Mr. Anthony Viegbesie asserts that he is entitled to intervene in this matter on the following bases:

(1) he is a retail electric customer of Tallahassee, and his substantial interests will be directly affected by the Commission’s decision whether to permit the proposed plant because Tallahassee’s participation in such construction will impact the rates Tallahassee will charge to Viegbesie;

(2) the plant is unlikely to be modified to eliminate carbon dioxide emissions, thus recipients of energy from the plant will be assessed a “carbon tax” or other such fees if and when implemented, and such assessments will increase the rates and charges that Viegbesie will be forced to pay Tallahassee for his energy needs; and

(3) construction of the plant further will adversely affect the health of Viegbesie and his family as well as the environment in which they live.

Petitioner Natural Resources Defense Council, Inc., (“NRDC”) disputes whether JEA, the City of Tallahassee, FMPA, or RCID (collectively the “Owners”) have demonstrated the need for a new 765 MW pulverized coal and petroleum coke electric generating plant to be located in Taylor County, Florida. We specifically raise the following disputed issues:

Issue: Whether JEA, the City of Tallahassee, FMPA, or RCID, independently or collectively, have adequately demonstrated a need for additional generating capacity in the area(s) that will be served by the proposed plant.

a. Whether the Owners analysis was sufficient to conclude that there are no reasonably available conservation or DSM measures, which would mitigate the need for the proposed plant.

b. Whether the Owners, independently or collectively, have adequately evaluated conservation and DSM opportunities, including identification and evaluation of all possible options.

c. Whether the Owners, independently or collectively, have appropriately evaluated conservation and DSC opportunities, including consideration of actual costs to rate payers.

Position: Owners have not met their affirmative obligation to demonstrate a need for the proposed additional generating capacity in the area(s) that will be served by the TEC because they have not adequately or appropriately evaluated DSM opportunities.

Issue: Whether JEA, the City of Tallahassee, FMPA, or RCID, independently or collectively, have met their affirmative obligation to demonstrate that the proposed TEC is the most cost-effective and lowest risk alternative to provide needed capacity in each area that will be served by the proposed plant.

a. Whether the regulation of CO2 is sufficiently likely to warrant formal consideration in the needs determination for the TEC.

b. Whether the Owners’ assessment of the proposed plant as the most cost-effective alternative adequately and appropriately accounts for the cost of complying with future CO2 regulation, including whether the application adequately discusses and evaluates potential CO2 cost and identifies an appropriate range of likely CO2 costs.

c. Whether the failure to formally and adequately consider CO2 in connection with the needs determination for the TEC is a breach of the Owners’ obligations and of the obligation of the FPSC to protect the interests of Florida’s electricity consumers.

Position: The future regulation of CO2 is sufficiently certain that in order to protect consumers the FPSC should require formal consideration of CO2 costs in connection with any need determination for a coal-fired power plant; and because the Owners have not adequately or appropriately accounted for the cost of complying with future CO2 regulation, they have not adequately demonstrated that the proposed plant is the most cost-effective and lowest-risk alternative to provide needed capacity in each area that will be served by the proposed plant.

Issue: Whether Owners adequately and appropriately valued conservation and DSM in connection

with assessing the need for and appropriateness of a new 765 MW coal-fired electric generating plant, including whether Owners appropriately identified the relative benefits of conservation and DSM in light of all the costs and risks associated with construction of a pulverized coal plant (including costs related to complying with future CO2 regulations).

Position: Owners have undervalued the relative benefits of conservation and DSM.

Issue: Whether the Owners adequately and appropriately considered alternative new capacity options such as renewable energy sources, natural gas, and IGCC.

Position: Owners have not adequately or appropriately considered alternative new-capacity options, including for example IGCC, especially in light of likely CO2 costs associated with coal-fired power production.

Conclusion

The analysis that the Owners offer in support of the request for a determination of need does not fully evaluate important alternatives (such as conservation, DSM and IGCC), does not adequately assess the full range of costs that will affect this plant over its life, and does not analyze important risks associated with the operation of a new coal-fired power plant. Each of these elements is necessary to protect the interests of affected consumers as required by Florida law. The FPSC must closely scrutinize the TEC proposal, including cost projections, evaluation of alternatives, evaluation of risks (including consideration of carbon-related costs), and the conclusion that new capacity totaling 765 MW is needed, collectively and independently, in the areas to be served by the proposed source. The FPSC must require additional analysis where any of these evaluations are found lacking, and should decline to certify the need for the proposed facility if the application does not fully and affirmatively demonstrate that the proposed plant is needed and is the best available alternative. . . .

