Baltimore Gas and Electric Company
B-406057,B-406057.2,B-406057.3,B-406057.4, Feb 1, 2012
Baltimore Gas and Electric Company (BGE), of Baltimore, Maryland, protests the award of a contract to City Light and Power, Inc. (CLP), of Long Beach, California, by the Defense Logistics Agency (DLA) under request for proposals (RFP) No. SP0600-08-R-0804, for privatization of the electric distribution system at the Aberdeen Proving Ground in Edgewood, Maryland.
We deny the protest.
DOCUMENT FOR PUBLIC RELEASE
The decision issued on the date below was subject to a GAO Protective Order. This redacted version has been approved for public release.
Matter of: Baltimore Gas and Electric Company
File: B-406057; B-406057.2; B-406057.3; B-406057.4
Date: February 1, 2012
1. Agency reasonably calculated its government should cost estimate used in the economic analysis required by 10 U.S.C. § 2688 (2009) to determine whether the privatization of an electric utility system would reduce the long-term cost to the government of the utility system. Based on this economic analysis, the agency reasonably concluded that the awardees proposal provided the required long-term cost reduction, and determined that the protester was ineligible for award because its proposal did not reduce the long-term cost to the government.
2. Protest that the agency unreasonably determined the protesters technical capability was unacceptable and high in risk is denied, where the record shows the agency reasonably determined that the protesters plans to perform the work were unacceptable and that its performance risk and cost realism risks were high.
Baltimore Gas and Electric Company (BGE), of Baltimore, Maryland, protests the award of a contract to City Light and Power, Inc. (CLP), of Long Beach, California, by the Defense Logistics Agency (DLA) under request for proposals (RFP) No. SP0600-08-R-0804, for privatization of the electric distribution system at the Aberdeen Proving Ground in Edgewood, Maryland.
We deny the protest.
The RFP was issued pursuant to the Department of Defenses (DOD) program to consider privatization of utility systems at military installations. Authority for this program is provided by 10 U.S.C. § 2688 (2009), enacted in 1997, which provides that the Secretary of a military department may convey a utility system to a municipal, private, regional, district, or cooperative utility company or other entity. 10 U.S.C. § 2688(a). This statute further provides that [i]f more than one utility or entity . . . notifies the Secretary concerned of an interest in a conveyance . . . the Secretary shall carry out the conveyance through the use of competitive procedures. 10 U.S.C. § 2688(b)(1). The DOD utility privatization statute further provides that the agency may not make the conveyance unless it prepares an economic analysis and submits it to the congressional defense committees. 10 U.S.C. § 2688(a)(2)(A). This economic analysis must be
based upon accepted life-cycle costing procedures approved by the Secretary of Defense, that demonstrates that--
(i) the long-term economic benefit to the United States of the conveyance of the utility system, or part thereof, exceeds the long-term economic cost to the United States of the conveyance;
(ii) the conveyance of the utility system, or part thereof, will reduce the long-term cost to the United States of utility services provided by the utility system by 10 percent of the long-term cost for provision of those utility services in the agency tender.
10 U.S.C. § 2688(a)(2)(A)(i), (ii).
The RFP, as amended, sought offerors to assume ownership of and responsibility for Aberdeens electric utility system and infrastructure, and to operate and maintain the system, and provide utility distribution services to the government. RFP at 2. As part of the privatization, the RFP also required offerors to provide a plan to complete a series of initial system deficiency corrections and initial renewals and replacements (ISDC) projects to bring the existing utility system up to industry standards. RFP at 30. The period of performance for the contract was 50 years. RFP at 2. In accordance with 10 U.S.C. § 2688, both regulated and non-regulated offerors could submit proposals.
It was contemplated that the contract would include a transition period. Offerors were to propose a specific period of time necessary to transition the utility system from government to private ownership and operation. RFP at 33. The transition period was to begin on the day the contract was awarded and continue until the day the contractor assumed ownership and operation of the utility system. RFP at 36. The transition period was to provide a contractor time to perform additional due diligence functions and stand up operations in support of the contract. RFP at 33.
Award under the RFP was to be made to the responsible offeror whose proposal satisfied the economic analysis requirements of 10 U.S.C. § 2688 and represented the best value to the government. To determine whether the economic analysis criteria of 10 U.S.C. § 2688 were met, the RFP provided for a comparison of offered prices at net present values with the governments should cost estimate (GSCE). RFP at 75. The agencys best value analysis would be based upon five evaluation factors:
(1) technical capability, (2) past performance; (3) risk, (4) socioeconomic plan, and (5) price. RFP at 73, 74. Technical capability, past performance, and risk were of approximately equal importance, while the socioeconomic plan was somewhat less important; when combined the four non-price factors were significantly more important than price. RFP at 75.
