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 RATE- )
MAKING PRINCIPLES AND TREATMENT )
PUBLIC SERVICE COMPANY OF NEW MEXICO, )
) Case No. 13-00390-UT
DIRECT TESTIMONY AND EXHIBITS
IN OPPOSITION TO THE STIPULATION
DAVID VAN WINKLE
ON BEHALF OF
NEW ENERGY ECONOMY
November 25, 2014
Table of Contents
San Juan abandonment 6
Acquisition of 132 MW in San Juan unit 4 7
Acquisition of 134 MW of Palo Verde 3 22
Alternative plans/approaches 29
Stranded assets, PV reliability, renewable energy paragraphs 43
DVW Exhibit nomenclature:
DVW-x Exhibits in 8/29/14 direct testimony
DVW S-x Exhibits in 9/10/14 CONFIDENTIAL supplemental testimony
DVW R-x Exhibits in 9/16/14 rebuttal testimony
DVW OST-x Exhibits in 11/25/14 direct testimony – opposition to stipulation
DVW COST-x Exhibits in 11/25/14 direct CONFIDENTIAL testimony – Reserve issue
Q. Please state your name and business address.
A. My name is David Van Winkle, and my business address is 343 E. Alameda St., Santa Fe, NM 87501.
Q. On whose behalf are you testifying in this proceeding?
A. I am testifying on behalf of New Energy Economy (“NEE”)
Q. Please summarize your educational and business background.
A. I have a Master’s degree in Electrical Engineering from Southern Methodist University. For the past 6 years, I have been involved in reviewing renewable resource plans of New Mexico utilities and making recommendations to various organizations including the Rio Grande Chapter of the Sierra Club, New Energy Economy and the Coalition for Clean Affordable Energy (CCAE). I have considerable experience in analyzing complex cost and financial issues and providing solutions to business problems. In addition, through extensive discussion and participation in New Mexico electric utility resource issues over the years, I have developed technical knowledge about resource options for meeting utility loads. I am the current Chairperson of CCAE’s Supply Team, which analyzes utility resource acquisitions on behalf of CCAE. I am also the technical/financial advisor to New Energy Economy. I have previously testified before the New Mexico Public Regulation Commission as an expert for CCAE in 14-00121-UT. A resume of my relevant educational and business experience is attached as Exhibit DVW OST-1.
Q. Have you filed previous testimony in this case?
A. Yes. Direct testimony on 8/29/14, CONFIDENTIAL supplemental testimony on 9/10/14, and rebuttal testimony on 9/16/14. My prior testimony is adopted and incorporated herein, and as per the October 9, 2014 Order of the Hearing Examiner it is unnecessary to refile it as part of my testimony in Opposition to the Stipulation. (October 9, 2014 Order, C, pp. 4, 5)
Q. Does the Stipulation, as a package, benefit PNM ratepayers and is it in the public interest?
A: The Stipulation as a package is not in the public interest. It is not the most cost-effective energy portfolio for ratepayers, and contrary to PNM’s claims, there are other feasible alternatives that are not only cheaper but have superior economic, health, and environmental results.
1. That said, I support the portion of the Stipulation that approves abandonment of San Juan units 2 and 3.
2. PNM’s request to put Palo Verde 3 (PV3) into rates should not be approved. PNM’s desire to add 134 MW of Palo Verde 3 power is understandable because this case presents PNM with a convenient opportunity to move their own asset heretofore excluded from rate base into rates. PNM acknowledges that PNM is losing money selling PV3 generated electricity on the open market but by putting PV3 into rates it turns a troubled asset into a profitable asset for PNM, at enormous expense and potentially catastrophic risk to the ratepayers. PNM wants to move PV3 into its rate base because, that way, it can sell energy to the rate payers of New Mexico at about 8.1 cents per kWh, assuming the valuation of $1650/kW. Today, they sell the PV3 energy at 3.7 cents per kWh in the merchant market. It does not make sense that New Mexico rate payers should pay 119% above market rates for this energy. This is especially true when there are cheaper alternatives. In addition, by moving PV3 into the rate base, PNM will shift from the shareholders to the ratepayers the future cost of decommissioning, which is significantly underestimated when compared to actual decommissioning costs of other nuclear plants, and the risk of potentially catastrophic events associated with an aging nuclear power plant.
3. PNM’s request to acquire 132 MW from California owners in SJGS unit 4 should not be approved. PNM now proposes to acquire additional coal capacity (in PNM’s Original Application they proposed the purchase of 78 MW and the Stipulation calls for the purchase of 132 MW) not because this is the best energy decision or the most cost-effective resource or a reasonable and prudent investment for ratepayers but because PNM could not “see that the non-binding [SJGS partnership] agreement would have been reached without” the acquisition by PNM of the 132 MW of coal in SJGS unit 4. (Senior Vice President Ron Darnell, Deposition of October 7, 2014, p. 25) PNM’s acquisition of this interest in San Juan may be beneficial for its shareholders, but the applicable regulatory standard is what is fair, just and reasonable and in the best interest for ratepayers.
Further coal acquisition at this time is imprudent for a number of reasons: replacing the closure of coal with more coal increases New Mexico ratepayer exposure to rapidly escalating costs due to coal fuel costs, pollution controls, carbon costs, mine reclamation, decommissioning, and coal ash disposal costs. These factors will demonstrably drive San Juan coal produced energy up to ~10 cents per kWh. In addition the Commission would put ratepayers at risk if it were to grant PNM’s CCN when coal fuel availability and the coal price for post 2017 is unknown because PNM has been unable to establish a source of supply. Further, the San Juan coal plant is an aging facility. The plant’s forced outage rate is 2.3 times the national average and only runs at 85% capacity at summer peak hours – so its full capacity cannot be counted on for peak attainment. Lastly, PNM’s choice will necessarily force New Mexico and its rate payers to embrace a technology that is harming their health, contributing to climate change and is enormously wasteful of New Mexico’s small, precious supply of water.
4. Ratepayers have not benefitted from a rigorous independent vetting or analyses of the best replacement power plan. PNM needs to immediately begin a vigorous, in-depth study of alternatives, with key stakeholders involved in the process that a) includes an all-source RFP for replacement capacity and energy, b) upgrade of methodologies for use of Strategist® that more accurately assesses alternatives, c) upgrade capabilities to integrate wind and solar in PNM’s system, d) seeks low risk and cost effective solutions and puts New Mexico on a low-carbon path for the provision of energy. PNM has testified that there is adequate time to pursue alternative solutions. Indeed, PNM is asking for approval of the Stipulation, which includes a major acquisition of coal fired generation, before it has negotiated a price or source for its fuel.
