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No. CEPR-AP-2015-0001

FORTIETH ANNUAL REPORT

ON THE ELECTRIC PROPERTY

of the

PUERTO RICO ELECTRIC POWER AUTHORITY

SAN JUAN, PUERTO RICO

UNDER TERMS OF TRUST AGREEMENT

Dated as of January 1, 1974, as amended,

U.S. BANK TRUST NATIONAL ASSOCIATION

TRUSTEE

JUNE 2013

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URS Corporation One Canal Park Cambridge, MA 02141 Tel: 617.621.0740 Fax: 617.621.9739

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FORTIETH ANNUAL REPORT

ON THE ELECTRIC PROPERTY

of the

PUERTO RICO ELECTRIC POWER AUTHORITY

SAN JUAN, PUERTO RICO

UNDER TERMS OF TRUST AGREEMENT

Dated as of January 1, 1974, as amended,

U.S. BANK TRUST NATIONAL ASSOCIATION

TRUSTEE

JUNE 2013

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EXECUTIVE SUMMARY This report is the 40th Annual Report by the Consulting Engineers in compliance with the 1974 Trust Agreement. The report is based on the Consulting Engineer’s inspections, interviews and review of relevant data pertaining to the operation of the Puerto Rico Electric Power Authority electric System during the fiscal year 2013, ending June 30, 2013. The Authority’s reported total energy sales in fiscal year 2013 were 0.6% more than the previous year, but still 7.0% less than in fiscal year 2008. During the past fiscal year energy sales increased in the residential and commercial sectors and declined in industrial. The decline in the industrial sector was its seventh consecutive year and reflected the continuing impact of the recession in Puerto Rico. The Authority’s Current Forecast for fiscal years 2014 through 2018 predicts a 1.3% growth in total energy sales for fiscal year 2014, with an average annual growth rate of 1.2% in fiscal years 2014 through 2018. The DOE Energy Information Agency forecasts the energy sales growth rate for mainland utilities during the same period will be 1.1%. Consistent with the interim-period forecast, the predicted slow growth of peak demand indicates the historic peak set in fiscal year 2006 will not be reached during the forecast period. In fiscal year 2013 the Authority’s electric sales revenues fell by 4.2% over the previous year as a result of the total cost of fuel declining 10.3% and purchased power increasing by 10.5% from the previous year. In fiscal year 2013 the Authority’s net generation declined by 5.4%, while its average cost of fuel per equivalent barrel dropped 6.1%, aided by the lower cost of the natural gas burned at its Costa Sur plant. The total cost of fuel is forecasted to decline 17.6% in fiscal year 2014 from 2013, with purchased power costs increasing 6.6%. Total electric sales revenues, including theft recoveries, are projected to decline by 7.4% from fiscal year 2013 to 2014. Net revenues, as defined by the 1974 Agreement, in fiscal year 2013 increased by 13.8% over the previous year as total current expenses fell by 6.6%, while total revenues were down 4.0%. The Authority forecasts its total revenues will decline by 6.8% in fiscal year 2014 from the results of fiscal year 2013; total revenues through fiscal year 2018 are projected to remain little changed from the fiscal year 2014 level. During the five-year forecast period through fiscal year 2018, the Authority projects its current expenses will also remain relatively stable as lower costs of fuel are offset by increased costs of purchased power. The resulting net revenues are forecasted to increase by 9.5% in fiscal year 2014 over 2013. In fiscal years 2015 through 2018 the net revenues are projected to increase 3.6%, drop 0.1%, and then increase 2.2% and 1.0%, respectively. With the forecasted net revenues and the projected annual debt service through fiscal year 2018 in the Authority’s budget used for this report, the projected debt service ratio based on the 1974 Agreement debt will range from 1.34 to 1.42 in the five fiscal years ending 2018. The budgeted financings may incur higher interest rates than forecasted and the ability to capitalize interest may be constrained as well. Both of these would increase the Authority’s projected principal and interest requirements in the intermediate term, thereby lowering the forecasted debt service coverage ratio. The largest operational issue facing the Authority is complying with the EPA hazardous air pollutant regulations by 2015. The Authority’s plan to dramatically switch from fuel oil to natural gas was endorsed by the island’s major stakeholders in a Commonwealth government convened public/private sector committee during fiscal year 2012. The committee identified alternative plans, but did not recommend a specific method for implementing the large increase in natural gas supply for the island. In the face of strong local opposition, projected cost escalations and regulatory uncertainty, during fiscal year 2012 the Authority stopped work on the proposed 92 mile pipeline from the south coast to three plant sites in the north. The Authority’s current approach to expand the supply of natural gas on the island has been an offshore gasification facility for LNG deliveries near its Aguirre power complex on the southeast coast. The proposed Aguirre Offshore Gas Port (AOGP) will be a floating facility to receive and gasify LNG shipments. The Authority plans that the AOGP will be installed by a vendor under a long term agreement and the Authority has continued with the coordi- URS Corporation One Canal Park Cambridge, MA 02141 Tel: 617.621.0740 Fax: 617.621.9739

I 000007 page 1 of 3 No. CEPR-AP-2015-0001 nated air permit effort with that vendor for both the AOGP scope and the Aguirre plants. The proposed permitting schedule would enable gas to be available for the Aguirre plant by the MATS compliance date of April 2015, with no margin for unanticipated delays. During fiscal year 2013 the Authority continued its due diligence on the contractual structure of the gas supply infrastructure and was evaluating alternative supply arrangements for natural gas to the north of the island. The Authority is evaluating the structure of the LNG commodity supply agreements, which would be separate from the infrastructure development. The Authority plans to select the bases for establishing the development of the natural gas infrastructure and fuel supply during fiscal year 2014. These will lead to qualifying bidders and soliciting proposals by the end of that fiscal year. Based on projected fuel costs, the Authority’s initiative to expand gas firing at its generating plants to meet environmental regulations will also lower the Authority’s cost of fuel, thereby benefitting the economy of Puerto Rico. During fiscal year 2013 the Authority operated Costa Sur Units 5 & 6, each a 410 MW unit, with natural gas providing most of the fuel for those units. The power generated from natural gas in these units accounted for 10.8% of the total power for the System; adding the power from the EcoEléctrica cogeneration plant put the total gas fired generation at almost 28% during fiscal year 2013. The Costa Sur units were the first steam units to be converted for dual fuel firing (burn oil and/or gas) because they are located adjacent to EcoEléctrica’s LNG facility, which supplied the fuel under a short term contract that is scheduled to be rene- gotiated in fiscal year 2014. The Capital Improvement Program (CIP) through fiscal year 2018 includes budgets to complete the dual fuel conversion work at the steam-electric units in accordance with plans for compliance with the EPA emission criteria, as well as the San Juan combined cycle units. By the end of fiscal year 2013 the Authority had performed much of the conversion work at various units during scheduled outages, and had completed the full scope for the two large units at Costa Sur. The next priorities are its two largest steam units at the Aguirre plant. Four steam units in the San Juan metropolitan area will be converted after the schedule for gas deliveries has been established. With sufficient fuel being available the Authority plans to add gas firing capability to the Authority’s two most efficient units, San Juan Units 5 & 6, which are combined cycle units presently burning high cost distillate fuel. Expenditures on capital improvement program projects during fiscal year 2013 were $327.7 million, which was 9.2% over budget; it was, however, 6.7% less than during the preceding fiscal year. The Authority has developed a lean capital expenditure plan for the five fiscal years through 2018, with plans to hold capital expenditures to an annual average of $310 million in that span. These budgets do not include construction of the natural gas supply infrastructure discussed above; the Authority plans to establish the funding structure for this work utilizing third party participants. Fiscal year 2013 was the first during which renewable energy sources contributed meaningful amounts of the energy transmitted and distributed within the System; the Authority purchased energy principally from four renewable energy projects—an additional small wind turbine provided power occasionally. Together these projects produced 0.7% of the total System power. At the end of fiscal year 2013 the Authority had signed a total of more than 60 Agreements to Purchase Power from proposed renewable energy projects with a total capacity of approximately 1,660 MW. In the past fiscal year the Authority began renegotiating its agreements with many renewable energy project developers to lower their energy costs to the Authority and incorporate the minimum technical requirements that were revised in 2012 after many agreements had been signed. This has been an ongoing process that applies to all new projects as well. In fiscal year 2014 the Authority plans to perform a more refined analysis to identify the maximum generation from projected renewable energy resources that can be accommodated by the System. The Authority has forecasted that renewable energy projects will contribute 4.7% of the System power by fiscal year 2015 and stabilize at that level through 2018. The Authority’s System performed reasonably well during fiscal year 2013. The equivalent availability of the Authority’s production plant at the end of fiscal year 2013 was 77%, the same level as one year earlier. The availability of the steam electric units in the past year was constrained by the continued program of overhauls and URS Corporation One Canal Park Cambridge, MA 02141 Tel: 617.621.0740 Fax: 617.621.9739

pageI 000008 2 of 3 No. CEPR-AP-2015-0001 gas conversion work at the Authority’s largest units. In addition, the Authority adopted a policy to minimize premium work time on scheduled outages to reduce its costs; extending the duration of the outages also reduced availability. The generating efficiency of the Authority’s thermal plants in 2013 matched the average of the preceding three years. The reliability of electric service to the Authority’s clients in fiscal year 2013, as measured by interruptions, consistently bettered their goals of less frequent and shorter interruptions. Since 2000 and 2002 the Authority has utilized two private cogeneration facilities for fuel diversity, natural gas and coal, respectively; these sources also provide cost stabilization for a portion of the System’s generation resources. During fiscal year 2013 these two plants produced approximately 34% of the System power and demonstrated reliable operation. The Authority’s total credits and costs to the Commonwealth for Contributions in Lieu of Taxes (CILT) and Other (comprised of three subsidies and an energy credit) were $180.6 million in fiscal year 2013, or 25% of the Authority’s net revenues for the fiscal year, using the 1974 Agreement accounting. The Authority’s fiscal year 2013 CILT credits (which apply to the municipalities) were well short of its actual obligations for that fiscal year, consequently the unpaid balance will be paid over the next three years. CILT credits during fiscal year 2013 included installment payments on unpaid CILT obligations from fiscal years 2010, 2011 and 2012. At the end of fiscal year 2013, the outstanding deferred CILT balance totaled $323.6 million. Recent legislation excludes municipal power consumption for money raising activities from the CILT amount. The Authority has factored this reduction into projected CILT obligations, which are structured to avoid increasing the accumulated deferred CILT balance. In addition to CILT, which benefits the municipalities, the Authority also incurred costs of $54.4 million for certain Commonwealth subsidies during the fiscal year and for the amortization of the outstanding line of credit used in the 2004 settlement of the lawsuit by the municipalities. The 1974 Agreement obliges the Consulting Engineers to make specific assessments of the Authority’s operations and make recommendations for deposits into certain Funds established under the 1974 Agreement. These are discussed in depth in the report and summarized below: In the opinion of the Consulting Engineers, the properties of the System are in good repair and sound operating condition. The Consulting Engineers believes the Authority will receive sufficient revenues in fiscal year 2014 with the existing rates to cover current expenses, to make all required deposits in accordance with the 1974 Agreement’s dictates and to exceed its 120% debt service coverage requirement. Based on the outstanding debt at the end of fiscal year 2013, the debt service coverage was 138% in fiscal year 2013 and is forecasted to be 141% in fiscal year 2014, prior to adjustment for planned financings during fiscal year 2014. The Consulting Engineers reviewed and approved the Authority’s Annual Budget of Current Expenses and Capital Expenditures for fiscal year 2014, which was adopted in May 2013. The budget for fiscal year 2014 includes the first year of the Authority’s five year Capital Improvement Program. In fiscal year 2014 the Authority is projected to contribute 7.6% or $22.7 million in internally generated funds to capital expenditures. The Consulting Engineers continues to recommend the Authority should pursue as aggressively as practicable the goal of achieving and maintaining annual levels of internal funding above that last met in fiscal year 2010 when it was 16%. The Reserve Maintenance Fund was last used in fiscal year 2008 as an interim source of funds for the recovery following the fire at the Palo Seco Steam Plant. The balance in this fund was $15.8 million at the end of fiscal year 2013. The Consulting Engineers recommends the Authority make no deposits to the Reserve Maintenance Fund during fiscal year 2014. At the end of fiscal year 2013, the Self-insurance Fund’s balance was $92.2 million. This fund was also last used in fiscal year 2008 to cover uninsured losses associated with the Palo Seco Steam Plant fires. Based on the current fund levels, the Consulting Engineers recommends the Authority need not deposit any moneys into the Self-insurance Fund.

URS Corporation One Canal Park Cambridge, MA 02141 Tel: 617.621.0740 Fax: 617.621.9739

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TABLE OF CONTENTS INTRODUCTION ...... 1 SYSTEM DESCRIPTION ...... 2 SYSTEM’S OPERATIONS ...... 4 Production Plant ...... 4 Maintenance ...... 4 Status of Production Units ...... 8 Steam-Electric Production Plant ...... 10 Aguirre Steam Plant ...... 10 Costa Sur Steam Plant ...... 12 Palo Seco Steam Plant ...... 15 San Juan Steam Plant ...... 18 Combined-Cycle Plant ...... 20 Aguirre Combined-Cycle Plant ...... 21 San Juan Combined-Cycle ...... 23 Combustion-Turbine Power ...... 25 Cambalache Combustion-Turbine Power Blocks ...... 25 Other Combustion-Turbine Power ...... 27 Hydro Production Plant ...... 29 Diesel Generators ...... 30 Fuels ...... 30 Battery Energy Storage System ...... 32 Spare Components ...... 32 Production Plant Capital Improvements ...... 32 Environmental...... 32 Cogenerators ...... 34 EcoEléctrica, L.P...... 35 AES-PR ...... 36 Transmission and Distribution Systems ...... 37 Transmission ...... 37 230 kV System ...... 37 115 kV System ...... 38 38 kV System ...... 40 Transmission Plant Capital Improvements ...... 41 Distribution ...... 41 Selected 13.2 kV Projects ...... 41 Other Distribution Work ...... 42 Distribution Plant Capital Improvements ...... 42

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Maintenance ...... 43 Transmission and Distribution Systems Reliability ...... 44 Reliability Indices ...... 44 Technological Systems Operations ...... 46 Energy Management System ...... 46 Asset Management Systems ...... 46 Production Plant Asset Management Systems ...... 46 Transmission & Distribution Asset Management Systems ...... 47 Remote Meter Reading ...... 48 General Facilities...... 49

CONDITION OF THE SYSTEM’S PROPERTIES ...... 50 CURRENT FORECAST...... 50 Economy of Puerto Rico ...... 51 Econometric Projections ...... 52 Macroeconomic Projections ...... 52 Current Forecast Projections ...... 53 Consumption of Electricity ...... 53

DEMAND AND ENERGY FORECAST ...... 54 Generation Forecast ...... 54 Peak Demand Forecast ...... 55 Demand-Side Management and Energy Conservation Programs ...... 56

CAPACITY AND ENERGY RESOURCE PLANNING...... 57 Overview ...... 57 Availability ...... 57 Capacity Planning ...... 57 Purchased Power ...... 58 Energy Resource Planning ...... 59 Alternative Energy Sources...... 60 Fuel Mix ...... 62 Authority’s Fuel ...... 63 ENERGY SALES FORECAST ...... 64 Short-to-Intermediate Term Energy Sales Forecast...... 64 Residential Sector ...... 65 Commercial Sector ...... 65 Industrial Sector ...... 66 Other Classes ...... 68 Total Electric Energy Sales ...... 68 ii I 000012 No. CEPR-AP-2015-0001

RATES ...... 69 Rate Schedules...... 69 Classifications and Revenues ...... 69 Rate Stabilization Fund ...... 71 Rate Structure ...... 71 Price Comparisons ...... 71 Subsidies and Credits ...... 72 Residential Fuel Subsidy ...... 72 Residential Rate Subsidy ...... 73 Hotel Subsidy Program ...... 73 Charitable Organizations Subsidy ...... 73 Life Preservation Subsidy ...... 73 Agricultural Subsidy ...... 73 Irrigation Service Subsidy ...... 73 Common Area Lighting Subsidy ...... 74 Other Subsidies and Credits ...... 74 Selected Rates ...... 74 Public Housing Residential Rate ...... 74 Special Rates ...... 74 Large Industrial Service Rate ...... 75 Time-of-Use Rates ...... 75 Standby Service Rate ...... 75 Power Producers at Bus Bar Rate ...... 76 Security Cameras Rate ...... 76 Cost of Service...... 76 Consulting Engineers Recommendation...... 76 FINANCIAL ...... 77 Annual Budget ...... 77 Revenues ...... 77 Expenses...... 77 Operating and Maintenance Expenses ...... 77 Net Revenues ...... 78 Debt Service Coverage...... 79 Depreciation Expense ...... 79 Accounts Receivable...... 80 Contributions to the Commonwealth ...... 80 Contributions in Lieu of Taxes and Other ...... 80 Economic Incentives Act ...... 82 Financing ...... 83 Long-term Capital Financing ...... 83 Interim Financing ...... 83 I 000013 iii No. CEPR-AP-2015-0001

Lines of Credit and Notes Payable ...... 83 Capital Improvement Program ...... 83 Production Plant ...... 85 Transmission Plant ...... 85 Distribution Plant ...... 86 General Plant ...... 86 Preliminary Investigations ...... 86 Funding of the Employee’s Retirement System...... 86 Inventories and Other Properties ...... 87 Insurance ...... 87 FUNDING RECOMMENDATIONS ...... 88 Reserve Maintenance Fund ...... 89 Self-Insurance Fund...... 89 Capital Improvement Fund ...... 90 HUMAN CAPITAL ...... 92 Human Resources...... 92 Labor Affairs...... 92 Employee Safety...... 93 LEGAL AFFAIRS...... 94 SUPPLEMENTARY INFORMATION ...... 96 Executive Director Changes ...... 96 PREPA Subsidiaries ...... 96

230 & 115 KV TRANSMISSION SYSTEM MAP

APPENDICES I INTERMEDIATE-TERM FINANCIAL PLANNING FORECAST II INCOME STATEMENT III DETAIL OF OPERATING and MAINTENANCE EXPENSES IV ANNUAL NET GENERATION, FUEL CONSUMPTION, FUEL AND PURCHASED POWER COSTS V DEBT SERVICE COVERAGE UNDER THE 1974 TRUST AGREEMENT VI CAPITAL EXPENDITURES VII SOURCES OF FUNDS FOR CAPITAL EXPENDITURES VIII SYSTEM CAPABILITY IX DEPRECIATION EXPENSE X DETAILS OF CAPITAL IMPROVEMENT PROGRAM

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INTRODUCTION The Authority further covenants that the Consulting Engineers shall at all times have free This is the Fortieth Annual Report by the Puerto Rico access to all properties of the System and every part Electric Power Authority’s (Authority) Consulting thereof for the purposes of inspection and examina- Engineers, URS Corporation (Consulting Engineers), tion, and that its books, records and accounts may filed to comply with the provisions of Section 706 of be examined by the Consulting Engineers at all rea- Article VII of the Trust Agreement, dated as of sonable times. January 1, 1974, as amended and supplemented, This Annual Report is based, in part, upon our between the Authority and U.S. Bank Trust National knowledge of the Authority’s operations gained over Association, the successor Trustee for the 1974 Trust the more than 65 years that we (Consulting Agreement. Engineers and its antecedent companies) have been Act No. 83 of the Legislature of Puerto Rico, approved retained as Consulting Engineers. We were initially May 2, 1941, as amended, reenacted and supple- retained in accordance with the provisions of Section mented (the “Authority Act”), created the Authority a 704 of Article VII of the Authorizing Resolution, body corporate and politic constituting a public cor- dated January 1, 1944, and subsequently in accor- poration and governmental instrumentality of the dance with Section 704 of Article VII of the 1947 Commonwealth of Puerto Rico. Hereinafter, we will Trust Indenture from its inception until its release, a refer to Act No. 83 of the Legislature of Puerto Rico, period of 53 years. We have also served as Consulting approved May 2, 1941, as amended, reenacted and Engineers in accordance with Section 706 of Article supplemented as the Authority Act. VII of the 1974 Agreement since its inception. With the release of the 1947 Trust Indenture on June Each year, in fulfilling our duties as Consulting 9, 1996, the 1974 Trust Agreement, dated as of Engineers, we visit and note the condition of all the January 1, 1974, as amended and supplemented, steam production facilities a minimum of three times; became the sole document governing all of the all the remaining production facilities at least once Authority’s long-term financings, with the exception each year; one-third of the approximately 380 distri- of minor subordinated interim debt. Throughout this bution substations and transmission centers; and a report we will refer to the 1974 Trust Agreement, representative cross-section of all additional property dated as of January 1, 1974, as amended and supple- owned and operated by the Authority. We regularly mented, as the 1974 Agreement. review the Authority’s various reports and records, Section 706 of the 1974 Agreement provides the fol- meet with the Authority’s management and staff to lowing: discuss present operations and future plans, and perform a number of analyses relying primarily on data It shall be the duty of the Consulting Engineers to and information provided by the Authority. We also prepare and file with the Authority and with the participate in all regular bond issue financings under- Trustee on or before the 1st day of November in taken by the Authority by assisting in the preparation each year a report setting forth their recommenda- of the Official Statements, by providing several signed tions as to any necessary or advisable revisions of Engineers Certificates, and by participating in most rates and charges and such other advices and rec- bond rating agency presentations. ommendations as they may deem desirable. After...the release of the 1947 Indenture, it shall be the duty of the Consulting Engineers to include in such report their recommendations as to the amount that should be deposited monthly during the ensuing fiscal year to the credit of the Reserve Maintenance Fund for the purposes set forth in Section 512 of this Agreement, deposited during the ensuing fiscal year to the credit of the Self-insurance Fund for the purposes set forth in Section 512A of this Agreement, if any, and deposited during the ensuing fiscal year to the credit of the Capital Improvement Fund for the purposes set forth in Section 512B of this Agreement.