The RFP contemplated the award of a regulated tariff, fixed-price, fixed-price with economic price adjustment, or a fixed-price with prospective price redetermination contract. RFP at 2. Detailed price proposal instructions were included in the RFP. Price was to be evaluated to determine compliance with the requirements of 10 U.S.C. § 2688 by calculating an offerors present value price and comparing it to the GSCE. RFP at 75. In addition, an offerors total evaluated price would be a consideration in the source selection decision. RFP at 74-75.
The agency received proposals from BGE and CLP by the April 2, 2009 due date, and after evaluation, engaged in four rounds of discussions. BGE submitted an alternate regulated tariff offer that included exceptions to the terms and conditions of the RFP. CLP submitted a fixed-price with prospective price redetermination offer. After the close of negotiations, both offerors submitted final proposal revisions (FPR) by July 28, 2011.
The proposals were evaluated as follows:
Service Interruption/Contingency & Catastrophic Loss Plan
Operation & Maintenance & Quality Management Plans
Operational Transition Plan
Assurance of Long-Term Price & Service Stability
Other Possible Long-Term Costs & Benefits
Net Present Value Price
Percentage below or above the GSCE
AR, Tab 27, Source Selection Decision, at 13.
The agency concluded that BGE was ineligible for award under the requirements of 10 U.S.C. § 2688, because its net present value price was 10.3-percent higher than the GSCE, and thus failed to meet the requirement that the governments long-term costs to retain ownership and operation of the electrical distribution system be reduced by at least 10 percent. Id. at 14. The SSD also concluded that BGEs proposal would not be considered for award because it received an unacceptable rating under the technical capability factor due to its unacceptable ISDC plan and operational transition plan, its high overall risk rating, and its approach of taking exception to many of the terms and conditions of the solicitation. Id.
The agency concluded that CLP was eligible for award because its price was more than 10 percent below the GSCE. Id. The SSD also found CLPs offer to be acceptable for overall technical capability and risk, with excellent past performance, and a good socioeconomic plan. Id. The contracting officer, with assistance of the Defense Contract Audit Agency (DCAA) and Defense Contract Management Agency (DCMA), also concluded that CLP was a responsible offeror. AR, Tab 26, Contracting Officers Responsibility Determination, at 1.
On September 30, the agency awarded the contract to CLP. After receiving a debriefing, BGE filed this protest with our Office on October 24.
BGE protests the evaluation of its proposal, including each of the reasons provided by the agency for rejecting its proposal. BGE also protests the evaluation of CLPs proposal, and asserts that CLPs proposal was unacceptable and ineligible for award.
In considering protests challenging an agencys evaluation of proposals, we will not reevaluate proposals; rather, we will examine the record to determine whether the agencys evaluation conclusions were reasonable and consistent with the terms of the solicitation and applicable procurement laws and regulations. James Constr., B-402429, Apr. 21, 2010, 2010 CPD ¶ 98 at 3. A protesters mere disagreement with a procuring agencys judgment is insufficient to establish that the agency acted unreasonably. Id.
Comparison of BGEs Price to GSCE Under 10 U.S.C. § 2688(a)(2)(A)(ii)
BGE contends that the rejection of its proposal based on the comparison of its price to the GSCE was improper because the GSCE was significantly understated. The only specific contention in this regard is that the GSCE did not include work related to deficiencies on the customer side of the meter, which BGE included in its proposal. Had this work been included in the GSCE, BGE asserts that its price would have met the requirements of 10 U.S.C. § 2688 and be eligible for award.
We review challenges to government estimates for reasonableness. A protesters mere disagreement with an agencys basis for developing a government estimate provides no basis to sustain a protest. NCI Information Sys., Inc., B-405589, Nov. 23, 2011, 2011 CPD ¶ 269 at 4.
The record shows that the agency performed an exhaustive analysis in preparing the GSCE. The GSCE was prepared in advance of receipt of proposals by financial and utility industry experts using widely accepted practices and publications for cost estimates, with input from installation personnel with extensive knowledge of the utility system, and included all efforts to bring the system up to industry standards and maintain it for the next 50 years. Contracting Officers Statement at 7; Agency Report at 14. An on-site assessment of the installations electrical distribution systems was conducted, and included input from the Department of Public Works utility staff. AR, Tab 51, Certified Economic Analysis, at 35. Field surveys were also performed to determine the age and condition of utilities, and inventory reports were prepared based upon this information. Id. As a result of this research, the agency determined the work necessary to bring the utility system up to industry standards, which formed the basis of the GSCE. Supp. AR at 16. The agencys estimate did not include work on the customer side of the meter. Id.