Petitioners The Sierra Club, John Hedrick, Barry and Brian Lupiani (“Petitioners”), by and through their undersigned counsel, hereby submit their proposed issues of fact and positions which the Florida Public Service Commission should resolve in determining the need for the Taylor Energy Center (TEC”), as proposed by applicants. . . .

Issue 1: Whether the request for proposals issued by each of the co-owners of the Taylor Energy Center included reasonable inputs and assumptions and projections as to the capital costs, operating and maintenance costs and fuel costs for the “self-build” option for the Taylor Energy Center?

Position 1: The co-owners have not included objective and reasonable inputs, assumptions and projections as to their capital, O&M or fuel costs in their requests for proposals or application for determination of need.

Issue 2: Whether the projections by the co-owners of the Taylor Energy Center in their respective request for proposals, and in the application for determination of need adequately adjusted for recent volatility in the capital costs for building pulverized coal plants, volatility in the market prices of coal to supply the TEC, and the volatility of transportation costs for coal delivered to the TEC.

Position 2: The co-owners have not adequately adjusted their projections to account for the degree of volatility the electric industry is presently experiencing in the capital costs to build coal plant, nor have they accounted for true volatility in the commodity prices of coal to supply the plant, or the transportations costs to deliver fuel to the plant.

Issue 3: Whether the co-owners have information, documentation or reasonable expectation of difficulties in the delivery logistics and infrastructure for delivery of coal to fuel the TEC?

Position 3: The co-owners have overwhelming information, documentation and should have more than reasonable expectations that there will be difficulties experienced in the logistics and infrastructure improvements to ensure adequate delivery of coal to the TEC site.

Issue 4: Whether the projections by the co-owners of the Taylor Energy Center in their respective request for proposals, and in the application for determination of need adequately addressed the cost impact of disruptions in coal delivery which result from existing dysfunction in the rail delivery operations in the US, or from delayed or inadequate upgrades and improvements to infrastructure, or from severe weather events?

Position 4: The co-owners have severely underestimated the cost impacts to O&M expenses that will result from dysfunctions experienced in the delivery of coal to the TEC site.

Issue 5: Whether the least-cost analyses conducted by each of the co-owners of TEC included reasonable inputs, assumptions and projections?

Position 5: The least-cost analysis conducted by the co-owners of TEC consisted of the request for proposals. To the extent that the inputs, assumptions and projections included in the RFP underestimated, and are not truly reflective of the costs the co-owners will incur if they build the TEC, the results were biased in the co-owners’ favor, and thus, the analysis is inadequate.

Issue 6: Whether the co-owners conducted modeling of alternative sources of supply, demand-side management, conservation, energy efficiency or demand-side management initiatives to determine if they provided lower cost alternatives, individually or as a portfolio, to serve the load to be served by the TEC, and to defer TEC?

Position 6: Information made available from the co-owners does not indicate that modeling of alternative sources of supply, demand-side management, conservation, energy efficiency or demand-side management initiatives was conducted to assess whether a portfolio would result in a lower cost to serve the load to be served by the TEC.

Issue 7: If the answer to issue 6 is “Yes”, whether reasonable and adequate inputs, variables and assumptions were used in these models?

Position 7: See Position 6.

Issue 8: If the answer to issue 6 is “no”, whether the request(s) for proposal conducted by the co-owners adequately evaluated alternative sources of supply, demand-side management, conservation, energy efficiency or demand-side management initiatives as lower cost alternatives?

Position 8: Because the co-owners determined that no resources were available, it does not appear that the RFP proposed or allowed vendors to consider these alternatives at all.

Issue 9: Whether the petition for determination of need adequately accounts for external costs of emissions compliance for the proposed pulverized coal plant?

Position 9: The co-owners have grossly understated the compliance obligations that the TEC will face, and thus severely underestimated the external costs that it will face.

Issue 10: Whether the petition for determination of need recognizes social and regulatory compliance costs imposed by SB 888?

Position 10: The information provided by co-owners does not indicate that SB 888 was given any consideration in their application.