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SYSTEM DESCRIPTION with tropical storms and hurricanes. The last hurricane to drastically affect both the island’s economy The Authority’s System supplies virtually all of the and the System, Hurricane Georges, struck the island electricity consumed in Puerto Rico and the smaller on September 28, 1998. islands of Vieques and Culebra. In the past fiscal year An electric power system is made up of production, the Authority generated approximately 66% of the transmission, distribution, communication and ancil- electricity itself and purchased the remaining. The lary facilities, not all of which are physically con- two largest sources were the cogenerators, nected, operated as a single integrated whole. The EcoEléctrica, L.P. located in the Municipality of flow of electricity within the system is maintained Peñuelas and AES-PR located in the Municipality of and controlled by a dispatch center. It is the responsi- Guayama. Power from five new renewable energy bility of the dispatch center’s operators to match the projects contributed 0.7% of the island’s electricity for real-time supply of electricity with the simultaneous the last year. During fiscal year 2013, which ended on demand for it. In order to carry out their responsibil- June 30, 2013, the System served on average ities the System’s dispatchers are authorized to buy 1,485,150 clients. power to complement the System’s own generation The Commonwealth of Puerto Rico is the eastern- and to economically dispatch it based on System most of the islands comprising the Greater Antilles requirements. and is approximately 110 miles in length and 35 The Authority’s primary dispatch center, which is miles north to south. Central mountain ranges with under the direction of the Director of Generation, is peaks as high as 4,390 feet extend the length of the located at Monacillos, approximately seven miles island from east to west. Coastal lowlands formed by south of metropolitan San Juan. A Supervisory the erosion of the central mountains extend inwards Control and Data Acquisition (SCADA) system, an on the north coast for 8 to 12 miles and for 3 to 8 integral part of the dispatch center’s control system, miles in the south. The northern coastal lowlands are has the ability to control total load flow on the island humid while those on the south side of the island are and can remotely control many of the Authority’s sub- semi-arid. The island’s population density is high; stations and all of the large generating units. A sec- approximately 58% of the island’s 3.65 million inhab- ondary dispatch center is located in Ponce; it is itants live in the broader metropolitan area of San continuously available to assume control if the pri- Juan; the next most populous urban areas are Ponce mary control center has problems. Both centers are and Mayagüez, with 12% and 7% of the island’s pop- fully staffed during System emergencies, coordinating ulation, respectively. The rural population is approxi- all restoration efforts. mately 6% of the total and resides in the numerous small towns located along the island’s perimeter and The three major components of the System are the in the remote mountainous interior. Data from the Production Plant, the Transmission system, and the 2010 census show the population of Puerto Rico Distribution system. They account for approximately declined by 2.2% in the ten years since the previous 86% of the $11.7 billion Plant-in-Service investment. census; this was the first observed decline in the Below is a brief description of each of these components. island’s population. Data collected since 2010 indi- The production plant’s dependable generating capac- cate the decline in the island’s population has contin- ity, to the nearest megawatt, is 4,878 MW comprised ued with an additional estimated loss of 1.9% through of 2,892 MW of steam-electric capacity, 846 MW of 2012. Taken together Puerto Rico’s geography, cli- combustion-turbine capacity, 1,032 MW of com- mate, and the dispersion of its clients within the bined-cycle capacity, 100 MW of hydroelectric capac- Commonwealth present the Authority with many ity, and 8 MW of diesel capacity. The 2,892 MW of challenges as it designs, builds, operates, and main- steam-electric capacity consists of 14 units at four tains its System. The Authority serves its clients in 26 sites: Palo Seco–602 MW (four units) and San districts through seven regional offices, each of which Juan–400 MW (four units), both on the north side of incorporates a technical office. the island; Aguirre–900 MW (two units) and Costa Puerto Rico is in the path of many of the tropical Sur–990 MW (four units), both on the south side of storms and hurricanes that cross the Greater Antilles the island. The last reduction in the Authority’s during the hurricane season, which runs from June capacity and number of steam-electric units occurred through November. The Authority’s transmission and at the end of fiscal year 2008 when Costa Sur Units 1 distribution systems, more than 90% of which are & 2, which had a combined capacity of 100 MW, were above ground, are particularly vulnerable to the high removed from service. While the Authority has addi- winds, torrential rains, and erosion that are associated tional older steam-electric plants, there are no present 2 I 000016 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report plans to retire them, although the future use of cer- the System, all were under 20 year PPOAs. The oper- tain older plants may be limited as part of the ating renewable sources were the Pattern wind farm in Authority’s strategy to meet new air emission stan- Santa Isabela with a nominal rating of 75 MW, Punta dards. The Authority’s 1,032 MW of combined-cycle Lima wind farm in Naguabo with a nominal rating of capacity is comprised of two units at the Aguirre com- 26 MW, the 1 MW wind turbine at the Bechara water plex with a capacity of 592 MW and two units located treatment facility in San Juan, the AES Iluminia 20 in the San Juan Station with a total capacity of 440 MW solar farm in Guayama and the 2.1 MW MW, which came into service during fiscal year 2009. Windmar solar farm near Ponce. Additional renewable The 846 MW of combustion-turbine capacity consists projects are scheduled for completion and operations of 29 units at nine sites around the island, the three- in fiscal year 2015. All of these renewable energy proj- unit 248 MW Cambalache Station being the largest. ects are intermittent sources of power because they The 100 MW of hydroelectric capacity consists of 21 rely on the availability of wind or sun light, conse- units at 11 sites around the island, the 25 MW Yauco quently they are not considered reliable capacity. No. 1 being the largest unit. The Authority has two The Authority’s transmission system is an intercon- diesel generators each with 3 MW of capacity on nected network of 230 kV, 115 kV, and 38 kV power standby reserve on the island of Vieques. On the lines that carry electrical power from the production island of Culebra four diesel generators having a com- plants to numerous distribution centers from where it bined capacity of 2 MW provide standby reserve. The is distributed to clients for consumption. Authority also has a mobile 1 MW diesel unit on Culebra; it is not connected to the System and is not At the close of fiscal year 2013, the transmission sys- listed as standby reserve capacity. tem was comprised of 2,478 circuit miles of lines: 375 circuit miles of 230 kV lines, 727 circuit miles of 115 During fiscal year 2009 ten units came into initial kV lines, and 1,376 circuit miles of 38 kV lines. service and four simple cycle combustion turbines Included in the transmission system totals are were retired; these changes are reflected in the data approximately 35 miles of underground 115 kV cable, above. The two largest new units were San Juan Units 63 miles of underground 38 kV cable and 55 miles of 5 & 6 combined cycle units, each having a depend- 38 kV submarine cable. In addition to the high volt- able capacity of 220 MW. At Mayagüez four 21 MW age lines, the transmission system includes trans- combustion turbines were retired and removed from the site and replaced by eight aero-derivative simple formers at the generating plant substations, cycle combustion turbines. The replacement combus- transmission centers for interconnection of different tion turbines increased the available capacity at the voltage systems and switch yards and gear for connec- Mayagüez station from 84 MW to 220 MW. tion or separation of portions of the transmission system operating at the same voltage. High voltage The Authority’s Sabana Llana battery energy storage transformers installed in the Authority’s transmission system was designed to provide up to 20 MW for system and its production plants have a total trans- power factor correction and reserve capacity, how- former capacity of 19,207 MVA. ever, the battery system has not been available for service since fiscal year 2006. At the end of fiscal year As of June 30, 2013, the Authority’s distribution sys- 2013 the Authority was evaluating proposals for sal- tem consisted of approximately 31,550 circuit miles vaging the facility’s batteries. of distribution lines (with operating voltages ranging from 4.16 to 13.2 kV) and 333 substations (with a To supplement its own capacity, the Authority pur- total installed capacity of 5,018 MVA). The distribu- chases power from two cogenerators under the terms tion system has more than 1,800 circuit miles of and conditions of Power Purchase Operating underground lines. The Authority has 22 portable Agreements (PPOAs). The Authority is in the thir- transformers with a total capacity of 349.6 MVA to teenth year of a 22-year PPOA for 507 MW of gas- substitute for existing transformers during mainte- fired capacity from EcoEléctrica, L.P. and is in the nance or outages; similarly the Authority has two tenth year of a 25-year PPOA for 454 MW of coal- portable capacitor banks each rated at 18 MVAR. fired capacity from AES-PR. The 961 MW of capacity There are 813 privately owned substations (with a provided by the cogenerators brings the total depend- total installed capacity of 3,266 MVA). The distribu- able capacity available to the Authority to 5,839 MW. tion system also includes approximately 1,485,200 Appendix VIII, System Capability.) (See client meters. 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SYSTEM’S OPERATIONS retubing condensers; replacing condenser vacuum equipment; replacing cooling water filtration systems, PRODUCTION PLANT and improving condenser backwash capabilities. The Authority has installed continuous condenser clean- The Authority continues its commitment to an ongoing systems on several units; vendor owned continuing, long-term program to extend the life and to main- ous condenser cleaning systems are operated on a tain the high level of availability of its generating units. pay-for-performance basis. Turbine efficiency is also The program consists of three components: formal being improved through the installation of high effi- operator training, comprehensive preventative mainte- ciency seals, through turbine control upgrades, and nance, and design modification. The formal operator training part of the program emphasizes safety, operat- through the installation of redesigned turbine blades. ing efficiency, and equipment integrity. The compre- The Authority purchased asset management software hensive preventative maintenance part of the program for its production plant and high voltage electrical requires the Authority to remove all major generating equipment during fiscal year 2010 to replace and units from service for maintenance at regularly sched- expand the existing system which was becoming out- uled intervals to ensure their reliability. These intervals moded. Among the expected benefits of the new pro- are referred to as “scheduled outages” in the text of this gram will be the improvement of the availability of Annual Report. A residual life assessment of critical critical generation and the reliability of certain high components is an integral part of the Authority’s pre- voltage transmission assets. The program was fully ventative maintenance practices. implemented during the past fiscal year for the pro- The design modification part of the program repre- duction plant assets. During fiscal year 2011 the sents the Authority’s commitment to improve the Authority’s engineers participated in factory accept- operation of its generating units by installing ance tests (FAT) of components of an upgrade to their redesigned, improved components, or by undertaking Energy Management System (EMS). After operating conversions. Examples of design modifications the new EMS in parallel with the existing system to include upgrades of the eight 50 MW combustion demonstrate its capabilities and reliability the new turbines with original equipment manufacturer EMS was placed in service during fiscal year 2013. (OEM) improvements and the completion of modifi- Both of these programs are more fully described in cations enabling them to burn distillate or natural the Technological Systems Operations section below. gas. During fiscal year 2012 the Authority began the We visit all the steam-electric production facilities a design modification of Costa Sur Unit 6’s boiler, minimum of three times each year and all of the burner, and control system to support full load gas fir- remaining production facilities at least once each year. ing. These modifications were completed in the first We examine numerous operations reports and we reg- half of fiscal year 2013; similar modifications to Costa ularly meet with the Authority’s management and staff Sur Unit 5 were completed by the end of fiscal year to discuss present operations and future plans. 2013. The initial phase of the modification of the In accordance with an agreement approved by the Aguirre Steam Units to enable them to burn natural Secretary of the Puerto Rico Department of Labor, gas was completed during fiscal year 2012. The instal- Puerto Rico’s Jurisdictional Boiler Inspector has lation of the remaining design modifications to the allowed the Authority to increase the interval Aguirre Steam Electric units are scheduled to coin- between boiler certifications from 12 months, as nor- cide with the availability of natural gas at the station. mally required by Commonwealth law, to 18 months. The Authority also plans dual fuel conversion at other Nevertheless, at the end of fiscal year 2013 the steam electric units and the combined cycle units at Jurisdictional Boiler Inspector had certified all of the the San Juan Station over the next several fiscal years. Authority’s boilers within the previous 12 months. Years ago the Authority also converted all of its “forced draft” thermal plant boilers to “balanced MAINTENANCE draft” operation. These modifications allow the Routine maintenance activities are performed during equipment to be operated at design or increased environmental outages and during planned major capacity with greater operational efficiency and relia- outages which have broader scopes of work. bility. Among the Authority’s current projects are Significant production plant upgrades or design mod- those that aim to increase the efficiency of its steam ifications are accomplished during major overhauls. turbines by improving the performance of the associ- The routine maintenance activities are charged ated steam condenser. These projects have included: against the plant’s maintenance budget. As is com- 4 I 000018 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report mon in the electric utility industry, expenditures asso- repaired. Hoppers are emptied and cleaned, expan- ciated with significant production plant upgrades and sion joints are inspected for corrosion and leakage. design modifications are capitalized rather than Fuel handling equipment is inspected, repaired, and charged as a current maintenance expense. Typically recalibrated as necessary. The forced and induced these activities are performed during scheduled major draft fans and the gas recirculation fan are cleaned, outages, although occasionally the Authority installs noise and vibration levels monitored, adjustments capitalized components during a scheduled environ- made and repairs completed. Motors for fans and mental outage. During scheduled outages the main boiler pumps are cleaned and inspected. Authority also performs non-destructive testing Dampers are inspected and adjusted. The windbox, (NDT) examinations of representative critical compo- burners, combustion air instrumentation, combus- nents to establish their condition and perform or tion controls, and soot blowers are inspected; dam- schedule appropriate repair work. The scope of NDT aged or worn components are either repaired or examinations includes boiler pressure parts, power replaced. Monitors for opacity, oxygen, and furnace piping, steam turbine components, electrical genera- pressure are cleaned, recalibrated, or as necessary tors, transformers, and switchgear. replaced. Pumps, feedwater heaters, the deaerator, and associated valves are inspected. Lubricating oil The duration of an outage varies based on the scope systems are inspected. Power transformers are of work, availability of personnel and material, and inspected and breakers tested and adjusted. If a pres- budgetary constraints. Where the Authority routinely surized part of the boiler has been replaced the boiler used extended work hours and temporary workers part will be pressure tested before the unit returns to from other plants to shorten the duration of an out- service. Life extension inspections and NDT activities age in the past, present budget constraints have are completed on critical systems and components in forced the Authority to minimize premium work preparation for future programmed outages. time. The Authority has judged the cost savings associated with extending an outage are cost effective In the discussions regarding the status of production given the good reliability of its plants and the com- units that follow, the narrative will note the duration fortable reserve capacity margin it has over recent of a unit’s environmental outage and describe work demand. completed during the outage, which is in addition to that routinely performed during an environmental The Authority schedules their fourteen steam-electric outage. generating units out of service for an environmental outage at intervals of twelve to eighteen months. All of the Authority’s fourteen steam-electric generat- During an environmental outage the boiler and other ing units were in service during fiscal year 2013. Ten components are cleaned to meet the requirements of of the 14 steam-electric generating units that were in the Air Compliance Preventative Maintenance service during fiscal year 2013 either completed or Schedule contained in the Authority’s Consent Decree began an environmental outage during the fiscal year. with the Environmental Protection Agency (EPA). The other four steam electric units were scheduled to The Authority may keep a unit in service up to an begin the Consent Decree mandated environmental eighteen-month limit subject to the unit’s compliance outage in the first or second quarter of fiscal year with the emissions criteria in the Consent Decree. 2014. At the end of fiscal year 2013 all 14 of the steam Frequently the Authority will advance the start of an electric units had completed an environmental outage environmental outage to ensure that adequate capac- within the 18 months allowed in the Consent Decree ity is available during a period of high demand or to with the EPA. avoid having several units out of service concurrently. With few exceptions the Authority sequences sched- The following paragraph describes some of the clean- uled outages so that the large steam electric units are ings, inspections, and replacements that the available for service from May through November, the Authority performs during an environmental outage. months of maximum demand and greatest risks of At the start of an environmental outage slag is weather disturbances. This strategy seeks, to the removed from the boiler and the water walls are extent possible, to maximize the availability of the cleaned. The superheater, reheater, air heater, and System’s capacity while maintaining compliance with economizer areas are washed and inspected, as are the the Consent Decree with the EPA. exhaust gas ducts and the stack. Air heater compo- Steam turbines are internally inspected every five-to- nents; seals, baskets, casing, and sector plates are seven years. This work, which is typically scheduled inspected and replaced as necessary. Ductwork is for a period of three-to-five months duration, I 000019 5 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report includes opening the high-, intermediate- and/or low- configuration. One of the benefits of the “PA” mod- pressure section of the steam turbine, turbine control ernization is that the interval between certain inspec- valve inspection, generator testing and repair, the dis- tions increased the equivalent fired hours as follows: assembling, repairing, or replacing of major compo- fuel nozzles of these units are inspected every 1,125 nents; the scope of work is more comprehensive than equivalent fired hours or 2,250 equivalent fired hours an “environmental outage”. It is identified as a “major for units with air atomization; combustion section overhaul” in the descriptions of the status of produc- inspections are conducted every 4,500 equivalent tion units that are discussed below. Major overhauls fired hours; and intermediate inspections are con- frequently include rehabilitation work on the boiler ducted every 9,000 equivalent fired hours. and balance of plant systems. Compressor and power turbine sections are rebuilt One exception to the scheduled interval between during major overhauls, which are scheduled every major overhauls is Palo Seco Unit 2, which has been 18,000 equivalent fired hours. in service more than ten years between major over- In 2004 the Authority began a program to replace cer- hauls. The Authority completed the overhaul of the tain components in 16 of its eighteen 21 MW com- HP, IP, and LP turbines of the 85 MW unit in May bustion turbines. The program included the 2002. During the reconditioning of each of the Palo replacement of the ratchet and torque converter Seco units following a major fire in December 2006 thereby improving starting reliability, the installation the Authority examined critical components of each of a universal fuel system, turbine modifications, an unit and determined that an extensive overhaul of upgrade of the turbine control system, and new digi- Unit 2 was not required. Given the anticipated low tal controls for the exciter. The final combustion tur- level of dispatch of this unit following the Authority’s bine in the program is scheduled for the upgrade in compliance plan for the MATS clean air emission fiscal year 2014. standards discussed in the Environmental section the Authority has not scheduled a major overhaul of this Lubricating oil analysis and other preventative main- unit, however environmental outages and targeted tenance and diagnostic tests are performed monthly. maintenance will continue. Palo Seco Unit 2 recorded Eight new FT8 aero-derivative simple cycle combus- an equivalent availability of 87% during fiscal year tion turbines went into service at the Authority’s 2013. Mayagüez plant during fiscal year 2009. These eight Occasionally the scope of work performed during a combustion turbines comprise four unit blocks. The major overhaul will cause the schedule to be combustion turbines are connected in opposed pairs, extended beyond the three-to-five months required to between each pair is a 55 MW generator. The four complete the turbine work. These events are detailed units are capable of 220 MW; they replace the four 21 in the unit descriptions that follow. MW combustion turbines that were previously sited at the Mayagüez plant. The new units will be The Authority’s remaining production plant also includes both simple cycle and combined-cycle com- inspected and maintained at the following intervals: bustion-turbines, and a number of relatively small “A” Inspection the sooner of every 1,000 hours or hydroelectric plants. annually, during which borescope inspections are The Authority schedules maintenance on its 39 com- performed and preventative maintenance completed bustion-turbines (29 operated in simple cycle config- under the direction of a technical advisor. uration and ten operated in combined-cycle “B” Inspection performed every 12,500 hours is a hot configuration) based upon the number of “equivalent section inspection of the combustors, the power tur- fired hours” of operation as specified in manufactur- bine sections and the seals and bearings. The unit is ers’ manuals. The equivalent fired hours concept disassembled and shipped to a shop for the inspec- takes into account the wear and tear associated with tion. starting up the units as well as other operating factors “C” Inspection performed at 25,000 hours includes that reduce the actual number of hours that units can the inspection and refurbishment of the combustion be run between inspections. Eighteen of the turbine’s intermediate case, the bearing compart- Authority’s simple cycle combustion-turbines are 21 ments, pumps, in addition to the components MW Frame 5 machines, located at seven sites throughout the island. During the 1990’s the inspected during a “B” inspection. Authority improved the performance of these com- “D” Inspection performed at 50,000 hours entails the bustion turbines by upgrading them to model “PA” shop inspection of all sections of the combustion tur- 6 I 000020 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report bine and the refurbishment or replacement of worn Major overhauls, during which the turbine and com- components. pressor are opened and blades in the first stage of the turbine are replaced, are scheduled after 31,800 The three 82.5 MW Model GT 11N combustion-tur- equivalent fired hours. In addition, reduction gears bines power blocks at the Cambalache Combustion- and other turbine components and auxiliaries are Turbine Station are inspected and maintained in inspected and repaired. Duct sections, baffles, the accordance with the schedule below: exhaust stack, the generator, and other electrical Class “A” Inspection every 4,000 equivalent fired equipment are also inspected and repaired. Filter hours: the combustor, burners, and turbine blades are media in the air intake system are also replaced at this inspected; the duration of the inspection is approxi- time. A major overhaul is typically completed over a mately six days. sixteen-week period. Class “B” Inspection every 8,000 equivalent fired The steam turbines of the Aguirre combined-cycle hours: the instrumentation is recalibrated; the com- plant are maintained in accordance with the same bustor, burners, and turbine blades are inspected; and guidelines as those followed for the 16 steam-electric the once-through steam generator (OTSG) is washed; turbines; however because their service is intermit- the duration of the work is approximately six days. tent and most often at partial load the years between scheduled overhauls may exceed those of the steam- Class “C” Inspection every 16,000 equivalent fired turbines. The service intervals for these two steam hours: the blades in the compressor section are turbines are discussed in the Aguirre Combined Cycle replaced; the combustor is removed for inspection; Plant section below. the combustor liner is replaced; thermal tiles and holding rings are replaced; the turbine is opened; the During October 2008 the Authority’s two 220 MW first three rows of blades in the high-pressure section combined-cycle units, San Juan Units 5 & 6, went of the turbine are replaced; auxiliaries are inspected into commercial service. Each unit is comprised of a and repaired as necessary; the duration of the work is single combustion turbine with a capacity of 160 MW approximately 31 days. The removed combustor liner and a steam turbine with a capacity of 60 MW. The and turbine blades are refurbished for use during Authority has signed a long term service agreement, future outages. LTSA, with the combustion turbine vendor of approximately eight years duration during which the The Authority completed the upgrade of the last of vendor will be responsible for the maintenance of the the Frame 7 combustion turbines at the Aguirre combustion turbine generator and the steam turbine Combined Cycle Station to a modified Frame 7EA generator. The Authority will be responsible for the design during fiscal year 2007. The upgrade allowed maintenance of the combined-cycle plant’s auxil- the Authority to increase the number of equivalent iaries. Combustion turbine inspections will be per- fired hours a combustion turbine is in service formed on the basis of equivalent service hours, ESH, between scheduled maintenance inspections to the as follows: hours cited below: 8,000 ESH – Modified Combustion Inspection – fuel Combustion inspections during which burner noz- nozzles, combustor baskets, transition pieces, turbine zles, check valves, filters, and associated instrumenta- blades in rows 1, 2, 3, and 4, and turbine vane and tion are inspected are scheduled every 5,300 ring segments in rows 1 and 2 will be replaced. equivalent fired hours. Prior to the design upgrade Inspections of the inlet, compressor, turbine, and combustion inspections were performed at 4,000 exhaust sections of the combustion turbine are com- equivalent fired hours intervals. Combustion outages pleted. take less than a week. 16,000 ESH – Combustion Inspection – fuel nozzles, Hot-gas-path inspections, during which the liner, the combustor baskets, transition pieces, turbine blades first stage turbine blades, rotor bearings, burners, etc., in rows 1, 2, 3, and 4, and turbine vane and ring seg- are inspected, are scheduled approximately every ments in rows 1 and 2 will be inspected and replaced 15,900 equivalent fired hours. The turbine inspection as necessary. Inspection of the inlet, compressor, tur- ports are opened; turbine blades are replaced as dic- bine, and exhaust sections of the combustion turbine tated by the degree of blade corrosion. A hot-gas-path are performed. inspection is typically completed over an eight-week 24,000 ESH – Major Inspection of the combustion period. turbine is completed with inspection and replace- I 000021 7 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report ment of blades in the compressor section and in the ment or sub-systems. Since heat rate is measured in turbine section. terms of required fuel heating value input to produce San Juan Units 5 & 6 Steam Turbine Generator inspec- one kilowatt of power, better performance is indicated tions will be performed on the following frequencies: by a lower heat rate. During fiscal year 2013 the Authority’s generation based on fossil fuels achieved a Steam Turbine Generator Valve Inspections will be net heat rate of 10,696 Btu/kWh, which was very close performed every 18 months. The scope includes the to the average for the previous three years. cleaning, NDT, and adjustment of HP stop and control valves, reheat stop valves, and intercept valves. Annual equivalent availability is defined as the percentage of time a generating unit was available, at its Major Inspections of the steam turbine generator are rated capacity, for service in a rolling 12-month performed every 50,000 ESH. period. For this Annual Report that period was the fis- The Authority has significantly reduced the duration cal year ended June 30, 2013. The equivalent availabil- of unscheduled outages of some of its large generating ity of the Authority’s production plant for fiscal year units by maintaining an inventory of critical spare 2013 was 77%, which was consistent with the previ- components. On a long-term basis this practice has ous year. The system availability in the past fiscal year contributed to the improvement of both unit and was constrained by the six month outage of Costa Sur System availability. Refer to the Spare Components Unit 5 for a major overhaul and gas conversion work. section below for a listing of the major spare compo- The Authority’s policy to minimize premium work nents. time for scheduled outages has extended the duration of these outages, which will also lower the equivalent The hydroelectric generating units are inspected on an availability. annual basis and opened every five years. The annual capacity factor of a generating unit is Maintenance expenditures outlined below include based on its total net generation over the last fiscal costs associated with the thermal plants as well as the year divided by the maximum power it could have hydroelectric generating plants. These costs do not produced based on operating every hour of the year. include the cost of the new capitalized units of property, and therefore they do not completely reflect the A summary of annual performance data for each unit Authority’s total cost of maintaining its fixed assets. As is presented on the table to the right: shown in Appendix III, Detail of Operating and Maintenance Expenses, maintenance expenditures for the production plant, including the hydroelectric, for fiscal year 2013 totaled $102.2 million. While maintenance costs were under the budget, the actual expenditures of $71.7 million for operations of the production plant exceeded that budget and erased the potential savings. The Authority’s budget for operation and maintenance of the production plant for fiscal year 2014 is 2.4% more than the actual expenses in fiscal year 2013. The total operation and maintenance budgets for fiscal years 2015 through 2018, respectively, decline 6.5%, increase 1.1%, increase 0.3% and are level for the last two fiscal years. STATUS OF PRODUCTION UNITS The statuses of the Authority’s production units are described in the following sections based on their condition as of the week of June 30, 2013 The table below provides a brief profile of each unit (capacity data, age, annual heat rate, and annual equivalent availability). The annualized heat rate is a measure of a unit’s operating efficiency, which can be affected by its level of dispatch and other factors, such as capacity limitations caused by out of service equip- 8 I 000022 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

AUTHORITY’S PRODUCTION PLANT SUMMARY PERFORMANCE FISCAL YEAR 2013

ANNUAL ANNUAL DEPENDABLE INITIAL HEAT EQUIVALENT DEPENDABLE INITIAL HEAT EQUIVALENT CAPACITY OPERATION RATE AVAILABILITY CAPACITY OPERATION RATE AVAILABILITY STEAM PLANTS COMBINED CYCLE UNITS (continued) Aguirre Unit 1 450 1971 10,197 86% San Juan Unit 5 220 2008 7,959 Aguirre Unit 2 450 1971 11,003 91% Combustion Turbine 5 160 79% Aguirre Station 10,615 89% Steam Turbine 5 60 96% Costa Sur Units 1 & 2 Removed from service 4/30/08 San Juan Unit 6 220 2008 8,665 Costa Sur Unit 3 85 1960 13,198 73% Combustion Turbine 6 160 100% Costa Sur Unit 4 85 1962 12,705 60% Steam Turbine 6 60 50% Costa Sur Unit 5 410 1969 11,280 42% San Juan Combined Cycle Units 8,253 85% Costa Sur Unit 6 410 1972 10,858 70% COMBUSTION TURBINES Costa Sur Station 11,163 58% Cambalache CT Power Blocks Palo Seco Unit 1 85 1959 11,171 88% CCTP 1 82.5 1997 - 0% Palo Seco Unit 2 85 1959 11,147 87% CCTP 2 82.5 1997 12,208 90% Palo Seco Unit 3 216 1967 10,566 60% CCTP 3 82.5 1998 11,750 99% Palo Seco Unit 4 216 1968 10,596 82% Cambalache CTs 11,989 63% Palo Seco Station 10,765 76% Frame 5 GT Power Blocks San Juan Unit 7 100 1964 11,384 72% 9 Blocks of 2 GT’s 378 1971-1973 15,583 88% San Juan Unit 8 100 1964 11,434 88% Mayagüez San Juan Unit 9 100 1966 11,390 81% GT 1 55 2009 9,821 27% San Juan Unit 10 100 1965 11,525 82% GT 2 55 2009 10,625 99% San Juan Station (excl 5 & 6) 11,435 81% GT 3 55 2009 10,411 86%

ANNUAL GT 4 55 2009 10,039 99% DEPENDABLE INITIAL HEAT EQUIVALENT CAPACITY OPERATION RATE AVAILABILITY Mayagüez GTs 10,317 78% COMBINED CYCLE UNITS ANNUAL DEPENDABLE INITIAL HEAT EQUIVALENT Aguirre Combined Cycle CAPACITY OPERATION RATE AVAILABILITY Unit 1 296 1976 THERMAL SYSTEM Combustion Turbine 1-1 50 12,704 99% 4,770 10,696 77%

Combustion Turbine 1-2 50 12,639 99% ANNUAL Combustion Turbine 1-3 50 12,541 64% DEPENDABLE INITIAL SERVICE EQUIVALENT CAPACITY OPERATION FACTOR AVAILABILITY Combustion Turbine 1-4 50 12,923 99% HYDRO Steam Turbine 1 96 64% Total for 21 Aguirre Combined Cycle Hydro Units 100 1929 - 1953 10% 63% Unit 2 296 1975 DIESEL GENERATORS Combustion Turbine 2-1 50 12,470 98% Total for 6 DG sets 8 1980 - 2006 0% 95% Combustion Turbine 2-2 50 12,685 93% Combustion Turbine 2-3 50 13,017 99% Combustion Turbine 2-4 50 12,738 91% Steam Turbine 2 96 88% Aguirre Combined Cycle Plant 10,582 87%