5. The Commission should require PNM to get approval of any long-term (beyond 2022) coal contract or other coal supply arrangement that would commit PNM and hence ratepayers to large costs (>$10 million). PNM has a history of committing to take-or-pay (fixed costs) coal supply contracts. That type of long-term obligation exposes the ratepayers to too much financial risk and ties them to an expensive technology just as the costs of renewable energy sources are plunging. These large contracts are in essence policy decisions that require Commission oversight and approval before contractual commitment guarantee ratepayer reimbursement.
Stipulation Issues and Recommendations
Q: Many PNM witnesses provide testimony that the RSIP is a superior outcome to the FIP. Paragraph 13 of the Stipulation states “PNM shall be authorized to abandon SJGS Units 2 and 3 effective December 31, 2017 and shall permanently retire them from providing service.” Do you agree with the testimony and the portion of the Stipulation that confirms this and why?
I had the privilege to be intimately involved in the negotiations that resulted in PNM’s last offer to the EPA, which the EPA accepted, and is now known as the Revised State Implementation Plan (“RSIP”). After the prior offer to EPA was rejected (the closing of units 1 & 2) because it didn’t fully comply with Clean Air Act standards, I was the person who figured out the puzzle and the answer was communicated to PNM to convey to EPA: to close units 2 & 3 instead. This was the answer that ultimately prevailed and has been widely touted as the superior outcome in the best interest of New Mexicans.
The request to abandon San Juan Units 2 and 3 on 12/31/17 and permanently retire them should be approved by the PRC. PNM has shown that abandonment of SJGS units 2 and 3 in conjunction with implementation of SNCR on SJGS Units 1 and 4 meet the Regional Haze Clean Air Act requirements. The EPA, New Mexico Environment Department and the New Mexico Environmental Improvement Board concur with the RSIP. PNM has shown in this case that the RSIP is less costly than implementing the Federal Implementation Plan (“FIP”) that required implementation of Selective Catalytic Reduction (SCR) on all four SJGS units. Further, the RSIP is a significantly better environmental outcome than the FIP.
Q. Paragraph 14 of the Stipulation requests that PNM be granted a CCN for an additional 132 MW of capacity in SJGS Unit 4, effective 1/1/18 and the initial value for ratemaking purposes will be $26 million. What is your recommendation?
A: The PRC should deny this request at this time. PNM should first be required to issue an independently evaluated all source Request For Proposal (RFP) for the capacity and energy it would otherwise seek to obtain from the 132 MW of capacity and energy from San Juan Unit 4 to determine if cheaper and less risky alternatives are available. This is the only way the Commission can be assured that ratepayers are obtaining the most cost effective solution. As things stand now, it is impossible to make that determination.
PNM is acquiring the 132 MW from SJGS Unit 4 not because it is the best energy resource for New Mexicans, or the most-cost-effective solution, but is “based on considerations relating to capacity that exiting owners want to divest.” (Olson, Direct Testimony in Support of Stipulation, p.61) So PNM is not acquiring this capacity for system needs, but rather acting as a sponge for excess capacity to keep the other owners placated. “I am personally unaware of any other path forward than PNM assuming the 132-megawatt ownership.” Senior Vice President of PNM, Ron Darnell testified at his deposition, on October 7, 2014, p.26. WRA testimony from Mr. Dirmier states “PNM should not be tasked with having to absorb whatever SJGS capacity the other owners forego, and the Commission, by granting a CCN, must protect ratepayers from the extraordinary risk that acquiring coal-fired generation today poses.” (Direct testimony, 8/29/14, page 29, line 5-8)
Mr. Darnell argues that because California entities and Tri-State “indicated their desire to exit from active participation in SJGS” PNM has to absorb the 132 MW to facilitate the ownership structure. “This would have put PNM and the Commission in the untenable position of awaiting years of costly litigation or arbitration to determine the respective obligations of the owners for paying for the costs of making San Juan compliant with environmental regulations or shutting it down….” (Darnell, Direct Testimony in Support of Stipulation, p.26) First, the fact that co-owners are trying to escape their ownership obligations is not an untenable position for the Commission, though it might be for PNM. Second, even if it is an untenable position for PNM that does not justify ratepayers having to absorb the additional coal shares. (PNM could buy the 132 MW from existing co-owners and sell it on the open market.) Third, the Commission should be extremely wary of approving 132 MW at $0 cost and the assumption of future liabilities.
“PNM is not paying any money to M-S-R or Anaheim for the acquisition of the additional 132 MW in San Juan Unit 4. … However, … the Stipulation calls for the additional 132 MW of San Juan Unit 4 to be placed on PNM’s books for ratemaking purposes at a value of $26 million.” (Olson, Direct Testimony in Support of Stipulation, p.19) There is no reasonable basis for this write-up. Furthermore, PNM has essentially made its relationship with its co-owners a black box, without any explanation of what the respective rights and obligations of the owners are now. The San Juan ownership mediation process and the confidentiality claims stemming from that process that started in 4Q 2013 are still limiting transparency. PNM seems to be simply saying, “Trust us. We don’t want to get into litigation with our co-owners regarding liability issues going forward. Let us just take their interests ‘for free’, write up their value, take on their shares of the future risks and let them off the hook.”
Gerard Ortiz argues that “[T]he proposed valuation is reasonable because it represents a fair compromise of the value to be assigned to the plant for ratemaking purposes, considering all the circumstances.” (Ortiz, Direct Testimony in Support of Stipulation, p.46) Yet, there are no circumstances that he really considers other than that the $26 million is half of PNM’s original request in the Application and “also reflects consideration of the concerns expressed by some parties of future coal risk associated with the additional SJGS Unit 4 capacity.” (Ortiz, at p. 46) This is circular logic and the $26 million is not justified.
Q. PNM Senior VP Ron Darnell states: “PNM has an obligation under the Public Utility Act to provide service at just and reasonable rates, and keeping costs under control is obviously an important part of being able to provide reasonably priced electricity.” (Darnell, at p. 15) Do you have other reasons why you believe that acquiring 132 MW of capacity from California owners in San Juan Unit 4 as part of PNM’s replacement plan is not reasonable and will continue to cause rates to soar because of PNM’s heavily reliance on coal?
A: Yes. 1. The cost to operate SJGS is higher than alternative resources. The levelized cost is $0.099/kWh for 2018-33. (Exhibit DVW OST-6)
2. Coal fuel costs are escalating rapidly. PNM is projecting that coal fuel cost per MWh will increase by 92% from 2014 to 2032, for a cost increase by 2032 of $78 million per year (PNM Exhibit Staff 7-1, wp 4, pp. 5-8). SJGS coal fuel costs are already one of the highest in west. The San Juan owners are certainly concerned about this issue, as they have articulated in a separate paragraph in the most recent term sheet.