Section J3 of the RFP listed the work to be accomplished by the contractor as part of the privatization and designated the points of demarcation, which defined the limits of the utility system being purchased, operated, and maintained by the contractor; work on the customer side of the meter was not included in this section. See RFP § J3, Table 1-Points of Demarcation, at 11-12; Table 7-Recognized System Deficiencies, at 42. Therefore, we see nothing unreasonable about the agencys decision not to include this work in the GSCE.
Despite the fact that work on the customer side of existing meters was not included in Section J3 of the RFP, BGE nevertheless asserts that this work was required. BGE argues the work was required because the solicitation mandated compliance with the National Electric Code, industry standards, and applicable regulations concerning health and safety, and was necessary for the contractor to accept ownership of, and to operate and maintain, the utility system.
The record shows that BGEs proposal was submitted as an alternate proposal with different elements and enhancements than were called for by the RFP. For example, BGEs unique metering proposal required each point of service at Aberdeen to be individually metered, which exceeded the requirements of the RFP. AR, Tab 11, BGE FPR, vol. I, Executive Summary, at 5. BGEs offer for the inclusion of the work on the customer side of the meter provided, [t]his is work that is required to bring the building wiring to BGE standards for the installation of BGEs meter. AR, Tab 14, BGE FPR, Price Proposal, at 12. BGEs alternate proposal also took exception to the points of demarcation of the utility system set forth in the RFP. AR, Tab 11, BGE FPR, vol. I, Executive Summary, at 5; AR, Tab 13, BGE FPR, vol. III, Contract Documentation, at 35-36. Based on the foregoing and on our review of the record, we conclude that BGEs proposed work on the customer side of the meter was not a requirement of the RFP, and was reasonably not included in the GSCE. Instead, this additional work was related to BGEs alternate approach that took exception to the metering and point of demarcation requirements of the solicitation.
BGE also alleges that the agency specifically advised it to include the costs of work on the customer side of the meter in its proposal, which in BGEs view, means the agency should have included those costs in its GSCE. BGE references here an email exchange that occurred between the agency and BGE during discussions regarding the cost of the work on the customer side of the meter:
BGE should include all costs that are associated with the ISDC to install new underground systems . . . including any modifications necessary as a result of the establishment of a new [point of demarcation], as part of that projects costs. . . . BGE is reminded that the GSCE includes all costs to install underground electric distribution infrastructure up to the current Section J [point of demarcation].
AR, Tab 10, Agency Email to BGE (July 20, 2011), at 1.
In our view, this email does not support BGEs contentions. Instead, the email points out that BGEs alternate proposal established a new point of demarcation, and reminded BGE that the GSCE includes only the cost to install infrastructure up to the current point of demarcation. It imposed no requirement that BGE include the costs of work on the customer side of the meter in its proposal, nor did it suggest that these costs would be included in the GSCE.
Because BGE has not shown that the GSCE was defective, there is no basis to challenge the agencys determination that BGE was ineligible for award because its proposal failed to meet the statutory requirement that the governments long-term costs for the agency to retain ownership and operation of the electrical distribution system be reduced by 10 percent. On this basis alone, the agency could not award this contract to BGE. We have also reviewed BGEs other arguments and conclude that they provide no basis to overturn the agencys evaluation conclusions about BGEs proposal. A few of these arguments, and our conclusions, are set forth below.
Evaluation of BGEs ISDC Plan
BGE also contests the unacceptable rating of its proposal under the ISDC plan subfactor, which contributed to its proposals unacceptable rating under the technical capability factor.
The RFP required offerors to provide a plan to complete a series of ISDC projects to bring the existing utility system up to industry standards, and required that these projects must be completed within 5 years of the contract award date. RFP at 30. The solicitation supplied a listing of eight government-recognized ISDC projects, as well as the governments approach to remedying each deficiency. RFP § J3.10. The solicitation also permitted offerors to submit their own ISDC projects, with rationale to support each proposed project. RFP at 30. The solicitation advised offerors that the ISDC project plans should describe in detail the purpose, scope, and cost of the ISDC projects, and include a detailed description of all proposed ISDCs with a schedule for each project. RFP at 63-64. The RFP provided that an offerors ISDC plan would be evaluated under the ISDC plan subfactor of the technical capability factor for the degree to which it supports the long-term ability of the utility system to provide utility service. RFP at 73-74. The ISDC plan would also be assessed under the performance subfactor of the risk factor for the degree to which award of a contract would present a risk of degradation of the quality of utility service. Id. The RFP required a fixed price for each ISDC project from both regulated and non-regulated offerors. RFP at 10, 12.