I 000023 9 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Steam-Electric Production Plant The planned CIP expenditures for station services that impact a number of the station’s units are Total Generating Capacity 2,892 MW included in the narrative of the station’s first unit. The generating units within a steam-electric generat- The federal air quality requirements that will restrict ing station are identified by acronyms in the follow- the Authority’s use of residual oil are discussed in the ing manner: Unit No. 1 in the Aguirre Steam Plant is Environmental section and are referred to as MATS, introduced as ASP Unit No. 1; Unit No. 3 at Costa Sur for mercury and air toxics standards. In this section Steam Plant is CSSP Unit No. 3, and so on. The nar- references to the NPDES (national pollutant dis- ratives on the generating units in this section gener- charge elimination system) sections 316 (a) and (b) ally present information by paragraph in the program apply to the Authority use of cooling water; following sequence: these requirements are also addressed in the The first paragraph provides historical and annual- Environmental section ized operational data and summarizes the types and Aguirre Steam Plant number of outages the unit experienced during the fiscal year. In this paragraph and in the following ASP Unit No. 1 (nominal 450 MW) was not in serv- paragraphs turbine sections are identified in the fol- ice on June 30, 2013, because it was in the middle of lowing manner: high-pressure (HP), intermediate- a scheduled environmental outage. During fiscal year pressure (IP), and low-pressure (LP). 2013 the unit was scheduled from service five times; once for a programmed outage and four times for The second paragraph describes the number and maintenance. Scheduled outages kept the unit from types of scheduled outages (major overhaul, environ- available status a total of 38 days in the past fiscal mental outage, or maintenance outage) the unit expe- year. It was forced from service five times for a total of rienced during the fiscal year. The work performed slightly more than nine days; each of the two longest during maintenance outages is described if the outage of these outages was between three and three and a was longer than 24 hours. However, if a unit was half days in duration. The unit accrued approxi- scheduled out of service repeatedly for the same rea- mately three equivalent outage days, attributed to six son, the cause of the maintenance outages and their different events over the course of the year. While in resolution will be noted regardless of the brevity of operation during the past fiscal year this unit gener- the outage. The time assigned to scheduled reserve ated an average net power of 270 MW. Unit 1 was in economic shutdown, in which the unit is available service 7,615 hours during the fiscal year and had an but excluded from dispatch, will also be noted. annual capacity factor of 52%. The third paragraph describes the number of times During the past fiscal year the unit was scheduled and the duration of forced outages and unit limita- from service four times for maintenance before it tions the unit experienced during the fiscal year. The began an environmental outage on June 3, 2013; the cause of the outage or limitation and the action(s) start of the environmental outage was prompted by a taken to return the unit to full service is described fault in the motor drive of boiler feed pump (BFP) 1- when the forced outage or limitation was of more 2 earlier that day. Each of the first three maintenance than 24 hours duration. Repeated outages or limita- outages was two days duration. The first in July tions attributed to the same cause are noted, despite involved repairs to reheater tube leaks, replacement being of less than 24 hours duration. The Authority of one of the boiler circulating water pumps tracks unit limitations as “equivalent outage hours” (BCWP), inspecting the lube systems on all BCWPs, (EOH), which are a measure of the hours the unit’s testing the burner management system (BMS), test- output was restricted below full capacity; for exam- ing the breaker for the motor driven boiler feed ple, operating for 24 hours while the unit output is pump (BFP) and rebalancing the induced draft fan limited to 50% is equivalent to 12 hours of outage for (IDF) 1-2. The second outage addressed repairs to the unit at full capacity. one of the superheater temperature control spray The fourth paragraph notes the next scheduled outlines. In December the third outage was to install ages for the unit that are planned for fiscal year 2014 thermocouples in the superheat and reheat sections or beyond, including the scheduled start of the unit’s of the boiler to collect performance data for firing next major overhaul. The discussion addresses equip- natural gas. The fourth maintenance outage took five ment and system replacements and upgrades that are days at the end of May to repair leaks in the genera- included in the Capital Improvement Program (CIP). tor hydrogen cooling system. 10 I 000024 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Unit 1 was forced from service for one day in gallon retention ponds, filtration equipment and pip- September to repair a service breaker associated with ing will be installed. Much of this scope is eligible for the normal station service transformer (NSST) 1-A. A low cost financing from the Commonwealth. During month later the unit was forced from service for three the last year the Authority completed the refurbish- days to repair a leak in the generator’s stator coolant; ment of one of the station’s fuel storage tanks; work while those repairs were being performed a deaerator on the next tank will begin in fiscal year 2014. The leak was repaired and the condenser gates were replacement of the boiler structural steel is continu- inspected and adjusted. In November the unit was ing on both units. The CIP has also budgeted for the forced out for a day to repair superheater tube leaks. requalification of the HP/IP turbine rotor and of the During this outage the proper operation of the forced generator rotor that was removed during the overhaul draft (FD) fans’ control vanes was verified, and the that was completed in February 2012. The Authority BMS and NSST were inspected. An eight hour forced will receive the replacement for the failed main power outage in June was caused by a fault in the motor transformer at Aguirre during fiscal year 2014. drive of BFP 1-2; this outage was continued as the ASP Unit No. 2 (nominal 450 MW) was in service environmental outage discussed above. The unit had and capable of full output on June 30, 2013. During six episodes of limitations during the fiscal year. fiscal year 2013 the unit was scheduled from service Three occurrences were caused by condenser tubes nine times, these outages kept it from service for a leak, which amounted to one equivalent outage day. total of more than 18 days; there were nine forced An electrical ground fault caused five hours equiva- outages causing the unit to be out eleven days. The lent outage hours in February. In May, problems with unit was in service for 8,046 hours during the fiscal fouling of the regenerative air pre-heater (APH) cou- year. During the past fiscal year Unit 2 generated an pled with a generator hydrogen leak accounted for average net output of 286 MW and recorded an two days equivalent outage hours. This unit was not annual capacity factor of 55%. placed in economy shutdown at any time during fiscal year 2013. The three outages for repairs to the main boiler feedwater control valve (FCV-1) accounted for more than The next major outage for Unit 1 is scheduled to half the year’s scheduled outage hours. Two of these begin in July 2014 and last 20 weeks, with its primary outages were for more than four days: in January the objective being the conversion of the boiler for firing electrical to hydraulic actuator for the control valve natural gas, in addition to heavy oil. The previous was cleaned and refurbished; in May a leak in the major outage was completed in February 2012, dur- control valve was repaired. In February during a two ing which the control systems were upgraded for dual day outage the stem on FCV-1 was replaced. In fuel operation. During the upcoming major outage August a two day outage was scheduled to repair the scope of work will include an environmental out- leaks in the boiler feedwater piping and some boiler age plus boiler modifications to the convection sec- tubes. During the outage, maintenance was per- tion (superheat and reheat) headers and tubes to be formed on the opacity meters, a burner isolation valve compatible with gas firing. Other work will include was replaced, a small steam line leak was repaired, the repairs to thermal insulation, installation of new BMS was tested, and the motor was replaced on the motor control center (MCC) and switchgear for the motor driven boiler feed pump. Most of the balance circulating water pumps. of scheduled outage hours for this unit were for prob- The replacement of equipment and upgrades to sys- lems with the superheater tubes and steam cooled tems during major overhauls are funded through the hangers. The troublesome steam cooled hangers will Capital Improvement Program, CIP. The CIP allocates be replaced as part of the convection section redesign a total of $23.6 million for the two Aguirre steam for the conversion to gas firing. Repairs to the super- units in fiscal year 2014 and $41.8 million the follow- heater section were included in a two day outage in ing year; these amounts include environmental proj- October and two outages in March totaling almost ects at the facility. three days. In March a leak in the superheat tempera- The Authority has a five year program to improve the ture control spray water line was repaired in a one day quality and quantity of its plant water supply. The outage. first phase included installing a reverse osmosis (RO), The longest forced outage resulted from a breaker fail- unit and adding a demineralized water storage tank. ure that tripped the unit from service; repairs were The second phase involves improvements to the completed and the unit returned to service 34 hours water supply from PRASA in which two 2.5 million following the trip. The three other outages were less I 000025 11 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report than half a day in duration. The Authority made omy for approximately 204 days during fiscal year repairs to the generator brush assembly during two 2013. It was in service the equivalent of 83 days dur- brief forced outages, the longer of which was four ing the fiscal year. Unit 3 was scheduled from service hours in duration. At the onset of a transmission sys- twice during fiscal year 2013 for a total of 76 days; the tem event the Authority put the unit in reserve shut- second scheduled outage was environmental. It was down and returned it to service 20 hours later. forced from service once for less than three days. The Unit 2’s next overhaul is an extended environmental unit’s output was limited for the equivalent of almost outage scheduled to begin in November 2013. In addi- 19 days. When operating, Unit 3 generated an aver- tion to the full scope of an environmental outage’s age net output of 54 MW, it had an annual capacity cleaning, inspection and maintenance, the scope of factor of 14%, and was in service 1,987 hours during work will include the repair of the pendant superheat fiscal year 2013. supports, evaluation of the reheat elements and the In August there was a four day maintenance outage replacement of sections of boiler steel. The low pres- for boiler repairs. This unit began an environmental sure feed water heaters will be examined for useful outage on October 1, 2012. The start was delayed life. Thermal insulation will be repaired as necessary. until the completion of the Unit 6 environmental out- In fiscal year 2016 Unit 2 is scheduled for a major age, which had priority. Given the low dispatch of outage. During the overhaul the installation of gas Unit 3, plant labor issues in October and budgetary constraints, the outage schedule was extended to piping, pressure reducing valve stations, and burners avoid overtime. During the outage the condenser was capable of firing natural gas will be completed to sup- cleaned, condenser water gates were adjusted, seals port full gas firing. A new turbine control system will on condenser vacuum equipment were replaced to be installed, as will a new automated voltage regula- reduce leakage, oil leaks on the BFPs were repaired, tion (AVR) system. The HP/IP turbine rotors and the APH elements were cleaned, maintenance was per- turbine control valve will be replaced and the stop formed on the forced draft (FD) and induced draft valve inspected and refurbished. The generator stator (ID) fans, damaged thermal insulation was replaced, will be rewedged and the generator’s rotor will be large motors were cleaned and inspected, breakers rewound. The deaerator will be replaced, as will the and critical electrical equipment, including relays, gates at the water boxes of the auxiliary condenser. were cleaned and inspected. When the unit’s environ- The pipe type high voltage underground cable will be mental outage was complete the unit went into RSH refurbished. status in December. Costa Sur Steam Plant Unit 3 was forced from service once by boiler tube fail- CSSP Unit No. 1 and CSSP Unit No. 2 (both nom- ures. The repair of tube leaks kept the unit from avail- inally 50 MW) these two units, which entered service able status for almost three days in February. The unit in the 1950s, were taken out of service in fiscal year was in service with its capacity limited seven times 2004. During fiscal year 2008 the Authority’s stopped during the fiscal year. The unit’s capacity was limited reporting on the availability of these two units and three times during the fiscal year while its condenser identified systems within these units that provide was cleaned. The unit accrued the remaining equiva- service to one or more of the other Costa Sur units; lent outage days due to unresolved problems with the these units no longer house or support components APHs and boiler casing air infiltration and their or systems that service the balance of the plant. In the impact on the ID fan performance. The Authority has past year the Authority solicited bids for the removal evaluated the cost to restore the APHs and boiler cas- of these units. The bids confirmed that the cost to ing and concluded the expenditure would not be cost demolish these units will be difficult to fund in the effective given the prospective limited service hours current environment of budgetary constraints. The contemplated for this unit in the future, Authority has deferred awarding the demolition work The Authority returned Unit 3 to service on comple- for at least a year. tion of its most recent major overhaul in January CSSP Unit No. 3 (nominal 85 MW) On June 30, 2004. Since then the unit has accumulated less than 2013 this unit was in reserve shutdown for economy; 48,000 service hours towards the 60,000 hour bench- it was available for service with its output limited to mark for its next overhaul. In view of its low dispatch 65 MW due to chronic problems of boiler casing air in the last five years, and the possible retirement or infiltration and with the air preheaters (APH). This greatly reduced service hours of this unit as part of unit was placed in reserve shutdown (RSH) for econ- the Authority’s compliance plan for MATS in the com- 12 I 000026 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report ing years, the Authority has not scheduled Unit 3 for output was limited for the equivalent of 26 days. a major overhaul. The next environmental outage is When operating, Unit 3 generated an average net out- scheduled for March 2014. put of 47 MW, it had an annual capacity factor of The following discussion applies to projects that sup- 14%, and was in service 2,287 hours during fiscal port the entire Costa Sur Steam Plant and will be in year 2013. service after the potential retirement of the two 85 Unit 4’s environmental outage began in late March. As MW units. The CIP includes $5.8 million for these discussed with Unit 3, the schedule for the outage projects in fiscal year 2014. During fiscal year 2013 will be extended to avoid overtime and ensure main- work continued on the turnkey construction of a new tenance personnel are made available for work at reverse osmosis (RO) facility, including the founda- higher priority units, such as Cost Sur Unit 5 and tion, structure and equipment, to improve the quality Aguirre Unit 1. The primary scope of the outage will of make-up water supplied for demineralization. be the cleaning, inspections, tests, and replacements Electrical work continued on the RO facility’s new called for by the Consent Decree with the EPA. In power supply, which is scheduled for completion by addition, the Authority plans to replace some of the mid-year fiscal 2014. The RO facility is scheduled to APH baskets and clean the balance of the baskets and go into service in the third quarter of fiscal year 2014. adjust the APH seals to improve the boiler perform- Improvements to the foam fire protection system of ance. Major power system equipment will be the fuel storage tanks continued in the past year, this inspected, including: FD and ID fans, large pumps work had been delayed by the initial contractor’s and motor drives, and the condenser. Relays will be financial problems. Piping for the foam protection tested and recalibrated as necessary. The replacement system to the reserve fuel tanks is scheduled to begin cable from the generator breaker to the normal sta- commissioning by mid-year fiscal 2014. The main tion service transformer (NSST) will be inspected. fuel tanks dike improvements were completed at the Generator auxiliaries will be inspected, cleaned and end of fiscal year 2013; the Authority plans to com- adjusted as necessary. Components of the distributed plete reinstallation of the recirculation piping within control system and burner management system will six months afterwards. The reserve tank dikes are be selectively tested and adjusted as required for reli- scheduled for completion in the same timeframe. ability. Process piping leaks will be repaired. All of Rehabilitation of the main bridge crane for Units 5 & Unit 4’s RSH hours were accumulated in the six 6 was completed in the past fiscal year. months of October through March, when it was avail- The Authority has developed a program for compli- able but operated only during February. ance with the NPDES 316 (a) and 316 (b) require- The unit was forced from service for the repair of tube ments regarding its cooling water systems impact on leaks in the boiler’s economizer section twice in July the bay. The CIP for the three years 2014 through for a total of six days. In February repairs of boiler 2016 includes $25.0 million for these projects. The tube leaks forced the unit from service twice more for scope of work includes new floating barriers to divert a total of almost eight days. In August the unit was fish at the intake, new higher capacity circulating forced out when heavy rain lead to a detected fault in water pumps and a bypass cooling water system to the generator’s 13kV breaker; the situation was lower the temperature of the water returned to the bay. resolved in two days. In February there was a fault in CSSP Unit No. 4 (nominal 85 MW) On June 30, the bus bars from the generator breaker to the NSST, 2013 this unit was in an environmental outage and leading to a three day outage during which insulated unavailable for service. When the unit was available cable was installed to replace the bus bars. Almost all for service in the past fiscal year its output was lim- of the 26 equivalent outage days accrued during fiscal ited to 65 MW due to chronic problems of boiler cas- year 2013 were attributed to problems with the boiler ing air infiltration and with the air preheaters (APH). air infiltration and APH fouling causing the ID fan to Since Unit 4 is a duplicate of Unit 3 it is not unusual be overloaded and exceed the capacity of its motor. that they have similar problems. This unit was placed Less than one day of equivalent outage time was in reserve shutdown (RSH) for economy for approxi- caused by condenser cleaning. mately 148 days during fiscal year 2013. It was in Unit 4 returned to service on completion of a major service the equivalent of 95 days during the fiscal overhaul in February 2007. Since then the unit has year. Unit 4 was scheduled from service once during been in service approximately 39,000 hours towards fiscal year 2013 for a total of 103 days. It was forced the 60,000 service hour benchmark for its next over- from service six times for a total of 19 days. The unit’s haul. In view of its low dispatch in the last five years, I 000027 13 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report and the possible retirement or greatly reduced service replaced. The turbine lube oil cooler was retubed and hours of this unit as part of the Authority’s compli- the lube oil system was pressure tested. The con- ance plan for MATS in the coming years, the denser was retubed, its waterboxes were blasted clean Authority has not scheduled Unit 4 for a major over- and coated, and the cathodic protection system was haul. The next environmental outage will be sched- recalibrated. The unit is scheduled to return to serv- uled for 18 months after initial return to service from ice early in July, the first month of fiscal year 2014. the current outage to comply with the requirements The first of two maintenance outages was in July to of the Consent Decree. repair a superheater line, it lasted 56 hours. The second scheduled outage was in November to repair a CSSP Unit No. 5 (nominal 410 MW) was offline on break in the reheat temperature control spray water June 30, 2013 nearing the completion of a major line, it took 13 hours. In an unusual event, the unit overhaul. During fiscal year 2013 this unit was sched- was placed in reserve shutdown (RSH) for economy uled from service for 210 days by the Authority. A for 58 hours in July because of a transmission line major overhaul for full gas firing accounted for constraint in the 115 kV system. almost all the outage days and two maintenance outages accounted for an additional three days; the unit The single forced outage occurred in August as result was placed in RSH for two days. One forced outage of heavy rain causing a field ground alarm; it was accounted for less than a day on which the unit was resolved in 15 hours. In the past year there were four unavailable. The unit’s capacity was limited for the instances of limitations that totaled 62 hours; the equivalent of two and half days during the fiscal year. three attributed to condenser cleaning accounted for Unit 5 generated an average net output of 281 MW, 56 of the equivalent outage hours. had an annual capacity factor of 28%, and was in When the unit returns to service it will have com- service 3,641 hours during fiscal year 2013. pleted both a major overhaul and environmental out- Unit 5 was removed from service in the first week of age. The next major overhaul for this unit has not December to begin a major overhaul. The principal been scheduled within the next five years. The next focus was to make modifications to enable the unit to environmental outage is scheduled to begin in operate continuously at full load with all natural gas December 2014. fuel, as well as dual fuel firing of natural gas with the The Authority’s CIP includes $12.3 million in fiscal original design fuel of residual fuel oil; the scope was year 2014 for capital projects at Units 5 & 6. Since similar to that already performed on Unit 6. During these are twin units the scopes of required work are the outage the scope of an environmental outage was similar and their common design promotes sharing also accomplished. The extensive scope of work per- equipment. The CIP includes funds for a replacement formed during the major outage included repairs and boiler feed pump barrel assembly, which is the pump’s modifications to the boiler, overhaul of the main tur- complete internal operational unit. The spare assem- bine generator, and repairs or refurbishments to bly is scheduled for delivery in fiscal year 2015 and major auxiliary systems. The work on the boiler will be compatible with the main feed pumps at Costa included a condition assessment to inform life exten- Sur Units 5 & 6 as well as the Aguirre Units 1 & 2. sion measures for the boiler components, modifica- The CIP also includes funds for replacing the high tions to the convection section headers, tubing, pressure feedwater heaters 6 & 7 of both Units 5 & 6; supports and baffles to accommodate the higher fur- they are scheduled for delivery in fiscal year 2015. nace gas temperature associated with natural gas fir- CSSP Unit No. 6 (nominal 410 MW) was in service ing, thermocouples were installed, sections of the and capable of generating at its rated capacity on June waterwall tubing were replaced, and refurbishing the 30, 2013. In early July the unit began an environmen- gas recirculation fan discharge ductwork. The gas tal outage with an expanded scope to upgrade the burners were cleaned and inspected. Repairs to boiler unit for full natural gas firing. This outage lasted 85 structural steel were performed. The deaerator pump days; subsequently there were two shorter scheduled was refurbished. Welds in the main steam line at the outages totaling three and half days. It was not placed turbine regulating valves were repaired. The main in economy shutdown in the past fiscal year. During turbine HP, IP and LP rotors were overhauled and the the fiscal year 2013 Unit 6 had eight forced outages seals were replaced. The generator stator windings that accumulated to 18 days; the longest outage were rewound and new bushings installed. A Mark VI accounted for half of that total. The unit’s capacity electro- hydraulic control system for the turbine was was limited for the equivalent of less than one and installed. The tubes in feedwater heater 3 were half days during the past fiscal year. Unit 6 generated 14 I 000028 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report an average net output of 304 MW, had an annual caused by a clogged instrument air line to the ID fans, capacity factor of 52%, and was in service 6,204 hours which restricted fan control. The second was to during fiscal year 2013. replace the relief valve on high pressure feedwater This unit began an expanded environmental outage heater 7. In February there were two successive in the first week of July; it returned to service at the forced outages that accounted for ten outage days. The initial event was to repair boiler tubes, which end of September. In addition to performing the man- took less than a day, followed by repairs to welds in dated scope of an environmental outage, the the main steam piping at the turbine control valves – Authority performed a wide range of maintenance these were the same welds that had passed examina- and rehabilitation activities and made extensive boiler tion during the environmental discussed above. The modifications to enable the unit to operate continu- weld failure prompted the Authority to re-evaluate ously at full load with all natural gas fuel, as well as the problem and increase scheduled inspections. The dual fuel firing of natural gas with the original design same area was subsequently repaired in Unit 5 based fuel of residual fuel oil. The work on the boiler on the latest evaluation. In March the unit was forced included a condition assessment to inform life exten- out for more than three days by a ground fault in the sion measures for the boiler components, modifica- auxiliary transformer; a bushing was replaced. In May tions to the convection section headers, tubing, there were three forced outages, two were less than supports and baffles to accommodate the higher fur- one shift, while the longest was more than a day. This nace gas temperature associated with natural gas fir- outage was caused by low lube oil pressure in one of ing, thermocouples were installed, sections of the three boiler circulating water pumps, which tripped waterwall tubing were replaced, and refurbishing the the pump. The unit’s output was limited twice during gas recirculation fan discharge ductwork. The gas the past year for an equivalent total of less than a day burners were cleaned and inspected. The reheat spray and half, first by the inability to fully open a turbine was replaced, the superheat spray control valve was control valve (TCV), which was repaired during the refurbished, safety valves were inspected repaired and extended outage, and secondly by broken condenser tested, air heaters were cleaned and inspected. The tubes causing high conductivity in the condensate. FD, ID, and GRF fans were inspected and maintenance performed. The GRF fan discharge duct was Unit 6 returned from its most recent major overhaul in November 2009. Recognizing that the scope of the refurbished. Flue gas duct expansion joints were extended outage in the past fiscal year included sig- repaired. Non destructive testing (NDT) was per- nificant portions of a major overhaul, the next over- formed on four welds at the main steam turbine con- haul will be scheduled for fiscal year 2018. trol valves; the welds were last repaired in 2009. NDT Environmental outages will be performed within 18 was performed on a superheat line and on the deaer- month intervals. ator. The generator, stator and hydrogen cooling systems were inspected and maintained, as was the Palo Seco Steam Plant generator’s seal oil system and the excitation system. PSSP Unit No. 1 (nominal 85 MW) was in service The Authority replaced the bundle in the turbine and capable of 80 MW, on June 30, 2013. During fis- drive BFP 6-1 & 6-2 and the motor on BFP 6-2. cal year 2013 the unit was scheduled from service Turbine CV 3 was repaired as was the discharge valve twice and was forced from service eight times. The on BCWP 6-3. Station batteries and chargers were Authority completed an environmental outage, which inspected. Electrical equipment, motors, breakers, lasted almost 13 days, on this unit in October 2012. transformers were inspected and the maintenance to The scheduled maintenance outage in June also ensure reliable service was performed. Routine main- lasted 13 days. The eight forced outages kept the unit tenance was carried out on the air compressors and from available status for a total of almost 14 days. The dryers. Damaged or deteriorating thermal insulation unit’s output was limited five times; the Authority was replaced as necessary. At the conclusion of the placed the unit in reserve shutdown for economy outage in September there was a brief outage to once for a total of 13 days. The unit was in service for resolve startup issues. In November a maintenance a total of 7,508 hours during the fiscal year; it gener- outage lasting slightly more than three days was taken ated an average net output of 58 MW while in service to remove stop valve screens installed during the and had an annual capacity factor of 59% for fiscal boiler overhaul. year 2013. The unit was unavailable for service for two days in The environmental outage was performed during the October as the result of two events. The first was first two weeks of October. The scope included the I 000029 15 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report routine activities for an environmental outage, plus pipeline during fiscal years 2014 and 2015. The repairs to the boiler and other systems. Repairs were Authority plans to finish the foam fire protection sys- made to the boiler casing to reduce air infiltration. tem for the fuel storage tanks at Palo Seco during fis- Burners were inspected, cleaned and leaks repaired. cal year 2014, with a total cost of $4 million. Palo Drains valves and traps for the superheater and main Seco Units 1 and 2 entered service more than fifty steam drain valve were refurbished or replaced. The years ago; the Authority has not budgeted for the con- drain valve on the lower boiler drum was replaced. version of these two units to gas firing. The soot blowers were repaired, as was a steam leak PSSP Unit No. 2 (nominal 85 MW) was on line on at the turbine. A leak in the normal station service June 30, 2013, however, its capacity was restricted to transformer (NSST) was repaired. The hydrogen cool- 55 MW because of condenser tube leaks. This unit ers were inspected. The condenser tubes were had two brief scheduled outages for maintenance cleaned. An updated distributed control system during the fiscal year. It was forced from service eight (DCS) was installed to support dual fuel (oil and nat- times; these outages kept the unit from available sta- ural gas) firing. The scheduled maintenance outage in tus for 24 days. This unit’s capacity was limited seven June to repair a leak at a generator hydrogen seal times; it was placed in reserve shutdown for economy lasted almost 13 days. During April the Authority for a total of 42 days. The unit was in service for a placed the unit in RSH for a total of 13 days. total of 6,999 hours during the fiscal year; it gener- In the past fiscal year the unit had the eight forced ated an average net output of 55 MW while in service outages, however one accounted for the bulk of the and had an annual capacity factor of 52% for fiscal 13 total forced out days. At the end of March the unit year 2013. went off line to repair a failed APH main trunnion The first scheduled outage in December lasted less support bearing. The bearing had failed from 40 years than two days, it was to repair boiler tubes. The sec- of service. The plant fabricated two new bearings ond maintenance outage lasted four days in February since replacement parts were not readily available and to repair a generator hydrogen seal leak. Half of the returned the unit to service in 11 days. In January unit’s RSH time of 42 was accumulated during acidic water from Unit 2 contaminated Unit 1 January; the balance of the RSH hours were in through a common condensate header. The unit was October, December, and April. out for almost two days to restore the correct boiler water chemistry. Each of six remaining outages lasted Unit 2 was forced from service in July for more than less than five hours. In the course of the year the unit four days to repair fuel oil line leak and replace pip- output was limited five times for an equivalent total ing at a feedwater valve. In August the unit was forced of four days. out for more than 12 days to repair a generator hydrogen seal leak, this was the longest single outage. In The last major overhaul was completed in April 2008. September the unit was unavailable for less than three Based on the forecasted service hours the next major days to replace the failed main power transformer and overhaul that was originally scheduled for August reserve relay. Rainwater leaking into control boxes 2015 has been indefinitely deferred. The next envi- caused two outages, once each in October and ronmental outage is scheduled for March 2014. November, these lasted less a day in total. In April the There were no capital projects budgeted specifically unit was forced out by condenser tubes leaks for less for Unit 1 during fiscal year 2013 and there are none than four days. Since the condenser tubes were lasted budgeted for fiscal year 2014. The Authority repaired replaced in 2011 and the recent failures do not follow boiler casing, and seals on air heaters to reduce air in a pattern, these premature failures are disconcerting. leakage and improve unit efficiency during times that The Authority will perform additional inspections the unit was in RSH for economy. and testing to search for the root cause of the prob- The CIP for fiscal year 2014 includes $4.4 million for lem. During fiscal year 2013 this unit accrued more the Palo Seco steam units; it is principally directed to than 15 equivalent outage days while in service with support Units 3 & 4. In fiscal year 2012 a second dis- limited capacity; the most frequent cause was con- tillate fuel transfer line between the Palo Seco and San denser tube leaks. Juan Steam Plants went into service. This eight inch Unit 2 is scheduled for its next environmental outage pipe-line increased the amount of distillate fuel read- in October 2013; it returned to service on completion ily available for San Juan Units 5 & 6, thereby easing of its most recent major overhaul in November 2007. a distillate storage constraint at San Juan Station. The The next major overhaul of this unit that was sched- CIP includes funds for refurbishments to the original uled to begin in fiscal year 2014 has been indefinitely 16 I 000030 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report deferred, based on the forecasted service hours. the unit’s APH. The clogged baskets restricted air flow While the Authority will continue with routine main- and the unit taken out of service for cleaning. During tenance, there are no capital projects for the unit bud- restart after the outage the LP turbine exhibited high geted during fiscal year 2014. vibration. Based on the severity of the vibration the PSSP Unit No. 3 (nominal 216 MW) On June 30, unit was scheduled to begin its environmental outage 2013 this unit was out of service while performing an early. Examination of the LP turbine revealed stage L- environmental outage that began on April 29, after a 1 blade movement and collateral damage; bearing 3 five day forced outage. During fiscal year 2013 the was also in poor condition. During the outage NDT unit was scheduled from service seven times; once was performed on the main steam piping to confirm early in the fiscal year for an environmental outage, its condition was satisfactory, although its design is five times for maintenance and again for an environ- the same as that on Unit 4 which had cracks. During mental outage late in the year. Scheduled outages the past fiscal year the unit operated with some limi- accounted for 93 days during the fiscal year. The unit tations principally due to cooling issues with the cir- was forced from service eight times; these unsched- culating water system, these totaled five equivalent uled outages kept it from available status for a total of outage days. 47 days. Unit 3 was placed in reserve shutdown for The schedule for the next environmental outage for eight days during fiscal year 2013. The unit was in Unit 3 will be established after the unit returns to service for a total of 5,215 hours during the fiscal service from the repairs of its LP turbine. The unit year; it generated an average net output of 153 MW returned to service following completion of its most and had an annual capacity factor of 42% for fiscal recent major overhaul in November 2009. Its next year 2013. major overhaul is included in the projected CIP for Unit 3 began an environmental outage in early July fiscal years 2016 and 2017 when it will be coordi- and returned to available status 19 days later. In addi- nated with the modifications to make this unit capa- tion to the mandated scope of an environmental out- ble of firing gas. The CIP for fiscal year 2014 includes age, routine cleaning, inspections and maintenance of funds for repairs to the LP turbine and rehabilitation auxiliary systems were performed and controls were of the boiler. The scope of the boiler work includes installed for dual fuel firing, that is fuel oil and natu- replacing boiler corners and superheat header 5, ral gas. Four days after returning to service there was repair of superheater header 6, and replacing air pre- a maintenance outage of less than one day duration to heater baskets and seals. repair a pipe leak in the superheat spray system. A two PSSP Unit No. 4 (nominal 216 MW) was in service, day maintenance outage in August was taken to rebal- capable of full output on June 30, 2013. This unit was ance the LP turbine. During another two day outage in scheduled from service for a total of 49 days during September boiler leaks were repaired and the APH fiscal year 2013 for three maintenance outages and an cleaned. The second environmental outage began at environmental outage. It spent one day in reserve the end of April following a forced outage that was ini- shutdown for economy. In the past fiscal year the unit tiated by broken refractory clogging the air preheater accumulated six forced outage days from ten inci- baskets and then subsequently when the LP turbine dents, of which four lasted one day each. The unit’s encountered high vibration during restart. Six of the output was limited four times, with the total equiva- eight days in RSH were accumulated in January. lent outages of ten days. The unit was in service for a Two of the eight forced outages were one shift in total of 7,421 hours during the fiscal year; it gener- duration, the other six ranged from one to 18 days in ated an average net output of 144 MW and had an length. In October the unit was forced from service annual capacity factor of 57% for fiscal year 2013. for 18 days to replace LP turbine bearing 1, following The unit was scheduled from service for three and over temperature and vibration. In November the one half days in August to clean the APH baskets; the boiler water pH became too acidic leading to a one deteriorating baskets had become a chronic problem outage to remedy. In December there two outages to that limited the unit’s capability. In November the repair boiler tube leaks, these lasted a total of ten unit began a 33 day environmental outage. In addi- days. Repairs to the furnace waterwall and boiler tion to the required maintenance, cleaning, inspec- tubes forced a two day outage in January. In February tions and tests, the Authority installed an upgrade to there was a fire caused by a ruptured flexible fuel hose the distributed control system (DCS) for dual fuel fir- in one burner corner; repairs to this forced outage ing, that is natural gas in addition to fuel oil. During took 13 days. In April failed duct refractory fell onto the outage the APH baskets and seals were replaced; I 000031 17 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report the normal station service transformer (NSST) was forced outages that kept the unit from service for 30 replaced with one of more capacity. Refurbishing the hours in total. The unit’s operating limitations were two air preheaters increased the boiler’s performance three equivalent outage hours in the past year. During and the unit’s capacity. There was a one day mainte- the 6,326 hours that Unit 7 was in service it generated nance outage in March to replace the seat of a boiler an average net output of 74 MW and had an annual safety valve. In April the unit was out for ten days to capacity factor of 54%. repair the main steam piping at the stop valve and The environmental outage for Unit 7 began late in perform NDT on the opposite line; Unit 3’s similar February. In addition to all the required inspections, piping was also examined. This unit was placed in cleanings and tests required for compliance with the RSH for one day in December. Consent Decree, the scope of work included mainte- Unit 4 was forced from service ten times for a total of nance on turbine control valves, cleaning the boiler six days. There were four one-day forced outages, the feed pump motors, repairing boiler tubes, assessment balance of unscheduled outages were random and of the boiler’s condition, and beginning the installa- brief. In November the unit was forced from service tion of new control wiring from the electrical room to for a day because of low pH in the boiler water, which the control room for regulation of the unit output, to resulted from a failed pH meter. The unit was forced replace old and damaged wiring. The scope of work out for one day in December to repair boiler tube was expanded to include removal of known asbestos leaks and another day to repair an internal fault in the insulation where the metal jacketing was deteriorating motor control center feeding the boiler feed pump. A and beginning to expose the asbestos insulation. All contractor punctured a buried cooling water line in the insulation containing asbestos was abated from the May while extending the fire protection foam piping low pressure feedwater heaters and piping. The unit to a fuel oil tank; the unit was out for one day. The was out of service for 82 days for this extended outage. unit remained in service with limited capacity for a Previously, in August the unit was scheduled out for a total of ten equivalent outage days principally due to four day maintenance outage to repair turbine control fouled APH baskets prior to their replacement. valves and clean the coolers for the turbine’s main oil The next environmental outage is scheduled for April tank. There were two maintenance outages in 2014. The unit returned to service following comple- September for less than two days in total to repair tion of its most recent major overhaul in July 2009. Its leaks in the fuel oil heaters and clean the condensate next major overhaul is included in the projected CIP filters. There was a three and a half day scheduled out- for fiscal years 2016 and 2017 when it will be coordi- age in January to repair leaks in the auxiliary steam nated with the modifications to make this unit capa- piping. There as a brief maintenance outage in mid- ble of firing gas. The CIP for fiscal year 2014 includes June to replace deteriorated wiring at the main turbine funds for a training simulator of the plant, including control valve. Late in June the unit began a mainte- the high voltage gas insulated switchgear interface, nance outage to repair circulating water traveling and rehabilitation of the boiler, during which it will screens; the work extended into early July. receive new boiler corners, burners, valves, and a new burner management system. The CIP includes funds During the past year the unit was forced from service for the rehabilitation of the turbine generator as part four times for a total of 30 hours, of which one out- of the next major overhaul. age accounted for 20 hours. In November the unit was forced out for almost a day to replace a failed tur- San Juan Steam Plant bine lube oil pump motor. Two other forced outages Units 1, 2, 3, & 4 have been retired from service for were to replace a burner control system solenoid and more than three decades. Units 5 & 6 are discussed a failed motor control relay for a boiler feed pump. under the Combined Cycle Plant section. The last forced outage was in February to repair leaking boiler tubes; after an hour this outage transitioned SJSP Unit 7 (nominal 100 MW) was not in service on to the scheduled environmental outage. June 30, 2013; it was out for repairs to the circulating water traveling screens. During fiscal year 2013 Since all the steam plant units at San Juan have expe- scheduled outages kept Unit 7 from service for 100 rienced an increase in trips associated with various days. The longest outage was an environmental and control system’s reliability, the Authority has there were six maintenance outages. Unit 7 was increased its focus on improvements to control sys- placed in reserve shutdown for economy for nine tem maintenance activities, including replacing old hours during the past fiscal year. There were four cables, and operator training. 18 I 000032 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Unit 7’s next scheduled outage will be an environ- wiring with new control wiring in Unit 8 from the mental outage in May 2014. It is scheduled for an electrical room to the control room for regulation of overhaul late in fiscal year 2015. During the overhaul the unit output. Except for those discussed below, the turbine, generator and boiler will be refurbished forced outages were brief and the unit usually to the extent consistent with the unit’s forecasted low returned to service following completion of corrective utilization for compliance with the air regulations action within one shift. In July, October and that will be in effect after that. The unit is not sched- December the unit was out of service for a total of uled for conversion to gas firing. This unit’s last over- almost six days to repair boiler waterwall tube leaks. haul was completed in fiscal year 2008. Unit 8 was forced from service in April for the repair The station’s capital projects in the CIP for the four of a circulating water pump coupling, the repair was steam units for fiscal year 2014 total $4.7 million. completed and the unit was placed in service in one The funds are directed to improvements in the plant day. This unit had no equivalent outage days in the circulating water traveling screens, cathodic protec- past fiscal year. tion of the condensers, revisions to discharge water Unit 8’s next scheduled outage will be an environ- streams for compliance with the NPDES criteria. In mental outage in August 2013. It returned to service addition the Authority will continue its program of on completion of its most recent major overhaul in rehabilitation of the plant fuel storage tanks. November 2010. It is scheduled for a major overhaul SJSP Unit 8 (nominal 100 MW) was online, capable early in fiscal year 2017. During the overhaul the tur- of full output on June 30, 2013. This unit was sched- bine, generator and boiler will be refurbished to the uled from service four times for maintenance during extent consistent with the unit’s forecasted low uti- fiscal year 2013 for a total of 33 days. Unit 8 was lization for compliance with the air regulations that placed in reserve shutdown for economy for four and will be in effect after that. The unit is not scheduled one half days during the past fiscal year. The unit was for conversion to gas firing. forced from service sixteen times, accruing a total of SJSP Unit No. 9 (nominal 100 MW) was online, less than nine forced outage days during the fiscal capable of full output on June 30, 2013. Unit 9 began year. During the 7,644 hours that Unit 8 was in serv- service during the past fiscal year in August; service ice it generated an average net output of 72 MW and was delayed for installation of the refurbished LP tur- had an annual capacity factor of 63%. bine. The unit was scheduled from service seven The unit’s first maintenance outage was in September times for maintenance during fiscal year 2013 for a to clean the condenser waterboxes and tubes; it total of 33 days. Unit 9 was placed in reserve shut- returned to service after three days. In November down for economy for 14 days during the past fiscal there was a 12 day maintenance outage to repair tubes year. The unit was forced from service nine times, in feedwater heater 6 and clean the oil side of the tur- accruing a total of 38 forced outage days during the bine lube oil cooler. In December the unit was sched- fiscal year, including the LP turbine outage that began uled out for five days to replace the bonnet gasket in the year. During the 6,720 hours that Unit 9 was in the main stop valve and to plug tubes in feedwater service it generated an average net output of 72 MW heaters 2 and 3. There was a 14 day outage beginning and had an annual capacity factor of 55%. in late May to repair tubes in feedwater heater 5 and The first two scheduled maintenance outages were in inspect the generator hydrogen cooling system for August to support testing and make adjustments fol- leaks at the bearing and coolers. This unit was placed lowing startup after the LP turbine was restored; these in reserve shutdown for economy for four days in lasted eight days in total. Transport time and refur- November. bishment of the LP turbine in a mainland shop had Three of the forced outages for boiler waterwall taken effectively all of fiscal year 2012, consequently repairs in Unit 8 during the past year accounted for the unit did not begin recovery startup until the first 65% of the total hours lost to forced outages; only one of August. In October the unit was scheduled out for more forced outage lasted a day. Some of the dozen less than a day to repair leaks at various vents and remaining outages were caused by problems with drains. There was a ten day maintenance outage in aging control elements (such as switches, sensors and December to repair boiler waterwall tube leaks. In relays) and control wiring, consequently the March the unit was scheduled out for 12 days to Authority has increased inspections and replacement change a recirculation valve for one of the boiler feed- of suspect components in the plant’s controls. As with water pumps and to correct a hydrogen leak at the Unit 7, the Authority has begun replacing old control generator bearing 5. During a brief maintenance out- I 000033 19 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report age in April a leak in the main steam stop valve seat doned control wiring from cable trays. During this drain was repaired. In May the unit was scheduled out outage the repair fabrications for the trunnion bear- for less than two days to repair tube failures in the pri- ing in APH 10-1 were inspected by NDT and found mary superheater. The unit was placed in reserve shut- satisfactory. Two weeks after returning from the envi- down for economy for 14 days in March and April. ronmental outage the unit was scheduled for a main- The longest forced outage was the continuation of the tenance outage of less than three days to repair tube forced outage caused by the LP turbine blade failure leaks in feedwater heater 5. In January the unit was at the beginning of fiscal year 2012. This outage scheduled out of service for seven days to repair mul- accounted for 32 of the 38 days the unit was forced tiple leaks in the extraction steam piping and to repair out during fiscal year 2013. In August the unit was leaks in the atomizing steam at the burners. The unit forced out of service for two days to repair boiler was placed in reserve shutdown for economy twice waterwall tubes. There was a two day outage in May for a total of one day. to repair tubes in the boiler reheat section. The other The longest forced outage for this unit occurred in forced outages were brief, with four related to various January when high condensate conductivity forced control system problems and one operator error. The the unit from service. Leaking condenser tubes were unit’s only equivalent outage hours were five in plugged; the unit returned to service eight days after February. being removed from service. A variety of control sys- The unit is scheduled for an environmental outage in tem problems accounted for five days of the remain- November 2013. It is scheduled for conversion to gas ing forced outages, many of which were brief. In firing in fiscal year 2017, in conjunction with modi- October the unit tripped three times due to instability fied scope of a major maintenance. The unit’s last in the boiler water level control, the third trip was ini- major maintenance was completed in August 2012. tiated by electric system transients; these outages resulted in two days out of service. The boiler water SJSP Unit No. 10 (nominal 100 MW) was unavail- level controls were adjusted. In November the unit able for service after being forced from service to was tripped once by a false signal of loss of fuel and repair a failed air preheater trunnion thrust bearing then by control problem resulting in high main steam late in June 2013. Repairs are scheduled for comple- temperature. In March the unit was tripped by a fault tion in the first ten days of fiscal year 2014. This unit in the generator lockout caused by a defective cable was scheduled from service three times for mainte- that was replaced. This unit tripped twice in May. The nance and once for an environmental outage; in total first was caused by an electric system rapid load these outages kept it from service for 48 days. The unit was placed in reserve shutdown for economy for change while the unit was operating in regulation, one day. It was forced from service 13 times; as a resulting in a trip from low boiler water level; the result of these outages the unit accrued 16 outage boiler water level controls were retuned. The second days. The unit accrued one equivalent outage day outage in May was caused by operator error inadver- while unable to generate at its nominal capacity. tently energizing a generator protective relay. The last During the past fiscal year Unit 10 was in service forced outage of the past fiscal year was to repair the 7,198 hours, it generated an average net output of 72 trunnion bearing on APH 10-1 at the end of June. The MW and had an annual capacity factor of 58%. fabricated repair parts installed a year earlier did not survive the duty. New replacement bearing compo- In July the unit was scheduled for a maintenance out- nents were being installed at the end of the fiscal year. age to repair the thrust collar on the air preheater (APH) 10-1 trunnion bearing. During the nine and a Unit 10 is scheduled to begin an environmental out- half day outage the plant fabricated and installed age in November 2013. The unit returned from a replacement parts; the unit then returned to service. major overhaul in August 2009 and is scheduled for a A 29 day environmental outage began during the first major overhaul in fiscal year 2016, when the scope of week of September, ending in October. In addition to the work will include gas conversion. all the required inspections, cleanings and tests Combined-Cycle Plant required for compliance with the Consent Decree, the scope of work included the transition to an upgraded Total Generating Capacity 1,032 MW distributed control system and beginning improve- The combined-cycle units located within the Aguirre ments to control wiring from the electrical room to generating complex contain 592 MW and the San the control room for regulation of the unit output, to Juan Units 5 & 6 located within the San Juan Steam replace old and damaged wiring, and removing aban- Plant add 440 MW of dependable combined cycle 20 I 000034 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report capacity to the System. The status of these combined loop cooling system is a major factor limiting the effi- cycle units is discussed below. ciency of the condensers. Periodic cleanings and removal of scale deposits from the condenser tubes Aguirre Combined-Cycle Plant have improved condenser vacuum and each unit’s This combined-cycle plant is comprised of two dupli- heat rate. The Authority plans to refurbish the cool- cate units, both rated at 296 MW. Each unit consists ing towers and replace old vacuum pumps during of four combustion-turbines (CTs), each rated at 50 scheduled overhauls. MW, with individual heat recovery steam generators Recognizing the age of the original combustion tur- (HRSGs), i.e. boilers, powering a single 96 MW steam bines’ technology, the Authority has completed an turbine-generator (ST). This configuration yields a upgrade of the combustion system on all eight of the unit capacity of 296 MW and a total plant capacity of station’s CTs. The upgrade brings the CTs to a modi- 592 MW. These units are primarily used for cycling fied Frame 7EA design, which gives the CT the capa- duty. During fiscal year 2013 the Aguirre Combined bility of operating at a higher combustion Cycle plant recorded a net capacity factor of 6% while temperature, thereby improving its efficiency. generating 1.5% of the total System’s net generation. Additionally the fired hours between combustion The station’s net generation for fiscal year 2013 was inspections, formerly every 4,000 equivalent fired approximately 20% less than the previous fiscal year. hours (EFH), is increased to every 5,300 EFH. This At the end of fiscal year 2013 the steam turbine for increase in EFH has increased the interval between Unit 1 was unavailable, the steam turbine-generator combustion inspections by six or more months. The in Unit 2 was available with significant limitation and replacement of the air inlet filter houses and filter all of the eight CTs were available for service. media was performed concurrent with the CT’s In the following discussion the CTs and steam tur- upgrade. An upgrade of the distributed control sys- bine-generators at this plant are identified by unit and tem (DCS) has been completed in both units. number and with respect to CTs by order within the Following the decision in 2009 to suspend the con- unit, i.e. the second CT in Unit No. 1 is numbered CT struction of a pipeline that would have brought natu- 1-2 and the steam turbine-generator in Unit 2 is iden- ral gas to these CTs the Authority blinded off the tified as ST-2. eight modules that gave the station dual fuel firing capability, put the nozzles in protected storage, and When the four CTs of a unit are in combined service installed climate control air conditioners in each of the associated steam turbine-generator is rated as the modules. The dual fuel modules have not been having a design capacity of 96 MW. Compromised commissioned. During the past year the OEM began steam production caused by exhaust duct seal leakage an evaluation of the turbines for conversion to dry and poor steam condenser performance have com- low NOx combustors firing natural gas. This technol- bined to impose long term limitations on the capacity ogy would increase the potential operating hours on of the steam turbine-generators in both units, how- natural gas by reducing its emissions. The combined ever. In fiscal year 2004 the Authority began a pro- cycle plant will utilize a portion of the natural gas gram to replace the poorly sealing diverters upstream slated for delivery to the Aguirre plant. of each HRSG. The diverters were leaking hot combustion turbine exhaust gases to atmosphere before The Authority’s CIP for fiscal year 2014 includes the hot gases passed through the HRSG. The loss of funds for completion of the overhaul of the steam tur- hot gas reduced the amount of steam generated in bine for Unit 1, rehabilitation of the cooling towers each HRSG to below the quantity required for its and scheduled inspections the combustion turbines associated steam turbine to generate at design condi- CT 2-1 and CT 2-3. The budget for these projects in tions. The last of the eight new design diverters was fiscal year 2014 is $7 million. installed in fiscal year 2012. Since the seals on several ACCP Unit No. 1 was available for service and capa- of the replacement diverters have been in service for ble of generating 200 MW on June 30, 2013. The four eight or nine years they are now in need of replace- CTs that comprise this unit were available for service ment. Consequently, the Authority has begun a sec- at their rated capacity of 50 MW. The steam turbine- ond round of replacing the diverter seals. generator was out of service for the overhaul In addition to the losses attributed to poorly sealing described below. diverters, the two steam turbine- generators are also CT 1-1 was available for service 8,718 hours during limited by inefficient condensing operations. The fiscal year 2013 and was in service 471 hours. This high temperature of the cooling water in the closed CT had two brief maintenance outages and four I 000035 21 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report forced outages in the past year. None of the outages year 2013 the steam turbine had three scheduled out- lasted more than ten hours and none of the causes ages and five forced outages. Four of the forced out- were repeated. The maintenance outage in February ages accumulated 20 hours and all were less than ten lasted eight hours to reconnect the auxiliary trans- hours in duration. A forced outage in January lasted former to CT 1-2. In March there was a seven hour 13 hours to correct faulty condenser hotwell level maintenance outage to replace a breaker at the station control. The first scheduled outage lasted 33 hours in transformer. Both of these maintenance outages October to repair an oil leak in the unit’s main power effected all four CTs in Unit 1, except for CT 1-3 transformer and repair a breaker. In February the which was already out of service in March for gener- steam turbine was scheduled out with the Unit 1 CTs ator rotor repairs. One forced outage of nine hours for for eight hours to reconnect the auxiliary transformer. CT 1-1 was caused by a false high temperature signal Later in February the steam turbine was scheduled from the main power transformer which tripped all out of service to repair hydrogen leaks at the genera- four CTs in Unit 1 in August. tor bushings. In April ST-1 began a scheduled major CT 1-2 was available for service 8,716 hours during inspection. The previous major inspection was com- fiscal year 2013 and was in service 608 hours. In addi- pleted in 2000. The planned work is scheduled to be tion to the two common maintenance outages and completed in the first quarter of the fiscal year 2014. one common forced outage, this CT had three forced During the turbine outage the Authority plans to outages. Two forced outages were initiated by high address maintenance activities, including structural pressure alarm in the exhaust duct, these lasted four repairs to the cooling tower and installing new cool- hours in total. In February the repair of the combus- ing tower fill. The condenser vacuum pumps will be tion turbine cooling fan forced the unit out for 17 refurbished, the condenser will be mechanically and hours. chemically cleaned, the condenser expansion joints CT 1-3 was available for service 5,625 hours during will be replaced and the condenser waterboxes will be fiscal year 2013 and was in service 601 hours. In addi- repaired. The boiler feed pump will be requalified and tion to the common February maintenance outage the circulating water pump impellers will be trimmed and the one common forced outage, this CT had to prevent overloading its motor. The 48” and 60” another scheduled maintenance outage and six forced diameter cooling piping from the cooling tower will outages, one of which extended into a maintenance be inspected. The major inspection of the steam tur- outage. In October CT 1-3 and CT 1-4 were sched- bine will include rewedging the generator stator, uled out of service for five hours to repair an oil leak rewinding the generator rotor, and replacing the LP in their shared main power transformer. Three of the first stage buckets. Electrical inspections of bushings, forced outages totaled seven hours. Repair of a fuel auxiliary components, and transformers are sched- pressure instrument line forced the unit out for 17 uled. hours in October. In December the unit was forced ACCP Unit No. 2 was available for service and capa- out for 15 hours to repair a leak in the instrument ble of generating 265 MW on June 30, 2013. The tubing at the high pressure fuel filter. In February the unit’s four CTs were available for service, each was unit was forced out with a failed restart; the generator capable of generating 50 MW; ST-2, the steam tur- rotor required rewinding. In March the outage was bine-generator was available but limited to 65 MW classified as a maintenance outage. The repaired rotor due to condenser performance issues. returned to the plant and was installed before the end of June. CT 2-1 was available for service 8,584 hours during fiscal year 2013 and was in service 1,109 hours. CT 1-4 was available for service 8,717 hours during During the past fiscal year this CT was scheduled out fiscal year 2013 and was in service 794 hours. This of service four times and forced out once. The one CT had three common scheduled outages as dis- forced outage lasted two hours to replace a defective cussed above for CT 1-3. The CT also shared one control card. In November the CT was scheduled out forced outage with the others in Unit 1. In addition of service 55 hours to repair a faulty flame scanner. CT 1-4 had one forced outage in June lasting 19 hours The following month the CT was out for 100 hours for caused by mis-operation of the generator breaker. In scheduled maintenance on the main power trans- the past fiscal year the hours of operation for CT 1-4 former. In January the CT was out seven hours while were second only to CT 2-1. its auxiliary transformer was reconnected. A corroded ST-1 was available for service 5,703 hours in the past section of fuel piping was replaced in February during fiscal year and was in service 701 hours. During fiscal a six hour outage. 22 I 000036 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

