Column A, Line 8 Exhibit HEM-2 (July 1 Supplemental) 132 MW Scenario, Page 1, Column A, lme 8

PNM Exhibit HEM-8 (July 1 Supplemental) Estimated 2018 Revenue Requirement for 40 MW Solar Facility Page 1 of 1 tine No A 2018 Revenue Requirement B Reference 1 Gross Plant 2 3 Accumulated Reserve 4 5 Total Average NBV 79,258,408 (7,879,295) 71,379,113.29 6 (Line 1 + Line 3) 7 ADIT (18,164,128) 8 (i) 9 Rate Base 53,214,985 10 (Line 5 + Line 7) 11 12 WACC 13 W 14 Return on Rate Base 15 16 Depreciation Expense 17 18 Income Taxes (3) 8.16% 4,342,343 2,555,447 666,005 19 20 Property Taxes 977,861 21 22 O&M 885,677 23 24 Total Non-Fuel Revenue Requirement 25 {Line 14 + Line 16 + Line 18 + Line 20 + Line 22) 26 Revenue Tax @ 0.508573% 27 Total PNM Non-Fuel Retail Revenue Requirement 28 29 (Line 24 + Line 26} 30 m Rate Base is based on Year-end balances 31 (z Return on Rate Base is based on sum of the monthly return calculations 9,427,333 47,945 9,475,278 32 3 ' Income tax is adjusted for ITC 33 Note - Revenue Requirement is presented to reflect updated solar pricing as described in May 22 Supplemental Testimony.

PNM Exhibit HEVI-9 (July 1 Supplemental) Estimated 2018 SCR Revenue Requirement Page 1 of 1 Line No A 2018 Revenue Requirement B Reference 1 Gross Plant 2 3 Accumulated Reserve 4 5 Total Average NBV 6 (Line 1 + Line 3) 7 ADIT 8 9 Rate Base 10 (Line 5 + Line 7} 11 12 WACC 13 14 Return on Rate Base 15 (Line9 "Line 12) 16 Depreciation Expense 17 18 Income Taxes 19 20 Property Taxes 21 22 OSiM 23 24 Total Non-Fuel Revenue Requirement 25 (Line 14 + Line 16 + Line 18 + Line 20 + Line 22) PNM Retail Share of Non-Fuel revenue requirement 26 (Line 21 * 9S.42%) 27 Revenue Tax @ 0,508573% 28 Total PNM Non-Fuel Retail Revenue Requirement 29 (Line 26 + Line 27) 457,796,582 (29,192,458) 428,604,124 (41,098,619) 387,505,505 8.18% Exhibit HEM-3, Column E, Line 8 31,697,950 12,047,278 12,361,501 3,447,623 14,259,866 73,814,219 70,433,528 358,206 70,791,734

PNM Exhibit HEM-11 (July 1 Supplemental) 78 MW Scenario Page 1 of 5 Estimated Impact of Revised SIP with PV Unit 3 78 MW to SJ4 on Customer Bills in 2018 Customer Impact Residential Customers Allocation by Year Line Year Notes 2018 1 RSIP with PV3 Revenue Requirement [A] 88,583,084 2 Cost Allocators [B] - 2012 Class Revenue 44.38% /Total Revenue 3 Estimated Residential RSIP with PV3 Allocation [C]=[A]*[B] 39,313,241 4 Residential kwh (2012 Actuals) [D] 3,333,146,888 5 Estimated RSIP with PV3 Rate per kwh [E] = [Q / [D] 0.011795 Residential Customers Estimated RSIP with PV3 Bill Impact Line kwh Use Estimated Annual RSIP with PV3 Bill Impact for 2018 [F] [G] = 0.011795 * [F] * 12 6 7 8 600 84.92

PNM Exhibit HEM-11 (July 1 Supplemental) 78 MW Scenario Page 2 of 5 Estimated Impact of Revised SIP with PV Unit 3 78 MW to SJ4 on Customer Bills in 2018 Small Power Customers Allocation by year Line Year Notes 2018 9 RSIP with PV3 Project Revenue Requirement [A] 88,583,084 10 Cost Allocators [H] = 2012 Class 13.51% Revenue/Toral Revenue 11 Estimated Small Power RSIP with PV3 Allocation [1]=[A]*[H] 11,971,679 12 Small Power kwh (2012 Actuals) [J] 966,425,575 [K]=[I]/[J] 13 Estimated RSIP with PV3 Rate per kwh 0.012388 Small Power Customers Estimated RSIP with PV3 Bill Impact Line kwh Use Estimated Annual RSIP with PV3 Bill Impact for 2018 fi-1 [M] = 0.012388 * [I] * 12 14 15 16 1,500 222.98