Issue 11: Whether the least-cost analysis conducted by the co-owners attributes value to alternative sources of supply, to energy efficiency, to conservation and to DSM for avoidance of emissions and other compliance costs?

Position 11: The information provided by co-owners does not indicate that these initiatives were attributed value because they would allow the co-owners to avoid compliance costs.

Issue 12: Whether the least-cost analysis conducted by the co-owners attributes value to alternative sources of supply, to energy efficiency, to conservation and to DSM for avoidance of transmission, distribution and coal transportation costs for the TEC?

Position 12: The information provided by co-owners does not indicate that the least cost analysis or the RFP process attributed value to these initiatives because they would allow the co-owners to avoid transmission, distribution and coal transportation costs for the TEC.

Issue 13: Whether the co-owners have information, documentation or reasonable expectation of enhanced regulation of green-house gas (GHG) to impact the operating costs of TEC, before or at the time TEC becomes operational?

Position 13: The co-owners have overwhelming information, documentation and should have more than reasonable expectations that the TEC will face substantially greater regulation of GHGs well before the time TEC becomes operational.

Issue 14: Whether the co-owners have adequately estimated and quantified the impact of enhanced GHG regulation on the operating costs of TEC?

Position 14: The co-owners have dramatically understated the full economic, and direct cost impact of enhanced GHG regulation on the operating costs of TEC.

Q. Please state your name and business address.
A. My name is Dian Deevey and my address is 1702 SW 35th Place, Gainesville FL, 32608.

Q. Please briefly describe your educational background and work experience.
A. I received a bachelors’ degree magna cum laude from Stanford University, in Philosophy. My early professional career was devoted chiefly to the design of computer systems (hardware and software), and artificial intelligence. In 1964 as an employee of United Technologies I received NASA funding to survey and review experimental approaches to the detection of life on Mars. From then until 1985 I conducted basic research in the biogeochemistry of the atmosphere, supported by NASA, as an employee of United Technologies and subsequently as an independent consultant. It featured the design and interpretation of field experiments on the biogenic sulfur cycle and on the chemistry of sea salt particles. e atmosphere. My research has focused chiefly on the natural sulfur cycle and sea salt particles. I received funding from NASA, NSF, and EPA, and designed, conducted, and interpreted field experiments. I retired from active research in 1985.

Q. Do you have experience in electric utility resource planning?
A. Yes. I have conducted detailed studies of the needs of my local municipal utility Gainesville Regional Utilities (GRU) for new capacity and ways to satisfy those needs for over three years.

Q. Why did you initiate these investigations?
A. Biogeochemistry of the atmosphere is a highly interdisciplinary field that integrates many subjects that are critically relevant to contemporary climate science, and fundamental to studies of the causes and consequences of global warming. I have followed scientific developments in global warming for many years. In 2003 when they planned a new coal-based generator, GRU management were oblivious to global warming issues, and believed that emissions of carbon dioxide were unrelated to global warming. I am and was a member of the Alachua County Environmental Protection Advisory Committee (EPAC), and at my urging and other EPAC members, the County Commission formally requested EPAC to conduct a review of GRU’s plans and their environmental impact.

Q. How was the review conducted and what was its outcome?
A. I conducted the review, with the help of Dr. David Harlos, a Gainesville resident with extensive experience in the health effects of air pollution. Together we produced a long written assessment of GRU’s plans. This review was based on a careful study of GRU’s plans and the reports of its consultants, together with extensive study of the voluminous literature of energy economics, integrated resource planning, demand side management, regulatory policy, legislative initiatives for the reduction greenhouse gas emissions both here and in other countries, and other important subjects.

After about 18 months of intensive work, Dr., Harlos and I produced a written report of our findings1, and at my request, the Alachua County Commission allocated money to pay for a professional peer review of the document.

Q. What did the reviewers report about your study?
A. The reviewers praised its professionalism, its balance, and its objectivity. All agreed with the findings, with a single minor exception. I was very gratified by the review.