This CT is scheduled for an inspection during fiscal outages and ten forced outages. Two of the scheduled year 2014. CT 2-1 had the best net heat rate of all the outages and one forced outage were to repair circulat- CTs and its service hours were more than any other CT. ing water system piping. In August the steam turbine CT 2-2 was available for service 8,193 hours during was unavailable for 60 hours to repair corrosion / ero- fiscal year 2013 and was in service 689 hours. During sion in the 60” diameter circulating water line at the the past fiscal year this CT was scheduled out of serv- pump discharge. The turbine was forced out of service three times; it was forced out twice. During ice for 67 hours in September to repair a break in the December the CT had a scheduled combustion circulating water piping manhole at the condenser. inspection. The air intake ducts were replaced, as Scheduled repairs in October to the buried circulating were the radiators and fuel oil recirculation line. The water piping and manhole required an additional 740 lube oil tank was cleaned. While the CT was out of hours. Two brief scheduled outages in March accrued service, scheduled maintenance on the main power ten hours in total. In September the steam turbine transformer was performed. In January the CT was was forced out twice more, the first lasted six hours to out seven hours, along with CT 2-1, while its auxil- repair a protective relay for the main power trans- iary transformer was reconnected. In June the CT was former; the second was caused by the turbine control out of service to allow replacement of the expansion valve failing to operate over its full range, this was joint at the HRSG diverter. In September this CT was repaired in 18 hours. The remaining seven forced out- forced out for six hours to replace a defective relay ages were brief and accumulated 20 hours in total. control card. In December it was forced out of service San Juan Combined Cycle for 106 hours to correct problems caused by low level in the lubricating oil system. Units 1, 2, 3, & 4 have been retired from service for more than three decades. Units 7, 8, 9 & 10 are dis- CT 2-3 was available for service 8,709 hours during cussed in the Steam-Electric Production Plant section. fiscal year 2013 and was in service 632 hours. During the past fiscal year this CT was scheduled out of serv- SJ Unit 5 (Dependable Capacity of 220 MW) is a com- ice two times; it was forced out three times. The two bined cycle unit comprised of CT 5, a combustion tur- scheduled outages accrued 11 hours out of service; bine with a capacity of 160 MW and ST 5, a steam one outage was to replace a cable from the NSST and turbine with a capacity of 60 MW. The unit began the other was to replace a radiator. A forced outage in commercial operation in October 2008. During fiscal September lasted six hours to replace a defective relay year 2013 Unit 5’s combustion turbine was available control card. Two events, in October and December, for service 6,909 hours and in service 4,394 hours, added two hours more of forced outage time for the which was a decline of one-third in the service hours balance of the fiscal year. During fiscal year 2014 this from the previous year. When in service the combus- CT is scheduled for a major inspection during which tion turbine’s average net generation was 114 MW. In its compressor section will be replaced with the spare fiscal year 2013 the unit’s steam turbine was in service compressor section. The compressor from CT 2-3 will 4,250 hours of the 8,438 hours that it was available for be sent for refurbishment; it will be stored as a spare service; it generated an average of 40 MW. For fiscal following its return. year 2013 Unit 5 generated 3.2% of the total System power and achieved a net capacity factor of 35%. CT 2-4 was available for service 7,998 hours during fiscal year 2013 and was in service 522 hours. During The Authority has a long term multi-year service the past fiscal year this CT was scheduled out of serv- agreement with the combustion turbine vendor to ice three times; it was forced out twice. In October the provide technical advice and to perform inspections CT was scheduled out for seven hours to replace a of the combustion turbine generators and the steam cable from the NSST, concurrent with CT 2-3. In turbine generators that comprise San Juan Units 5 & February the CT had a combustion inspection. Based 6. The Authority is responsible for the inspection and on prior inspections by a technical advisor, bearing 2 maintenance of auxiliary equipment in these units. A was replaced. This outage lasted 517 hours and the discussion of the frequency of the contracted inspec- CT returned to available status. In March the CT was tions and their scope is found in the Maintenance inspected to verify alignment of the mechanical section above. accessories, this outage lasted eight hours. SJ CT 5 was available for service and capable of gen- ST-2 was available for service 7,837 hours in the past erating 160 MW on June 30, 2013. During fiscal year fiscal year and was in service 1,062 hours. During fis- 2013 this CT was scheduled from service eight times; cal year 2013 the steam turbine had four scheduled these outages kept it from service for a total of 64 I 000037 23 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report days. It was forced from service eight times and The Authority has scheduled CT 5 to come out of accrued a total of 14 forced outage days as a result. service in January 2014 for a Combustion Inspection. CT 5 was in service approximately 183 days and was During this work the generator will be rewedged and in reserve shutdown 105 days. upgrades to the HRSG will be incorporated. The CIP includes funds for purchasing the parts to modify This combustion turbine had six scheduled outages both of the combustion turbines for dual fuel capabil- between July and October, prior to its scheduled ity, firing natural gas or distillate. The conversion Modified Combustion Inspection at 32,000 ESH. The work is scheduled for fiscal year 2017. CT was scheduled out of service twice in July and August for a total of two days to do weld repairs on SJ ST 5 was capable of generating 60 MW on June 30, the generator hydrogen piping. An equal amount of 2013. During fiscal year 2013 it was in service 177 of time was spent in August and September during two the 352 days that it was available for service. In the outages to replace the turbine inlet pre-filters. In past fiscal year this steam turbine was scheduled for September the CT was scheduled out twice for a total maintenance four times during which it accrued four days out of service. Seven unscheduled service inter- of less than a day while the ST 5 circulating water fil- ruptions forced ST 5 to be unavailable for service for ters at the condenser were cleaned. The Authority a total of ten days in the past fiscal year. The replaced the inlet air filters in a two day scheduled Authority placed the steam turbine in reserve shut- outage in June. The operating life of the inlet filters down for economy for 175 days during the fiscal year. and pre-filters has improved since completion of construction of the GIS structure, its associated improve- This steam turbine was scheduled out of service on ments and paving the areas that are adjacent to Units two successive days in September to clean circulating 5 & 6 combustion turbines. The scheduled inspec- water filters at the condenser; the operation took one tion took the combustion turbine out of service from day in total. In March the turbine was scheduled out October to mid-December. The scope of the Modified for 6 hours to replace its hydraulic control system oil Combustion Inspection includes replacement of fuel filters. The last scheduled outage was in June while CT 5 air filters were replaced, which lasted two days. nozzles, combustor baskets, transition pieces, turbine blades in rows 1, 2, 3, and 4, and turbine vane and The longest forced outage was to repair a steam con- ring segments in rows 1 and 2. Inspections of the trol valve dump at the condenser of Unit 5’s steam inlet, compressor, turbine, and exhaust sections of the turbine. This forced ST 5 and CT 5 from service for a combustion turbine were also performed. The return total of almost six days in the beginning of July. to service was delayed by observed high vibration and Repairs to the circulating water piping in March rebalancing the power turbine. forced a steam outage lasting less than three days. Temporary repairs were completed and the ST The longest forced outage for CT 5 was caused by returned to available status; permanent repairs have repairs of a steam control valve dump at the con- been added to the plant’s CIP. The three forced out- denser of Unit 5’s steam turbine. This forced CT 5 ages in May for CT 5 described above had similar from service for a total of almost six days in the begin- consequences on ST 5, which accrued 15 hours ning of July. A leak in the circulating water piping unavailable from these incidents. sprayed sea water on the condensate pump motor SJ Unit 6 (Dependable Capacity of 220 MW) is func- causing the pump and the steam turbine to trip; this tionally a duplicate of the combined cycle Unit 5, with outage lasted nine hours. Additional repairs to the CT 6 being a 160 MW combustion turbine and ST 6 circulating water piping in March forced a steam tur- being a 60 MW steam turbine, ST 6. This unit also bine outage lasting less than three days. Temporary began commercial operation in 2008. On June 30, repairs were completed and the CT returned to avail- 2013 both the combustion turbine and steam turbine able status; permanent repairs have been added to the in Unit 6 were available. During fiscal year 2013 the plant’s CIP. During three forced outages in May the unit’s combustion turbine was available for service CT accrued more than four days out of service as the 8,741 hours and was in service 3,071 hours; while result of incorrect set points or logic in the DCS; these operating it generated a net average of 127 MW. In the stemmed from migration of old files into the updated past fiscal year the steam turbine was available for serv- DCS. These values were checked and corrected. The ice 4,414 hours and was in service 2,183 hours; while two other events that forced CT 5 from available sta- operating it generated a net average of 42 MW. For fis- tus were each resolved in one shift or less and their cal year 2013 Unit 6 generated 2.3% of the System causes were unrelated. power and achieved a net capacity factor of 25%. 24 I 000038 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

SJ CT 6 was available for service and capable of gen- repairs. The repaired rotor returned to the island in erating 160 MW on June 30, 2013. During fiscal year December and the steam turbine was available for 2013 this CT was not scheduled from service; it was service in January. In each of the next four months forced from service six times and accrued a total of 18 there was a single forced outage; these accrued 19 forced outage hours as a result. CT 6 was in service forced outage hours in total. Two of the outages were approximately 128 days and was in reserve shutdown triggered by trips in the combustion turbine. 236 days. During the scheduled outage of CT 6 in August the For CT 6 the average duration of each forced outage generator will be cleaned and inspected. The was three hours; the causes were not repetitive and Authority plans on performing full maintenance and their occurrences were infrequent. In chronological potential upgrades to ST 6 while CT 6 is in its next order, the outages were caused by a failure in the 480 major inspection. During fiscal year 2014 the volt auxiliary electrical system, weld repairs to a fuel Authority has scheduled performance tests to identify line, repair of the master trip relay associated with potential improvements in the steam turbine. new control system components, CT exhaust gas path condition trip, incorrect operation of a 115 kV Combustion-Turbine Power breaker and failure of the air conditioning units for Total Generating Capacity 846 MW the generator exciter room. Cambalache Combustion-Turbine Power Blocks The Authority has scheduled CT 6 to come out of These units were designed to provide rapid response service in August 2013 for a Combustion Inspection. spinning reserve, to ensure System stability in the During the outage the turbine will be inspected to event of the unanticipated loss of a large generating identify the cause of high vibration in bearing #2. The CIP includes funds for purchasing the parts to mod- unit and thereby improve the reliability of service to ify both of the combustion turbines for dual fuel the Authority’s clients. The three combustion tur- capability, firing natural gas or distillate. The conver- bines at Cambalache comprise a plant rated at 247.5 sion work is scheduled for fiscal year 2017. MW. Prior to the return of the four Palo Seco units and the addition of new combined cycle capacity at SJ ST 6 was capable of generating 60 MW on June 30, San Juan in 2009, the Authority had dispatched at 2013. During fiscal year 2013 it was in service 91 of least one unit daily at partial load. During the past the 184 days that it was available for service. This four years, however, the Cambalache units have been steam turbine began the past fiscal year out of service dispatched sparingly and were not in daily service. while waiting for the return and installation of the The low level of dispatch has been driven by the high repaired generator rotor. This repair work plus a sec- cost of Cambalache’s distillate fuel and lower System ond repair cycle for the rotor put the steam turbine demand. Unit 1 was unavailable for service for all of into outages totaling 180 days in fiscal year 2013. fiscal year 2013, consequently the station had an Four short unscheduled service interruptions forced availability factor of 63%, however, the two operable ST 5 from service for less than a day in total. The units averaged 95% availability. The two operable Authority placed the steam turbine in reserve shut- units produced approximately 0.3% of the total down for economy for 93 days during the fiscal year. System’s generation in the past fiscal year. The failure of CT 6’s generator late in fiscal year 2011 Despite their high availability Units 2 and 3 each had caused the Authority to put ST 6 in reserve shut- operated less than 500 hours during the past fiscal down for economy. In fiscal year 2012 it was accruing year. Given the low dispatch rate, it was typical that a days in reserve shutdown for economy when Unit 5’s unit could return from an outage or inspection and be steam turbine generator rotor failed. To return Unit 5’s available, but not be promptly placed in service. To steam turbine to available status, the Authority ensure their reliability the Authority rolls each unit installed the Unit 6 generator rotor into ST 5’s genera- twice weekly. The plant’s air permit allows 780 unit tor. This switch enabled Unit 5 to return to combined starts per year, the equivalent of five starts per unit cycle service in the second quarter of fiscal year 2012. per week; the number of starts in the past fiscal year The generator rotor from ST 5 was sent to a mainland did not approach the allowable number of starts. facility to be refurbished. It was returned to Puerto Rico for installation in ST 6 in August; the steam tur- The Camabalache units are located near Arecibo on bine was ready for service in September. After less the island’s north coast, approximately 40 miles west than 100 hours in operation the rotor failed again. In of the San Juan metropolitan area. As discussed in the October the OEM removed the rotor and sent it for Capacity and Energy Resource Planning section, by I 000039 25 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report the end of fiscal year 2012 the Authority had elected services contract with the OEM to assist with inspec- to pursue alternative off-shore natural gas supply tions and maintenance work. Under this contract the arrangements and stop work on the Via Verde Project OEM provide a full time technical assistant (TA) dur- which would have routed a gas pipeline close to the ing class C inspections and for the replacement parts Cambalache plant. With no firm plans for the supply needed in the hot gas path during class C inspections of natural gas in the vicinity of the plant, the of the combustion turbine. These services have been Authority deferred work to convert the Cambalache extended through the next eight class C inspections. units to dual fuel firing, with the addition of natural The Authority’s employees are responsible for the gas. While the Authority has awarded a contract to installation of the replacement parts. The service the original turbine manufacturer for the conversions agreement also establishes the basis for the provision of the three combustion turbines and the components of additional technical assistance as required for for the conversion are in storage at the station, the scheduled maintenance. Refer to the Maintenance vendor has not been released to install the equipment; section for a description of the scope of a class C this work is no longer included in the CIP. The scope inspection. of the fuel conversion is well defined and each unit While operating with the original blades in service, would be unavailable for approximately 30 days for each CT experienced a failure of compressor section the conversion. Before starting these conversions the blades. The failures were attributed in part to the cor- Authority will need a revised Prevention of rosive effect of airborne contaminants. The Authority Significant Deterioration (PSD) Air Permit. Since it replaced the media in the air intake filter houses and can be prepared relatively quickly, the Authority did the OEM tested a number of sacrificial anti-corro- not submit the PSD application to the EPA during fis- sion/erosion coatings on compressor blades to deter- cal year 2013. mine the most durable coating, with the goal of up to Although the Cambalache combustion turbines oper- 100,000 hours of protective service for the compres- ate in an open cycle, each machine exhausts to a heat sor blades. Based on the OEM’s analysis and recom- recovery steam generator that provides steam for mendation, blades with the special coating were NOx control and power augmentation. The steam installed in the first ten rows of the compressor sec- generators are referred to as a once-through steam tion of Unit 3. With the completion of a class C generator (OTSG) and were specifically designed to inspection of Unit 3 early in fiscal year 2009 the withstand dry operation, i.e. the hot exhaust gases coated blades were installed in all three Cambalache can pass through the steam generator while it is units. The coated blades have been reliable since the empty and producing no steam. The steam from the 2009 installation. With the new blades the Authority OTSGs is made from demineralized water produced no longer performs online compressor section wash- on site in a water treatment facility common to all ings. Compressor section cleanings are now done three units. Raw water is drawn from local wells and twice a year with the unit off line. The OEM has also stored on site in a 1.25 million gallon tank; half of recommended that the Authority synchronize each that capacity is reserved for fire fighting. The water unit to the System and operate it at 50 MW for a treatment facility includes storage of 2.4 million gal- period of a half to one hour each week. lons of demineralized water. During startup and fast The station’s air permit establishes the maximum fir- load ramping, demineralized water is injected into ing rate of distillate fuel oil at 104 gallons per minute the combustion turbines to compensate for insuffi- per unit. Adherence to this fuel oil consumption rate cient steam. impacts the capacity of these units. The amount of Combustion turbine technology has continued to the limitation is subject to ambient air temperature. advance since the development of the turbines Higher air temperatures decrease a unit’s power out- installed in Cambalache and the original equipment put while cooler temperatures, only rarely experi- manufacturer (OEM) has offered improvements that enced in Puerto Rico, increase power output. On June could increase the power of each machine by approx- 30, 2013 the one CT that was available was limited to imately 16 MW. The Authority decided to defer this 77 MW. Typically a CT would be limited to 80 MW capital commitment indefinitely, however the indicating a 2.5 MW limitation. upgrade can be pursued in the future. During fiscal year 2013 work was deferred complet- During fiscal year 2013 Authority personnel per- ing the rehabilitation of the main crane shared by the formed routine inspections on each of the combus- units; this work is approximately 70% complete. tion-turbines. The Authority also uses a technical With the main crane unavailable the Authority has 26 I 000040 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report used rented mobile equipment to service equipment. for this work, which is consistent with the Authority’s The Authority has a program to install fire suppres- current policy on scheduled outages. In addition to the sion systems in all three units. Included in these proj- routine scope of the class C inspection the Authority ects are the replacement of the CO2 fire suppression plans to replace an air cooled auxiliary heat exchanger, system’s controls, replacement of corroded piping, rebuild the exhaust gas duct upstream of the OTSG, and the replacement of components of the foam fire replace the hot gas exhaust housing with that from suppression system. The CO2 system provides pro- Unit 1 and rebuild sections of the roof and doors. tection to the enclosed turbine areas; a foam system The next scheduled inspection for Unit 2 will be a provides fire suppression at the storage tanks. At the class A late in fiscal year 2015, based on the current end fiscal year 2013 the progress on this work was operating level. 60% for Unit 1, 85% for Unit 2 and 10% on Unit 3. For fiscal year 2013 this CT generated an average of The CIP for the Cambalache plant includes $2.5 mil- 69 MW and had an annual capacity factor of 5%. lion for the scheduled “C” inspection of Unit 2 in fiscal year 2014; CIP budgets for fiscal years 2015 – CCTP Unit No. 3 (nominal 82.5 MW) was available 2018 have been deferred pending resolution of the on June 30, 2013 but limited to 77 MW based on ambi- availability of natural gas to the site. ent conditions, as discussed above. During fiscal year 2013 this CT was available 99% of the annual hours, it Please refer to the Maintenance section above for a was in service 452 hours and had no unit trips. full description of what constitutes a class “A”, “B”, and “C” inspection referred to in this section. There were two maintenance outages in fiscal year 2013 that totaled less than two days duration. In CCTP Unit No. 1 (nominal 82.5 MW) was out of February the Authority replaced the battery charger service for all of fiscal year 2013 due to a failure in the for the instrument DC power supply. In April the hot gas path during startup in September 2011. While compressor section was washed off line. the unit was in stable startup, a control system fault The class A inspection scheduled for mid-year fiscal allowed high pressure steam from the OTSG to cause 2013, was rescheduled to the first quarter of fiscal a flameout in the combustor, followed by an year 2014 based on its accumulated equivalent oper- attempted re-ignition; the unburned fuel from the ating hours. Work on the fire suppression system is failed restart subsequently exploded. The explosion scheduled during the class A inspection. The current caused severe damage to the combustor and damaged projections are that Unit 3 may be ready for a class C rows of blades and a bearing in the compressor sec- inspection late in fiscal year 2015, however, the tion. The OEM updated its control cards to prevent Authority plans to defer the class C inspection until recurrence of this fault and these new control cards the equivalent operating hours meet the criteria dis- were installed in all three Cambalache turbines. cussed in the Maintenance section above. The CIP The OEM made an initial inspection of the damaged for fiscal years 2014 through 2018 does not include combustion turbine, confirmed by a more detailed funds for this inspection. inspection and submitted a quotation for repair parts In fiscal year 2013 Unit 3’s average generation was 67 and services. The OEM also provided the recom- MW and its annual capacity factor was 5%. mended procedures for long term preservation of the turbine which the Authority are following, pending Other Combustion-Turbine Power final disposition of the matter. The Authority has a total 26 combustion turbines oper- CCTP Unit No. 2 (nominal 82.5 MW) was unavail- ated in simple cycle, i.e. they do not have exhaust heat able for service on June 30, 2013 while a class C recovery for steam production and power augmenta- inspection was being performed. During fiscal year tion as utilized at Cambalache. The oldest machines 2013 this CT was available 90% of the year, it was in are nine Combustion-Turbine Power Blocks, each with service 496 hours and had no unit trips. two simple cycle machines. In fiscal year 2009 the Authority installed four pairs of aero-derivative com- The only forced outages occurred twice in February bustion turbines at the existing Mayagüez plant; they and were caused by fuel system problems; each out- are configured with each pair driving a common power age lasted less than four hours. generator. In the paragraphs that follow the terms com- Unit 2 began its scheduled class C inspection in late bustion turbine and gas turbine are synonymous; these May and is scheduled to extend 60 days, in part machines are identified as GT, in accordance with the because the Authority will avoid premium time labor Authority’s convention. I 000041 27 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