PNM Exhibit HEM-11 (July 1 Supplemental) 78 MW Scenario Page 3 of 5 Estimated Impact of Revised SIP with PV Unit 3 78 MW to SJ4 on Customer Bills in 2018 All Other Customer Classes Cost Allocators by Year Line Customer Class 2018 [N] - 2012 Class Revenue/ Total Revenue 17 3B/3C - General Power 18 4B - Large Power 19 5B-Mines 46/115 kv 20 10 - Irrigation 21 1 IB - Wtr/Swg Pumping 22 15B - Universities 115 kv 23 30B - Manuf. (30 MW) 24 6 - Private Lighting 25 20 - Streetlighting 21.26% 12.06% 0.72% 0.29% 1.44% 0.81% 4.30% 0.34% 0.89% All Other Customer Classes Allocation by Year Line Customer Class 2018 26 3B/3C - General Power 27 4B - Large Power 28 5B-Mines 46/115 kv 29 10 - Irrigation 30 11B - Wtr/Swg Pumping 31 15B-Universities 115 kv 32 30B - Manuf. (30 MW) 33 6 - Private Lighting 34 20 - Streetlighting [O] = [N]class * m.583,084 18,829,506 10,680,032 637,186 259,800 1,273,854 717,669 3,810,452 300,940 788,724 2012 Actual kwh - All Other Classes Line Customer Class 2018 [P] 35 3B/3C - General Power 36 4B - Large Power 37 5B-Mines 46/115 kv 38 10 - Irrigation 39 11B - Wtr/Swg Pumping 40 15B-Universities 115 kv 41 30B - Manuf. (30 MW) 42 6 - Private Lighting 43 20 - Streetlighting 1,939,015,568 1,411,906,111 91,241,920 28,455,014 191,783,766 101,874,529 633,849,603 16,252,906 50,551,135

PNM Exhibit HEM-11 (July 1 Supplemental) 78 MW Scenario Page 4 of 5 Estimated Impact of Revised SIP with PV Unit 3 78 MW to SJ4 on Customer Bills in 2018 Estimated RSIP with PV3 Rate - All Other Classes Line Customer Class 2018 /(.'/ /''/ /'7 44 3B/3C - General Power 45 4B - Large Power 46 5B- Mines 46/115 kv 47 10 - Irrigation 48 1 IB - Wtr/Swg Pumping 49 15B-Universities 115 kv 50 30B - Manuf. (30 MW) 51 6 - Private Lighting 52 20 - Streetlighting 0.009711 0.007564 0.006983 0.009130 0.006642 0.007045 0.006012 0.018516 0.015603 Estimated Average Annual RSIP with PV3 Bill Impact - All Other Classes Line Customer Class 53 3B/3C - General Power 54 4B - Large Power 55 5B-Mines 46/115 kv 56 10 - Irrigation 57 11B - Wtr/Swg Pumping 58 15B - Universities 115 kv 59 30B - Manuf. (30 MW) 60 6 - Private Lighting 61 20 - Streetlighting Est. Average Monthly Estimated Average kwh Annual RSIP with PV3 Based on 2012 Actuals Bill Impact for 2018 m 35,248 476,871 3,801,747 7,842 101,796 8,489,544 52,820,800 N/A N/A [S]~[Q] *[RJ* 12 4,107.51 43,286.11 318,592.90 859.18 8,113.72 717,668.87 3,810,451.99 N/A N/A

PNM Exhibit HEM-11 (July 1 Supplemental) 78 MW Scenario Page 5 of 5 Estimated Impact of Revised SIP with PV Unit 3 78 MW to SJ4 on Customer Bills in 2018 Annual of Customer Bills - All Classes Line Customer Class Annual of Bills - Projected 2018 62 1 A/IB - Residential 63 2A/2B - Small Power 64 3B/3C - General Power 65 4B - Large Power 66 5B-Mines 46/115 kv 67 10 - Irrigation 68 1 IB - Wtr/Swg Pumping 69 15B - Universities 115 kv 70 30B - Manuf. (30 MW) 71 6 - Private Lighting 72 20 - Streetlighting [T] 5,539,706 659,200 55,010 2,961 24 3,629 1,884 12 12 0 1,716 Average Dollar per Bill Impact - All Classes Line Customer Class 73 1 A/1B - Residential 74 2A/2B - Small Power 75 3B/3C - General Power 76 4B - Large Power 77 5B- Mines 46/115 kv 78 10 - Irrigation 79 11B - Wtr/Swg Pumping 80 15B-Universities 115 kv 81 30B - Manuf. (30 MW) 82 6 - Private Lighting 83 20 - Streetlighting Average Dollar per Bill Impact N/A N/A [U] 7.10 18.16 342.29 3,607.18 26,549.41 71.60 676.14 59,805.74 317,537.67