It is understood that prior to executing the Restructuring Agreement, the Remaining Participants will need to have greater certainty in regard to the economic cost and availability of fuel for the SJGS in the period after January 1, 2018. (13-00390-UT, PNM Testimony, July 15 Olson, PNM Exhibit CMO-1, page 14.)
Additional information is provided in my sealed CONFIDENTIAL testimony regarding specific risks and potential liabilities about the Reserve issue regarding uncertain coal fuel supply.
3. Ratepayer exposure to fixed costs associated with the “take-or-pay” coal contract that PNM signed at the end of 2013 at Four Corners Power Plant commits NM ratepayers to more than $500 million in long-term fixed costs (Van Winkle 8/29 testimony, page 25). This fixed cost obligation starts at $21 million in 2016 and nearly doubles to $39.5 million in 2031. As far as I know, this $500 million commitment has not yet been communicated to the PRC. If PNM were to commit to a similar liability at SJGS, it would be about $1500 million.
4. As discussed in more detail later in this testimony at pages 19-22 herein, PNM is negotiating to buy the San Juan mine. This would expose ratepayers to huge fixed costs and liabilities. The real bottom line on this purchase is that the utilities that own SJGS are not mining companies. They are not qualified to buy a mine, and especially a troubled mine like SJCC. Additional information is provided in my confidential testimony of 11/25/14.
5. The coal fuel supply from the San Juan mine has a history of unreliability. Currently, all coal fuel is sourced from the adjacent San Juan mine. This mine was closed for eight months, from September 2011 to May 2012, due to a fire. It took another two years and four months to recover to normal operations as stated in PNM’s 10Q of 10/31/14 page 61 “SJCC provided notice to PNM on September 23, 2014 that the mine has been restored to normal operations.”
6. The quality of the coal coming from the San Juan mine is degrading rapidly, as measured by heat content, ash content, and sulfur content.
(Minus = unfavorable)
Lower quality coal means lower energy output and less efficiency. This translates into the need for more coal to be mined, more coal burned, more coal ash to be created, more greenhouse gas emissions and toxic pollutants produced. This means higher fuel costs and greater externalized health care costs for society.
7. Methane output of the San Juan mine was 32,514 metric tons in 2013, making it the second largest methane contributor in the San Juan basin.
8. The San Juan mine is the subject of a lawsuit by WildEarth Guardians. See pages 19-20 herein for details.
9. Mine reclamation costs will be very significant. From PNM’s 10Q report of October 31, 2014, page 60 “Based on the 2013 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $53.9 million [~$18M for SJGS and ~$36M for FCPP] for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of June 30, 2014. PNM did provide their forecast of mine reclamation costs separately from the costs of SJGS, but it only totals to $29.6 million through 2033 (Monroy, 10/31/14, HEM-15 Stip). PNM input these costs to Strategist® at intervenor’s behest in August in response to CCAE Interrogatory 12-10. So, there is a gap of $63.7 million ($93.3 - $29.6 = $63.7 million) between the needed mine reclamation accruals and the planned accruals to fully fund the liability.
10. PNM has repeatedly told investors (as recently as 10/31/14) that they have “significant exposure” to large compliance cost increases associated with the new coal ash disposal rules that the EPA will announce in December 2014. PNM’s 10Q report to the SEC filed on 10/31/14 stated (page 60)
On January 29, 2014, EPA entered into a consent decree directing EPA to publish its final action regarding whether or not to pursue the proposed non-hazardous waste option for CCBs by December 19, 2014.PNM advocates for the non-hazardous regulation of CCBs. If CCBs are ultimately regulated as a hazardous waste, costs could increase significantly. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of EPA’s or OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material impact on its operations, financial position, or cash flows.
SJGS produces a large amount of coal ash, 1.8 million tons in 2013 that may be subject to these new EPA standards (PNM answer to CCAE Interrogatory 7-4). The mid-range cost estimate by the Company of the cost of compliance is $61/ton (Deposition of Maureen Gannon, 8/22/2014, pages 54, 55, Exhibit DVW-38). At this cost, the ratepayers will see an increase of $38 million per year. PNM’s high risk estimate for coal ash disposal is $271/ton. Although PNM has informed its investors of these risks, PNM has not mentioned it in its 1000’s of pages of testimony filed in this case.
11. The remaining owners are concerned about environmental liabilities:
the Participants will engage an independent, third-party environmental consultant ("Consultant") to complete a confidential baseline multi-media environmental self-evaluation ("Baseline Environmental Study" or "BES") of SJGS and its operations. The purpose of the BES is to establish a baseline of environmental conditions in anticipation of the Exiting Participants' exit from active involvement in the operation of SJGS on the Exit Date. (13-00390-UT, PNM Testimony, July 15 Olson, PNM Exhibit CMO-1, page 4).
12. Carbon costs to bill-payers, as projected by the Company, are $68 million in 2020 and grow to $297 million in 2033 (PNM Exhibit CCAE 14-2zd, pages 389-91).
13. The cost of pollutions controls at SJGS has continued to escalate. In 2006-9, PNM implemented an environmental upgrade that cost $320 million (Exhibit DVW-8). When PNM first presented this program to the owners for their approval in 2005, the cost estimate by PNM was $110 million. More recently, the cost of SNCR has increased by 400% (See DVW 8/29 direct testimony, page 7, lines 9-12).
14. The reliability of SJGS is significantly worse than national averages. SJGS Equivalent Forced Outage Rate (EFOR) for 2007-13 was 17.6%. The national average for EFOR as reported in NERC for similar size coal facilities was 7.6% for 2007-11 (Exhibit DVW OST-2, pages 11-13)
As a result of SJGS unreliability PNM must have back up sources of energy, either gas or purchases on the open market, that cost more than coal fuel, and represent additional cost burden to ratepayers. PNM VP Olson testified that “Unit 4 has been a solid performing unit with an average availability factor of 87.47% for the period from 2008 through 2012. (Olson supra, at p. 62) However, this directly conflicts with PNM’s “Equivalent Measures Report,” which PNM provided NERC, that states that average equivalent availability factor (EAF) of 79.7% for the period from 2008 through 2012. (PNM Exhibit CCAE 12-15) It is also interesting that Mr. Olson omitted the 2013 actual EAF of 74.7%. (PNM Exhibit CCAE 12-15)
15. The SJGS output during summer peak demand hours is 15% below capacity (Exhibit DVW OST-2, page 8, line 4), so PNM’s nameplate capacity cannot be counted upon to meet peak summer demands. By comparison to another investor owned utility serving New Mexicans, Southwestern Public Service (SPS) coal plants operate within 3% of nameplate capacity in these same summer peak hours. This means that PNM has to acquire gas capacity or capacity from the merchant market to meet peak demand and this has significant costs for ratepayers. For 2011- 2013 PNM purchased an average of 400 MWh of energy to meet THE peak hour customer demand. (Exhibit DVW OST-2, pages 26, 27).