The original eighteen gas turbine units went into injected to reduce NOx but must not leave deposits in service between 1971 and 1973, are located at seven the turbine. sites and have an aggregate capacity of 378 MW. They All of the Frame 5 gas turbines combined were in are distillate-fired Frame 5 gas turbines, each capable service less than half the hours of the Mayagüez units of generating 21 MW. These old units are in service during fiscal year 2013. Of the Frame 5 GTs that only occasionally. The eight new aero-derivative com- operated in the past fiscal year, the average annual bustion turbines installed in the Mayagüez plant service was less than 100 hours. Consequently these replaced four of the Frame 5 GTs that had been in turbines have accumulated equivalent operating service at the plant since 1972. The new GTs provide hours at a low pace and scheduled inspections have the Authority with 220 MW of capacity at Mayagüez been adjusted. The Authority has continued routine and increased the System’s total simple cycle combus- operation in which engineers perform preventative tion turbine capacity to 598 MW. The Authority has maintenance tests and inspections of GTs at pre- offered two of the redundant Frame 5 GTs from scribed weekly and monthly intervals. Mayagüez for sale and is using two for spare parts. Twenty-one of the GT units were in service during the The Authority’s CIP includes $3.3 million for planned past fiscal year and were available for service on June inspections of the Mayagüez turbines for the five fis- 30, 2013. For fiscal year 2013 the GTs had a com- cal years 2014 through 2018. The CIP also allocates bined equivalent availability of 77%. $12.2 million for three major inspections of GTs in the same period. The scope of planned work includes While the total net generation of the GTs during fis- completion of the program to install new fire suppres- cal year 2013 was almost twice that of the previous sion systems at the combustion turbine sites. year, the GTs contributed only 0.6% of the total System’s net generation. During fiscal year 2013 the Since the Authority relies on the GTs to provide reli- Mayagüez aero-derivative units accounted for 91% of able power it is essential that their diesel starting sys- the net generation of all GTs, which was consistent tems be in good operating condition. As discussed with recent years. The Mayagüez units have a heat below the Authority has repaired or replaced three of rate approximately 30% lower than the older Frame 5 the diesel motors in the last two years in the 18 Frame gas turbines and were dispatched more frequently. 5 GTs. However, due to low System-wide demand and the Jobos 1-1: During fiscal year 2010 the Authority availability of lower cost generating capacity, the completed an intermediate inspection of this GT. As Mayagüez units only achieved a capacity factor of 6% part of the inspection the generator rotor was while recording an EA of 78% for fiscal year 2013. rewound in a mainland shop. While conducting pre- The availability of the Mayagüez units was reduced in acceptance testing late in fiscal year 2010, the gener- the past year because the four turbines comprising ator’s rotor vibrated excessively possibly caused by Units 1 & 2 require replacement and modifications to crossed windings. During fiscal year 2012 the rotor the turbine first stage blade and seals at the OEM was removed, inspected and balanced on site by the mainland shop. The four turbines in Units 3 & 4 had contractor under warranty. In fiscal year 2013 the GT been modified during production. While at the fac- was reassembled. It is scheduled for testing prior to tory the OEM is installing upgrades under warranty. its return to available status in fiscal year 2014. The Authority has rotated one turbine at a time for Daguao 1-2: The Authority completed a major over- the repair; by the end of fiscal year 2013 two were haul of this unit during fiscal year 2012. Its generator upgraded and in service, one was in the OEM’s shop stator was rewound and the generator’s rotor being prepared for shipment back to the island and replaced, a new excitation system and a Mark VI tur- the last was scheduled to be sent to the OEM in early bine control system were installed. The turbine and calendar year 2014. In the past fiscal year Unit 3B’s compressor sections were replaced, as was the ratchet control system software was updated under warranty and torque converter. The GT was repainted. During for improved vibration sensor processing, all the testing the Authority encountered problems with the other Mayagüez units will share the control system turbine control system and with the diesel motor. The updates. The CIP for fiscal year 2014 for the plant diesel motor was replaced and the control system was includes funds for replacing the electrodeionization tuned. An electrical fault in one phase of the station (EDI) water demineralizers that have been unreliable power output delayed returning the unit to available recently. High purity water is required since it is status, which is forecasted for fiscal year 2014. 28 I 000042 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Aguirre 2-2: This GT did not operate in fiscal year discussed below, the Authority’s largest hydroelectric 2013. During preventative maintenance testing the unit, Yauco 1, was dispatched at less than half of its diesel motor failed late in fiscal year 2012. The rated 25 MW capacity during the 1,921 service hours Authority has hired a local firm to repair the diesel that it accrued during the fiscal year. The three units motor, along with one for Palo Seco 1-1. This unit is at Dos Bocas averaged 2,282 hours each in service expected to return to available status at the end of the which was the most of all the Authority’s hydroelec- first quarter of fiscal year 2014. tric plants in fiscal year 2013. Housekeeping at the Palo Seco 1-1: The diesel motor failed in the second hydroelectric stations was uniformly good, logbooks quarter of fiscal year 2012. Since the Palo Seco GT were well maintained, inspections, and operational units have a backup power feed directly from the data were well documented. Preventative mainte- adjacent Palo Seco Steam Plant, the loss of a starting nance activities were completed at specified intervals. diesel is less disruptive for these units than others. During fiscal year 2013 the Authority spent $1.8 mil- Nevertheless the Authority sent the failed diesel to lion on capital rehabilitation improvements of existing the same repair shop as the Aguirre 2-2 motor. This hydroelectric facilities. The Capital Improvement unit is expected to return to available status at the end Program includes $3.2 million for the refurbishment of the first quarter of fiscal year 2014. of hydroelectric units in fiscal year 2014; a portion of Vega Baja 1-1: This unit was unavailable for more the fiscal year 2014 CIP budget will be directed to than half of fiscal year 2013 to replace turbine bear- ongoing work carried forward from the previous fiscal ing number 1. The GT returned to available status for year. From fiscal years 2015 through 2018, however, the last two months of the past fiscal year. the CIP includes significant budget increases for capi- Hydro Production Plant tal projects at hydroelectric facilities. A total of an additional $11 million is allocated for rehabilitation Total Generating Capacity 100 MW projects and $13 million is budgeted for partial dredg- The Authority has 21 hydroelectric generating units ing of the sedimentation in Dos Bocas reservoir which at eleven locations. They have an aggregate capacity feeds the Dos Bocas and Coanillas hydroelectric of 100 MW. The Authority reported that for fiscal year plants. The low level of funding in the past two years 2013 the hydroelectric generating units had an aggre- forced planned inspections to be delayed and gate equivalent availability of 63% and generated increased the potential impact of a critical equipment 90,900 MWh, which was 73% of their net generation failure or unplanned event on the corresponding unit’s during fiscal year 2012 and 61% of their output in fis- availability and capacity. These impacts will be dimin- cal year 2011. The hydroelectric units had an annual- ished as the scheduled improvements are performed. ized service factor of 10% in the past fiscal year. Recent power generation from the hydroelectric The following is a brief discussion of work at hydro- plants has been constrained in part by low rain fall electric plants during during fiscal year 2013: and accumulating sediment that compromises the Caonillas 1-1: With a design capacity of 9 MW the useful capacity of reservoirs. unit experienced excessive turbine vibration when On June 30, 2013 the hydroelectric system was capa- operating above 6 MW. These vibration issues arose ble of generating 43.5 MW. Thirteen of the 21 units following the forced outage of Caonillas 1-2. The were reported as available for service. Two of these, unit was removed from service for inspection in fis- the Patillas units with a combined capacity of less cal 2012. The Authority has identified improve- than two megawatts, have not been in service for ments in the controls which should resolve the more than eight years. Budget constraints have instability. These new controls were ordered for both lengthened the time to repair units and return them Caonillas units in fiscal year 2013. Delivery and to available status; this was most evident following a installation of the improved controls is scheduled forced outage event. Sixteen units were forced from for fiscal year 2014. service; on average each of these units accrued a total of 3,012 forced outage hours during fiscal year 2013, Caonillas 1-2: The Authority found water leaks at the which was 15% less than the previous year. Five of wicket gates of this 9 MW unit in April 2011. Repairs the 21 units were scheduled from service for mainte- were completed before the end of the past fiscal year, nance and scheduled inspections during fiscal year however, the unit did not return to service during fis- 2013. These outages accumulated 4,800 hours, that cal year 2013, pending installation of the new control total was one-tenth of those for the forced outages. As system discussed above. I 000043 29 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Caonillas 2-1: This unit’s 3.5 MW of capacity has not the scope also includes replacement of several turbine been available since Hurricane Georges struck the bearings, and miscellaneous repairs. Once the safe Commonwealth in 1998 and filled Lake Vivi with operation of the bypass control valve is assured, the sedimentation. The current five year CIP does not Authority estimates the repairs can be performed in fund the removal of the sedimentation making a less than a year. return to available status unlikely in the foreseeable Yauco 2-1 & 2-2: Although the Yauco 2-1 was avail- future. able 6,861 hours in the past fiscal year, its generator Garzas 1-1: This 5 MW unit was unavailable for serv- exciter needs repair or replacement. The Authority ice during fiscal year 2013. It was forced from service may defer this work until fiscal year 2016 when it in fiscal year 2012 when the generator’s excitor failed. plans to refurbish both units. The schedule of the The contract award for the replacement excitor was overhaul is dependent on installing new main isola- contested; the procurement process was repeated. tion gate valves for the units. The rewound generator is scheduled to be returned in the first quarter of fiscal year 2014. Diesel Generators The diesel generators installed by the Authority on Rio Blanco 1-1 & 1-2: Each unit is rated to be capa- the islands of Vieques and Culebra provide backup ble of generating 2.5 MW; they both were forced from power in the event of an interruption of the power service in fiscal year 2012 by breaks in the penstock and did not return in the past fiscal year. Penstock delivered by submarine cables to these islands. repairs were completed, but the penstock supports During fiscal year 2012 the Authority began work to had not been tested and accepted by the end of fiscal replace the four diesel generators on Culebra, with a year 2013. While these repairs were in progress the combined capacity of 2.0 MW, with three new 2 MW Authority sent the two generator rotors out for diesels. The first step was the installation of a tempo- inspection, repair, and rebalancing. Both rotors were rary back-up 2 MW diesel generator to provide emer- returned at the end of fiscal year 2013. The units are gency generation while the replacement of the four scheduled to return to available status during the small diesels was in progress. During fiscal year 2013 third quarter of fiscal year 2014, after the integrity of the temporary diesel was in service a total of 14 hours the penstock has been confirmed. and generated 5 MWh. The three 2 MW diesel gener- Yauco 1: With a design capability of 25 MW, this is ators are scheduled to be installed on Culebra in fis- the Authority’s largest hydroelectric unit. The water cal year 2014. Site development, erection of the fuel passing through the unit is used for irrigation. storage tank and other work that will precede the Damage to turbine nozzles, the turbine, and other installation of the new units continued during the mechanical components have limited its capacity to past fiscal year. The new units bring 6 MW of capac- 10-12 MW for the past several years. In preparation ity to Culebra and are scheduled to enter service late for the unit’s overhaul a water bypass system was in fiscal year 2014. Following their commissioning installed during fiscal year 2011. The bypass system’s the Authority will remove the temporary 2 MW diesel discharge lines were modified during fiscal year 2012 generator that provided emergency capacity while the and testing of the bypass system began late in the fis- three new diesel generators were being installed. cal year. During testing the Authority determined that Expenditures on this project were $770,000 in fiscal the bypass control valve was undersized and filed a year 2013, with the budget of $2.5 million in the CIP claim against the design contractor for the replace- to complete. ment of the valve with one of the appropriate capac- On Vieques the Authority’s two 3 MW diesel genera- ity. In fiscal year 2013 the Authority solicited bids for tors were in service a total of 28 hours during the fis- the replacement bypass control valve, but the order is cal year and generated 49 MWh while in service. not scheduled to be placed until fiscal year 2014. The During the last fiscal year the Authority installed schedule for further work on the repairs is subject to replacement control systems for the two diesel gener- the bypass system demonstrating safe operation. Also ators on Vieques. The replacement system has an during fiscal year 2012 the tunnels bringing water to open architecture for ease of troubleshooting which the station were inspected and new trash rakes were will expedite repairs. installed. Trash removal continued in fiscal year 2013. To reduce the overhaul cost the Authority plans FUELS to replace the most severely damaged turbine buckets Since March 2007 the Authority has been burning a with spare buckets that the Authority has in storage, residual fuel oil with a sulfur content not exceeding 30 I 000044 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

0.5% by weight in all of its large steam electric gener- approximately 10,100 BPD of residual fuel oil when ating stations. Following the switch to the low sulfur in service during the past fiscal year. fuel, the two stations on the south side of the island The one-year contract for the supply of residual oil discontinued the use of fuel additives. In fiscal year for the Palo Seco and San Juan Steam Plants that was 2009 the Authority revised its distillate fuel specifica- awarded in January 2013 includes an option for a tion and since making the revision has been burning four-month extension. As described above, prior to a distillate fuel oil with a sulfur content not exceed- awarding this contract the Authority placed a four- ing 0.05% sulfur in its simple and combined cycle month contract with a different supplier for the sup- units. This standardization has helped the Authority ply of residual fuel oil to these plants through the end to realize better pricing and supply options. of calendar year 2012. At the Palo Seco Steam Plant The Authority’s standard practice for the supply of the Authority has the capacity to store 450,000 bar- fuel oil is based on one-year contracts with the option rels of residual oil; at the San Juan Steam Plant there of extending the contract for an additional year or is an additional 138,000 barrels of storage capacity for less. The fuel oil pricing is structured on the com- residual fuel oil. These stations receive a combined modity market with a fixed adjustment to account for total of 250,000 barrels of residual fuel oil every ten delivery to Puerto Rico and the local delivery require- days. Over the course of the full year these stations ments of smaller barges for the plants on the north consumed a combined average total of 22,400 BPD of coast. The Authority selectively employs different residual fuel oil in fiscal year 2013. strategies to minimize the commodity price volatility The Authority’s contract for the supply of natural gas in these contracts; these strategies include fixed price to the Costa Sur Plant is for two years and runs contracts and commodity hedges. through April 30, 2014. The gas is supplied from the During the first two months of fiscal year 2013 resid- gasification facility at the EcoEléctrica cogeneration ual oil was supplied to the Aguirre Steam Plant in plant adjacent to the Costa Sur Plant. The quantity of completion of a six-month contract that went into gas available gas under this contract will meet the effect on the first of March 2012. A four-month con- combined consumption of Units 5 & 6 firing only gas tract to another supplier was effective as of September with a capacity factor of approximately 60%. The 1, 2012 and was in effect until the end of calendar Authority plans to restructure and rebid this contract year 2012. The Authority placed a one-year contract during the next fiscal year. with a third supplier for the supply of residual fuel oil The Authority’s contracts for the supply of distillate for the Aguirre and Costa Sur steam electric units specify that the distillate not contain more than beginning in January 2013. This contract is in effect 0.05% sulfur by weight. In July 2012 the Authority through calendar year 2013, with a four month exten- awarded a contract for the supply of distillate fuel to sion clause. The Authority has three residual oil stor- the Cambalache and Mayagüez gas turbines, and to age tanks at Aguirre, each with a capacity of 260,000 the combined cycle units at Aguirre and San Juan. barrels. The Aguirre units typically receive 70,000 The contract is in effect for one year and does not barrels of residual fuel oil every three days. During include the option for an extension. Distillate fuels fiscal year 2013 these units consumed an average of are delivered to a south coast storage facility and approximately 21,700 barrels per day (BPD) of resid- from there are barged to each of the four stations. ual fuel oil when both were in service. During fiscal year 2011 the CAPECO facility was The contracts for the supply of residual oil to the acquired by Puma Energy Caribe; remediation work Costa Sur Steam Plant followed the same sequence as and restoration of fuel storage capacity is progress- the Aguirre Steam Plant outlined above. Units 5 & 6 ing. A portion of the restored storage capacity for dis- are the dominant production units at Costa Sur and tillate fuel oil could be available to the Authority have been converted to burn natural gas, as discussed during fiscal year 2014. in the Capacity and Energy Resource Planning sec- The Authority has not entered into a long term con- tion. Since the Authority plans that natural gas will be tract for the supply of distillate fuel oil for the the principal fuel in these units their consumption of Authority’s Frame 5 gas turbines. As discussed in the residual fuel oil will be less than previously. The Other Combustion Turbine Power section, these units Authority has 800,000 barrels of residual oil storage are located in nine power blocks around the island capacity at the Costa Sur Steam Plant. The station and they accumulated very few service hours in the receives 250,000 barrels of residual fuel oil every two past year; because of their high production costs they to three weeks. On average these units consumed are forecasted to remain backup power capacity. In I 000045 31 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report practice the fuel consumption at each Frame 5 gas Ⅵ Normal Station Service Transformer adaptable turbine block requires only an infrequent truck deliv- to Costa Sur Units Nos. 5 & 6 and Aguirre Unit ery of distillate fuel oil, which is paid based on the Nos.1 & 2 market price at delivery. Ⅵ Motors and pumps for condensate, boiler circulating, & boiler feed water for Costa Sur Unit BATTERY ENERGY STORAGE SYSTEM Nos. 5 & 6 The 20 MW Battery Energy Storage System, BESS, at Ⅵ Emergency Station Service Transformer for Sabana Llana was commissioned in August 2004. The Aguirre Steam Station plant was designed to provide ready reserve capacity Ⅵ LP turbine rotor for Palo Seco Unit Nos. 3 & 4 in response to a System disturbance and power factor Ⅵ Generator rotor for Palo Seco Unit Nos. 1 & 2 correction when needed. The plant consisted of two Ⅵ Main Power Transformer for Palo Seco Unit units, 1A and 1B, each with more than 3,000 batter- Nos. 3 & 4 ies. Within two years of commissioning a fire in the Ⅵ CT generator rotor for the Aguirre Combined- batteries of one unit forced it from service. The Cycle Plant Authority alleges that design faults with the batteries Ⅵ CT turbine rotor for the Aguirre Combined- caused the fire, consequently neither unit was Cycle Plant returned to service. Ⅵ Main Power Transformer for Aguirre Combined Cycle Station Since 2008 the parties have engaged in complex liti- Ⅵ Two generator rotors for the Frame 5 gas tur- gation with extended discovery. In succession the bat- bines tery manufacturer, its Puerto Rican partner, and most Ⅵ Compressor rotor assembly for a 21 MW gas recently the bonding company have all failed and turbine declared bankruptcy. The litigation continues, how- Ⅵ Service transformer for San Juan Station Units ever, it is unlikely that there will be much recovered. Ⅵ Replacement motors for all large pumps The Authority continues to evaluate the future use for Ⅵ Replacement rotors for FD, ID, & GRF fans the BESS building as well as the salvage value of the more than 6,000 batteries and the associated obsolete Ⅵ Large pumps and vacuum equipment for combined cycle & steam-electric units electronic gear. Ⅵ Burners, soot blowers, air heater components SPARE COMPONENTS for steam-electric units To reduce the unscheduled outages of various units, the Authority has purchased a number of critical PRODUCTION PLANT CAPITAL spare components (see the following list). Using IMPROVEMENTS such spare components during an emergency outage Production plant capital expenditures in fiscal year has expedited a unit’s return to service. Once the 2013 amounted to $148.3 million. As shown in damaged component is repaired, it becomes the Appendix VI, Capital Expenditures, production plant spare. This practice has significantly reduced the capital expenditures in millions are forecasted to be downtime of some of the Authority’s large units $96.4, $115.9, $110.4, $128.5, and $124.7 in fiscal thereby helping to maintain both unit and System years 2014 through 2018 respectively. Details by availability. Budget Item Number for these five fiscal years are The value of these spares is included in the value of shown in Appendix X, Details of Capital the Authority’s inventoried equipment and material Improvement Program. reported in the Inventories and Other Properties sec- ENVIRONMENTAL tion. The Environmental Protection and Quality Assurance The following is a list of major spare components: Division is responsible for assisting the Authority’s Ⅵ HP/IP and LP turbine rotors for Aguirre Unit operating directorates to comply with applicable Nos. 1 & 2 Federal and Commonwealth environmental laws and Ⅵ HP/IP and LP turbine rotors & diaphragms for regulations. These responsibilities include the devel- Costa Sur Unit Nos. 5 & 6 opment of comprehensive programs to achieve the Ⅵ Generator rotor for Aguirre Unit Nos. 1 & 2 Authority’s environmental performance goals. This Ⅵ Motors for FD, ID, GRF, & air heaters for Costa division is charged with obtaining the permits Sur Units Nos. 5 & 6 and Aguirre Unit Nos.1 required to increase or modify any Authority owned & 2 capacity assets prior operating within the System. 32 I 000046 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

In December 2011 the EPA signed regulations under The Authority has focused first on its four largest the Clean Air Act (CAA) that reinforced the steam units for dual fuel conversion—gas in addition Authority’s long standing objective to maximize the to oil—on the south coast. The four steam units in utilization of natural gas in its generating units. the San Juan metropolitan area will be converted after While the Authority’s principal objectives have been the schedule for gas deliveries has been established. fuel diversity and lower cost, natural gas has the ben- With sufficient fuel being available the Authority eficial feature of being a much cleaner fuel than resid- plans to add gas firing capability to the Authority’s ual oil. The EPA regulations established new national two most efficient units, San Juan Units 5 & 6, which emission standards for hazardous air pollutants under are combined cycle units presently burning high cost the mercury and air toxics standards (MATS). These distillate fuel. regulations apply to certain solid waste incinerators and large commercial and industrial boilers; these are During fiscal year 2011 Costa Sur Units 5 & 6 were principally coal and oil fired steam electric generating converted to dual fuel burning capability. units larger than 25 MW. The pollutants subject to Subsequently the boiler internals were modified to regulation are heavy metals, including mercury, support continued full load operation with all gas fir- arsenic, chromium, nickel and acid gases such as ing; this work was performed for Unit 6 during fiscal hydrogen chloride and hydrogen fluoride, sulfur year 2012 and completed for Unit 5 by the end of last dioxide, and also particulate matter and carbon fiscal year. Initial stack testing with dual fuel firing monoxide. If pollution abatement equipment is has demonstrated compliance with MATS criteria. required to reach the mandated emission levels of The natural gas was supplied by EcoEléctrica L.P. via these hazardous air pollutants, the EPA will require a pipeline from its facility adjacent to the Costa Sur the installation of up to the maximum achievable Steam Plant. During fiscal year 2013 EcoEléctrica control technology (MACT), which is based on the installed and made operational two additional regasi- best demonstrated performance technology regard- fiers. Additional regasification production is possible less of cost. The MACT for the Authority’s units could with the installed equipment, however this would consist of various retrofitted emission control sys- require a revised permit from the Federal Energy tems, such as filter baghouses and flue gas desulfur- Regulatory Commission (FERC). ization equipment and associated ancillary systems. During fiscal year 2013 the Authority performed The high cost and restricted space at most steam environmental protection or environmental remedia- plants make this approach impratical. tion projects at each of its major generating stations Since compliance with MATS will be established on and at numerous transmission and distribution facil- the basis of individual units, the Authority’s compli- ities. Environmental projects performed in the last fis- ance strategy is to convert its eight largest oil fired cal year were budgeted at $8.1 million; actual 2013 steam generating units to dual fuel firing, burning nat- expenditures were $2.2 million. The Authority’s five- ural gas fuel in addition to or in place of oil, and to year capital improvement program (CIP) for fiscal restrict the operation of the remaining six steam units year 2014 through 2018 identifies environmental to 8% capacity per year to qualify as limited use liquid projects valued at $62.8 million. During fiscal year oil fired generating units (LULOF). The EPA’s initial 2014 the Authority has budgeted $12.6 million to be schedule for the implementation of MATS requires spent principally on modifications to cooling water compliance by April 2015, with two one-year extensions potentially available. The Authority plans to systems and spill prevention projects. request some extensions since the necessary gas sup- In fiscal year 2014 at the Costa Sur Steam Plant the ply infrastructure will not be in place by April 2015 to Authority has budgeted $5 million to fund section support gas firing at all eight of the steam units. 316 (a) & (b) Clean Water Act projects; these proj- The Authority’s current strategy to expand the supply ects address mitigation of the cooling water intake of natural gas on the island has been an offshore gasi- and discharge systems. The section 316 (a) & (b) fication facility for LNG deliveries near its Aguirre projects are each budgeted to cost $27.1 million over power complex on the southeast coast. During fiscal the five years to completion in fiscal year 2018. These year 2013 the Authority continued its due diligence are the two largest and most costly environmental on the contractual structure of the gas supply infra- projects that the Authority has currently funded. structure and was evaluating alternative supply After several years of work, in fiscal year 2012 the arrangements. Meanwhile the Authority continued to Authority completed the rehabilitation of the station’s develop a coordinated air permit application for both outflow channel walls which was another environ- the off-shore scope in addition to the Aguirre plants. mental project at the Costa Sur Steam Plant. I 000047 33 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

The Authority has pursued a long term program to ment with PCB concentrations greater than 499 ppm refurbish its large fuel oil storage tanks and contain- were removed from service and disposed of years ago. ment dikes at all its steam electric plants. In fiscal In February 1992 the EPA conducted a multimedia year 2013 it has budgeted $1.1 million for the refur- inspection of the Authority’s four steam electric bishment of fuel storage tanks at the San Juan Steam power plants (Aguirre, Costa Sur, Palo Seco, and San Plant. The refurbishment of the fuel storage capacity Juan) and the Monacillos Transmission Center. In at the Aguirre and Costa Sur Steam Plants is sched- December 1992, the EPA identified several instances uled to continue through fiscal year 2017; at a bud- of noncompliance related to air emissions, water dis- geted cost of five million dollars. charges, and to the Spill Prevention Control and Although the Authority has had an active asbestos Countermeasure (SPCC) compliance program at the abatement program for decades some equipment and Authority’s four major steam electric generating sta- facilities still have asbestos containing material which tions and at the Monacillos Transmission Center. has been secured until such time when maintenance These findings led in March 1999 to an agreement activities require its removal; $1.5 million of the envi- between the agencies of the federal government and ronmental program budget for fiscal year 2014 is ded- the Authority, which became the basis for the court icated to asbestos remediation projects. These approved Consent Decree, which while subsequently projects enable the Authority to reduce exposures to amended, is still in effect. The Authority agreed that and release of asbestos containing materials through starting in March 2003 the residual fuel oil burned in encapsulation and removal. The abatement work the steam electric generating stations at Palo Seco and takes place during programmed outages such as the San Juan on the north coast of the island would have major overhaul of a steam unit. a sulfur content not exceeding 0.5% by weight. Since March 2007 the Authority has been burning a fuel oil Since discovery in 1997 of oil contaminated soil at the with a sulfur content not exceeding 0.5% by weight at Palo Seco Steam Plant and in the area of the Palo Seco its south coast steam electric generating stations at Warehouse, the Authority has taken steps to remedi- Aguirre and Costa Sur. For more discussion on this ate contamination from oil with a low concentration refer to the Fuels section of System’s Operations. of PCB that was found in monitoring wells; this work During fiscal year 2007 the Authority completed proj- included investigations and removal of contaminated ects to reduce NOx emissions at steam electric gener- soil. Based on a letter notice from the EPA in ating stations at Palo Seco, Aguirre, and Costa Sur. As December 2011, further investigation and remedia- a condition of receiving certain permits the units at tion activities at this site will not be required pending San Juan Station had previously been modified to submittal of the Authority’s final report and accept- reduce NOx emissions. The Authority and the EPA ance by the EPA. The Authority expects the conclu- monitor compliance with the lower NOx emissions sion from the EPA during fiscal year 2014. requirements. The Authority has a program to comply with Spill During the past fiscal year the Authority reported Prevention Control and Countermeasures (SPCC) achieving compliance in excess of 99% with its in- regulations regarding containment of potential leak- stack opacity requirements and with its Air Quality age from oil containing electrical equipment in its Compliance Program and also achieving the same distribution substations. During fiscal year 2011 the high level of compliance with Clean Water Act regu- Authority completed the installation of signage and lations. At the end of fiscal year 2013 none of the spill response material at all its substations. By the Authority’s generating stations was on probation with end of fiscal year 2013 it had completed the construc- the EPA. There were no events, leaks or spills tion of compliance containment at 42 of the 58 sub- reported during fiscal year 2013 that could lead to stations that need to be upgraded and will complete significant administrative action. the balance during fiscal years 2014 and 2015. The Authority completed a program many years ago COGENERATORS to remove from service and dispose of all of its trans- The Authority has entered into long-term Power formers and electrical equipment with PCB concen- Purchase Operating Agreements (PPOAs) with the trations greater than 499 ppm. Since then the owners of two cogeneration plants in Puerto Rico. Authority has continued with a long standing pro- These plants, one fueled by natural gas (vaporized gram to remove transformers with oil containing PCB LNG) and the other by coal, bring fuel diversity to the between 50-499 ppm. The Authority has cataloged island’s generation mix. The Authority’s PPOAs with less than two hundred remaining transformers for the cogenerators establish the technical and commer- removal. All of the transformers and electrical equip- cial principles under which they mutually operate. 34 I 000048 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