PNM Exhibit HEM-11 (July 1 Supplemental) 132 MW Scenario Page 1 of 5 Estimated Impact of Revised SIP with PV Unit 3 132 MW to SJ4 on Customer Bills in 2018 Customer Impact Residential Customers Allocation by Year Line Year Notes 2018 1 RSIP with PV3 Revenue Requirement [A] 93,415,178 2 Cost Allocators [B] = 2012 Class Revenue 44.38% /Total Revenue 3 Estimated Residential RSIP with PV3 Allocation [('! = [A] *[B] 41,457,729 4 Residential kwh (2012 Actuals) [D] 3,333,146,888 5 Estimated RSIP with PV3 Rate per kwh [E]=[C]/[D] 0.012438 Residential Customers Estimated RSIP with PV3 Bill Impact Line kwh Use [F] Estimated Annual RSIP with PV3 Bill Impact for 2018 [G] = S0.0I243H*[F] * 12 6 7 8 600 89.55

PNM Exhibit HEM-11 (July 1 Supplemental) 132 MW Scenario Page 2 of 5 Estimated Impact of Revised SIP with PV Unit 3 132 MW to SJ4 on Customer Bills in 2018 Small Power Customers Allocation by year Line Year Notes 2018 9 RSIP with PV3 Project Revenue Requirement [A] 93,415,178 10 Cost Allocators [H] = 2012 Class 13.51% Revenue/Total Revenue 11 Estimated Small Power RSIP with PV3 Allocation fu = [A] * [H] 12,624,719 12 Small Power kwh (2012 Actuals) [J] 966,425,575 13 Estimated RSIP with PV3 Rate per kwh [K] = [1]/[J] 0.013063 Small Power Customers Estimated RSIP with PV3 Bill Impact Line kwh Use Estimated Annual RSIP with PV3 Bill Impact for 2018 [Q [M] = (1013063 * [L] * 12 14 15 16 1,500 235.14

PNM Exhibit HEM-11 (July 1 Supplemental) 132 MW Scenario Page 3 of 5 Estimated Impact of Revised SIP with PV Unit 3 132 MW to SJ4 on Customer Bills in 2018 AH Other Customer Classes Cost Allocators by Year Line Customer Class 2018 /7V7= 2012 Class Rm-nue/ Total Revenue 17 3B/3C - General Power 18 4B - Large Power 19 5B-Mines 46/115 kv 20 10 - Irrigation 21 1 IB-Wtr/Swg Pumping 22 15B-Universities 115 kv 23 30B - Manuf. (30 MW) 24 6 - Private Lighting 25 20 - Streetlighting 21.26% 12.06% 0.72% 0.29% 1.44% 0.81% 4.30% 0.34% 0.89% All Other Customer Classes Allocation by Year Line Customer Class 2018 [O] = [NJclass ' 93.415,178 26 3B/3C - General Power 27 4B - Large Power 28 5B-Mines 46/115 kv 29 10 - Irrigation 30 1 IB - Wtr/Swg Pumping 31 15B-Universities 115 kv 32 30B - Manuf. (30 MW) 33 6 - Private Lighting 34 20 - Streetlighting 19,856,632 11,262,614 671,943 273,972 1,343,341 756,817 4,018,307 317,356 831,748 2012 Actual kwh - All Other Classes Line Customer Class 2018 35 3B/3C - General Power 36 4B - Large Power 37 5B-Mines 46/115 kv 38 10 - Irrigation 39 1 IB - Wtr/Swg Pumping 40 15B -Universities 115 kv 41 30B - Manuf. (30 MW) 42 6 - Private Lighting 43 20 - Streetlighting [f'l 1,939,015,568 1,411,906,111 91,241,920 28,455,014 191,783,766 101,874,529 633,849,603 16,252,906 50,551,135