16. SJGS uses 594 gallons of water per MWh (PNM Exhibit CCAE 1-1). At PNM’s planned level of production for 2018-33, PNM’s share SJGS will consume more than 30 billion gallons for the time period 2018-33. (To understand the magnitude of this water usage, Santa Fe’s entire consumption is about 3 billion gallons of water per year.)
17. PNM Director, Planning and Resources, states: “It is simply not reasonable to assume that there will not be additional costs associated with greenhouse gas emissions during the twenty-year planning period.” (Direct Testimony of Patrick O’Connell, December 20, 2013, p. 18) PNM repeatedly acknowledges that there is a cost risk associated with compliance with environmental regulations associated with coal. (Darnell, supra at p.18; Ortiz, supra at pp. 27, 40, 42) PNM’s compliance with the new EPA Clean Power Plan rule is unknown. However, San Juan CO2 emissions are projected by PNM to be 2312 lbs/MWh. (PNM Exhibit CCAE 1-1) New Mexico Electric Generating Unit (EGU) emissions may be required to average 1107 lbs/MWh between 2020 and 2029, followed by a final CO2 limit of 1048 lbs/MWh at 2030 and beyond. (PNM’s independent consultant, Edward Cichanowicz p. 32) At PNM’s planned output for the 132 MW, an additional 2013 million lbs. of CO2 per year will be produced. (PNM Exhibit CCAE 12-9) PNM claims that it will be “well-positioned to meet anticipated environmental regulations,” but fails to definitively state that they will meet the requirements of EPA’s Clean Power Plan. (Olson, supra, at p. 60) In fact, PNM’s Executive Director of Environmental Services, Maureen Gannon testifies in her deposition that “in the context of what EPA has proposed for its state standards under the Clean Power Plan, [PNM’s emissions] gets the State very close to the proposed standard.” … “New Mexico will get within 10% of the Clean Power Plan.” Gannon Deposition of August 22, 2014, pp. 75, 76). In other words, they don’t make it with the current proposed replacement plan.
18. PNM does not need to replace the lost capacity with base load resources. PNM has now and will have in 2018 more base-load relative to their customer needs than other major utilities in this region. (See, DVW OST-2, pages 4-7, for more details) When a utility has too much base-load on its system there will be times when the customer demand forces the utility to curtail the output of coal and/or sell the excess energy on the open market at a volatile price.
19. Energy produced by coal-fired power plants does not contribute to attainment of the Renewable Portfolio Standard and makes it harder to achieve. PNM will need to add more than 100 MW of wind or solar, in addition to its proposed plan, to achieve the 2020 RPS requirement. (Exhibit DVW-27)
20. Decommissioning costs for San Juan will also be significant. According to a 2013 study by Black & Veatch, the decommissioning costs for San Juan will be $24 million to $259 million. (DVW OST-14) In PNM’s testimony by Mr. Olson, he states “The San Juan participants have agreed to an initial funding amount of $30 million. This initial funding amount must be fully funded by December 31, 2022….. PNM will be required to contribute 46.6% of the initial $30 million so its initial contribution is $13,980,000.” (PNM Olson testimony, page 39, lines 3-4, 11-12) These costs have not been comprehended in revenue requirements for San Juan costs provided by the company in discovery. In Strategist®, SJGS decommissioning costs were first comprehended at intervenor behest in August, CCAE Interrogatory 12-10. These costs are much lower than Mr. Olson’s testimony, at only $2.6 million through 2022. (PNM Exhibit NEE 4-4) The remaining owners are also concerned about uncertainty regarding decommissioning costs:
Decommissioning: As soon as practicable after adoption of this Resolution, the Participants will continue to develop a method for funding decommissioning of SJGS. (13-00390-UT, PNM Testimony, July 15 Olson, PNM Exhibit CMO-1, page 7)
21. Operating reserve requirements will likely increase. Today, the largest hazard in PNM’s system is San Juan unit 3 at 248 MW. If PNM’s CCN is approved, the largest hazard will become San Juan unit 4 with 327 MW. Patrick O’Connell states “PNM expects that the reserves will increase in 2018 assuming Southwest Reserve Sharing Group does not change their current method for calculating Reserves.” (PNM answer to CCAE Interrogatory 12-14) Typically, the largest hazard reserve requirement is to maintain 50% as spinning reserve. The consequence of PNM’s proposal would require an addition of 40 MW of spinning reserve. This extra 40 MW of spinning reserve could add the cost of a 40 MW gas peaker to customer costs.
22. PNM’s New Mexico residential ratepayers saw their bills increase by 41% from 2008 to 2011, due to PNM’s heavy reliance on coal (60% of PNM’s energy is supplied by coal). The cost factors cited here will likely cause “rate shock” multiple times in the next 20 years if PNM is allowed to expose ratepayers to further investment in coal mining and burning.
Q. PNM acknowledges that there is no fuel supply availability or price certainty, other than current stock pile, for the San Juan Generating Station post 2017. (Deposition of Senior VP Ron Talbot, Deposition of November 24, 2014; Olson supra, pp. 48-51) Paragraph 15 of the stipulation states that “the granting of a CCN for 132 MW of SJGS Unit 4 should include conditions related to future coal supply agreement or arrangement for SJGS Units 1 and 4.” (Stipulation at p. 5) What is your recommendation?
A. In order to protect ratepayers, PRC oversight and approval must be required prior to PNM locking in $100’s of millions for ratepayers, such as take-or-pay contracts, mine acquisition, or other similar contractual arrangements that lock-in large fixed costs to ratepayers.
The following issues are major concerns that should be comprehended:
In addition to potential take-or-pay contracts, PNM is proceeding to negotiate with BHP to buy the SJCC mine. The opportunity to acquire large fixed costs as well as a whole host of future liabilities is significant.