The agency found BGEs ISDC plan unacceptable because its timeline was unclear for some ISDC projects, and BGEs approximate completion date of all ISDC projects was 8 years, which failed to meet the RFP requirement that the contractor complete all system upgrades within 5 years of the contract award date. AR, Tab 27, SSD, at 4; Tab 34, Final Technical Consensus Report, at 33.
BGE argues that its proposals unacceptable rating under this subfactor was unreasonable because the agency incorrectly assumed that it would take BGE 8 years to complete the ISDC projects. BGE contends that its proposal actually offered to complete the ISDC projects within 4 years from contract start date (after completion of the transition period), which was 5 years from contract award date. BGE also asserts that the RFP did not mandate a time period for ISDC project completion, but only provided an estimate of when each project should be completed.
We first note that BGE is wrong in asserting that the 5-year from contract award date timeline for completion of these projects was permissive. The RFP clearly stated that all ISDC projects proposed to remedy government identified deficiencies shall be completed within 5 years of the contract award date. RFP at 30.
We also find that the agency reasonably determined that BGEs ISDC plan did not comply with this requirement. In this regard, we first note that BGEs initial proposal clearly offered an estimated ISDC plan to complete the entire project in an 8-year time frame from the contract start date after completion of the transition period. AR, Tab 52, BGE Initial Proposal, vol. I, Technical Capability, at 51. During discussions, the agency requested that BGE revise its schedule to comply with the required 5-year (5 years from contract award date/4 years from contract start date) completion date of the RFP. AR, Tab 4, Negotiation Messages, at 188. BGE responded during discussions that it was willing to accept a completion date for ISDC projects of 4 years from the contract start date, but this was contingent upon various conditions, such as the agencys approval of the first set of contract approved drawings and execution of any required easements. Id.
Despite BGEs representations during discussions, its FPR expressly provided that all ISDC projects would be completed 6 years after contract award. AR, Tab 11, BGE FPR, vol. I, Technical Capability, at 134-145. For example, BGEs FPR included a chart, on which it displayed BGEs timeline for completion of its proposed ISDC projects, which showed a contract award date in 2011, with the end of ISDC resolution occurring during the later half of 2017--6 years after contract award--and even this schedule was made contingent on a number of conditions. Id. at 135. Accordingly, the agency reasonably found BGEs proposal to be unacceptable under the ISDC plan subfactor because BGE did not meet the requirement that the ISDC projects be completed within 5 years of the contract award date.
Evaluation of BGEs Operational Transition Plan
BGE also contests the unacceptable rating of its proposal under the operational transition plan subfactor, which also contributed to its proposals unacceptable rating under the technical capability factor.
Offerors were required to submit an operational transition plan for execution during the transition period. RFP at 33. The transition period was to provide a contractor time to perform additional due diligence functions and stand up operations in support of the contract. Id. Offerors were to propose a specific period of time necessary to transition the utility system from government ownership and operation to private ownership and operation. Id. The RFP provided that an offerors operational transition plan would be evaluated under the technical capability factor for the degree to which it will ensure an effective and efficient transition. RFP at 73-74. The operational transition plan would also be assessed under the performance subfactor of the risk factor for the degree to which award of a contract would present a risk of degradation of the quality of utility service. Id.
The agency found BGEs operational transition plan was unacceptable because it failed to provide a clear timeline and detailed descriptions of all activities. The agency also concluded that BGEs timeline for its phased transition approach for portions of the newly built underground system was unrealistic. AR, Tab 27, SSD, at 5.
BGE asserts that the agency improperly determined that BGE did not clearly specify the actual activities to be conducted during the transition nor the allotted time required for each activity. However, the technical consensus report for BGEs technical capability under this subfactor found, and our review confirms, that BGEs proposal did not specify all of the activities to be conducted during the transition period, nor did BGE allot the time required for each activity. AR, Tab 34, Final Technical Consensus Report, at 37-38. The report also concluded that BGEs transition plan was not clearly defined and activities presented did not contain enough language to determine if a logical/acceptable flow of events exists. Id. The agency also found:
Since BGEs alternate proposal does not take ownership of the cantonment area, the Government will continue to own and operate the electric system while BGE constructs the new underground system as part of the [ISDC] project. BGEs proposed transition period anticipates 2 years of construction to implement this work. [Aberdeen] estimates that it will take at least one (1) additional year to get all required permits. Therefore, [Aberdeen] will continue to have [operations and maintenance] responsibility for existing electric system components that does not convey to BGE for a minimum of three (3) years after contract award. . . . A three year transition period is unacceptable to the Government.
Id. at 38. Based on our review, we find the agencys concerns were reasonable, and that they reasonably support BGEs unacceptable rating under this subfactor.