Q. What in your opinion were the most important conclusions of your study?
A. We concluded that large investments in coal-based generators are too risky for municipal utilities in the present energy environment, given the extreme regulatory and technological uncertainties. Regulatory uncertainties derive from global warming and the need to reduce carbon dioxide emissions very substantially in a short time, which will result in regulations that either impose financial sanctions on greenhouse gas emissions by utilities and/or offer subsidies that make other energy sources far more attractive to consumers. In both cases, the result could be financial problems for the utilities, their customers, and their municipal owners. There is a huge market for technological innovations in energy technologies that entail greatly reduced greenhouse gas emissions. Many established and new companies are working on radically new and possibly even revolutionary technologies to serve these growing markets. One promising possibility was announced in June by a Silicon Valley company called Nanosolar, which is one of working on novel solar PV technologies. They use a new nano-technology based solar PV system that is much easier and cheaper to produce than the conventional silicon-based system. Production is so cheap that it is expected to cut the cost of solar PV by a factor of four or five, making it cost-competitive with conventional electric energy over much of the world, and make distributed solar energy a reality in Florida and elsewhere.

Given these uncertainties, the prudent course for Gainesville and other municipalities is to make heavy demand side investments, and where possible adopt alternative energy sources.

Q. What is the purpose of your testimony today?
A. I have two major criticisms of the Applicant’s claim that a supercritical pulverized coal plant is the most cost-effective way to satisfy projected increases in the demand for electricity by the customers of the participants:

1. The participants have not evaluated generators that woody biomass, an alternative fuel with many environmental and cost advantages, or compared them to the other fossil fuel-based generators they have considered. Their consultants have wrongly assumed that woody biomass supplies are too limited in the locations of interest to support more than about 50 MW of capacity in any suitable location.

2. The participants base their estimates of the compliance costs of future greenhouse gas emission reduction regulations on (a) the 2005 version of the McCain-Lieberman Climate Stewardship Act, legislation which would be incapable of effective reductions in greenhouse gas emissions were it to be passed by the Congress, and (b) they also make a n umber of very questionable assumptions about how this act would be administered, the construction of nuclear power plants, reductions in the demand for electricity in other states than Florida, and the effectiveness of other sectors of the economy in reducing greenhouse emissions. The result is a set of estimates of allowance costs that is extremely low. . . . [details and documentation follow]

Q. Is there any other subject on which you wish to offer testimony?
A. Yes. I am concerned about the participant’s use of extremely low carbon dioxide emission allowance prices, and the very questionable assumptions their consultants Hill and Associates used to arrive at these prices.

The forecast of compliance costs per ton of CO2 emitted range from $4.22 of CO2 in 2012, to a maximum of $10.28 in 2016, after which they drop rapidly to $2.43 in 2018, and rise very slowly through the interval 2017 to 2030 to a maximum of $9.52. While these are not the lowest cost estimates I have found in the literature, their erratic progression over time from low to high and then down again is unusual. The strange behavior of these prices appears to be the consequence of some very questionable assumptions made by Hill and Associates, who produced the estimates for the Participants. Here are some problems I have noted:

Hill and Associates based their estimates on the McCain-Lieberman Climate Stewardship Act of 2005, which provides for reducing the emissions of all covered entities in the United States to the levels emitted by the US in 2000. (These entities account for an estimated 85% of US annual greenhouse gas emissions.) Compared to other legislative initiatives, this bill is extremely industry-friendly and in its present from will achieve very few reductions in total US emissions.

The bill as written provides that reductions begin in 2010, and Hill and Associates begin their analysis by determining the probable emission levels as of 2010 from Electricity Generating Units (“EGUs”) as equal to 110% of EPA’s estimate of emissions from this in the year 2000.) They then make the following assumptions:

1. Demand increases for some EGU’s will not exceed 1% per year. No list of these EGU’s is supplied, nor is the basis for selecting them fully described in the materials I have examined. This is what the relevant section of Volume A says about the method of selecting EGU’s assumed to exhibit reduced demand growth: “A reduction in electricity demand growth. In the regulated-CO2 fuel and corresponding emission allowance price sensitivity scenario, electricity demand growth was limited to 1.0 percent in any area of the country that had exceeded 1.0 percent in the base case fuel price forecast.”

I could find no estimate of the proportion of energy production accounted for by these EGUs, or their greenhouse gas emissions. The basic idea that some utilities will experience reduced demand growth, while the Participants and other Florida utilities experience very significant demand growth seems illogical and should be substantiated. At the very least, one needs detailed data to determine how this assumption affects the outcome of the allocation price analysis.