These include the methods for calculating the capac- unloading dock, an LNG storage tank, LNG vaporiz- ity and energy costs of the delivered power, which are ers, and associated facilities. adjusted for a twelve-month period at the start of In accordance with the PPOA each calendar year each calendar year. The plants incorporate emission EcoEléctrica fixes the fuel cost per million BTU for control technologies enabling them to comply with the first 76% of the station’s capacity for that year. For current environmental standards; both plants are capacity in excess of 76% the Authority has been highly efficient. The Authority controls the dispatch charged based upon a spot fuel price that was set by of the cogenerators’ power. During fiscal year 2013 EcoEléctrica at the time the excess capacity was dis- the cogenerators accounted for 33.7% of the System’s patched. From time to time the Authority has agreed net generation, up from the 31.3% in the preceding to purchase power at a capacity above the facility’s fiscal year. (For further discussion of these power nominal rating of 507 MW, however power purchases producers see the Capacity and Energy Resource at these levels has not been formally incorporated in Planning section) the PPOA. The Authority treats its purchased power costs as an The EcoEléctrica plant is located in close proximity to operating expense in its various financial schedules the Costa Sur generating complex and a gas pipeline and recovers them from its clients utilizing a pur- from the EcoEléctrica facility has been installed to the chased power charge similar to its fuel charge. The Costa Sur plant. The Authority has contracted with Authority’s purchased power costs from the cogener- EcoEléctrica to store and regasify LNG in sufficient ators were $735.1 million in fiscal year 2013. The quantity to supply the Authority with natural gas for amount of $755.7 million shown in Appendix III, the Costa Sur Units 5 & 6 which have been converted Detail of Operating and Maintenance Expenses, for to dual fuel capability. To supply sufficient natural gas purchased power includes the renewable energy proj- for itself in addition to Costa Sur Units 5 & 6, ect. For fiscal years 2014 through 2018 the Author- EcoElectrica has installed two new regasifiers in addi- ity’s forecasts of purchased power include the costs tion to the existing two. Of the two regasifiers initially and power contributions from additional renewable commissioned for service, one was needed to regasify energy projects coming on line as discussed in the LNG for EcoElectrica’s two combustion turbines and Capacity and Energy Resource Planning section com- the second regasifier was a full spare backup that ing on line. The Authority, however, projects that the would be used if the other regasifier were not avail- cogenerators will be the largest sources of purchased able. To satisfy the Authority’s need for natural gas at power through fiscal year 2018. As shown in Appen- Costa Sur and have spare capacity, EcoEléctrica dix IV, Annual Net Generation, Fuel Consumption, installed two additional LNG regasification units dur- Fuel and Purchased Power Costs, during the five year ing fiscal year 2012. While EcoEléctrica then had four period beginning with fiscal year 2014 the Authority regasification units, they did not have FERC’s forecasts the costs of cogenerator sourced purchased approval to put more than one additional regasifier power in millions of dollars will be $702.8, $732.5, into continuous service. Under the present FERC per- $759.8, $789.2, and $817.9, respectively. mit the third and fourth regasifiers are spares and a permit revision would be required to increase the EcoEléctrica, L.P. number of LNG ship deliveries per year or the num- On March 21, 2000, the Authority began buying 507 ber of regasifiers in concurrent operation; this sce- MW of power from EcoEléctrica, L.P. in accordance nario could be associated with increased gas with a 22-year PPOA. The plant consists of two com- utilization by EcoEléctrica at its facility or expanded bustion-turbines (CTs) each with a heat recovery gas firing by the Authority at the Costa Sur plant. steam generator (HRSG), i.e., boiler, combining to Based on projected demand and System dispatch, the power a single steam turbine-generator, STG. Each of gas supply from two regasifiers will support both of the CTs is capable of generating 167 MW; the steam the large Costa Sur units firing 100% with gas, in turbine-generator is capable of generating 173 MW. addition to the EcoEléctrica units. If additional power The plant’s waste heat is used in a desalinization plant is required from Costa Sur Units 5 & 6, these units capable of producing 2 million gallons of fresh water can use residual oil in conjunction with natural gas or a day. The water is for its own use and for sale to the as the only fuel, within the limitations of the air per- Puerto Rico Aqueduct and Sewer Authority and the mit criteria. Authority for its use at the Costa Sur plant. The For fiscal year 2013 EcoEléctrica achieved an equiva- EcoEléctrica, L.P. complex also includes an LNG lent availability of 91.4%, considerably lower than the I 000049 35 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report equivalent availability of 95.0% achieved during fiscal hours associated with the forced outages for CT 1 in year 2012, and less the contractual target of 93%, con- August and CT 2 in October discussed above. sequently reducing EcoEléctrica’s capacity payments. In fiscal year 2013 EcoEléctrica provided 17.0% of the Although the plant’s availability dropped during the System’s power, exceeding the Authority’s forecast of past fiscal year, its annual capacity factor increased 15.3% of the System’s net generation during the past from 77% to 80% while generating 4.3% more energy fiscal year. The Authority forecasts that EcoEléctrica, in fiscal year 2013 than in fiscal year 2012. L.P. will generate 17.5% of the power sold by the CT 1 was scheduled out of service twice and forced Authority during fiscal year 2014. out three times during fiscal year 2013. The sched- AES-PR uled outages totaled ten days, while the unscheduled accrued 16 days. The first scheduled outage in AES-PR’s coal-fired steam-electric cogeneration sta- January was for six hours to isolate from the steam tion began commercial operation in November 2002. turbine which was beginning its major inspection. In The owners of the facility have entered into a PPOA February this combustion turbine was out for ten with the Authority to provide 454 MW of power for a days for its scheduled annual maintenance. The com- period of 25 years. The station is made up of two sim- bustion turbine was out of service for two days in ilar units; each is comprised of a circulating fluidized August to resolve high temperature differential in a bed steam generator employing clean coal burning combustor. In September it was unavailable for six technology and a steam turbine-generator capable of hours due to a failure in an LNG pump. The last of generating 227 MW. AES-PR has assured the the three unscheduled outages was for almost 14 days Authority that its units will readily comply with the to resolve problems with the generator stator. new MATS standards, discussed in the Environmental section, which will apply to the coal firing plant CT 2 was scheduled out of service twice and forced beginning in April 2015. During fiscal year 2013 AES- out four times during fiscal year 2013. The scheduled PR produced 16.7% of the power sold by the outages totaled 15 days, while the unscheduled Authority, compared to the 16.1% of the System’s net accrued eight days. The first scheduled outage in generation that the Authority had forecast for AES- January was for seven hours to isolate from the steam PR. The net generation by AES-PR in fiscal year 2013 turbine which was beginning its major inspection. In was 9.5% more than in fiscal year 2012 and more than February this combustion turbine was out for 15 days 4% above its previous five-year average. The for its scheduled annual maintenance. The combus- Authority’s forecast for power from AES-PR for fiscal tion turbine was out of service for seven hours in July years 2014 through 2018 are based on output compa- to repair a loose connection on protective relays for rable to the five-year average of fiscal years 2009 one phase of the generator. In September it was through 2013. For the remaining years of the PPOA’s unavailable for eight hours due to a failure in an LNG pump. In October this combustion turbine was out term, the plant has a target equivalent availability of for four hours to repair damaged fuel tubing at a com- 90%, a target it did not achieve in the five years pre- bustor. The last of the unscheduled outages was for ceding fiscal year 2013. almost seven days to resolve the same problems with During the past fiscal year AES-PR achieved an equiv- the generator stator as applied to CT 1. alent availability of 91.1%, which was a significant ST During fiscal year 2012 this 173 MW steam tur- improvement over the 87.4% in fiscal year 2012. The bine was fully or partially unavailable for approxi- scheduled maintenance in Unit 1 was the longest out- mately 43 days; 32 of which accrued during a age event for the two units in fiscal year 2013. The scheduled major inspection beginning in January. plant achieved a capacity factor of 88.3% for all of fis- During the inspection the steam turbine valves were cal year 2013. The Authority forecasts that AES-PR cleaned and inspected. The turbine internals were will generate 15.8% of the power sold by the refurbished as necessary. Preventative maintenance Authority during fiscal year 2014. was completed on unit auxiliaries. The steam turbine Unit 1: was scheduled out of service once and forced was unavailable for an additional eight days following out four times during fiscal year 2013. The scheduled the inspection to rebalance the rotating elements to maintenance outage lasted 27 days, while the resolve high vibrations. The loss of an LNG pump in unscheduled events accrued 25 days. Unit 1 came out September that took out both combustion turbines of service in March at the start of its scheduled outage forced the steam turbine out for seven hours. The for annual maintenance. During the outage auxil- steam turbine also accrued several equivalent outage iaries were cleaned and inspected, refractory repairs 36 I 000050 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report completed; routine cleanings, inspections, and pre- the 38 kV lines and equipment that serve the whole ventative maintenance was completed on burners, island and also provide the submarine service to the mechanical equipment, coal, limestone, and ash han- islands of Vieques and Culebra. For reference when dling systems. The turbine was opened and inspected. reading this section, a map of the Authority’s 230 kV In August this unit was forced from service for ten and 115 kV transmission systems precedes the days to repair tube failures in the fluidized bed heat Appendices. The map shows the existing transmis- exchanger (FBHE). Two additional heat exchanger sion system with the planned modifications to the failures required repairs in February and March, systems through fiscal year 2018. accruing 12 days unavailable. In September the unit was forced from service for three days to repair the 230 kV System generator exciter system controls. The existing 230 kV system is comprised of 375 circuit miles of transmission lines that encircle and sec- Unit 2: During fiscal year 2012 this 227 MW unit was fully or partially unavailable for approximately 25 tionalize the island. The 230 kV system has two days. There was no scheduled maintenance during the north-south corridors which divide the system into past fiscal year, the next is scheduled for the second three principal loops—the western loop, the central quarter of fiscal year 2014. Three incidents accounted loop and the eastern loop. Each north-south trans- for 97% of the total equivalent lost generation for this mission line originates at a major production facility unit in fiscal year 2013. In October the unit was out of in the south and carries power to the load centers in service for six days to repair the superheater ash regu- the north. lating valve. Repairs to the boiler heat exchanger The central loop has been in operation for many forced the unit out for ten days in December. The years. It was the first 230 kV transmission line to tie unit’s output was limited by 83 MW for nine days the generating plants located on the island’s south beginning in May because of vibration in one of the coast to the load concentrated in the San Juan metro- boiler feed pump hydraulic couplings. Seven other politan area via the Aguas Buenas TC south of the brief incidents accounted for the balance of the limita- city. A parallel 230 kV line in the center of the island tions and outage hours for the past fiscal year. connects the Costa Sur and EcoEléctrica production TRANSMISSION AND DISTRIBUTION units in the south with the Manatí TC located SYSTEMS between San Juan and the Cambalache combustion turbine station on the north coast. The central loop is The Authority’s transmission and distribution sys- joined by east-west transmission lines connecting the tems is comprised of an island-wide network of Costa Sur units with the Aguirre plant in the south power lines, switchyards, substations and electrical and a line on the north side of the island connecting equipment that carry the electrical power from the Manatí to Aguas Buenas via Bayamón. production plants to serve the Authority’s clients. The western loop connects the Costa Sur and On an annual basis the Consulting Engineer’s person- EcoEléctrica production units in the south with the nel visit and note the condition of approximately one- Mayagüez switchyard and production units, on the third of the Authority’s 333 distribution substations west coast of the island, and from there to the north- and 45 transmission centers (TCs). In order to ern cities of Aguadilla, Hatillo, and Arecibo. The observe a representative sample, we select substations western loop was completed in fiscal year 2002 fol- from among the 78 municipalities in the 26 districts lowing the construction of the segment connecting served by the Authority. The scope of the inspections Mayagüez and the Cambalache TC. The loop include a representative portion of the Authority’s increased the transmission system’s capacity and reli- 230/115 kV transmission lines. ability and improved the quality of electric service in TRANSMISSION the north-western municipalities. The Authority’s transmission system consists of high The most recent expansion to the 230 kV transmission voltage power lines, switchyards and electrical equip- system was the eastern loop that went into service ment that carry the electrical power from the produc- during fiscal year 2006. The eastern loop was installed tion plants to the dispersed substations, both the to support the load growth in the northeastern area of Authority’s and privately owned substations, which the island, complete the encirclement of the island by serve the System load. The backbone of the transmis- the 230 kV system, and improve the transmission sys- sion system is the 230/115 kV network that moves tem reliability and capacity by increasing the available bulk power. The balance of the transmission system is transmission lines to move electrical power from the I 000051 37 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report complex of generating plants in the south to major The Authority plans to expand the 230 kV transmis- load centers in the north. The eastern loop runs from sion system with a new line from the Aguirre genera- the large power production units in the southern plain tion complex to Aguas Buenas TC, via an extension in at the Aguirre units in Salinas and the AES plant in the Cayey TC. The transmission line project is sched- Guayama to the eastern part of the island through uled for completion in fiscal year 2017 with expendi- Yabucoa and Río Blanco and terminates in Sabana tures of $889,000. The new line is scheduled to use a Llana, southeast of the San Juan metropolitan area. new right of way to provide an additional measure of Large sections of the new 230 kV eastern transmission redundancy and capacity for moving power from the line run along existing 115 kV rights of way. The proj- critical generation source at Aguirre to the load cen- ect required the relocation of 16 miles of existing 115 ters in the north. This project will coordinate with a kV lines between Río Blanco and Quebrada Negrito. new 230 kV interconnection with the AES cogenera- The scope of the eastern loop project also included the tion plant to the east of the Aguirre complex. expansion of the 230 kV facilities at the Sabana Llana The Authority has a long-term project for expansion and Yabucoa TCs. of the 230 kV transmission system with a new 50 mile The Authority is presently installing two new trans- long line being constructed between the Costa Sur mission line projects and recently completed con- Steam Plant in Guayanilla and the Aguas Buenas TC, struction of a new transmission center to expand the located south of the San Juan urban area load center. 230 kV transmission system. In addition to increasing During the past fiscal year expenditures were $2.2 the system capacity, the new transmission lines will million and the project was approximately 66% com- provide additional redundancy for power flow from plete. The estimated cost of the new line is $110 mil- the major production units in the south, thereby lion, with completion planned in fiscal year 2020. improving operational flexibility for the system and Construction work is scheduled to resume in fiscal support economic dispatch, as well as enhancing year 2018, with a budget of $5.0 million for that year. voltage stability at the major load centers and improv- Consistent with the installation of new transmission ing system reliability. line projects the Authority expanded the capacity of The Authority’s priority project for expansion of the the existing 230 kV switchyards at the Costa Sur 230 kV transmission lines will connect the Costa Sur plant and the Cambalache combustion turbine sta- plant and the EcoEléctrica, L.P. cogeneration plant, tion. The initial expansion at the Costa Sur switch- both of which are on the south side of the island, with yard cost $2.8 million and was placed in service the key switchyard at the Cambalache combustion during fiscal year 2012. The $2.5 million expansion turbine station near Arecibo, which is on the north at Cambalache was completed in fiscal year 2013. In side of the island. The total length of the line will be fiscal years 2015 and 2016 the Authority plans to add 38 miles, however, more than half of its length con- 230 kV switchgear at the Aguirre plant and the AES sists of upgrading existing 115 kV line and structures cogeneration facility, with a total cost of $3.1 million to 230 kV, thereby shortening the construction sched- for the two projects. ule of the 230 kV line from the Costa Sur plant to the 115 kV System transmission center at Dos Bocas. Construction on this section of the new transmission line was com- The 115 kV system is comprised of 727 circuit miles pleted late in fiscal year 2012. During the past fiscal of transmission lines that encircle and cross the inte- year the new line entered service operating at 115 kV rior of the island; the 155 kV system includes 35 cir- until the balance of the route to Cambalache is com- cuit miles of underground lines. The 115 kV system pleted, when the entire line will be interconnected was the first high voltage transmission system put into with the 230 kV system. The section of the new 230 operation on the island to improve the efficiency and kV line between Dos Bocas and Cambalache will uti- reliability of the bulk distribution of power. The 115 lize a new right of way. The Authority’s current CIP kV lines and substations serve all the major load cen- shows spending on this project for completion in fis- ters on the island. Many of the 115 kV transmission cal year 2014 will total $8.1 million; expenditures in line corridors were subsequently used as rights of way fiscal year 2013 were $21.2 million. Completion of for the 230 kV system lines as that system grew. construction has been delayed pending resolution of In its plans for the long term expansion and improve- certain disputed acquisitions of rights of way, however ments to the 115 kV system, the Authority has priori- the Authority has scheduled the end of fiscal year tized a number of new and rehabilitation capital 2014 to finish construction of the new 230 kV line. improvement projects for 115 kV transmission centers 38 I 000052 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report and other components of the system. Given the scope, project is scheduled to be completed in fiscal year complexity, and cost of these projects, their execution 2016. During fiscal years 2014 and 2015 the typically spans many years between initial work and Authority plans to install a new 115/38 kV transmis- placement into service. sion center at the existing Buen Pastor substation in Over the five fiscal years ending in fiscal year 2018, Monacillos. Each of the new transmission centers is the Authority plans to complete two new 115 kV lines. situated where it will help to reinforce the 38 kV sys- The first new line is scheduled to start in fiscal year tem capacity and reliability by providing for addi- 2016 and will feed the planned 115/38 kV Bairoa TC, tional operational contingencies. The budgets for north of Caguas. The work is forecast for completion these three projects total $13.4 million for the fiscal in fiscal year 2017 at a cost of $7.2 million. The next years 2014 through 2016. The CIP for fiscal years project will provide a second feed to the new Hato 2016 through 2018 includes $7.5 million for a new Tejas 115/38 kV TC; the line will run from the Palo 115/38 kV transmission center in Venezuela, near Rio Seco plant to the Hato Tejas TC in Bayamón. This Piedras in San Juan; the project schedule has been project is scheduled to be worked on in fiscal years extended to allow for resolution of local issues. Also 2017 and 2018 with a total cost of $10.6 million. in fiscal years 2016 through 2018 the Authority plans to install second transformers in three 115/38 kV During fiscal year 2013 the newly constructed 150 transmission centers around the island for increased MVA 115/38 kV Hato Tejas transmission center capacity. located in the region of Bayamón was placed in service. Also during the past year the Authority continued The Authority continued work on the 115/38 kV work on two new 115/38 kV transmission centers. switchyard utilizing gas insulated switchgear (GIS) at The first is a new 150 MVA 115/38 kV transmission the San Juan plant during the past fiscal year. The center in Barraquintas. This new transmission center new GIS will provide interconnection with the 38 kV is located between existing transmission centers in system; interconnection to the 115 kV system will be Aguas Buenas and Juana Díaz and is scheduled for via the existing aerial lines. The Authority plans a sec- completion in fiscal year 2014. The Authority plans ond phase of the GIS project to provide a permanent to continue work on a new 150 MVA 115/38 kV interconnect with the underground 115 kV system, transmission center in Bairoa, part of Caguas; the meanwhile that connection can be accomplished on an interim basis if required. The final phase of the GIS project is scheduled for completion in fiscal year 2015. During fiscal year 2014 the Authority plans to install and place into service two sectionalizers near the San Juan metropolitan area; the sectionalizers provide switchable isolation of portions of the 115 kV system, thereby improving operational flexibility to minimize the impact of a local problem. The Authority also plans to extend the busbar at the 115/38 kV Hato Rey TC located in San Juan. The scope of the work includes additional structures and breakers. The Authority plans five more extension projects at 115/38 kV transmission centers from fiscal year 2015 through 2018. The total budget for projects within this scope of work during the five fiscal years ending in 2018 is $12.9 million. To protect the integrity of the transmission system in the San Juan urban area during and following extreme weather events, the Authority installed a 28-mile underground loop of 115 kV transmission cables that link the major components of its System in the metropolitan

I 000053 39 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report area; the scope included four new 115/38 kV GIS sub- Palo Seco and San Juan Steam Plants. The Palo Seco stations, three of which are in operation. The general GIS has been in operation since fiscal year 2009. configuration of the loop is shown on the 115 kV 38 kV System underground system map, which is color coded to demarcate the construction phases. The system can More than half of the Authority’s transmission system be fed through existing transmission centers in the circuit miles operate at 38 kV, which is considered its loop and by the Palo Seco units which are intercon- “sub-transmission” level. While most of the sub- nected with the new transmission loop. The perma- transmission system is near load centers, it is also the nent interconnection of the San Juan units is planned primary transmission system to some of the island’s for fiscal year 2015. most inaccessible interior regions. At the end of fiscal year 2013 there were 1,375 circuit miles operating at The principal function of the underground cable is to 38 kV, including 63 miles of underground line and 55 provide a robust measure of redundancy so that the miles of submarine service to the islands of Vieques Authority will be able to maintain continuity of serv- and Culebra. ice in San Juan’s central business district, perhaps at partial load, in the event overhead lines are lost dur- The 38 kV system feeds approximately two-thirds of ing a hurricane or other disaster. In addition, the the Authority’s distribution substation capacity and cable will be available for back up service to the almost all of the private substations on the island. Authority’s existing overhead transmission lines Given that the 38 kV system is an essential compo- under normal circumstances. The scope of this proj- nent in the Authority’s transmission network, for ect was prompted by the devastation caused by many years the Authority has been pursuing a system Hurricane Georges in fiscal year 1999. The Federal wide rehabilitation program to upgrade the reliability Emergency Management Agency (FEMA) reimbursed and capacity of the 38 kV system. In addition, the the Authority a total of $73 million of the project’s Authority continues to invest in new 38 kV system cost of $195.8 million for the underground cable and lines, switchyards and expansions. Both rehabilitation ductbank scope of work. and new work are included in the Authority’s CIP. The 115 kV underground work was installed in four The scope of the rehabilitation work includes replac- major phases between fiscal years 2002 and 2008. All ing old conductors with new, replacing aging wooden the underground 115 kV cable was fabricated using poles with steel poles and upgrading the system for cross-linked polyethylene (XLPE) cable. While the forecasted local loads. In some areas, certain sections XLPE cable was more expensive than cable insulated of the rehabilitated 38 kV lines have been installed by oil or other chemical compounds it eliminated the along new rights of way to facilitate its installation as possibility of environmental contamination if such well as future maintenance. compounds were to leak into the surrounding terrain. In fiscal year 2013 the Authority expended $12.6 mil- The Authority incorporated provisions in the com- lion on 24 projects of 38 kV line rehabilitation work. pleted work for a future extension of the 115 kV The largest project involved the major reworking of a underground system from the Isla Grande substation line in the island’s interior from Aguas Buenas to to the Covadonga substation in Old San Juan. This Barranquitas, which constituted approximately one underground cable could provide increased load flow half of the total 38 kV line rehabilitation expendi- under normal and emergency conditions to the gov- tures. The project is budgeted for $5.2 million for fis- ernment buildings located in the Old San Juan area. cal year 2014, when it will be completed. Typically 38 The Covadonga 38 kV gas insulated switchgear distri- kV line rehabilitation projects are located throughout bution substation was constructed in a dedicated the island and reflect the extent and age of the 38 kV building that includes space for future 115kV equip- system. During fiscal year 2014 the Authority has ment fed by an underground duct bank. budgeted $15.1 million and plans to work on 25 line The 115 kV underground system includes four new rehabilitation projects in the 38 kV system. substations incorporating gas insulated switchgear, With regard to the 38 kV system transmission lines, providing for compact and enclosed substations. The the Authority’s focus has been on rehabilitating exist- first two new substations at Isla Grande and Martín ing lines. During fiscal year 2014 the Authority has Peña have been in service since fiscal year 2008. budgeted $1.5 million for five projects to extend or These substations were designed to support existing increase the capacity of aerial 38 kV lines; the budget and anticipated load growth in their respective areas. for fiscal years 2015 through 2018 for these expan- The third and fourth substations are located at the sions is $3.7 million, with funding for eight projects in 40 I 000054 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report total. Expenditures in the past fiscal year were approx- Authority’s aerial distribution systems are convention- imately one half million dollars for two projects. ally located along road rights of way, although some The 38 kV system also includes more than 60 miles of are located along rear lot lines or installed along the underground cable in mostly urban areas. In response Authority’s rights of way. To improve operational reli- to civic and business leader requests, the Authority is ability the Authority has a program to relocate high expanding the scope of the underground cable in value lines from rear lot lines to more accessible rights urban and industrial areas. During fiscal year 2013 of way. Service ties from the distribution lines and the Authority expended $2.4 million completing an meters complete the connection to clients’ premises. expansion underground 38 kV project in the Bairoa Selected 13.2 kV Projects sector of Caguas. The Authority has deferred essen- The Authority has a long-standing program in place tially all new 38 kV underground lines during fiscal to upgrade its primary distribution level to 13.2 kV. years 2014 and 2015, but is planning to resume The higher voltage is a cost effective method that selected projects in 2016. The total budget for fiscal enables the existing conductors to carry more load, years 2016 – 2018 is $17.9 million for four projects. while updating older distribution equipment such as Transmission Plant Capital transformers, switches, capacitors and reclosers. In Improvements addition, operating at 13.2 kV reduces line losses and The transmission plant funding forecasts in the allows for longer circuits runs, thereby providing Authority’s current CIP address a wide range of more flexibility in making system interconnections. improvements covering the entire transmission sys- During fiscal year 2013 the Authority expended $3.5 million on the construction and extension of new tem. Transmission capital expenditures in fiscal year overhead 13.2 kV lines in nine projects. During the 2013 amounted to $69.7 million. The Authority is past fiscal year the Authority expended $6.6 million planning to spend $66.3 million on capital improve- for new and extending 13.2 kV feeders at 24 substa- ments to its transmission system in fiscal year 2014: tions. Including the special project in Ponce dis- $26.7 million for expansion projects and $39.7 mil- cussed below, expenditures for underground 13.2 kV lion for rehabilitation projects. The Authority plans to lines during fiscal year 2013 were $15.5 million. spend $329.5 million on its transmission system over the next five fiscal years. These expenditures are dis- The Authority makes on-going investments in new cussed in the Capital Improvement Program section distribution substations to support new or increasing and are itemized in Appendix X, Details of Capital load, such as in areas with increasing residential con- Improvement Program and summarized in Appendix struction, to improve system performance and to VI, Capital Expenditures. replace aging equipment. The Authority has standardized on two sizes of permanent substations based DISTRIBUTION on the transmission system supply voltage. This stan- The Distribution System is the final link between the dardization expedites the engineering, procurement, Authority’s production plants and Transmission and construction cycle, increases flexibility in poten- System and its clients, with the exception of the small tially utilizing equipment as spares, and provides a number of commercial and industrial clients who cost effective installed capacity margin for load purchase power at the transmission level. The growth. In situations where the Authority needs addi- Distribution System includes Authority owned sub- tional substation capacity on an interim basis or with stations that reduce the power from transmission short lead times, the Authority installs temporary voltage to the level at which it is locally distributed; substations that are standardized unitized metal clad the three voltage levels serving most clients are 4.16 equipment, which can be relocated as required. kV, 8.32 kV and 13.2 kV, with a small portion distrib- During fiscal year 2013 the Authority completed the uted at 7.2 kV. At the end of fiscal year 2013 there construction of new 13.2 kV substations at Río were approximately 31,550 circuit miles in the distri- Bayamón II and Hato Tejas, both in the Bayamón bution system. The circuit miles operating at 13.2 kV region, and completed work to increase the capacity and 8.32 kV are each approximately 24% of the total of substations at Cayey in Caguas and at Palmer TC distribution circuit miles, with 4.16 kV lines account- in Carolina. In the past fiscal year work was coming for most of the balance. pleted to install an additional transformer at the While most of the Authority’s primary distribution Grana II substation in San Juan. All are scheduled to systems are overhead, almost 6% of the Authority’s enter service early in fiscal year 2014. During fiscal distribution circuit miles are underground. The years 2014 and 2015 the Authority plans to construct I 000055 41 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report five new 13.2 kV substations. These substations will The FDIR system has the capability to isolate faults be at Sea Land (Caparra) in Guaynabo, at Charco and restore service in response to multiple contingen- Hondo in Arecibo, at Añasco in the west coastal area cies, such as might happen during severely inclement of the island, at Morovis in the central region west of weather. The Authority has also installed reclosers for San Juan, and at Las Piedras in the eastern central fault detection and isolation without automatic load region. The Authority has allocated a total budget of transfer, however these systems include remote com- $27.4 million for 12 new substation projects during munication to facilitate manual response. The the five years through fiscal year 2018; $5.8 million is Authority’s CIP budget for the five fiscal years budgeted for increasing the capacity of existing sub- through 2018 is $4.0 million for the installation of stations during the same five years. distribution automation equipment. In compliance with a settlement with the municipal- The Authority has an on-going program to comply ity of Ponce, the Authority agreed to improve the with recent EPA’s requirements on Spill Prevention electric distribution system in the historic district of Control and Countermeasures (SPCC) Plans pertain- Ponce. The project involves upgrading the existing ing to their electrical distribution system equipment overhead 4.16 kV system to a 13.2 kV underground containing oil. The Authority’s SPCC Plan includes distribution system. The Authority has taken the lead spill response material and notification signage at all in the underground work in the historic district substations. This scope of the plan was fully imple- which requires coordination with the telephone com- mented during fiscal year 2012. In addition, the pany and the water and sewer utility who are also SPCC Plan has identified 58 substations in which concurrently relocating buried utilities in the same spill containment dikes will be installed under trans- district. The scope of the entire project is being exe- formers and oil containing circuit breakers. By the cuted in four sequential phases to minimize disrup- end of fiscal year 2013 the Authority had installed the tions to the neighborhoods and local traffic. The first majority of these modifications at 42 substations. two phases of the work have been completed and Authority plans to complete all the required SPCC placed in service. The third phase of work began in works modifications at the affected substations in fis- fiscal year 2011 and was essentially completed by the cal year 2015. end of the past fiscal year; expenditures during the past fiscal year were $8.9 million. Work on the final The Authority owns 22 portable distribution substa- phase is targeted to begin late in fiscal year 2014 or tions that enable them to perform substation mainte- early the next fiscal year, with a duration of four nance with minimal or no interruption of service, to years. The CIP budget for this project through 2018 speed recovery after a substation failure, and for is $12.9 million. enhanced operation during line clearance constraints. Other Distribution Work The portable equipment ranges in size from 10 MVA to 44 MVA at 38 kV and 115 kV, and includes two Consistent with the wide use of lower voltage distri- capacitor banks at 38 kV 18 MVAR. bution lines and equipment, during fiscal year 2013 the Authority expended $34.2 million on improve- Distribution Plant Capital Improvements ments to the distribution system and overhead distri- The Authority’s capital expenditures on the distribu- bution lines at 4.16 kV – 8.32 kV. Expenditures on tion system were $127.9 million in fiscal year 2013. improvements to underground distribution lines The scope of these expenditures included $16.0 mil- operating at 4.16 kV – 8.32 kV totaled $10.3 million lion in the past year for the remote read meters pro- in fiscal year 2013; these improvements typically are gram discussed below. The Authority is planning to in urban areas. spend $99.9 million on capital improvements for its To improve client service and reduce operating costs, distribution system in fiscal year 2014: $18.8 million the Authority is expanding the installation of various for expansion projects and $81.1 million for rehabili- distribution automation equipment systems to tation projects and other distribution expenses, such respond to line faults. The fault detection, isolation as remote read meters, line transformers, breakers, and restoration (FDIR) system selected for priority sectionalizers, and reclosers. The remote read client distribution lines will automatically isolate the fault meters discussed below have been a long term capital and transfer loads to an alternative feeder to minimize commitment by the Authority and they account for the duration and number of clients impacted by the 12% of the Distribution CIP budget for fiscal year fault; the system provides real time information to the 2014. The Authority plans to spend $465.1 million Authority’s operation center on its actions and status. on its distribution system capital improvements over 42 I 000056 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report the next five fiscal years; this is 30% of the total exceeded the budget, it equaled the average expendi- planned capital expenditures over that period. tures for the most recent three fiscal years 2011 MAINTENANCE through 2013. The budget for total operations and maintenance of the Transmission and Distribution The Authority generally maintains its transmission systems for fiscal year 2014 is $271.0 million, which and distribution equipment using a time-based sys- is 2.2% less than the previous year’s actual expenses; tem. In some cases the maintenance intervals have the differences between the budget and the previous been modified to meet the challenging tropical envi- years’ actual expenses are principally reductions in ronment or relevant operating experience. As an operations costs. The maintenance budget for the five example of routine periodic inspections, the fiscal years 2014 through 2018 for the Transmission Authority performs infrared inspections of all substa- and Distribution systems through 2018 is forecasted tions and switchyards twice a year. The infrared to be 4.9% above the actual expenditures of fiscal year inspections are used to identify “hotspots” which are 2013. The Authority’s total Transmission and faulty connections that are overheating and are likely candidates for failure. In addition to performing elec- Distribution operation and maintenance budgets for trical and mechanical testing, the equipment is the four fiscal years 2015 through 2018 are forecasted painted on a periodic basis to help prevent corrosion. to decrease 7.4% in fiscal year 2015, increase 1.1% and 0.3% in 2016 and 2017 respectively and remain The Authority’s inspection and maintenance program unchanged in 2018. for high voltage electrical equipment is based on the criticality of the equipment’s service, with the scope Transmission system maintenance expenses, shown in and frequency of the inspections and maintenance Appendix III, Detail of Operating and Maintenance guided by the manufacturer’s standard recommenda- Expenses, totaled $30.0 million in fiscal year 2013; the tions. Main power, transmission and substation trans- expenditures were 2.7% less than budget. For fiscal formers are inspected on a four year cycle. The year 2014 the Authority has reduced the annual trans- Authority takes oil samples annually from all high mission maintenance budget to $17.4 million, with voltage transformers in an effort to identify internal the five-year average through fiscal year 2018 being deterioration before it leads to failure. The Authority’s $17.1 million. In these same time frames the budget oil analysis program relies on a recognized industry for transmission system operations increased from the consultant’s recommendations, coupled with its own actual expenses of $19.3 million to a budget of $26.1 operating and maintenance experience, to perform million; the five-year average through fiscal year 2018 more frequent monitoring or eventually repair. As is $25.0 million for transmission operations. Activities many major transformers approach their design serv- included in the maintenance budget include funding ice life this program has become increasingly impor- for tower maintenance, tree trimming, insulator tant in maintaining the system operating reliability. replacement, helicopter patrolling of transmission The inspection and testing frequency for other high lines, and right of way management. The costs associ- voltage equipment in the maintenance program ated with the transmission system portion of substa- include: gas circuit breakers—six years; oil circuit and tion maintenance are also included in these budgeted vacuum circuit breakers—four years; and protective expenditures. relays—no more than three years for calibration and Distribution system maintenance expenses, also testing. Relays protecting major equipment, such as shown in Appendix III, Detail of Operating and transmission transformers, are tested more frequently Maintenance Expenses, totaled $74.7 million in fiscal based on when the equipment is out of service. year 2013; the expenditures were 18.6% over budget. In response to sporadic theft of aluminum structural For fiscal year 2014 the Authority has increased the bracing members for their scrap metal value from annual distribution maintenance budget to $94.9 mil- transmission towers in past years, the Authority has lion, with the five-year average through fiscal year increased inspections of transmission towers using 2018 being $92.8 million. In these same time frames both the helicopter patrols and inspections from the the budget for distribution system operations ground. Any deficiencies identified in these inspec- decreased from the actual expenses of $153.0 million tions are repaired on a priority basis. to a budget of $132.6 million; the five-year average In fiscal year 2013 the total operation and mainte- through fiscal year 2018 is $126.6 million for distri- nance expenses for the Transmission and Distribution bution operations. The distribution maintenance systems was $277.1 million. While this level expenditures include distribution system related I 000057 43 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report expenditures similar to those described under trans- notorious blackouts are caused by the transmission mission system maintenance expenses. systems, most interruptions to client service are TRANSMISSION AND DISTRIBUTION caused by problems in the local distribution system. SYSTEMS RELIABILITY Two industry criteria generally accepted for measur- ing an electric system’s reliability of service to its The principal guideline in the operation of a utility clients are the following: electric system is to continuously balance the real time demand for electricity (the load) and the simultaneous System Average Interruption Duration Index production of power while maintaining regulation of (SAIDI)- The average duration of sustained service the system’s voltage and frequency. The electric system interruptions per client occurring during the preced- is designed to meet this requirement across a wide ing twelve-month period. It is the average time a typ- range of operating conditions, which include loss of ical client was without power over a rolling an operating transmission line or other key system twelve-month period. The average is determined by component. Analyses of these design conditions estab- dividing the sum of the durations of all sustained lish the required redundancies in the system and oper- client interruptions by the total number of clients ating criteria. Consistent with industry practice, the served. The Authority reports its SAIDI duration sta- Authority has designed the entire transmission system tistics in hours. to maintain continuous operation with at least one System Average Interruption Frequency Index contingency event (loss of an operating component) (SAIFI)- The average frequency of sustained inter- and two contingencies for critical lines that move ruptions per client occurring during the preceding power from the major production plants. twelve-month period. It is calculated by dividing the Reliability Indices total number of sustained client interruptions by the total number of clients served. Reliability standards have been in place within the North American electric utility industry for many SAIDI and SAIFI indices take into account only sus- decades. Following recent wide spread power losses tained outages; they do not reflect momentary inter- in America, such as the Northeast blackout in August ruptions or voltage irregularities, which can affect 2003, the electric power industry and its regulators sensitive electronic equipment. For both SAIDI and have reaffirmed the importance of reliable service to SAIFI, lower index values indicate better client serv- support the requirements of the economy. This was ice, i.e. shorter and fewer service interruptions. reinforced in the Energy Policy Act of 2005, which Throughout the electric power industry the general called for mandatory reliability standards for the procedure for calculating reliability indices has been interstate bulk power systems. The Authority’s expe- implemented by most utilities with their own specific rience is consistent with the industry in that while the adjustments to reflect their service conditions. The

System Average Interruption Duration Index (SAIDI) 2

1.8

1.6

1.4

1.2

0.8

0.6 Hours per 12 Months 0.4

0.2

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System Average Interruption Frequency Index (SAIFI) 0.8

0.7

0.6

0.5

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0.2 Frequency per 12 Months Frequency