Evaluation of BGEs Risk
BGE also challenges the agencys evaluation of its overall high risk rating, which was based on BGEs high risk ratings under the performance and cost realism subfactors.
As indicated above, the solicitation sought offerors to assume ownership of the utility system and infrastructure, and as the new owner, operate and maintain the systems and provide utility services to the government. RFP at 2. It was the goal of the agency to transfer all right, title, and interest of the United States in and to the utility systems, with the government retaining no reversionary interest in the utility system sold. Id.
As mentioned previously, BGE submitted an alternate proposal in which it did not offer to take complete ownership of the utility system, but only parts of the system. For example, BGEs proposal refused to take ownership or operate two Aberdeen substations because it planned to instead build different substations. AR, Tab 11, BGE FPR, vol. I, Technical Capability, at 3, 104, 151. Moreover, BGE proposed that during the construction of a new underground distribution system, [Aberdeen] will continue to operate and maintain the existing overhead distribution system that BGE does not own. Id. at 151.
The agency assigned a high performance risk rating to BGEs proposal. The agency found that BGEs plan for assuming ownership of only parts of the system while rebuilding other portions placed a continued burden on the government for operations and maintenance. The agency also concluded that BGE lacked a detailed plan for the transition to complete BGEs ownership and that its unrealistic timeline associated with the plan carried a high risk of schedule delays and service degradation. Furthermore, the agency found that BGEs 8-year plan for completion of system upgrades represented a high performance risk to the government because [Aberdeens] system is already near failure and any further delays in completion of system upgrades beyond the 5 years allowed by the RFP presents a high risk to the government. AR, Tab 27, SSD, at 8. Based on our review, we see nothing unreasonable about the high performance risk rating.
Cost Realism Risk
The RFP provided that cost realism risk would be evaluated as follows:
A cost realism analysis will be performed in accordance with FAR [§] 15.404-1(d)(3). Realism will be based on an evaluation of the information provided in support of the offered price to determine if the prices reflect a clear understanding of the requirements; are consistent with the various elements of the offers technical proposal; are not unbalanced; and are neither excessive nor insufficient for the effort to be accomplished.
RFP at 74.
For this risk subfactor, the agency determined that some of BGEs costs were not consistent with its technical approach, and that certain of its transition period activities and ISDC costs did not clearly correspond to the same tasks in the technical volume. AR, Tab 27, SSD, at 9. In addition, the agency found that BGE did not provide supporting documentation to show how its prices were calculated, so that the agency was limited in its ability to determine how consistent the costs were with BGEs technical approach. Id.
Another cost risk noted by the agency was BGEs price for its proposed ISDC projects. BGEs proposal stated that its ISDC project prices were based upon on estimates only, and that its actual project costs will be based on detailed design specifications developed during the engineering study/design phase. AR, Tab 14, BGE FPR, vol. IV, Price Proposal, at 4, 14. The agency concluded that these preliminary assumptions created risk given that the RFP required fixed prices for these projects. RFP at 10; AR at 25; AR, Tab 19, Final Cost Realism Report, at 5.
The agency was also concerned with the risk related to BGEs proposal to perform certain projects at 50 percent of its actual costs with no return of these costs to BGE built in, except for that achieved through the payment of utility rates by its entire customer base. AR at 25; see Protest at 44. As indicated by BGE, this approach was subject to approval by Marylands Public Service Commission. If the Maryland Public Service Commission failed to accept BGEs approach, BGEs proposal noted that the government would be liable for 100 percent of the costs. AR at 25; AR, Tab 14, BGE FPR, vol. IV, Price Proposal, at 12.
Based on the foregoing, the agency determined that the cost realism of BGEs proposal constituted a high risk to the government. We find that this determination was reasonable.
BGEs Exceptions to RFP Requirements.
Finally, the agency determined that BGEs alternate approach was unacceptable because BGEs FPR took numerous exceptions to the RFP requirements and the agency found that these exceptions were unacceptable to the government. BGE claims that the agencys determination here was improper because the RFP allowed for alternate proposals and exceptions to the RFP requirements.
It is true that the RFP permitted the submission of alternate proposals and exceptions to terms and conditions, which add value when compared with the requirements of the RFP. RFP at 67. Offerors submitting alternate proposals were required to provide a rationale explaining the advantages of the alternate proposal. Offerors were also required to provide a rationale in support of each exception, explaining its effect in comparison with the original requirements of the RFP. RFP at 68.