2. Electric utilities in states which do not currently have any renewable energy standards were projected to produce an average of 12% of their energy from carbon-free (“non-emitting”) sources within two years (2009), and to increase their percentage of carbon-free energy production by 0.5% per year thereafter until they have achieved a total of 20% renewable energy sources. It is not clear how this is to be achieved, or whether the Participants themselves plan to assume the burden of this conversion, as all are EGU’s in a state that presently has no renewable energy portfolio standards.

3. Hill and Associates assume that 12 nuclear plants will come on line between 2016 and 2020, and that these will be considered non-emitters. Some analysts have recently challenged the notion that nuclear power is carbon-free, on the grounds that building and fueling them entails very significant carbon dioxide emissions equal to about one third of the greenhouse gas released by natural gas-fueled combined cycle generators with an equivalent capacity release. (Other life cycle considerations suggest that nuclear generation is not the solution to greenhouse gas reduction needs that many have assumed it to be.)

4. Hill and Associates also assume that other US industries covered by S 1105 will achieve more than their proportionate share of greenhouse gas reductions, which reduce the cost of tradable emission credits, and will relieve the participant’s need to make genuine CO2 emission reductions, or even to purchase expensive allocations.

5. The final very questionable assumption is that political pressure on the credits, federal government will force it to give the EGU’s relief in the form of special offset credits in order to buffer electricity customers from higher electricity costs.

Given the reliance on a notoriously industry-friendly legislation, the large number of additional questionable assumptions made by Hill and Associates, and the lack of data on the impact of each of these curious assumptions, I find it impossible to have any confidence in the forecast of costs of compliance with future greenhouse gas emission reduction legislation.

Q. Do you favor other estimates of compliance costs?
A. Yes. I am familiar with the several publications by consultants at the firm Synapse Energy Economics, and regard them as among the best available. This firm is responsible for an evaluation of compliance costs for one of the Participants—Tallahassee Electricity Department—and I think their estimates should have been used by all the participants. At the very least, the Participants should have performed and compared the impact of compliance prices provided by Synapse with those provided by Hill and Associates.

There is one respect in which I differ from consultants at Synapse. I think that reviews of greenhouse gas-limiting legislative initiatives should consider the goals of the legislation—the specific tonnage of emission reductions—and determine through economic modeling whether those goals are met. Several studies of legislative proposals by the EIA have taken this approach, and found that without much higher economic sanctions than are found in many of the studies cited by Synapse, little or no actual reduction in emissions occurs. This is especially true of legislation that features low trigger prices for tradable emission rights that result in temporary lifting of the relevant caps until auction prices decline. These are typically favored by industry, but they do not achieve the stated goals of the legislation.

If legislation is to achieve the large greenhouse gas emission reductions that scientists tell us are urgently needed, the costs of allocations must be approximately the same as the costs of technology that achieves the reduction. At present, many analysts see carbon capture and sequestration as the best hope of avoiding disastrous climate effects while still provided reliable and economic electric energy to the world.

The cost of removing carbon dioxide from the flue gas of a coal or natural gas fired generator should be considered in every integrated resource plan that considers these technologies. Useful estimates of the comparative costs of carbon capture and sequestration for pulverized coal generators, IGCCs and NGCCs combined cycle units has been published by Rubin, Bau and Chen, of the Carnegie Mellon University, who present representative costs in the range of $26 to $47 dollars per ton of CO2 emissions avoided. These costs include capture and compression of the CO2, but not transport to a storage site.

In my opinion, use of the most industry friendly greenhouse gas legislation introduced into the Congress as a basis for estimating the future cost of compliance grossly misrepresents the potential costs both to utility customers and to the municipalities that own the utilities. A conscientious study should include the most recent legislative initiatives, specifically the Safe Climate Act introduced in the Senate last June (2006) by Senator Jeffords (S. 3698) and the companion bill introduced by Representative Waxman in the House (HR 5642).

Q. Does this conclude your testimony?
A. Yes.                    [Footnotes follow and can be viewed on the PSC website]

Q: Please state your name and address.
A: My name is Steve Urse. I live at 1118 Waverly Rd, Tallahassee, F 32312.

Q: Please summarize your education and experience.
A: I hold an A.B in Economics from Indiana University, an M.B.A. in finance, and a J.D. degree from the University of Florida. . .