On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the UG-CSA that provides for the negotiation of a potential purchase transaction for the mine assets to be consummated on or before December 31, 2016. The purchaser could be one or more of the San Juan owners, an affiliated company, or a third-party agreed to by the parties. On October 2, 2014, the parties entered into an agreement that provides the San Juan participants with access to data necessary to evaluate the mine assets and liabilities. If the mine assets are acquired from SJCC, it is contemplated that a third-party miner would be engaged to conduct mining operations on a contract basis or would assume ownership of the mine assets and carry out the mining operations. (Olson testimony, 10/31/14, page 50, lines 2-12)
The San Juan mine is the subject of a lawsuit between WildEarth Guardians and Office of Surface Mining (OSM).
In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (“NEPA”) violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact. (PNM 10Q report, 10/31/14, page 57)
Methane output of the San Juan mine was 32,514 metric tons or 812k tons of CO2 in 2013. The footnoted website from EPA shows that the San Juan mine is the second largest methane contributor, behind only ConocoPhillips, in the region. The area of the report was -109.6 to -107.0 W, 36.2 to 37.4 N. The San Juan mine is located at -108.4 W, 36.8 N, almost in the exact middle of the study area.
Overall, acquisition of the San Juan mine by PNM would be a very bad business decision and a major disaster for the company and the ratepayers: high costs due to underground mining low productivity, volume reductions of 50%, unreliability due to fire potential, the temporary or permanent closure of the mine due to regulatory non-compliance, exposure to liability from a lawsuit, large methane emitter, and questionable future of SJGS. The Commission needs to step in and protect the ratepayers from this potential calamity from becoming a devastating reality. More specific issues are detailed in my confidential testimony.
In addition to this action, the SJGS owners are working with Ute Mountain Ute to develop a new coal mine. This is yet another opportunity to acquire large fixed costs. My sealed confidential testimony will provide more information on this issue.
As stated more fully above and in my prior testimony I am adamantly opposed to the CCN for more coal because I don’t believe it is reasonable or prudent and is not in the public interest. If the Commission grants a conditional CCN for the 134 MW of coal from SJGS Unit 4 these are my recommended conditions precedent:
Require a PRC docket be opened specifically on the benefits and risks of acquiring the San Juan mine from BHP Billiton before PNM purchases it, including, but not limited to:
the disclosure, independent assessment, and response by PNM of coal price (including fixed and variable components), a comprehensive business plan that includes a breakdown of fixed and variable costs by category, an analysis of potential stranded costs, and indicates the length of time of operation;
the satisfactory resolution of outstanding lawsuits;
the disclosure and independent evaluation of the baseline environmental study conducted by the Remainers, and PNM’s response including a low-medium-high risk analysis with corresponding dollar amounts;
a cost analysis by an independent evaluator that considers the impact of methane and other pollutants on the health of the local community and the cost of compliance of future environmental regulations, and PNM’s response;
the disclosure of the legal and financial ownership structure of the mine;
proof of insurance or a surety bond from the mine owner and/or operator;
the contract between the mine owners and the miner, including any take-or-pay contract, cost per unit, profit agreement, and term of contract; and
an explanation by PNM how it will address and evaluate all risks already articulated by BHP Billiton in WRA 1.3 1592, pp. 25 and 27, attached to my confidential testimony filed on November 25, 2014.
Require a PRC docket to be opened specifically on the benefits and risks of developing another mine at Ute Mountain Ute or any other source of coal (i.e., Navajo mine).
Fulfill all required permitting by law: NEPA, cultural and paleo, etc.;
the disclosure and independent assessment and response by PNM of coal price (including fixed and variable components), a comprehensive business plan that includes a breakdown of fixed and variable costs by category, an analysis of potential stranded costs, and indicates the length of time of operation;
a cost analysis by an independent evaluator that considers the impact of methane and other pollutants on the health of the local community and the cost of compliance of future environmental regulations, and PNM’s response;
the disclosure of the legal and financial ownership structure of the mine;
proof of insurance or a surety bond from the mine owner and/or operator; and
the contract between the mine owners and the miner, including any take-or-pay contract, cost per unit, profit agreement, and term of contract.
Q. What is PNM requesting concerning Palo Verde Unit 3 in paragraph 16?
A. The company is requesting issuance of a CCN to include PNM’s share (10.2%) of Palo Verde Unit 3, with capacity of 134 MW, in rate base to serve New Mexico retail customers effective January 1, 2018, at a value for ratemaking purposes of $221.1million, i.e. $1650/kW. In addition, the net book value of transmission assets associated with Palo Verde Unit 3 shall be included in rate base, currently estimated to be $3.0 million at December 31, 2017.
Q. Should this request for a CCN for PV3 at a valuation of $221.1 million be approved by the Commission?
A. No, not at this time. PNM should first be required to issue an all source Request For Proposal (RFP) for the capacity and energy it would otherwise seek to obtain from Palo Verde 3 to determine if cheaper and less risky alternatives are available. This is the only way the Commission can be assured that ratepayers are obtaining the most cost effective solution. As the Public Service Company of New Mexico (PNM) is the current owner of this 134 MW of capacity in PV3 (PNM answer to NEE Interrogatory 2-8), an arms-length transaction is not possible. PRC Staff Testimony from David Rode warns: “because PNM itself is taking both sides of these transactions (i.e. “selling” from the non-regulated side to the regulated side), it seems worthy of heightened scrutiny” (13-00390-UT, PRC Staff Testimony, Rode, p.17)
Q. What are your objections to acquiring the 134 MW of nuclear power from Palo Verde 3?
A: 1. PNM is currently selling PV3 nuclear generated electricity on the open market at 3.7 cents per kilowatt hour and it costs PNM 4.3 cents per kilowatt hour to make; this translates into a $6 million loss annually. PNM wants to move PV3 into its rate base because, that way, it can sell energy to the ratepayers of New Mexico at 8.1 cents per kWh. (See exhibit DVW OST-5) It just does not seem reasonable or prudent that PNM should sell this energy to its ratepayers at 119% above the market price. However, when you consider that San Juan levelized costs are over 9¢/kWh, it could make sense to include PV3 in PNM’s portfolio when all of San Juan capacity is retired, assuming other, less expensive and risky resources are not available.
2. The cost to put PV3 into rates is higher than other alternatives. The levelized cost is $0.081/kWh. (Exhibit DVW OST-5). The following table has two alternatives that are significantly less expensive than PV3.
3. PNM’s system does not need any more base-load. If the PNM replacement plan is approved, PNM will have more base-load relative to their customer need than any other major utility in the region. (See DVW OST-2, pages 4-7 for details.)