Thus, while alternate offers that took exceptions to the RFP requirements were permitted, nothing in the RFP prevented the agency from evaluating the exceptions offered and rejecting them as unacceptable. In fact, agencies have a duty to evaluate alternate offers and exceptions to determine whether such exceptions would be advantageous to the government. See Dell Fed. Sys., L.P., B-404996, B-404996.2, July 22, 2011, 2011 CPD ¶ 151 at 3-5; Northern Light Prods., B-401182, June 1, 2009, 2009 CPD ¶ 117 at 3-4.
Here, BGEs FPR included numerous exceptions to the RFP requirements. For example, BGEs FPR stated, BGE takes exception to any and all portions of the RFP, as amended, and any attachments or accompanying documents and materials thereto that differ from or are in conflict with the alternate proposal submitted by BGE in response to the RFP. AR, Tab 13, BGE FPR, vol. III, Contract Documentation, at 2. BGEs FPR also included over 50 pages of exceptions to the RFP terms and conditions together with the rationale for each exception. Id. at 6-57. While BGE asserts that most of the exceptions were a result of its regulated status and tariff, it is clear that not all were. For example, as indicated above, BGEs FPR took exception to the requirement to submit fixed prices for each ISDC project, see RFP at 10; AR, Tab 14, BGE FPR, vol. IV, Price Proposal, at 4, 14, even though the protester admitted that this was not part of its tariff. Protest at 22 n.4 (work required to make the existing portions of the system that BGE would take ownership of ready for operation was simply not a part of its tariff.)
We find the agency acted reasonably within its discretion in determining that these exceptions rendered BGEs proposal unacceptable.
BGE also challenges the evaluation of CLPs proposal and asserts that CLP was ineligible for award, that CLPs proposal was unacceptable, and that the agencys determination that CLP was responsible was unreasonable. BGE specifically claims that the agency miscalculated CLPs life-cycle costs with regard to the economic analysis required under 10 U.S.C. § 2688, and improperly failed to assess CLPs responsibility and financial capability. Had the agency appropriately conducted these evaluations, BGE asserts that CLP would have been found ineligible for award.
Comparison of CLPs Price to GSCE Under 10 U.S.C. § 2688(a)(2)(A)(ii)
BGEs proposal informed the agency that if Aberdeen elects to privatize with any party other than BGE, the current utility service and billing provisions contract rates, listed as 115 kilo-volt (kV) rates for 34kV service at the Aberdeen and Edgewater substations would be eliminated. AR, Tab 14, BGE FPR, vol. IV, Price Proposal, at 13. Instead, BGE would meter and charge for the electric commodity service supplying the privatized on-post electric distribution system at 34kV rates. Id. BGE estimated its charges at the 34kV rate to be $3,058,088 annually, or $1,626,761 higher than the current 115kV rates. Id. at 13-14. BGE concluded by instructing the agency that a proper comparison of BGEs proposal with any other party should not be based upon the 115kV rate, but rather its estimated 34kV rate. Id.
BGE asserts that the rate increase resulting from accepting a proposal other than BGEs should have been taken into account in evaluating CLPs proposal. BGE states that the net present value of this rate difference is approximately $71 million. Protest at 49 n.20. BGE states that if this cost to the government were included in the economic analysis required by 10 U.S.C. § 2688(a)(2)(A)(ii), CLPs proposal could not be found to reduce the long-term cost to the United States of utility services provided by the utility system by 10 percent of the long-term cost for provision of those utility services, as required. Supp. Comments (Dec. 30, 2011) at 7-8.
DLA considered BGEs contentions concerning the impact of these electrical rate increases, and has provided an explanation questioning the applicability and enforceability of the 1950 agreement, and claims that these additional commodity costs could be mitigated even if the 1950 agreement were applicable. AR at 29; AR, Tab 27, SSD, at 10. While BGE disputes in some detail DLAs conclusions that these costs may not be incurred, we cannot find, on this record, that the DLAs determination--which may involve a future dispute between the government and BGE--to be unreasonable.
In any case, even assuming that the government may incur the additional costs claimed by BGE, it is not clear that the costs incurred for an electric commodity rate change under a separate contract with BGE were required to be considered under the economic analysis required by 10 U.S.C. § 2688(a)(2)(A)(ii). In this regard, this section of the statute requires the economic analysis to consider whether the conveyance of the utility system . . . will reduce the long-term cost to the United States of utility services provided by the utility system. Id. (Emphasis supplied.) A utility system is defined by DOD as
any system for the generation and supply of electric power . . . For the purposes of this definition, supply shall include distribution. A utility system includes equipment, fixtures, structures, and other improvements utilized in connection with systems . . . as well as the real property, easements or rights-of-way associated with those systems.