PNM Exhibit HEM-11 (July 1 Supplemental) 132 MW Scenario Page 4 of 5 Estimated Impact of Revised SIP with PV Unit 3 132 MW to SJ4 on Customer Bills in 2018 Estimated RSIP with PV3 Rate - AH Other Classes Line Customer Class 2018 44 3B/3C - General Power 45 4B - Large Power 46 5B-Mines 46/115 kv 47 10 - Irrigation 48 1 IB - Wtr/Swg Pumping 49 15B-Universities 115 kv 50 30B - Manuf. (30 MW) 51 6 - Private Lighting 52 20 - Streetlighting IQJ'/OMP] 0.010241 0.007977 0.007364 0.009628 0.007004 0.007429 0.006340 0.019526 0.016454 Estimated Average Annual RSIP with PV3 Bill Impact - All Other Classes Line Customer Class Est. Average Monthly Estimated Average kwh Annual RSIP with PV3 Based on 2012 Actuals Bill Impact for 2018 53 3B/3C - General Power 54 4B - Large Power 55 5B-Mines 46/115 kv 56 10 - Irrigation 57 1 IB - Wtr/Swg Pumping 58 15B - Universities 115 kv 59 30B - Manuf. (30 MW) 60 6 - Private Lighting 61 20 - Streetlighting w 35,248 476,871 3,801,747 7,842 101,796 8,489,544 52,820,800 N/A N/A (SJ'IQJ *fr]*l2 4,331.57 45,647.31 335,971.74 906.05 8,556.31 756,816.79 4,018,307.30 N/A N/A

PNM Exhibit HEM-11 (July 1 Supplemental) 132 MW Scenario Page 5 of 5 Estimated Impact of Revised SIP with PV Unit 3 132 MW to SJ4 on Customer Bills in 2018 Annual of Customer Bills - AH Classes Line Customer Class Annual of Bills - Projected 2018 62 1A/1B- Residential 63 2A/2B - Small Power 64 3B/3C - General Power 65 4B - Large Power 66 5B-Mines 46/115 kv 67 10 - Irrigation 68 1 IB - Wtr/Swg Pumping 69 15B - Universities 115 kv 70 3OB - Manuf. (30 MW) 71 6 - Private Lighting 72 20 - Streetlighting m 5,539,706 659,200 55,010 2,961 24 3,629 1,884 12 12 0 1,716 Average Dollar per Bill Impact - All Classes Line Customer Class 73 1 A/IB-Residential 74 2A/2B - Small Power 75 3B/3C - General Power 76 4B - Large Power 77 5B-Mines 46/115 kv 78 10 - Irrigation 79 11B - Wtr/Swg Pumping 80 15B - Universities 115 kv 81 30B - Manuf. (30 MW) 82 6 - Private Lighting 83 20 - Streetlighting Average Dollar per Bill Impact N/A N/A [U] 7.48 19.15 360.96 3,803.94 27,997.64 75.50 713.03 63,068.07 334,858.94

BEFORE THE NEW MEXICO PUBLIC REGULATION COMMISSION IN THE MATTER OF THE APPLICATION } OF PUBLIC SERVICE COMPANY OF NEW ) MEXICO FOR APPROVAL TO ABANDON ) SAN JUAN GENERATING STATION UNITS ) 2 AND 3, ISSUANCE OF CERTIFICATES ) OF PUBLIC CONVENIENCE AND ) NECESSITY FOR REPLACEMENT POWER ) RESOURCES, ISSUANCE OF ACCOUNTING ) ORDERS AND DETERMINATION OF ) RELATED RATEMAKING PRINCIPLES AND) TREATMENT, ) ) PUBLIC SERVICE COMPANY OF NEW ) MEXICO, ) ) Applicant ) Case 13-00390-UT AFFIDAVIT STATE OF NEW MEXICO ) ) ss COUNTY OF BERNALILLO ) Henry E. Monroy, Director, Cost of Service and Corporate Budget, Public Service Company of New Mexico, upon being duly sworn according to law, under oath, deposes and states: I have read the foregoing July 1 Supplemental Testimony of Henry E. Monroy and it is true and accurate based on my own personal knowledge and belief. SIGNED this day of July, 2014. HENRY E. MOfrROY k, i

SUBSCRIBED AND SWORN to before me this day of July, 2014. NOTARY PUBLIC IN AND"FOR THE STATE OF NEW MEXICO i^ondff Morehead V^,D S^7 NOTARY PUBLIC STATE OF NEW.MEXICO My Comwlaslon R«^iro«; y, fl - 2 GCG #518299