Q: Have you been involved in planning issues involving electric utilities?
A: Yes, since May 2005 I and other members of the Big Bend Climate Action Team have been engaged in a successful collaborative effort with the staff of the electric utility of the City of Tallahassee concerning development of the integrated resource plan to guide acquisition of energy resources by our city’s electric utility.

Q: What is the Big Bend Climate Action Team?
A: The Big Bend Climate Action Team (BBCAT) is a group of citizens with extensive experience in a variety of fields, including energy, the environment, economics, and law. Due to concern about global warming, we united in a common mission:

“to help local governments, businesses, and citizens in Florida’s Big Bend do their share to abate climate change by reducing fossil fuel use and promoting energy efficiency, conservation, and renewable fuels in power plants, buildings, and vehicles.”

The impetus for BBCAT’s formation was a church group that spent more than five years working towards a national accreditation to become a Green Sanctuary, a multifaceted approach to becoming Earth friendly. In February 2005 the group started studying the impacts of global warming and potential solutions, organizing and participating in educational meetings with various experts about climate/ energy topics.

Q: Please describe the BBCAT’s collaborative work on the city’s IRP.
This collaborative effort commenced when BBCAT began meeting regularly with Tallahassee’s Electric Department staff in May of 2005 and is ongoing. I note that BBCAT first learned of the coal plant that is at issue in this case when Tallahassee’s possible participation was publicly announced in June 2005.

In July 2005, the Tallahassee City Commission voted to support preservation of Tallahassee’s participation in the Taylor County coal plant proposal as a possible option in the IRP. In addition, the city commission directed utility staff to “continue the collaborative work currently underway…” and to hire clean energy experts to help “develop an enhanced energy strategy emphasizing cost effective efficiency, alternative energy technology, and renewable resources…” Thereafter, the collaborative effort engaged in an earnest search for cost effective clean energy options, with input from the city’s utility staff and clean energy consultants and BBCAT – building from successful examples at other utilities. Through this work, 162 MW of additional cost effective Demand Side Management was identified and 38 to 75 MW of cost effective biomass was identified – an amount that exceeds Tallahassee’s 150 MW share in the proposed Taylor County pulverized coal plant at issue in this case.

At a city commission meeting in June 2006, staff advised the commission that the city’s experts had identified 167 MW of DSM whose acquisition would lower the total costs of each of the candidate IRP plans being considered. . . .

On August 23, 2006, the city commission voted to acquire the least cost Demand Side Management programs identified by the city’s experts, which I will refer to as the “least cost DSM”. According to the city’s calculations, acquiring the first 100 MW of this least cost DSM meets the city’s need for additional capacity until 2016. . . .

On October 11, 2006, the city commission voted to acquire 38 MW of biomass, with an option to increase to a total of 75 MW of biomass from a company called BG&E. The operation date is expected to be June 2010. According to the city’s calculations, this biomass also lowers the cost of each candidate IRP plan under consideration by the City of Tallahassee. . . .

The city has not provided a calculation to show how much longer this biomass energy acquisition will defer the city’s need for additional capacity when considered as an addition to the previously described DSM programs.

Before these 162 MW of least cost DSM and 38 to 75 MW of least cost biomass were identified, the analysis of the city’s staff and other city consultants indicated that the city needed additional capacity of 150 MW in 2012 and they stated their belief that few-to-no additional DSM or biomass options were available to cost-effectively meet any of that additional capacity need. . . .

Q: Please summarize your testimony:

A: Based on my participation in this collaborative IRP effort I have observed that:

1) Before hiring consultants with expertise in DSM and renewables, the city staff, based on reports from city consultants, had indicated that the city was already acquiring virtually all of the DSM and renewables that was cost effective.

2) With the help of clean energy consultants, the city identified and now plans to acquire 162 MW of additional DSM that will significantly reduce total costs of meeting energy service needs in the service area of the city utility.

3) Upon learning that the city was interested in adding biomass to its energy mix, biomass providers contacted the city and the city now plans to acquire between 38 and 75 MW of biomass, at a cost that is less than other energy supply or demand side options.

Based on these observations, it is my hope that the Florida Public Service Commission will ensure that the other participating utilities fully evaluate the potential for DSM and renewables to meet energy needs at a cost that is less than the proposed pulverized coal plant.

Q: Does that conclude your testimony?
A: Yes, it does.