AR, Tab 24, DOD 2002 Guidance, app. A, at 2. A utility service is defined as all services associated with the conveyed utility system other than the utility commodity. Id. Accordingly, it would seem that the economic analysis required for the privatization of utility systems requires the consideration of the costs and benefits related to the utility system and services that are being considered for privatization, and that these costs do not include costs related to the electric commodity.
Furthermore, we find nothing in the RFP that would require such an analysis. With regard to the 10 U.S.C. § 2688 economic analysis, the solicitations price evaluation section stated that net present value prices would be compared to the GSCE as follows:
the Government will use the [contract line item (CLIN)] data in Schedule B-1, B-2, B-3 or B-4 to develop a projected 50-year cash flow. Present values will be calculated at the discount rate specified in Appendix C of the Office of Management and Budget (OMB) Circular A-94 that is current at the time proposals requested herein are due.
The economic analyses conducted will be done in accordance with OMB Circular A-94, Department of Defense Instruction 7041.3, and [the DOD 2002 Guidance].
RFP at 75. The RFP does not require the consideration of any long-term costs or benefits to the United States relating to electrical commodity rate changes in the analysis of an offerors life-cycle costs or the GSCE.
In sum, BGE has provided no basis to question the agencys determination that the acceptance of CLPs proposal satisfies the economic analysis requirements of 10 U.S.C. § 2688.
BGEs also challenges the agencys affirmative responsibility determination of CLP. BGE claims that the contracting officer failed to consider relevant information and unreasonably ignored negative findings pertaining CLPs financial resources.
Because the determination that an offeror is capable of performing a contract is largely committed to the contracting officers discretion, our Office will generally not consider a protest challenging an affirmative determination of responsibility except under limited, specified exceptions. Bid Protest Regulations, 4 C.F.R. § 21.5(c); Verestar Govt Servs. Group, B-291854, B-291854.2, Apr. 3, 2003, 2003 CPD ¶ 68 at 3. One specific exception is where a protest identifies evidence raising serious concerns that a contracting officer, in making an affirmative determination of responsibility, unreasonably failed to consider available relevant information. 4 C.F.R. § 21.5(c). As explained in the preamble to our revised regulations, the revision to our regulations was intended to encompass protests, where, for example, the protest includes specific evidence that the contracting officer may have ignored information that, by its nature, would be expected to have a strong bearing on whether the awardee should be found responsible. 67 Fed. Reg. 79,833-34 (2002).
Here, the protester has not provided evidence that shows that the agency failed to consider all relevant information, including that referenced by the protester, in reaching its responsibility determination. AR, Tab 26, Affirmative Responsibility Determination Memorandum, at 1; Agency Report at 27. Specifically, the contracting officer considered (including negative comments) that DCMAs pre-award survey included satisfactory findings for all areas and that DCAAs pre-award accounting system survey determined that CLPs accounting system was acceptable. Moreover, the contracting officer reviewed the financial data provided by CLP as well as publicly available information including a Dun & Bradstreet report, and found that CLPs financial resources were adequate. AR at 27. The contracting officer also took into consideration CLPs current federal government contracts (including one for privatization of utilities at another facility) in the responsibility determination. Based on the foregoing, we find that BGEs allegations provide no basis to question the contracting officers determination that CLP was responsible.
The protest is denied.
Lynn H. Gibson
 Section 2688(a)(2)(A)(ii) was amended by the National Defense Authorization Act of 2010, Pub. L. No. 111-84, div. B, tit. XXVIII, § 2821, 123 Stat. 2664 (Oct. 28, 2009), to add the specific 10-percent cost reduction requirement included at the end of this section. (Previously, this section only required a general finding of a reduction in the long-term cost to the United States of utility services provided by the utility system.)
While not applicable to our decision here, we also note that the National Defense Authorization Act of 2012, Pub. L. No. 112-81, div. A, tit. X, subtit. G, § 1061(21), 125 Stat. 1298 (Dec. 31, 2011), has, among other things, removed all requirements for the economic analysis required by section 2688(a)(2) and all requirements for reporting the conveyance of utility systems to the congressional defense committees.
 On June 19, 2008, DLA issued the current solicitation for the privatization of Aberdeens water distribution system and wastewater collection system. Amendment 2, issued on December 16, 2008, added the privatization of the electrical distribution system to the solicitation requirements. On June 16, 2011, amendment 7 removed the water distribution and wastewater collection systems, leaving the electrical distribution system as the only remaining requirement.
 Under DOD guidelines, privatization of utility systems generally consists of two transactions: (1) the conveyance of the utility infrastructure from the government to a private entity under a bill of sale, and (2) the acquisition of utility services on the privatized system under a utility services contract. Agency Report (AR), Tab 24, DOD 2002 Guidance for Privatizing Defense Utility Systems (DOD 2002 Guidance), at 3.