4. Ongoing capital expenditures to maintain its operation at Palo Verde are quite large. Actual ongoing capital expenditures for total Palo Verde were $800 million for 1994-2003 and, $2192 million for 2004-13. (PNM answer to NEE Interrogatory 1-20) PNM’s current forecast for their share of Palo Verde for 2014-33 is $193 million for units 1 & 2 plus $84 million of ongoing capital expenditures for unit 3. (PNM Exhibit NEE 4-4) PNM’s Strategist® runs excluded any of these relevant costs prior to August when CCAE Interrogatory 12-10C requested that this error be fixed. Yet, ongoing capital expenditures were not comprehended in PV3 revenue requirements (even through PNM Exhibit NEE 2-1 that was provided on 10/31/14). The omission of these numbers are quite significant ($5M in 2019, rising to $16M in 2033 – PNM Exhibit NEE 4-4), Patrick O’Connell admits to not including ongoing capital expenditures at p. 14 of his testimony. His statement indicates that PNM’s use of Strategist® has always been biased towards maintaining existing resources, by understating the variable costs of existing resources, and not fairly considering new cost effective resources.
5. Significant financial risks associated with Palo Verde 3 currently reside with the corporation. If this facility were to be brought into rates, the New Mexico ratepayers would now shoulder those risks. These risks include decommissioning, possible failure to operate for the next 33 years – the current permit horizon, catastrophic events, increased health and safety concerns evident from the Fukishima disaster, and fuel waste disposal.
6. The decommissioning risk is particularly significant. PNM testimony from Horn on 10/31/14 (page 13, line 1) states that PNM share of decommissioning PV3 is $91.1 million. This equates to $680/kW. In PRC Staff testimony of 8/29/14 from David Rode, he states “Exhibit DCR-18 contains the decommissioning cost experience for these thirteen facilities. The average cost, in 2014 dollars, is $1217/kW,” (13-00390-UT, PRC Staff Testimony, David Rode, pages 38-39 & see Exhibit DVW OST-18 for reproduction of the DCR-18 document). This is 79% higher than PNM’s estimate. At the average cost of $1217/kW, Palo Verde 3 decommissioning would cost $163 million or $72 million more than PNM’s estimate.
7. Concerning major equipment failure risk, Rode also documents three cases since 2002 of nuclear power plants that either incurred large costs due to down time or were retired early. The Davis-Besse Power Plant in Ohio had a two-year outage and cost about $600 million. The Crystal River plant was retired early in 2012 instead of incurring $1200-3700 million to repair it. San Onofre was retired early instead of incurring $317 million in repairs and replacement power. (13-00390-UT, PRC Staff Testimony, Rode, pages 40-41) Current projections for decommissioning San Onofre, a 2250 MW nuclear facility, exceed 4 billion dollars.
8. Palo Verde 3 output has not been as reliable as projected by the Company (PNM Testimony 12/20/13, Reed, page 19-20). The Company is projecting a capacity factor of 91.5%. The actual net capacity factor for PV3 has been 85.6% for 2007-13 (Exhibit DVW OST-8). PRC Staff testimony from David Rode further highlights this issue, as actual average refueling times for Palo Verde in total and Palo Verde 3 are 52 days over the past 7-10 years, versus PNM’s projection of 34 days. (DVW OST-8) Reduced reliability affects the cost per unit of energy.
9. The original valuation of $2500/kW is questionable. Vice President and Treasurer for PNM, Terry Horn, attempts to justify the price for PV3 as reasonable using two cases: “[T]he $1,650/kW agreed to in the Stipulation as the value for inclusion of PNM’s 134 MW of PVNGS Unit 3 into rate base is approximately $114 million ($850/kW) less than the market value of $2,500/kW to $2,600/kW that was required to purchase three of the PVNGS Unit 2 leases on the open market. (Horn Testimony in Support of the Stipulation, p. 5) The more that PNM pays for an asset that they purchase the more PNM makes in profit because they get 11.4% return on assets. So there is little motivation for PNM to get the best price. Horn refers to a 2011 lost bid for a Palo Verde lease which is at least more indicative of market price (despite that we have no idea about the specifics of the contract) but it is three years old.
Horn p. 4, argues that PNM paid $2500/kW and $2600/kW for the exercise of options for Palo Verde 2 leases that may have been included in 1986 participation agreements. While there was allegedly some fair market value assessment there was no bidding process. (PNM Exhibit CCAE Interrogatory Answer 8-6) Once again, we are not privy to the specifics of the sales transactions. Regardless, the question before the Commission is if the $221 million investment by ratepayers in PV3 is reasonable and prudent and in the best interest of ratepayers given all the circumstances and its system benefit.
It’s like a used car dealer buying a 1987 Pontiac for $2500. That does not mean that he can sell other 1987 Pontiacs in his inventory in the market for $2500. The value of the asset depends on the willingness of both the seller and the buyer. That’s why I reiterate my point about the need for an all resource RFP to determine the appropriate competitive price and relative system benefit. PNM might be correct about the price, but they might be wrong. If they are so sure that having ratepayers invest $221 million dollars is a reasonable and prudent investment then they should test it against the market and have an independent evaluator asses it. It is particularly striking that PNM has put out RFPs for solar, for wind, for gas plants but when it comes to the largest assets in this replacement plan (that they own) they refuse to do the same. The ultimate question in this case is: what energy resources are the best investments for ratepayers given the cost benefit ratio?
10. Electricity produced at PV3 in Arizona incurs a transmission energy loss of 1.5% more than New Mexico produced electricity (PNM answer to CCAE Interrogatory 2-12).
11. Energy produced by nuclear power plants do not contribute to attainment of the Renewable Portfolio Standard and makes it harder to achieve. PNM will need to add more than 100 MW of wind or solar, in addition to its proposed plan, to achieve the 2020 RPS requirement. (Exhibit DVW- 27)
12. It is my understanding that Palo Verde does not contribute to attainment of the proposed Clean Power Plan (CPP) as issued by the EPA earlier this year. “It is important to recognize the CPP Rule is a proposal at this point for the State of New Mexico….” not Arizona where the plant is located. (Cichanowicz, at p. 32)
13. Palo Verde consumes 768 gallons of water per MWh (PNM Exhibit CCAE 1-1). At PNM’s planned level of production for 2018-33, PNM’s share of PV3 will consume more than 12 billion gallons of water for the time period.
14. Importing energy from Palo Verde 3 that is located west of Phoenix, creates zero jobs for New Mexicans. Almost, any other alternative would create jobs in New Mexico.
Q. What types of resources are needed to replace the lost capacity and energy from the retirement of San Juan Units 2 and 3?