0.1

0.0

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Authority’s SAIDI and SAIFI data include only out- reflect the Authority’s objectives in continuing to ages longer than fifteen (15) minutes and exclude improve client service. major events, such as the effects of tropical As the Authority’s SAIDI and SAIFI goals have storms/hurricanes and disruptions from multiple dropped and become more challenging to achieve and contingencies. maintain, the margin between the goals and actual The charts provide perspective on the short term performance has shrunk. This past fiscal year contin- trend of the Authority’s SAIDI and SAIFI data over the ued a general trend that began in fiscal year 2009 period beginning in January 2010, when the indicating that additional significant reductions in the Authority established the goals still in place and end- average duration and frequency of interruptions may ing on June 30, 2013. During this timeframe the aver- be difficult to achieve in the near term. age duration and frequency of service interruptions The average total duration of a client’s sustained have usually stayed in a relatively narrow band, but interruptions during the past fiscal year, as shown have trended on a gradual downward slope. In com- above in the Authority’s 12-month rolling average of parison to the reliability indices of five years ago, SAIDI, was consistently below the Authority’s current however, the recent SAIDI and SAIFI data are consid- goals although it trended somewhat higher as the year erably below the levels in fiscal year 2008. To achieve progressed. these significant reductions in service interruptions the Authority prioritized improving the reliability of During fiscal year 2013 the twelve-month rolling the distribution system. A critical component in the average of the number of sustained outages per client Authority’s program was to re-establish emphasis on trended in a relatively narrow band that was consis- tree trimming and vegetation control programs that tently below the Authority’s SAIFI goals for the year. specifically address a major cause of service interrup- As mentioned above, the observed performance was tions. The scope of the Authority’s on-going program basically consistent with the interruption frequency includes both transmission and distribution lines, as for more than the last three fiscal years. well as public education of appropriate plantings As the Authority reduces the outages caused by trees located near overhead power lines. To reinforce its and vegetation, one key to further improving the objectives over the last ten years the Authority pro- Authority’s reliability performance will be the identi- gressively dropped the performance index goals of fication of the cause of service interruptions. The fewer and shorter interruptions (lower SAIDI / potential integration of the proposed, improved auto- SAIFI). The most recent reduction in January 2010 mated systems and Remote Meter Reading may allow lowered the target SAIDI by 10% and SAIFI by 30% to more detailed analysis of reliability data. In addition, I 000059 45 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report it would be possible to acquire data on an individual structure protection (CIP) standards.. Approximately client’s actual experience rather than relying on com- one half of the funding for the $7.5 million replace- posite averages. ment EMS was obtained through the U.S. Department of Energy’s “Recovery Act Smart Grid Investment TECHNOLOGICAL SYSTEMS Grant Program”. The new EMS can interface with the OPERATIONS distribution management system, which is an impor- The Authority employs numerous automated control tant communications link for “Smart Grid” technolo- systems to ensure safe and reliable operation of its gies. In addition, the vendor of the new EMS system System. These systems coordinate with or are inte- offers pre-engineered features if the Authority wishes grated into larger systems that support the Authority’s to expand the system’s scope. routine technical and commercial operations. This sec- Concurrent with the development of the new EMS, tion addresses selected automated systems employed the Authority has been upgrading the supervisory by the Authority for control and operation of the gen- control and data acquisition (SCADA) system func- eration, transmission and distribution systems. tionality. The SCADA system is the secure communi- ENERGY MANAGEMENT SYSTEM cations network linking the central EMS with all the generation sources and substations. Consistent with good operating practice in the industry the Authority uses a sophisticated control system The scope of work for the new EMS includes new to regulate operation of its production sources to hardware and software to replace the existing control always match in real time the System’s consumption system in both the primary energy control center in of electric power while maintaining the proper volt- Monacillos and the back-up control center in Ponce. age and frequency. The upgraded EMS will enhance the Authority’s ability to respond to critical situations if the primary In fiscal year 2010 the Authority contracted with the control in Monacillos is limited or compromised, energy management system (EMS) supplier to mod- based on continuous real-time data synchronization ernize the EMS that had been in operation for more between the two control centers and enhanced sys- than 11 years by that time. The vendor of the latest tem error detection and failure determination. The generation EMS was chosen to facilitate the design of EMS features include extension of the Authority’s the new EMS to meet the Authority’s new require- load forecasting and load flow analysis. The auto- ments, provide continuity of operator interface and matic generation control (AGC) is based on revised minimize potential issues during the transition to the economic and security criteria. Among the network new system. Although the EMS in operation since applications are power scheduling opportunities, 1999 had continued to function properly with the improved software for the analysis of disturbances, existing System, the EMS hardware and software were phase angle and frequency monitoring and for the aging and the Authority’s performance requirements detection and analysis of inter-area oscillation. The had evolved to include operation of the System with new EMS will more accurately identify fault loca- intermittent renewable energy generation sources and tions thereby facilitating faster service restoration wheeling mandated by Commonwealth legislation. and interface with the distribution outage manage- Following completion of several factory acceptance ment system. tests, in fiscal year 2012 the new system and training ASSET MANAGEMENT SYSTEMS modules were installed in the Authority’s control centers. Since the new EMS was developed by the same During fiscal year 2013 the Authority implemented vendor who supplied the present system, similarities an upgraded program of work and asset management in their architecture facilitated the training; the oper- systems for its users responsible for generation and ator training simulator also includes distributed gen- the high voltage electrical system, while evaluating eration and wheeling. During the first half of the past programs for transmission and distribution activities. fiscal year the Authority operated the new system in Production Plant Asset Management parallel with the existing for many months to demon- Systems strate reliable operation of the new before retiring the In fiscal year 2010 the Authority began a program to existing from service. upgrade its enterprise asset management systems The new EMS also updates the Authority’s cyber- (AMS) that support its generation and high voltage security system for compliance with North America assets to more effectively monitor and manage these Electric Reliability Council’s (NERC), critical infra- critical assets and associated inventory. The objective 46 I 000060 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report has been to improve their reliability, safety and avail- of the AIRe are improved client service; reduced ability, while reducing costs. The previous system had O&M expenses; improved emergency response; bet- been in place for more than a decade and had been ter planning; improved and consistent superseded by newer technology. The supplier of the engineering/design and estimating practices; archived new AMS suite of programs is well established in this maintenance records; and, real-time system status field and has direct relevant experience with electric reporting. utilities; the supplier is also the successor to the pre- Since the AIRe system was implemented more than vious AMS vendor. The new AMS is designed to ten years ago, the applicable vendors, hardware and improve coordination with the numerous directorates software technologies have evolved. During fiscal that are involved in the management of the produc- year 2011 the Authority re-evaluated various options tion and high voltage electrical assets. It will facilitate to replace the existing AIRe system that was originally the integration of data into the different programs supplied by a vendor who was subsequently acquired used within the human resource, financial, engineer- by a larger vendor; the new vendor agreed to support ing, procurement, and management disciplines. the old system for only a limited time. The Authority Following acceptance testing, establishing the data- established continuity of the user interface with bases for the new AMS based on the earlier AMS pro- which the transmission and distribution users were gram as well as with new data, and widespread accustomed as an essential feature in selecting its training, the Authority fully implemented the new replacement state of the art asset management sys- AMS during the past fiscal year. tem. The evaluation process of alternative AMS systems continued through the past fiscal year. The The new AMS scope includes modules that address Authority plans to make its selection in fiscal year work and asset management through maintenance 2014, at which time the schedule for implementation optimization, life extension, work planning, predic- of the new system will be established. The Authority tive failure, materials and planning, monitoring of plans that the new asset management system for critical equipment on a real time basis, and analysis of transmission and distribution work will include historical performance data to improve repair or interfaces with the production AMS, as well as inter- replace decisions. The suite of programs are designed face with the outage management system and geo- to support effective management of supply chain graphical information system with web based responsibilities, maintenance of critical spares, pur- technology. chasing, expediting, material receipt, management of accounts payable, and quality control. In addition the The work management system (WMS) component of AMS includes safety and compliance management the AIRe system has been in service in all of the components that identify requisite safety training Authority’s districts since 2001. The WMS tracks the requirements for the work being performed, possible progress of all construction and maintenance work chemical exposures, permit requirements, document from start to completion. The functions of the system control procedures, and environmental compliance. include estimating, engineering, scheduling, required approvals, the generation of bills of material of Transmission & Distribution Asset approved equipment in accordance with Authority Management Systems standard designs, and the accumulation of labor and Presently the Transmission & Distribution operations material costs for each project. of the Authority use a multi-faceted work and asset The geographical information system (GIS) compo- management system that is more than ten years old. nent of the AIRe system is a comprehensive geospa- The Authority’s transmission and distribution asset tial model of the entire transmission and distribution management system integrates a work management systems including an inventory of all components. system, a geographic information system and an out- The GIS database is designed to interface with the age management system into an Integrated Resource WMS and the outage management system (OMS), as Management System that is known by its Spanish well as providing an engineering tool for modifica- acronym of AIRe (Administracion Integrada de tions, new work, and circuit analyses. Completing the Recursos). GIS was a major task since the global positioning sys- The AIRe system is structured to maintain its data- tem (GPS) coordinates of every pole on the island had bases as well as interface with existing computerized to be plotted and all the associated equipment physi- systems in other Authority areas such as Finance, cally inventoried. Subsequently the Authority Human Resources, and Procurement. The objectives expanded the scope of the GIS to include validating I 000061 47 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report the location of client meters to improve the precision transmission voltage are a small portion of the total of the outage management system discussed below. client base; the high voltage meters for these clients The GPS coordinate data are utilized with a one- are not included in this discussion, however these meter resolution satellite map database of the entire meters do provide remote reading capability. During Commonwealth that was developed by a Puerto the course of the remote meter reading program the Rican interagency governmental group. meters have gone through technological evolutions, The outage management system (OMS) has been in which are discussed below. Capital expenditures for island-wide operation since the end of fiscal year the AMR system in fiscal year 2013 were $16.0 mil- 2008. The OMS is designed to improve the Authority’s lion, bringing the total to approximately $225 mil- recovery efforts following a hurricane or tropical lion; $43.4 million is budgeted for fiscal years 2014 storm by generating: a damage assessment report through 2018. The continuing program consists of based on data received from various system transpon- actively replacing old and defective meters and the ders and the Customer Information System; a com- selective installation of new design digital meters. By plete inventory of equipment needing replacement; the end of fiscal year 2013 automated meters had maps of all areas affected by the outage(s); and, an up- been installed in effectively all of the Authority’s to-the-minute report of the System’s status. When the clients. The system being installed utilizes a propri- restoration work is underway, the AIRe system moni- etary technology that communicates between meters tors and records the labor and material costs. and remote controllers by superimposing a frequency modulated signal on the Authority’s existing distribu- In conjunction with the OMS system the Authority tion lines between the client meter and the expanded the use of an automatic vehicle location Authority’s substation. Because it uses the electric (AVL) system to 750 vehicles. The AVL system is power wires, this technology’s performance is not capable of providing the real-time location of any impaired by the island’s varied terrain. Authority vehicle fitted with the GPS receiver and communication link to the Authority’s local dispatch Communication between the AMR system central center. Vehicle location information has been useful processor and the individual meters is through dedi- in reducing travel time to respond to problems and cated transformers and communication equipment routing assistance to work crews if required. The AVL installed in the substation serving the associated also enhances the safety of the crews by providing client’s meter. The processed signals from the AMR their location whenever it may be needed, such as substation equipment are routed to the central during wide area power restoration work. Since the processor via the Authority’s existing fiberoptic, experience with the AVL system has been favorable, microwave systems or secure internet. The AMR the Authority plans to eventually install it in all emer- equipment is installed at all the Authority’s active gency vehicles. substations and all new substations include the AMR equipment with the original construction. Since the Authority completed the installation of the work management system in each district and imple- The Authority’s early experience with the AMR mented the interface with the Customer Information meters exposed weaknesses in the meter’s resistance System, Customer Services operators can access the to tampering. During the first ten years of deploy- WMS to provide timely information to clients. During ment the meter technology evolved from electro- emergencies, all the commercial offices located across mechanical meters with communication modules to the island are integrated into the work management rugged digital meters, fitted with the same communi- system, allowing trouble orders to be immediately cation module. Over the years the Authority has generated electronically. The implementation of these worked with meter vendors to develop increasingly automated systems has allowed the Authority to con- robust units to resist tampering. It has also enhanced solidate many of its Customer Service centers. sealing of the plastic case of meters that were already in inventory but had not been deployed. The REMOTE METER READING Authority now buys meters with the most robust anti- In fiscal year 2000 the Authority began the island- tampering specifications commercially available; wide installation of an automated meter reading these meters also include internal memory good for (AMR) system. The primary goal that the new meters storing many months of data, which might be used if support is the ability of the Authority to remotely tampering or theft were suspected, or for data recov- read the parameters measured by the meter of all ery if the AMR communications were disrupted. clients. Industrial and commercial clients served at Beginning in fiscal year 2011 the Authority has been 48 I 000062 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report installing meters with an integral disconnect/connect attribute of the “Smart Grid”. By controlling such feature. These meters have greatly reduced the time devices from a central location, the Authority would required for customer service disconnections and be able to enhance its capability to control load flow, reconnects for short term clients or in problematic manage restoration of service from an outage, and locations. In most instances these meters enable a improve the operational power factor. If added, this client to re-establish disconnected service after mak- type of control could reduce operating costs, improve ing a secure payment of an overdue invoice by phone client satisfaction, and facilitate Demand-Side or internet within minutes of that payment. By the Management & Energy Conservation (DSM & EC) end of fiscal year 2013 there were approximately programs by allowing the utility to control its clients’ 170,000 meters with this technology installed. energy use; refer to the Demand and Energy Forecast During fiscal year 2013 the Authority continued its section. aggressive theft detection and prevention program. GENERAL FACILITIES Amongst other detection techniques, the program utilizes the comparison of local/temporary meters on The budget for capital improvements for the General the distribution lines versus the aggregate of the indi- Plant encompasses General Land and Buildings and vidual served meters, a comparison of a client’s pres- Equipment. During fiscal year 2013 the budget for ent electricity usage versus historical data, General Plant capital improvements amounted to unannounced meter inspections, and a toll free hot $29.3 million. The actual expenditures during fiscal line for anonymous reporting of suspect electricity year 2013 were $22.3 million; the savings from budget theft. Based on recent experience, the Authority resulted principally from reductions in expenditures anticipates the theft recovery program will generate for improvements to buildings and grounds for considerable additional revenues and help deter fur- administration services and improvements to ware- ther theft. As discussed in the Legal Affairs section the houses. As shown on Appendix X Details of Capital Authority has established legally binding administra- Improvement Program, the expenditures for General tive processes to recover contested billings for theft Plant for fiscal years 2014 through 2018 are forecasted from culpable clients. to be $33.8 million, $31.3 million, $29.9 million, $32.8 million, and $32.2 million, respectively. As the technology for remote meter reading has evolved the Authority has identified certain applica- Maintenance expenses for the General Plant in fiscal tions which may benefit from enhanced access to the year 2013 were $6.9 million. While this level was client meter data. The meter data management system below the original budget of $9.3 million, it was may be used for enhanced data input to the OMS dis- within 6% of the previous three-year average cussed above. The Authority is also evaluating using expenses. The Authority’s maintenance budget for the AMR system to provide data to support the General Plant in fiscal year 2014 is $8.8 million. upgraded EMS, discussed above, which will be the The extensions and improvements planned for fiscal principal system for controlling the generation and year 2014 include $7.2 million for General Land and transmission of power on the island. The electrical Buildings. The largest budget item in this group is for power consumption data could also be used to sup- the acquisition of transmission and distribution port analyses of operational performance and time rights of way and land for planned expansions. Other based pricing structures that may be evaluated in the expenditures within this category are for improve- future. ments to the Authority’s warehouses, workshops, The Authority plans to upgrade the AMR communi- offices, buildings, and grounds. The Capital cation equipment at its large substations to improve Improvement Program for fiscal year 2014 includes data transfer speed. In addition, the Authority plans funds to complete the structural rehabilitation of the to install internet communication with the AMR plaza at the Authority’s headquarters in Santurce, San communication gear at many of its substations to Juan, as well as other improvements to various improve reliability and provide operational flexibility. administrative services buildings. Although they are not among the AMR system fea- The total expenditures for Equipment in fiscal year tures now being installed, the AMR has the capacity 2013 were $17.8 million; office and computer equip- to incorporate at a later date the ability for the ment accounted for $9.0 million, overhaul of the large Authority to simultaneously monitor and control the helicopter used for installing and rehabilitating trans- performance of key components of its distribution mission lines cost $1.9 million and $3.8 million was system. This two-way communications is a critical expended on replacement vehicles. For fiscal year I 000063 49 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

2014 the total Equipment budget is $26.6 million; CURRENT FORECAST this is comprised of four budget subgroups, as follows: The Office and Computer Equipment budget During the second half of every fiscal year the for fiscal year 2014 is $5.6 million. The largest proj- Authority prepares a forecast entitled Presupuesto de ect is $2.8 million for improvements to the informa- Ingresos (Revenue Budget) that projects energy sales tion services systems as part of a long term upgrade by service sector, revenues, and number of clients, as that has a budget of $18.4 million for the five fiscal well as projected generation, annual peak demand year 2014 – 2018. The Transportation Equipment and fuel costs. This annual report references the Authority’s Revenue Budget as the “Current budget is for repairs or improvements to the Forecast”. The Current Forecast contains detailed Authority’s aircraft and for purchase and replacement short to intermediate-term projections of energy sales of the Authority’s vehicles; the budget for fiscal year revenues, number of clients, and fuel prices based on 2014 is $8.3 million. The Communication Energy Information Agency (EIA) projections and Equipment budget is $4.2 million for fiscal year 2014; other sources; the forecast also includes projections of this budget is directed to improving and expanding long-term generation and long-term peak demand. the communication network used by the Authority The remainder of this section will describe the results for operation of the System. The projects include of these forecasts and the methodologies used in its improvements to the fiber optic network and upgrad- preparation. ing the microwave system between essential facilities. The preparation of the Current Forecast is timed so The last Equipment subgroup is Other Equipment, that its projections may be used to develop short-term which has a budget of $8.5 million for fiscal year (1-2 years), intermediate-term (3-5 years) and long- 2014. The scope of this subgroup spans a wide range term projections (6 years and beyond) of various of equipment including miscellaneous tools used for financial and operational parameters. The initial year the installation of transmission and distribution lines, of the short-term financial projection is used for the environmental monitoring equipment, specialized Authority’s Annual Budget of Current Expenses power quality monitoring equipment, vehicle repairs (Annual Budget) for the ensuing fiscal year. The short tools, and small construction tools. to intermediate-term energy projections are utilized to establish the Authority’s needs for capital require- CONDITION OF THE ments and the projected income statements, which are used in turn to project its ability to meet the nec- SYSTEM’S PROPERTIES essary requirements of its Trust Agreement covenants The Consulting Engineers visited and noted the con- regarding net revenues to projected debt service. dition of each of the Authority’s steam-electric gener- The long-term peak demand and generation projec- ating facilities three or more times during fiscal year tion through fiscal year 2040 are generally used for 2013 and also visited the other production facilities at trends of generating capacity that may be needed in least once during the fiscal year. In addition, we also the future. (See Capacity and Energy Resource visited and noted the condition of approximately one- Planning) The Authority developed a Current third of the Authority’s three hundred and eighty Forecast in April 2013 as the basis for the fiscal year transmission centers and distribution substations. In 2014 budget, financial projections through fiscal year the course of these visits we observed other property 2018 and long-term generation and peak-demand in the production, transmission, distribution, and projections through 2040. general plant functional groups. To establish energy sales data for fiscal year 2013, In conjunction with our field activities, we have which is the base year in the Current Forecast, the reviewed various maintenance reports of the Authority’s Planning Directorate used actual energy Authority, specific maintenance activities, and the sales from July 2012 through February 2013 and preliminary generation data for March 2013. These planned actions for the next fiscal year. We have also energy sales do not include the adjustments applied reviewed reports submitted by manufacturers’ repre- principally to the industrial class sales to avoid dis- sentatives. torting the base year of the forecast; the adjustments In the opinion of the Consulting Engineers, the prop- are discussed in the Energy Sales Forecast section. erties of the System are in good repair and sound The estimate for energy sales for the remaining operating condition. months of fiscal year 2013 were extrapolated from 50 I 000064 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report generation data for the comparable months in the the first recorded drop in population on the island, five-year period ending in fiscal year 2012, while sales but was consistent with the prolonged weak economy by service sector were estimated to follow the average discussed below. Subsequent census data have shown distribution of the 12 months through March 2013. the decline has continued at a steeper rate. The cen- The projections for energy sales and related data for sus data showed the population drop was due to a low the period of fiscal year 2013 and after were based on birth rate and increased emigration; the population econometric modeling of energy sales by service sec- losses were disproportionately in urban areas and tor. Macroeconomic indicators provided by economic amongst the young and middle age. The rural popu- consultants are key dependent variables for these lation actually grew modestly in the same period. The models. The Authority also has extrapolations of trends from the census data indicate that 15% of the energy sales by service sector based on monthly data people were over the age of 65 years in 2010 and that since fiscal year 1993 and annual data since 1983. portion is projected to continue growing. According Generation requirements are derived from sales pro- to GDB statistics the 2012 estimated population jections, adjusted to reflect system operating losses. growth rate was negative 0.44%, and the net migra- The forecast methodology reduces data to a daily tion rate minus 0.82 migrants per 1,000 of the popu- basis to allow adjustment for leap years. lation. A report issued by the Puerto Rico Planning The short-term and intermediate-term forecasts proj- Board attributed the declining birthrate to migration ect sales, revenues, number of clients, generation, and of the people in their child bearing years, an economy maximum demand on a monthly basis for the remain- that discourages family growth, more women marry- der of fiscal year 2013 and for all of fiscal year 2014 ing later in life, the drop in population of those in and on an annual basis thereafter through fiscal year reproduction age, and family planning policies. 2018. Projections of fuel costs are also provided According to a Puerto Rico Labor Department report through fiscal year 2018. The long-range forecast the unemployment rate remained high at 13.5% in projects annual generation (in GWh) and peak July 2013, but this was still less than the highest per- demand (in MW) through fiscal year 2040. centage of 16.9% in May 2010. The labor participa- The projected revenues in the Current Forecast are tion rate in July 2013 was 41 percent. derived from the forecast energy sales by classifica- The Puerto Rico Government Development Bank’s tion using existing base rates and the appropriate pro- data published as of January 2013, states that the jected adjustment charges for the cost of fuel and composition of the Puerto Rico Gross Domestic purchased power. The Current Forecast also includes Product (GDP) by sector is as follows: manufacturing projections for the reductions due to subsidies and 48.6%; finance, insurance, and real estate 17.8%; credits applied to the fuel and purchased power rev- services 12.7%; government 8.3%; trade 7.6%; trans- enues and the hotel subsidy, but these reductions are not incorporated in the total revenue forecasts. The portation and utilities 2.9%; construction and mining Authority’s forecasted revenues and payment obliga- 1.4%; and agriculture 0.7%. tions are discussed in the Financial section. The Planning Board is the official Commonwealth agency that collects and reports the macroeconomic ECONOMY OF PUERTO RICO indicators utilized in the Current Forecast, including Since the present depressed state of the economy of the Gross Domestic Product (GDP), and the Gross Puerto Rico is unprecedented in recent history, eco- National Product (GNP), of the Puerto Rico economy. nomic forecasting for the island is currently difficult As measured by the GNP the Puerto Rican economy and more uncertain. The demand for electric energy was robust in the three fiscal years ending in 2005; in Puerto Rico has historically tracked the island’s subsequently the economy grew marginally by 0.5% economy and its attendant economic development. in fiscal year 2006 and then began five years of Puerto Rico’s economy has evolved from primarily an decline with contractions of 1.2% in fiscal year 2007, agriculture economy in the early 1900s to one domi- 2.9% in fiscal year 2008, 3.8% in 2009, 3.6% in 2010, nated by manufacturing in the 1940s through the 1.7% in 2011 and finally positive growth of 0.9% in 1970s and, finally, moving to a mixed economy 2012. During the five fiscal years from 2007 to 2011 largely comprised of the manufacturing and service Puerto Rico’s economy receded by over 12%, a mag- sectors over the past three decades. nitude not seen since the Great Depression. For fiscal According to census data the population of Puerto year 2013 the Planning Board reports a marginal Rico declined 2.2% between 2000 and 2010. This was growth rate of 0.3%. I 000065 51 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

PUERTO RICO Economic Activity Index 3.0% 2.0% 1.0% 0.0% -1.0% -2.0% -3.0% -4.0% -5.0% -6.0%

Jan 2010Mar 2010May 2010Jul 2010Sep 2010Nov 2010Jan 2011Mar 2011May 2011Jul 2011Sep 2011Nov 2011Jan 2012Mar 2012May 2012Jul 2012Sep 2012Nov 2012Jan 2013Mar 2013May 2013Jul 2013

The Government Development Bank of Puerto Rico sales; and GNP, used as a factor in forecasting indus- measures the island’s economic activity with the trial energy sales. Economic Activity Index (EAI). This index is similar MACROECONOMIC PROJECTIONS to the Gross Domestic Product Index; it is keyed to four major local monthly economic indicators. As can In the preparation of the Current Forecast the be seen by the data, the GDB-EAI returned to growth Authority typically incorporates analyses of the Puerto in December 2011 which lasted approximately one Rico economy that are prepared each year by three year. This was the first period of growth since the independent economic consultants. The forecasts pre- island’s economy recession began in 2006. The EAI pared by the Commonwealth of Puerto Rico’s maintained some positive growth on a 12 month Planning Board (Planning Board) were unavailable when the Authority performed its analyses for this rolling basis through calendar 2012, however the year’s Current Forecast. The Authority used the two brief recovery ended at the beginning of calendar year forecasts that were available, which were the eco- 2013 and had declined by 5% in the next six months. nomic projections developed by the Inter-American The Planning Board attributes the modest recovery in University of Puerto Rico – IHS Global Insight (IAU- the economy of Puerto Rico during fiscal year 2012 to GI) and Advantage Business Consulting Group the moderate expansion of the U.S. economy, the (ABC). A summary of the economic consultant’s pro- additional revenue provided by the temporary excise jections on the key indicators on the five-year outlook tax on sales of Controlled Foreign Corporations man- are as follows: ufacturing companies to affiliates, the additional Commonwealth revenue provided by the Tax Reform Puerto Rico Economic Indicator Projections Act, a drop in the employee’s social security tax rate, Five year Compound Annual Rate 2013-2018 and an resurgence in demand in consumption and ABC IAU-GI private investment in Puerto Rico. Gross National Product 0.99 1.28 ECONOMIC PROJECTIONS Personal Disposable Income 1.64 1.75 Gross Domestic Product 1.58 1.63 The Current Forecast is based on econometric models which attempt to correlate the future consumption of electricity with recent consumption data, The key economic indicator projections correlate industrial sector power costs and selected historical with the resultant predictions by the Authority for and projected macroeconomic indicators. These electric sales by major classification as described macroeconomic indicators are: personal disposable below. income, used in part to forecast residential energy In view of the uncertainties in the economic forecasts sales; GDP, used in part to forecast commercial energy the Authority generally uses the least optimistic five- 52 I 000066 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report year intermediate-term energy sales projections for 2.4%, the price of a barrel of oil (WTI) of between financial planning purposes and the most expansive $103.25, an increase over the current price of $95.07; economic projections for capacity and operational U.S. federal funds target rate of 0.25% until 2014 and planning. In the Current Forecast the Authority 0.5% to 1.15% through 2018 and the 10-year treasury selected ABC’s projections as the bases for its fiscal rate of 1.80% to 3.00%. year 2014 annual budget as well as the financial pro- There were several endogenous variables considered jections through fiscal year 2018, yielding a five-year by the ABC projections. Those listed are: that there compounded annual growth rate (CAGR) of 1.22% in would no further degradation of the Authority’s its electric energy sales model. power bonds to non-investment grade, that the fiscal The expansive projections, those of IAU-GI, yielded a austerity period would extend until 2014 or early five-year CAGR of 1.43% in the Authority’s electric 2015, very moderate growth in real public expendi- energy sales model which were used in its load tures, public investment begins to recover vigorously growth forecast for capacity planning. after 2015, that in 2016 the elimination of the struc- For many years the short-term energy sales projec- tural deficit of the central government would be tions in the Authority’s Current Forecasts were usu- achieved, and that the rate of inflation over the years ally conservatively close to actual performance; these of the projection would be controlled between 2.5% were during a period of almost continuous electric and 2.6%. sales growth only interrupted by the impact of hurri- CONSUMPTION OF ELECTRICITY canes. In fiscal year 2006, however, short-term con- Over the period from the mid-1980’s through 2006, sumption forecasts began to understate the actual the annualized rate of growth in the consumption of decline in consumption. To improve the accuracy of electricity in Puerto Rico was generally greater than its projections, in 2008 the Authority revised the that of the U.S. mainland. Interruptions in this pat- modeling of residential and industrial sector con- tern were principally caused by major weather events. sumption to reflect the clients’ sensitivity to the price The event with the greatest impact occurred in 1998 of electricity. when Hurricane Georges devastated the island, caus- CURRENT FORECAST PROJECTIONS ing severe damage to the Authority’s system and a dramatic, short-term curtailment in energy sales. By In developing the Current Forecast the Authority uni- fiscal year 2000, however, the annual growth rate in formly employs the economic indicators from each the Authority’s energy sales rebounded back to a economic consultant. The resulting projection of robust 6.8%. The growth rates for energy sales in fis- energy sales over the five-year intermediate term fore- cal years 2001, 2002, and 2003, were moderate at cast period are summarized below: 3.2%, 2.2% and 4.0% respectively. For fiscal years TOTAL ENERGY (GWH) SALES PROJECTIONS 2004 through 2007 the decline in the annualized growth rate for energy sales continued with marginal Fiscal ABC Annual IAU-GI Annual growth rates of 1.9%, 1.2%, 0.6% and 0.3%, respec- Year Change Change tively. For fiscal years 2008 and 2009 energy sales 2012 18,112.5 18,112.5 declined sharply resulting with negative growth rates of 5.2% and 5.5%, respectively. In fiscal year 2010, the 2013 17,966.7 -0.80% 17,966.7 -0.80% negative trend in energy sales reversed when total 2014 18,199.0 1.29% 18,191.5 1.25% energy sales increased by 3.9%, principally as a result 2015 18,267.8 0.38% 18,431.2 1.32% of a 10.8% jump in energy sales in the residential sector. However, during fiscal years 2011 and 2012 2016 18,476.0 1.14% 18,699.3 1.45% energy sales continued the previous negative trend 2017 18,756.9 1.52% 18,988.1 1.54% with declines of 3.8% and 2.1%. As discussed in the Energy Sales Forecast section, the reported energy 2018 19,090.6 1.78% 19,292.7 1.60% sales for fiscal year 2013 show an increase of 0.6% 5-yr CAGR 1.22% 1.43% over the previous year. ABC’s model dated April 2013 considered a wide As shown on the comparative chart, Electric Retail range of factors while developing its economic fore- Sales-All Sectors US & PR, the rate of growth in elec- cast. As reported in the Current Forecast, these fac- tric sales contracted in Puerto Rico and the U.S. main- tors included the following exogenous variables: land during 2008 and 2009. Both Puerto Rico and the growth of the U.S economy of between 1.8% and U.S. mainland experienced robust electric sales I 000067 53 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report growth in 2010. However, as the U.S. mainland recov- DEMAND AND ENERGY ered from its recession electric utilities posted modest electric energy sales growth in 2011 and are projected FORECAST to produce marginally positive electric energy sales GENERATION FORECAST growth less than 1% annually to 2018. Although the GNP of Puerto Rico increased marginally by 0.9% The total net generation during fiscal year 2013, during fiscal year 2012, electric sales were off 2.1% including hydro-power and power purchased from from the previous year. For reference, the comparable the cogenerators and renewable energy projects, was statistics in fiscal year 2011 were a decline of 1.7% in 21,009 GWh, which was a 0.9% decrease compared the GNP and 3.8% decline in electric sales. In the to that generated in fiscal year 2012. In 2014 the Current Forecast the Authority projected a decrease Authority projects that total net generation will in electric energy sales of 0.8% in fiscal year 2013, in increase by 1.4%. With the exception of fiscal year contrast to the reported increase of 0.6%. The Current 2010, net generation has been in decline since fiscal Forecast projects growth in electric energy sales in year 2008, when it was 9.1% more than fiscal year 2014 of 1.3%, followed by steady growth in the fol- 2013. lowing four years from 0.4% in fiscal year 2015 to Electric generation projections in the Current 1.8% in fiscal year 2018. Forecast track with forecasted sales. The contribution It should be noted that in the comparison chart the to the System of power from renewable energy proj- Authority’s energy sales for fiscal year 2013 are the ects is forecasted to grow from 0.7% in fiscal year reported actual energy sales and preliminary electric 2013 to more than 4.5% of the total for the fiscal years energy sales replaced the forecasted energy sales for 2015 through 2018. The growth of renewable energy U.S. electric utilities in calendar year 2013. The fore- projects will displace generation from the Authority’s casted percentage change for Puerto Rico in the sub- least efficient and most costly units. The Current sequent year 2014, however, reflects the Current Forecast projects a decline in net generation by the Forecast projected change. By updating the 2013 data Authority of 1.8% in fiscal year 2015, followed by for the US the percentage, the change to 2014 may be increases of 1.6%, 2.2% and 2.9 % in fiscal years 2016 slightly different than that formally estimated or pro- through 2018. jected. The data for the U.S. mainland are derived Each year in the Current Forecast the Authority from EIA’s Annual Energy Outlook 2013 (AEO 2013), develops a ratio, referred to as the system efficiency, prepared in June 2013. based on total energy sales as a percent of the total of the Authority’s gross generation plus the net amount

Actual & Forecast 2009–2018 6.0%

4.3% 4.0% 3.9%

1.8% 2.0% 1.5% 1.3% 1.1% 1.1% 1.3% 1.1% 0.6% 0.7% 0.5% 0.4% 0.0% -0.6% -0.3% -0.1%

-2.0% -2.1%

-3.4% -4.0% -3.8%

-6.0% -5.5% 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

54 I 000068 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report of purchased power, which is the net output of the The peak demand for fiscal year 2013 was 3,265 MW two cogenerators plus the output of the renewable was 1.2% less than that reached during fiscal year energy projects. The annual generation for the fore- 2012 and 11.4% less than the historic system peak cast period was determined utilizing a system effi- demand. ciency that was the System’s 12-month average for the The Current Forecast utilized a system load factor of period ending February 2013, based on the sales and 77.2% to predict peak demand for the duration of the generation methodology in the Current Forecast. The generation forecast. The system load factor is the ratio actual and projected generation by plant are pre- of the average demand in kilowatts supplied during a sented in Appendix IV, Annual Net Generation, Fuel designated period, in this case the fiscal year through Consumption, Fuel and Purchased Power Costs. March 2013, to the peak or maximum demand also PEAK DEMAND FORECAST measured in kilowatts. The most expansive model in the Current Forecast predicts that the 3,685 MW Consistent with the Authority’s conservative peak demand established during fiscal year 2006 will approach to planning for expansion of generation not be exceeded during the duration of the long-term capacity the Current Forecast used the projections forecast. The forecast peak demand projects a CAGR that resulted in the most expansive forecast for the growth of 1.4% for the five years through fiscal year development of the peak demand forecast. For this 2018, with effectively no growth in peak demand for year’s Current Forecast the projections from IAU-GI the balance of the forecast period. met that criterion and were the basis of the peak demand forecast. For a comparison of the economic Since 1993 the Authority has included explicit recog- consultants kWh sales projections refer to the nition of the potential effects of its DSM & EC pro- Economic Projections section above. grams in its peak demand forecasts; these programs are discussed below. The Long-Term Peak Demand For the seventh consecutive year the System did not Forecast graph shows the degree in which the peak reach a new peak demand. The current historic sys- demand forecast has declined over the last four years. tem peak of 3,685 MW was established in September 2005, in fiscal year 2006. From fiscal years 2008 to 2013 the five-year compound average growth rate (CAGR) in actual peak demand contracted by 0.5%.