 The GSCE is based on an industry standard level of service and government specifications required to bring the system up to industry standards within 5 years and maintain that level for the remainder of the service contract. AR, Tab 86, Briefing to the SSA, at 27.
 The technical capability factor had five equally weighted subfactors: (1) service interruption/contingency and catastrophic loss plan, (2) operations and maintenance plan/quality management plan, (3) ISDC plan, (4) operational transition plan, and (5) financial strength. RFP at 73.
 The risk factor had four equally weighted subfactors: (1) performance, (2) assurance of long-term price and service stability, (3) cost realism, and (4) other possible long-term costs and benefits. RFP at 74.
 Past performance and socioeconomic ratings were removed from this table as they are not relevant to our decision.
 The work on the customer side of the meter proposed by BGE included such tasks as rewiring the inside of the governments buildings.
 The RFP required the contractor to own, operate, and maintain the existing meters at locations throughout the installation between the electric supply point and the end-user point of demarcation. The RFP provided that the agency would pay for the installation of new meters under the Armys Metering Program. RFP § J.3.4, Secondary Metering. The RFP also stated that the contractor shall leave all existing meters in place and maintain them. RFP at J.3.4.1, Existing Meters.
 BGE also makes much of the fact that the record shows that the contracting officer and contracting specialist had an internal email discussion regarding whether or not the work on the customer side of the meter should be included in the GSCE, leading BGE to argue that the agency agreed that work on the customer side of the meter should be included. See AR, Tab 82, at 82-3183. While there is no dispute that the contracting personnel discussed this issue, these internal deliberations did not result in an amendment to the solicitation or the GSCE, and they are of no consequence with regard to the final conclusions of the agency.
 We also note that even BGEs initial protest to our Office indicates that its FPR proposed to complete the ISDC projects 6 years after the contract award date. Protest at 40 (complete ISDC projects within 4 years from contract start date after a 2-year transition period from the contract award date).
 BGE also asserts that the agencys evaluation of its ISDC plan unreasonably found that BGEs estimated completion date of the ISDC projects was 8 years. However, the record shows that the agency reasonably found that BGEs schedule omitted key activities that the agency determined would have delayed BGEs schedule for up to 2 more years. AR, Tab 34, Final Technical Consensus Report, at 33. For example, while BGE acknowledged that it would need approval from the Maryland Public Service Commission, the agency found that time for this effort was not included in BGEs schedule for the ISDC projects. AR at 22.
 BGEs exception to the requirement that it take ownership of the utility system (discussed above) was also not required by its tariff or regulated status.
 Because BGEs proposal was reasonably found unacceptable, we need not address its other contentions regarding the evaluation of its proposal.
 Despite the agencys reasonable determination that BGEs proposal was unacceptable, the protester remains an interested party to raise those issues that pertain to the acceptability of CLPs proposal because CLPs proposal was the only one found acceptable. See DOER Marine, B-295087, Dec. 21, 2004, 2004 CPD ¶ 252 at 2 n.2. However, BGE is not an interested party eligible to maintain the remainder of its protest of the evaluation of CLPs proposal or the award decision. See Bid Protest Regulations, 4 C.F.R. § 21.0(a)(1) (2011).
 These rates were negotiated as part of a contract entered into by Aberdeen and BGE in 1950. AR, Tab 13, BGE FPR, vol. III, Contract Documentation, at 5. The contract had been amended many times, and was accepted for filing by the Maryland Public Service Commission on November 29, 2000. Id.
 For the same reasons, we do not find that this potential commodity rate increase required the assignment of high risk ratings to CLPs proposal under either the cost realism subfactor of the risk factor or the other possible long-term costs and benefits subfactor of the risk factor. Indeed, as discussed above, the agency specifically considered whether the conveyance affects separate contract relationships, particularly for commodities, and based on its analysis found the risk of accepting CLPs proposal was acceptable. AR at 29; AR, Tab 27, SSD, at 10. Moreover, the work on the customer side of the meter was properly not considered in assessing the cost realism risk of CLPs proposal, given our finding above that this was not a requirement of the solicitation, but rather a requirement BGE put on itself in its alternate proposal.
 Only Schedule B-4 was applicable to CLPs fixed-price with prospective price redetermination proposal. This schedule requested prices for CLIN 0001, Utility Service Charge; CLIN 0002, [ISDC]/Connection Charges; CLIN 0003, Recoverable Portion of Purchase Price; CLIN 0004, Transition Period. RFP at 9.
 Based on the record, we also find no merit to BGEs assertion that CLP warranted a high risk rating under the financial strength subfactor of the technical capability subfactor.