A. PNM needs resources that are flexible to meet changing customer demands. In PNM’s May 22 supplemental testimony, PNM’s native peak demand jumped dramatically by 79 MW in 2018 when compared to the December 20 testimony. At the same time, PNM lost its wholesale business with Gallup and lost 38 MW of demand. So, the net demand increased by 41 MW. PNM is now projecting that its load factor will decline from 60% in 2011 to 50% in 2030. In other words, their system demand is becoming more peaky. The following chart shows PNM’s load factor actuals and forecast for 1990 to 2032. (Ortiz 5/22/14 supplemental testimony, PNM Exhibit GTO-1)
This trend means that PNM will need even less base-load in the future. Right now, they already have more base-load relative to customer demand than other utilities in the region. Assuming approval of PNM’s plan to add 134 MW of PV3 and 132 MW of San Juan, this next chart compares PNM’s 2018 base load to its Load Duration Curve (LDC) and compares that to the other utilities in the region. PNM has more base load that any utility in the region when compared to the LDC for their respective utility.
Another measure of base load relative to customer demand is base load versus peak. The following chart shows that PNM’s projected base-load versus peak will the highest in the region in 2018.
In conclusion, PNM does not need to replace the lost base-load capacity that it will lose when retiring San Juan units 2 and 3 with base-load. In fact, it is desirable to not replace it with base-load so that the company has better flexibility in meeting changing customer demands and declining load factors. Investors in the utility business agree “Large scale power generation, however, will be the dinosaur of the future energy system: Too big, too inflexible, not even relevant for backup power in the long run.”
Q. What specific recommendations do you have for the Commission regarding the replacement of the lost capacity and energy from the retirement of San Juan Units 2 and 3?
A. First, a comprehensive all-source RFP process should be undertaken immediately, including independent evaluation.
Second, upgrade of methodologies for use of Strategist that more accurately and transparently assesses alternatives, including making Strategist® available to all parties at no cost, so that we can all understand the inputs and outputs.
Third, upgrade capabilities to integrate wind and solar in PNM’s system
Fourth, the replacement capacity and energy solution should be low cost, and cost effective solutions that put New Mexico on a low carbon path for energy procurement.
Q. Please explain the need for the RFP process, including independent evaluation.
A. This question of replacement capacity and energy is being faced all across the country and the overwhelming majority of states are choosing renewables and gas for replacement power, after a rigorous Request for Proposal (“RFP”) process. The RFP process is critical, as Ronald Lehr submits in New Energy Economy’s rebuttal testimony, because “there is no substitute for a resource price that is sourced from a reasonably competitive market.” (Lehr Rebuttal testimony at p. 7) Having a transparent process with an independent qualified evaluator whose task it is to examine market bids for new generation resources will almost certainly be more accurate and accountable than in-house determinations by PNM, with little or no mechanisms for external vetting or analyses. At no time in the last two years has PNM conducted an all-resource RFP to determine whether other alternatives can better replace the capacity and energy lost from San Juan unit 2 and 3 retirements.
Without the rigor of an RFP for replacement capacity and energy lost from SJGS units 2 & 3 the resource approach defined in the Stipulation is mere conjecture and does not demonstrate that is a cost effective approach. The unwillingness of PNM to conduct business in this way necessarily handicaps the public from fairly evaluating the coal and nuclear resource choices of the utility and evenly weighing the alternatives. Lastly, given the history of PNM’s poor planning, selective modeling and inadequate forecasting, even as demonstrated within the time period of the case herein, PNM’s calculation of risks in favor of the resource options they advocate cannot be given credence or be trusted. See, for example the more than $222M difference between PNM’s “Revised SIP with PV3” net present value (“NPV”) estimate in December 2013 and the same estimate in July 2014: $6,640,253,862 versus $6,862,680,319. And when the same run included ongoing “capital expenditures” at San Juan and Palo Verde – a known real cost, the NPV jumped another $532 million on August 15, 2014, to $7,394,425,624.
Q. Please explain the need for upgrading methodologies for use of Strategist.
A. In developing the replacement plan, the Company’s analysis has been inadequate or omitted important risk factors. As David C. Rode articulates: “I find the omission of coal as a variable in the risk analysis striking in this case, given that a central element of PNM’s case revolves around the value and risks of coal-fired generation.” Rode, at p. 23 This is a prime example of the biased and flawed modeling used to justify PNM’s replacement power plan.
Q. Are you concerned about the accuracy of PNM’s assertions regarding cost estimates and financial forecasting and the impact those have on the Commission’s ability to protect ratepayers?
A. Yes. First, I find it incredibly problematic that there is no standardization of analysis required by the Commission for PNM reports. The Commission should require that PNM, and all utilities, provide accessible financial analysis when the utilities file their Integrated Resource Plans, CCNs, and rate cases. Once revenue requirements are determined for each year, the remainder of the information is relatively easy to calculate. This should include: comprehensive revenue requirements by year with all relevant cost factors delineated, such as O & M, fuel, on-going capital expenditures, environmental regulatory compliance, depreciation, profit, reclamation, decommissioning, etc. Also there must be consistent, systemized methodological paperwork that delineates: cost per kWh for each year of expected asset operation (and with a gas peaker a $/kW-year cost); levelized cost per kWh over the life of the project; the utilities’ expected profit for each asset, the percentage rate increase to average residential consumers and the levelized costs of environmental regulations with a low-medium-high risk likelihood. As a result of the inconsistent ways of reporting, PNM answers are inconsistent, erroneous and create potentially misleading results. This lack of clear concise reporting prevents the Commission from knowing precisely the impacts of utilities’ proposals.
Here are a couple of examples when PNM has made major mistakes in estimation of costs. In 2005, it communicated to the other owners of SJGS that an environmental upgrade project would have a capital cost of $110 million. The actual capital cost of the project was $320 million. (See Exhibit DVW-8) The actual cost was 290% of the original communication to the other owners.
Also, in this case, the Company has recently admitted that the Strategist runs that they used to determine the “least cost solution” did not include decommissioning costs, mine reclamation costs, and ongoing capital expenditure costs for SJGS and PV3. (See Exhibit DVW-5) Once the Company included the known capital expenditure costs for both SJGS and PV3 the NPV cost rose by $532 million to $7,394, 425,624 (See Exhibit DVW-4).
These errors are just a few examples that have arisen in this case and are considerable, material and affect ratepayers.
Q. What has PNM stated about time available to consider other alternative replacement solutions?
A. PNM has stated that there is time to consider other alternatives for San Juan replacement. Patrick O’Connell, Director of Resource Planning, stated in his deposition that PNM has time to implement other alternatives (Deposition of Patrick O’Connell, 8/22/2014, page 42, lines 6-21, Exhibit DVW-39). Concerning how much time it would take to determine how much capacity is available in the market, he stated that “it could be done in a relatively short period of time….Could issue an RFP. We could talk to a broker.” (Deposition of Patrick O’Connell, 8/22/2014, page 49, lines 5-12, Exhibit DVW-39)
Q. In analyzing the costs for alternative solutions, have you made changes to your analysis based on feedback from NMIEC witness James Dauphinais?
A. Yes, I have made modifications to my cost and operating assumptions, due to his feedback and other new data.
First, Mr. Dauphinais testifies “NEE calculations did not account for declining capacity factor at San Juan 4 over the 20-year study period as carbon emission regulation is implemented….” (Dauphinais testimony in Support of the Stipulation page 32-33, Lines18-1) I reviewed the recent PNM Strategist® results and have determined that the capacity factor for San Juan is 72.8% (DVW OST-9) in their result. Thus, I am now using this 72.8% capacity factor in my analysis.
Second, Mr. Dauphinais expresses concern about “assumed refueling outage duration for the three Palo Verde nuclear generating units” (Dauphinais testimony in Support of the Stipulation, page 18, lines 15-16). I reviewed the actual Palo Verde capacity factors and refueling outage durations for the past 16 years (DVW OST-8) and determined that the actual PV3 capacity factor for the last seven years is 85.6% and the average refueling outage duration for that time period for all of PV was 52 days. Thus, I have revised my capacity factor to 85.6%.
Third, Mr. Dauphinais testifies that “NEE calculations were based on lower costs for solar and wind capacity than are being assumed by PNM in the Strategist® model. With respect to this factor, we did not make a determination of whether NEE’s or PNM’s solar and wind cost assumptions are more accurate” (Dauphinais testimony in Support of the Stipulation, page 33, lines 3-5). My levelized cost of solar is $0.068/kWh and this was provided by PNM (See Exhibit DVW-25 for a copy of the RFP results from14-0158-UT) as the low cost RFP result for their 40 MW facility that they are building in 2015. PNM’s Strategist® has the solar cost at $0.068/kWh in the beginning time period, but escalates the cost by 2+%/year to reach $0.105/kWh by 2033. I am in a quandary as to why PNM has ignored the RFP result in future time periods. Once a solar facility is built, there is not a reason to include inflation. This is the only resource in their replacement portfolio that has an actual RFP in-hand. So, I continue to maintain that the proper cost projection is the actual RFP result of $0.068/kWh for all time periods. For wind, my levelized cost is $0.037/kWh and this was provided by PNM (See Exhibit DVW-24 for a copy of the RFP results from14-0158-UT) as the low cost RFP result. PNM’s Strategist® has the wind cost at $1776/kW in 2014, but escalates the cost by 2.5%/year to reach ~2900/kW by 2033. As with solar, I am in a quandary as to why PNM has inserted baseless cost forecasts and ignored the RFP result in future time periods. So, I continue to maintain that the proper cost projection is the actual RFP result of $0.037/kWh for all time periods.
Q. Please provide a possible alternative replacement solution and analyze the costs for it and PNM’s proposed replacement plan.
An alternative that would likely be more cost effective and reduce risks is one that includes the following resources: Two 143 MW gas peakers, 260 MW of solar, and 400 MW of wind. Using levelized costs as developed in Exhibit DVW OST-3, PNM’s plan costs $249.8 million per year. The cost of this alternative is $178.5 million per year. See the following tables.
(This alternative does not comprehend the fact that SJGS operates at 85% capacity for peak, nor does it comprehend the increased spinning reserve requirement if San Juan unit 4 grows to 327 MW. If these factors were included the cost for the alternative would be about $12M/year less and require ~ 80 MW less gas peaking capacity.)
This straight forward analysis technique is a fundamentally sound approach based on revenue requirements for each resource and other key factors provided by PNM. This approach also provides easy to understand metrics, like cost/kWh and cost per year.
The alternative proposed above would be less exposed to many risks: carbon regulation, coal ash disposal costs, nuclear decommissioning risks, natural gas price fluctuation, coal fuel price increases, coal decommissioning, coal mine reclamation, and methane issues. Further, it facilitates attainment of the RPS in 2020 and reduces water usage and contributes positively to the economic development of New Mexico.
There are other alternatives that are lower cost than PNM’s proposed replacement plan. The alternative presented here is only one. My colleague Dr. Fisher presents other alternatives that are lower cost than PNM’s proposal.
Some of the common features to lower cost solutions are:
Flexible resources that facilitate meeting changing customer demands on an hourly, seasonal, or yearly basis.
Single-axis tracking solar technology that increases solar capacity value to as high as 76%, thus reducing needed gas peaking capacity by that amount (Exhibit DVW-15 & 16). Further, it has been shown that solar energy output is higher during peak demand hours (by about 5 points) than the average summer day at the same hour (Exhibit DVW OST-2, page 21).
New wind farms also have improved output characteristics that better match PNM system needs. (Exhibit DVW OST-2, pages 17-18) The new data shows that capacity factors are increasing from 30% to 46%. Even more importantly the data shows that the output is more stable in non-summer months and provides significant energy at the 8 pm sub-peak in the summer months.
For a more comprehensive review of PNM’s energy system please see Exhibit DVW OST-2. Also, see DVW OST-4 for an explanation of the energy system modeling that I did that demonstrates that this alternative works well in PNM’s system.
Q. NMIEC witness James Dauphinais has analyzed the NEE replacement portfolio versus PNM’s proposed replacement plan using Strategist® and has testified to the results in his 10/31 Direct Testimony in Support of the Stipulation. Please review his results and provide your analsyis.
A. Mr. Dauphinais provides Strategist® generated NPV for NEE’s alternative of $6945 million, using NEE wind and solar costs (Dauphinais testimony in Support of the Stipulation, JRD-2). The PNM Stipulation alternative generates an NPV of $6870 million. Thus, the difference is NPV = $75M. It is my understanding that Mr. Dauphinais used PNM provided fuel costs for SJGS. We have recently learned that the SJGS fuel costs used in Strategist® by PNM are significantly lower than those SJGS fuel costs provided by Mr. Monroy in testimony (DVW-13). The costs from Mr. Monroy are $47 million (average) per year higher with an NPV of $289 million than those costs in PNM’s Strategist®. The portion concerning 132 MW would be $77 million. Please see Dr. Fisher’s testimony for an in-depth review of the coal cost problem.
Also, New Energy Economy experts have demonstrated that the proper re-statement of costs between fixed and variable further reduces our alternative costs.