Long-Term Peak Demand Forecast 4,600

4,400

4,200

4,000

3,800

3,600

3,400 Peak Demand (MW)

3,200

3,000

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Fiscal Year

2013 Peak Demand Forecast 2012 Peak Demand Forecast 2011 Peak Demand Forecast 2010 Peak Demand Forecast 2009 Peak Demand Forecast I 000069 55 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

DEMAND-SIDE MANAGEMENT AND the installation of energy savings equipment with a ENERGY CONSERVATION PROGRAMS provision that the savings in energy costs would be shared between the two entities. Electric utilities offer programs to encourage clients to modify their levels and patterns of electric con- In February 2013 the EPA and the Commonwealth sumption. The implementation of such programs, announced new guidelines for energy efficient homes known collectively as Demand-Side Management & in Puerto Rico. These guidelines, developed by the Energy Conservation (DSM & EC), achieve two EPA under the federal Energy Star program, were for- objectives; energy efficiency and load management. mulated based on Puerto Rico’s Caribbean climate to DSM initiatives such as load management programs establish energy efficiency standards and practices for are designed to shift load from peak hours to nonpeak local home construction. The goal of the energy effi- periods. Energy efficiency measures reduce the cient homes is to identify features that will reduce energy consumption of end-use devices and systems energy use by an estimated 20 to 30% compared to by promoting high-efficiency equipment and energy standard homes. The efficiency features include: high efficient building design. Successful DSM & EC pro- quality energy efficient windows; efficient systems for grams promote energy efficiency and achieve cost- heating, ventilating and cooling; comprehensive effectiveness for utilities and clients thereby delaying water management systems to protect floors, walls the need for new capacity. DSM & EC programs help and foundations from moisture damage; and energy to conserve fossil fuel resources, reduce air pollution, efficient lighting and appliances. and lower a utility’s need for additional capital and its The Commonwealth government created a Green carrying costs. Energy Fund following passage in 2010 of the Puerto As part of its Load Management Program the Rico Green Energy Incentives Act. The six-year pro- Authority promotes: Time-of-Use (TOU) rates to gram began in fiscal year 2012 with a budget of $20 improve or smooth out its load curve; the purchase of million for each of the first two fiscal years and $25 energy-efficient motors and air conditioners; and the million in fiscal year 2014. The fund is structured to use of more efficient lighting. TOU rates offer eco- provide grants to business and homes that invest in nomic incentives to Industrial and Commercial renewable energy technologies such as photovoltaic, clients who modify their patterns of energy consump- wind, and renewable biomass combustion. Under the tion, i.e., adding load to off peak hours and reducing Green Energy Fund incentives are available for up to load during peak hours. (For more information on 60% of the eligible costs for small renewable energy TOU rates see the Rates section.) The Authority, with projects, and up to 50% for larger projects. The incen- a limited staff, also offers advice to clients on power tives do not apply to an installation which generates factor improvement that benefits both the client and power that exceeds it internal requirements as the Authority. defined based on the technology. During recent years the Commonwealth Govern- The Authority, as it has for the past several years, ment’s Energy Affairs Administration (EAA) has pro- projects that the savings from its DSM & EC program moted a succession of programs and incentives will lower peak demand by 1 MW per year (see pre- promoting cost effective energy saving. These have vious section). ranged from encouraging the replacement of incan- The Authority is evaluating its long term metering descent light bulbs with compact fluorescent bulbs to plans to potentially expand the operational features of voucher initiatives that subsidize purchasing energy its automated meter reading system to include a load efficient home appliances. The EAA has been active in control component. This feature would increase the encouraging projects to access federal grant money impact of load reduction by allowing the Authority to through the stimulus funding from the American control clients’ equipment, such as air conditioners, Recovery and Reinvestment Act and the Department for periods when load management is desirable. of Energy’s “Energy Efficiency and Conservation Block Grant” (EECBG) program. Some EECBG grants, such as light bulb exchange programs, are also directly administered through larger cities. In addition to weatherization projects for the private sector and vouchers for high efficiency appliances, the EAA has promoted energy savings agreements between public agencies and a specialized private company for 56 I 000070 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

CAPACITY AND ENERGY restored to service. The availabilities of both the steam plant and total system steadily increased during RESOURCE PLANNING fiscal years 2010 and the first half of 2011 reaching OVERVIEW 82%, as routine maintenance at other plants that had been delayed while the Palo Seco outages were per- The Authority periodically updates its Capacity formed. Expansion Plan (CEP) to ensure its ability to meet expected long term electric load growth with reliable, In October 2011 the Authority removed the 450 MW cost effective and environmentally compliant electric Aguirre Unit 1 from service for a major overhaul and power. To address cost and reliability, the Authority to perform initial boiler modifications for its conver- employs system-planning software that is widely sion to dual fuel firing. Later in 2012 the 410 MW accepted throughout the electric utility industry. South Coast Unit 6 was removed from service for final boiler conversion modifications, allowing the Consistent with its goals to provide reliable, cost unit to increase its gas firing capability. The removal effective electric energy the Authority has also pur- from service of these large generating units reduced sued fuel diversification for many years, with the pri- total system availability to 78% from December 2011 mary focus being on increasing the utilization of through September 2012, after which availability natural gas in its production plants. Conversion of oil increased again to 80%. In January 2013 the 410 MW fired production plant to dual fuel firing of natural South Coast Unit 5 was removed from service for the gas and / or oil would both reduce air pollution and final boiler conversion upgrades similar to that of provide the Authority’s ratepayers with reduced elec- South Coast Unit 6, reducing total system availability tric energy costs. to 77% by the end of fiscal year 2013. Concurrent As discussed in the Environmental section, regula- with extended outages for dual fuel conversion work, tions issued by the EPA in fiscal year 2012 have added the Authority has adopted the policy of avoiding other imperatives for the Authority to reduce its overtime for scheduled outages to reduce their costs. dependence on fuel oil and switch to natural gas for This work practice has extended the duration of these electric generation. The Authority’s environmental outages and negatively impacted availability. compliance strategy involves dual fuel firing conver- The Authority’s overall production plant equivalent sion at its eight largest steam plants. By the end of the availability for the five-year period ending June 30, past fiscal year the two 410 MW units at the South 2013 is shown in the chart based on rolling twelve Coast plant were capable of full firing on natural gas, month data. Performance is shown by the which was purchased by the Authority from the Authority’s total system and by the three major nearby regasification facility at the EcoEléctrica kinds of generation — steam, combustion turbine, cogeneration plant. The development of the natural and combined cycle. Prior to fiscal year 2010, the gas supply infrastructure is discussed in the Energy availability of San Juan Units 5 & 6 was included Resource Planning section below. with the steam portion of the system. Beginning in AVAILABILITY fiscal year 2010 San Juan Units 5 & 6 were tracked in the combined cycle group. Over the last two decades the Authority has directed much of its production capital expenditures on CAPACITY PLANNING improvements to extend the life of its generating The Authority’s current capacity expansion plan is facilities, reduce the need for extended scheduled based on the Authority’s most recent Current Forecast outages, and lower the frequency of forced outages, dated April 2013. Based on these projections the pre- thereby increasing the percentage of time its generat- vious peak demand will not be exceeded within the ing units are available for service. As the Authority’s horizon of the Authority’s capacity planning. The dual fuel conversion strategy has been implemented Current Forecast foresees relatively modest increases the largest units have been through extended outages in peak demand averaging 0.7% per annum over the to implant the scope of required work. first ten years of the forecast period. The previous sys- Since the availability data reflect accumulated per- tem peak was 3,685 MW, established in fiscal year formance over the preceding twelve months, an 2006; in fiscal year 2013 the peak was 3,265 MW. The extended outage of a large unit can impact the system Current Forecast projects the peak demand in ten data well beyond its return. This was observed fol- years will be 3,499 MW and the previous peak will lowing the outages at the Palo Seco plant due to fires. not be exceeded even within the long term horizon of During fiscal year 2010 the Palo Seco units were fully the Authority’s forecast. I 000071 57 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

100%

95%

90%

85%

80%

75%

70%

65%

60%

55%

Jun-08 Sep-08 Dec-08 Mar-09 Jun-09 Sep-09 Dec-09 Mar-10 Jun-10 Sep-10 Dec-10 Mar-11 Jun-11 Sep-11 Dec-11 Mar-12 June-12 Sep-12 Dec-12 Mar-13 Jun-13

Combustion Turbine Steam Combined Cycle Authority System (Includes San Juan (Includes San Juan 5 & 6 to June 2009) 5 & 6 after June 2009)

Details of existing generating capacity of the System In accordance with a 22-year power purchase operat- are shown in Appendix VIII, System Capability. The ing agreement (PPOA) that commenced in March Authority does not plan to add or retire capacity 2000, the Authority has been purchasing 507 MW of through fiscal year 2018. power produced by EcoEléctrica, L.P.’s gas-fired combined-cycle cogeneration facility. The PPOA outlines The Authority has numerous proposed renewable capacity and energy charges to be paid by the energy projects under power purchase agreements, Authority based on the performance and electrical however, none meet the criteria for firm and reliable output of the facility. A principal condition of the capacity therefore these projects are recognized as agreement is a progressive reduction in the monthly only sources of energy; this is also consistent with capacity charge, paid by the Authority, subject to the their characteristically low capacity factor. facility meeting a minimum 93% availability on a 12- PURCHASED POWER month rolling average. EcoEléctrica’s availability during fiscal year 2013 was 91.4%, down from 95% in the In parallel with the internal program to improve pro- previous year. In fiscal year 2013, EcoEléctrica, L.P. duction plant performance, the Authority entered represented 8.6% of the System’s capacity and pro- into long-term purchased power operating agree- vided 17.0% of its power. For fiscal year 2014 the ments with the owners of two privately owned and energy provided to the Authority’s from EcoEléctrica operated cogeneration facilities. These relatively new is forecast to be 17.5% of the System total. plants were selected to aid the Authority in providing for electric load growth. They reduce the island’s The Authority also has an agreement with AES-PR to dependence on fuel oil, and continue to improve the purchase 454 MW of power from its coal-fired steam- System reliability. electric plant. The plant, which consists of two iden- tical fluidized-bed boilers and two steam turbines, Prior to the Authority purchasing power from the uses clean coal-burning technology. The facility com- cogenerators, nearly 99% of the energy sold by the menced commercial operation in November 2002. Authority was produced by its oil-fired units. In fiscal The 25-year PPOA with AES-PR is similar to year 2013 the cogenerators produced 33.7% of the EcoEléctrica, L.P.’s. The minimum guaranteed avail- System total power. Subject to dispatch and actual ability for AES-PR is 90%, slightly lower than availability, the combined generation of EcoEléctrica, EcoEléctrica, L.P.’s, but typical of coal-fired electric L.P. and AES-PR is forecasted to be 33.3% of the total generating plants. The availability of AES-PR for the System generation in fiscal year 2014. 12 months ended June 30, 2013 was 91.1%; its avail- 58 I 000072 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report ability was 87.4 % during fiscal year 2012. Although on the pipeline was in its early stages when the AES-PR comprises 7.7% of the System’s capacity, this Commonwealth decided to terminate the project in cogenerator provided 16.7% of its energy during fis- 2009. cal year 2013. It is anticipated that the plant will pro- The Authority subsequently developed a broader provide 15.8% of the System’s total generation in fiscal gram to expand natural gas firing in its units. This year 2014. program was based on a pipeline from the LNG These PPOA’s have allowed the Authority to reduce regasification facility at the EcoEléctrica cogeneration its dependency on fuel oil, mitigate the economic risk plant to certain Authority plants on the north coast. of its electric system operation, and to schedule the The proposed 92 mile long pipeline route was north retirement of some of its older, less efficient generat- through the island’s interior and then east to the San ing units. For further discussion on EcoEléctrica and Juan area. By fiscal year 2012 the Authority had made AES-PR, refer to the Cogenerators in the System’s significant progress in the permitting process, during Operation section. which the Authority responded to numerous recom- The operating agreements with both cogenerators mendations with respect to routing, safety and envi- include provisions for fixing the cost of fuel used to ronmental mitigation. As the completion of the generate electricity for each year of the contract at the permitting process drew near, the US Army Corps of beginning of such year. Annually, the fuel portion of Engineers, who were the lead permitting agency, extended its review after several federal agencies sub- the energy charge per kWh is based on actual fuel- mitted additional concerns or revised comments. related energy charges for the preceding year, During this period contentious opposition to the adjusted using inflation and other indices. The fixed pipeline within the Commonwealth continued to nature of the fuel cost reduces short-term variations grow; in addition, it was determined that the pro- in the Authority’s energy costs by bringing purchased posed pipeline would not have enough capacity to power costs out of step with price changes in other support the Authority’s compliance with the MATS components of the Authority’s fuel mix. The fixed environmental objectives. fuel costs also afford the Authority the opportunity to better dispatch its electric production plant. In view of the seriousness of the situation, as discussed in the Environmental section, the Commonwealth’s ENERGY RESOURCE PLANNING government appointed a select committee presided With the prospect of adequate generation reserves for over by the chairman of the Environmental Quality many years, the Authority’s focus has been on devel- Board of Puerto Rico to evaluate the alternatives for oping an environmental compliance program dis- compliance with MATS. The committee concurred cussed in the Environmental section, while reducing with the Authority that conversion from oil to natural and stabilizing future electric power costs, by gas was the best method. The committee’s general rec- decreasing its dependence on oil. The Authority has ommendations included employing one or more off- identified the first step in this process is to expand its shore regasification and delivery systems for LNG, but use of natural gas, which would be supplied to the acknowledged other technologies such as compressed island as liquefied natural gas (LNG). Typically the natural gas (CNG) should be considered. The 92 mile price structure of LNG provides more stable energy pipeline project was judged to be not viable, due to prices in comparison to oil. The availability of com- constrained capacity, projected cost escalation and peting, alternative fuels may also benefit the community opposition. Authority in its negotiations with fuel suppliers. After cancellation of the southern pipeline to Aguirre, The Authority’s first proposed program to expand gas the Authority decided to utilize the excess gas storage firing was a planned gas pipeline on the island’s south capacity which it was leasing at EcoEléctrica by con- coast from the LNG regasification facility at the verting the boilers at the 410 MW Costa Sur Units 5 EcoEléctrica cogeneration plant in Guayanilla to the & 6 to dual fuel. These units were selected because of Authority’s Aguirre plant approximately 40 miles to their proximity to the LNG facility, resulting in a the east. The first units scheduled to use the surplus short pipeline from EcoEléctrica to the Costa Sur gas capacity from EcoEléctrica were the two existing plant and the relatively low capital cost and short 296 MW combined cycle units at the Aguirre plant, schedule to convert the units to dual fuel. During fis- which had been converted to dual fuel capability. The cal year 2011 the Costa Sur Units 5 & 6 were con- pipeline project had raised significant local opposi- verted to dual fuel burning capability. Since then the tion and controversy from its inception. Construction units have operated with at least partial gas firing. I 000073 59 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Subsequently the boiler internals were modified to being available the Authority plans to add gas firing support continued full load operation with all gas fir- capability to the Authority’s two most efficient units, ing; this work was performed for Unit 6 during fiscal San Juan Units 5 & 6, which are combined cycle units year 2012 and completed for Unit 5 at the end of fis- presently burning high cost distillate fuel. cal year 2013. ALTERNATIVE ENERGY SOURCES The quantity of natural gas available to Costa Sur from EcoEléctrica has been constrained under the To promote the use of renewable resources for the pro- terms of the short term fuel purchase agreement duction of electric energy and further expand energy which is scheduled to expire late in fiscal year 2014. diversification, the Commonwealth passed Act 82 in The maximum quantity of fuel had been based on the 2010 that established new initiatives to strongly capacity of the regasification facility. During fiscal encourage the development and implementation of year 2013 EcoEléctrica installed and made opera- renewable energy sources in Puerto Rico. The legisla- tional two additional regasifiers. Under their FERC tion effectively sets a target renewable portfolio stan- permit EcoEléctrica regasification capacity enables it dard that requires an increasing percentage of retail to provide sufficient gas for its own consumption as electric power be provided from renewable energy well as Costa Sur Units 5 & 6 at approximately 55% sources. The initial target calls for 12% of total energy capacity factor. Additional gas production is possible sales should be from renewable energy production by with the installed equipment, however this would the end of calendar year 2015, increasing to 15% by require a revised FERC permit. 2020 and 20% by 2035. These targets are premised on the basis that the renewable energy projects will not The Authority’s current approach to expand the supply of natural gas on the island has been an offshore compromise the continued safe and reliable operation gasification facility for LNG deliveries near its Aguirre of the island’s electric system. The legislation creates a power complex on the southeast coast. The proposed financial incentive to meet these standards by estab- Aguirre Offshore Gas Port (AOGP) will be a floating lishing Renewable Energy Certificates that can be sold facility to receive and gasify LNG shipments. The nat- if the standards are exceeded or must be purchased if ural gas will be delivered to the Aguirre plant by the standard is not met. pipeline from the AOGP. The Authority plans that the As more renewable energy projects have entered serv- AOGP will be installed by a vendor under a long term ice the electric utility industry has been analyzing the agreement and the Authority has continued with the impact of these intermittent resources on system coordinated air permit effort with that vendor for operations and stability. The Authority has performed both the AOGP scope and the Aguirre plants. The similar screening studies to evaluate the impact on proposed schedule at the end of fiscal year 2013 their System operation which is inherently more sus- would enable gas to be available for the Aguirre plant ceptible to disturbances given that as an island they by the MATS compliance date of April 2015, with no lack an interconnected external transmission and margin for unanticipated delays. generation network. To corroborate earlier studies, During fiscal year 2013 the Authority continued its the Authority plans to perform refined analyses dur- due diligence on the contractual structure of the gas ing the coming fiscal year; the analyses will identify supply infrastructure and was evaluating alternative the maximum generation from projected renewable supply arrangements for natural gas to the north of energy resources that can be accommodated by the the island. The Authority is evaluating the structure System. As the percentage of renewable capacity of the LNG commodity supply agreements, which increases within the System, the inherent uncertainty would be separate from the infrastructure develop- of these sources imposes conditions on reserves and ment. The Authority plans to select the bases for economic dispatch which could increase overall sys- establishing the development of the natural gas infra- tem electric production costs. Also the electrical char- structure and fuel supply during fiscal year 2014. acteristics of some renewable technologies affect the These will lead to qualifying bidders and soliciting transmission and distribution of electric energy proposals by the end of that fiscal year. requiring the implementation of mitigating technolo- The Authority has focused first on its four largest gies to maintain electric system stability. In 2012 the steam units for dual fuel conversion on the south Authority revised their minimum technical require- coast. The four steam units in the San Juan metropol- ment (MTR) standard, which establishes the techni- itan area will be converted after the schedule for gas cal parameters for integration of renewable projects deliveries has been established. With sufficient fuel into the Authority’s electric system. 60 I 000074 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

In the past fiscal year the Authority began renegotiat- Fiscal year 2013 marked the first year during which ing its agreements with many renewable energy proj- renewable energy sources contributed meaningful ect developers to lower their energy costs to the amounts of the energy transmitted and distributed Authority and incorporate the revised MTR. This has within the System. During fiscal year 2013 the been an on-going process that applies to all new proj- Authority purchased energy principally from four ects as well. renewable energy projects; an additional small wind As of the end of fiscal year 2013 the Authority had turbine provided power occasionally. signed a total of 63 power purchase agreements from The largest capacity renewable source was the Pattern renewable energy projects with a total capacity of wind farm in Santa Isabel, in the southeast of the 1,661 MW. All of these agreements are for only energy. As tabulated, few of these were in operation island. Its initial capacity was planned for 75 MW; by the end of fiscal year 2013. The preponderance of pending certain changes it is anticipated that the the pending projects had not begun construction by facility will operate at 95 MW seven months of the the end of the past fiscal year. The total energy from year and 75 MW for the balance. The second large the operating renewable sources accounted for 0.7% wind farm provides 26 MW from the Punta Lima of the System total during fiscal year 2013. The facility in the east of the island near Naguabo. Both Authority projects the contribution from renewables wind turbine facilities began commercial operations will increase to 4.7% by fiscal year 2015, where it will in December 2012. Finally, the Authority installed a 1 stabilize at that level through 2018. MW wind turbine in the Bechara section of San Juan RENEWABLE ENERGY PROJECTS STATUS that went into operation late in fiscal year 2012. The FISCAL YEAR 2013 turbine is located at a PRASA (Puerto Rico Aqueduct and Sewer Authority) facility which uses basically all Category Number Associated Operating Associated the output. of Projects Capacity Projects Capacity During the past fiscal year the largest solar photo- Wind 10 382.9 3 102 voltaic facility on the island was the 20 MW solar Solar Photovoltaic 46 1157.4 2 22.1 project in Guayama, on the south coast. This plant

Landfill Gas 4 11.5 began commercial operation in October 2012. The 2.1 MW Windmar Cantera Martinό solar facility in Waste-to-Energy 3 109.0 Ponce began operations at 1.7 MW in 2011 and Total 63 1660.8 6 124.1 expanded in October 2012. U.S. Electric Utility y Costs Cost oof Selected Fossil Fue els 2002 - 2013 25.00

20.00

15.00

10.00

5.00

0.00

2002 2003 2004 20005 2006 2007 2008 2009 2010 2011 22012 2013

Coaal Natural Gas Petroleum Liquids

I 000075 61 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

U.S. Electric Utility & PREPPAA Cost of Sele ected Fossil Fuels Ju uly 2011 to July 2013 3 30.00

25.00

2020.00 00

15.00

10.00

5.00

0.00

2011 2011 2011 2011 2012 12 2012 2012 2012 201 012 2 2012 2012 2013 2013 2013 2011 1g 20 1p 20 1t 201120 c 20 1 2012 2012 2012 202012 p 20 t 201220 c 20 2 2013 202013 2013 2013 ug n 20 ar 20 2 ay 20 2n 20 2 n 20 ar 20 3 ay 20 3n 20 3 Jul 20AugA Sep Oct NNov v 20Dec Jan FFeb b 20MMar AApr r 20May Jun Jul 2 AAug g 20Sep 2 OOct NovN v 20Dec Jan FFeb b 20Mar AApr r 20MMay Jun Jul 2

Coal Natural Gas Petro oleum Liquids PREPPAA

FUEL MIX do not isolate the Authority from changes in energy costs in the global market; all production related fuel For information on the types of fuel used in the Authority’s various generating units see the Fuels sec- expenses are currently recovered through the fuel tion under System’s Operations. component of the adjustment charge. The mix of generation by energy type for the The total projected use of each type of fuel—residual Authority’s System during fiscal year 2013 consisted or distillate oils, natural gas and the production from of 54.4% being oil generated, 10.8% from natural gas the cogenerators and renewable energy projects—is at the Authority’s Costa Sur plant, 17.0% from natu- based on the generation required to meet the energy ral gas at the EcoEléctrica’s facility, 16.7% from AES’s demand forecasts which are developed in the Current coal burning facility, and 0.4% from the Authority’s Forecast, as discussed above. The contribution to the hydroelectric plants. The amount of power generated System of power from renewable energy projects is from natural gas in fiscal year 2013 totaled 27.8%, up forecasted to grow from 0.7% in fiscal year 2013 to from 18.9% in the previous year. Fiscal year 2013 more than 4.5% of the total for the fiscal years 2015 marked the first year during which the renewable through 2018. Since the Authority is obliged to energy projects produced meaningful quantities, with always take the power from the renewable energy 0.7% of the System’s generation. project, except in unusual circumstances, the growth As discussed in the Fuels section in System’s of renewable energy projects will displace generation Operations the Authority regularly purchases its fuel from the Authority’s least efficient and most costly oil under one year contracts that include provisions units. The Authority utilizes an economic dispatch for extension. These contracts are structured to simulation of all generating sources in the System to reflect physical clearing prices, and avoid speculation determine the lowest cost generation plan. This dis- in the market. Frequently the Authority uses various patch simulation takes into account the heat rate, strategies such as fixed price contracts and commod- operational characteristics and fuel costs specifically ity hedges to minimize fuel cost volatility. In addition, for each plant. As discussed in the Current Forecast the pricing structures of the two cogenerators are section, this information was developed for the based in part on annual indices to provide stable pric- remaining months of fiscal year 2013 and summa- ing for purchased power. These strategies, however, rized annually for the five-year intermediate-term 62 I 000076 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report forecast through fiscal year 2018. The actual annual are based on EIA indices for the types of fuel oil the results of generation, fuel use and costs for fiscal year Authority burns adjusted for the Authority’s location 2013 and those forecasted over the five-year period and incidental charges. The composite fuel cost is are presented in Appendix IV, Annual Net Generation, based specifically on the mix the Authority has fore- Fuel Consumption, Fuel and Purchased Power Costs. casted to be utilized in its generating units. The fore- Although the data in the charts of the costs of selected casted dispatch and fuel use are shown in Appendix fuel for utilities are based on mainland electric pro- IV, Annual Net Generation, Fuel Consumption, Fuel duction facilities, the oil and coal pricing are indica- and Purchased Power Costs. tive of trends applicable to Puerto Rico. The charts In forecasting the price per barrel of all fuel oil the show the variations in the cost of selected fossil fuels Authority adds $0.40 for transportation and han- on an MMBtu basis as reported to the Energy dling, and also approximately $0.40 for the interest Information Administration’s (EIA), the reporting on the Authority’s fuel credit line and a arm for the Department of Energy; the first chart is on Commonwealth tax of $3.36 is also added to the cost an annual basis from 2002 to 2013, the second shows of distillate fuel oil. These projected fuel costs were monthly data from July 2011 to July 2013. It should used to develop the annual costs of fuel and the fuel be noted that the natural gas data in the chart reflect adjustment revenues in the Authority’s Current pipeline gas, while the only natural gas available in Forecast (See Appendix I, Intermediate-Term Puerto Rico is liquefied natural gas (LNG), which has Financial Planning Forecast). a different and higher pricing basis. This differential Including rented fuel storage tanks, the Authority has in price would be due to the high capital costs of continued to maintain a 30 day inventory of fuel oil. infrastructure to liquefy, store and regasify the LNG, It is noteworthy that the Authority has never had to specialized transportation vessels and the energy con- curtail electric service from fuel oil shortages or from sumed in its liquefaction, transportation, storage and problems delivering fuel to its generating facilities. regasification. AUTHORITY’S FUEL The Authority’s average composite cost of fuel, including transportation and fuel-handling costs and the cost of the fuel line of credit, in fiscal year 2013 was $111.18 per barrel. The composite barrel cost is based on the total cost of all the petroleum burned by the Authority, both distillate and residual oils, plus natural gas, which is equated to distillate on the basis of distillate’s nominal heating value in terms of MMBtu per barrel. During fiscal year 2013 natural gas was burned only at Costa Sur Units 5 & 6. The total costs of fuel for fiscal year 2013 and the five-year forecast period are shown in Appendix III, Detail of Operating and Maintenance Expenses. During fiscal year 2012 the Authority entered into a Commodity Swap Agreement that provided protection against increases in the price of No. 6 fuel oil. The premium for the swap was $29.2 million, which is being amortized from June 2012 to October 2013. The payout to its counterparties amounted to $21.9 million in fiscal 2013 and $141,500 in fiscal year 2012. Based on the Current Forecast, the Authority’s estimated costs of fuel per barrel excluding finance charges, fiscal years 2014 through 2018 are forecasted to be $95.25, $94.67, $88.71, $87.27 and $80.94, respectively. The projected composite average fuel costs per barrel include natural gas, equated to distillate as described above. The forecasted prices of fuel I 000077 63 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

ENERGY SALES FORECAST and Commercial increasing by 4.0%; the two remaining sectors decreased, with Industrial down by 7.2% The Authority’s annual Current Forecast contains and Other by 25.8%. detailed projections of short-to-intermediate-term As shown in the summary table, total sales for fiscal year energy sales and revenues. The methodology and 2014 are projected to increase by 1.3%. The Current results of the Current Forecast are discussed in the Forecast predicts the positive trend will continue with Current Forecast section above. In summary, the growth of 0.4% in fiscal year 2015, 1.1% growth in 2016, Authority typically chooses the least expansive or 1.5% in 2017; and 1.8% growth in 2018. most pessimistic projection over the intermediate five-year period for its financial forecast to account Last year’s Current Forecast projected that energy for the uncertainties inherent in economic forecast- sales would increase at a CAGR of 0.9% over the five- ing. The Authority generally uses projections from year period ending in fiscal year 2017. Based on the three economic consultants. However, as was the case Current Forecast for fiscal years 2014 through 2018 last year, the Puerto Rico Planning Board’s projections electric energy sales are expected to increase with a were not available during the development of the CAGR of 1.2% over the five-year period. Current Forecast, therefore only two economic con- The projected energy sales through fiscal year 2018, sultants projections were used. Each consultant fore- taken from the Authority’s Current Forecast, are sum- casts three key macroeconomic indicators—Gross marized in Appendix I, Intermediate-Term Financial Domestic Product, Gross National Product and Planning Forecast. Personal Disposable Income— which are used with The table for Short-term Energy Sales Forecast data other variables to project the intermediate-term elec- shows kilowatt-hour sales and percent change from tric sales, revenues and number of clients. the prior year by major client classifications for fiscal The energy sales reported for fiscal year 2013 reflect years 2012 and 2013. It also shows the forecasted per- certain adjustments. These were principally carried cent change and kilowatt-hour sales from the prior forward from the last three months of fiscal year 2012 year by major client classifications for fiscal years when the new customer and care billing system went 2013 and 2014 taken from the Authority’s respective into initial operation. While these adjustments did Current Forecasts. not affect revenues, they increased the reported energy sales in fiscal year 2013. Taken together, the SHORT-TERM PLANNING AND adjustments increase reported total energy sales for FINANCIAL FORECAST fiscal year 2013 by 1.4%. The bulk of the adjustments (Million of kWh) were in the industrial class. The projections devel- FY 2012 FY 2013 FY 2013 FY 2014 oped in the Current Forecast did not take into Actual Forecast1 Actual2 Forecast3 account these adjustments for fiscal year 2013, to Residential Sales 6,559.6 6,481.5 6,655.6 6,929.6 avoid skewing the data for the base year of the fore- Annual Increase (2.2%) (0.8%) 1.5% 2.4% casts. In the balance of this Annual Report, however, (Decrease) the energy sales reported for fiscal year 2013 reflect Commercial Sales 8,300.1 8,417.8 8,635.2 8,591.1 these adjustments. Annual Increase (2.9%) (0.3%) 4.0% 1.5% The projected numbers of clients in the residential (Decrease) class are based on an econometric model using regres- Industrial Sales 2,778.5 2,678.3 2,578.4 2,337.5 sion analysis. For the commercial class the econometric model for number of clients uses logarithmic Annual Increase (3.6%) (2.6%) (7.2%) (2.2%) (Decrease) regression analysis as a function of gross domestic 4 product and population. The industrial class has a rel- Other Sales 474.3 354.5 352.0 340.8 atively low number of clients and the forecasted Annual Increase 31.3% 0.0% (25.8%) (1.6%) change in the number of clients was based on extrap- (Decrease) olation of recent years. Total Sales 18,112.5 17,932.0 18,221.2 18,199.0 SHORT-TO-INTERMEDIATE TERM Annual Increase (2.1%) (0.8%) 0.6% 1.3% ENERGY SALES FORECAST (Decrease) 1. From May 2012 Current Forecast In three out of the last five fiscal years there has been 2. Includes adjustments a contraction of energy sales. The reported total 3. From April 2013 Current Forecast energy sales in fiscal year 2013 increased 0.6 % from 4. Other Sales are comprised of Agricultural, Other Public Authorities, the previous year with Residential increasing by 1.5% and Public Lighting 64 I 000078 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

The energy sales statistics for the U.S. cited in the fol- number of residential clients the Authority served lowing discussions are taken from EIA reports: during fiscal year 2013 was 1,353,550—an increase of Annual Energy Outlook 20123 with Projections to 1.0% from the previous year. The Current Forecast 2035 dated June 2013, US Electric Power Monthly - projects that the average number of residential clients September 2013 and Short-term Energy Outlook – will increase by 1.1% in 2014 and continue to September 2013. The U.S. 2012 calendar year energy increase at a CAGR of 1.1% over the five-year period sales are preliminary and 2013 are estimated. 2014 through 2018 as well. RESIDENTIAL SECTOR CONSUMPTION ENERGY SALES In fiscal year 2013 the average annual electric con- Residential sector energy sales increased by 1.5% sumption per residential client was 4,917 kWh, annually in fiscal year 2013 following an annual which was 0.5% more than the previous fiscal year. In decrease in 2012 of 2.2%. Since the start of the eco- spite of the modest increase in the past year, over the nomic downturn on the island in 2006, residential previous five-year period the average consumption of energy sales have dropped 8.2%. Over the past five the residential client decreased by a CAGR of 0.9%. In fiscal years, 2008 – 2013, the CAGR of residential fiscal year 2014 the average residential energy con- electrical energy sales was negative 0.3%. The sumption is forecast to increase by 1.3%. The Current Current Forecast projects that residential energy sales Forecast projects that the residential sector consump- for fiscal year 2014 will increase by 2.4% and projects tion will increase at a five-year CAGR of 0.4% that over the next five fiscal years through 2018 the through fiscal year 2018. EIA data for recent perform- CAGR will increase by 1.5%. ance of the U.S. electric sales are preliminary. According to EIA statistics, the average electric con- The EIA reports the CAGR of residential sales in the sumption of the Authority’s residential clients is U.S. decreased by 0.1% from 2007 – 2012. U.S. resi- approximately 31% of the average electric consump- dential energy sales decreased 2.8% in calendar year tion of residential clients of the U.S. East South 2012 and are estimated to decrease by 0.3% in calen- Central Census Division which consists of the states dar year 2013. The projected five-year compound of Alabama, Kentucky, Mississippi and Tennessee. growth rate in U.S. residential energy sales for calendar years 2013 through 2018 is 0.3%. COMMERCIAL SECTOR CLIENTS ENERGY SALES The average number of residential clients from 2008 Commercial energy sales for fiscal year 2013 increased to 2013 increased at a CAGR of 0.6%, in spite of the 4.0% from the previous fiscal year. This level, however, reported overall decline in the island’s population of was still 1.2% below the corresponding sales in fiscal more than 2% in that same timeframe. The average year 2008. The Current Forecast projects that commer-

Change in Energy Sales and Average Consumption 12.00% Residential Sector 10.00% Energy Sales Average Consumption 8.00% 6.00% 4.00% 2.00% 0.00% -2.00%

Annual Growth Rate Annual Growth -4.00% -6.00% -8.00% 2008 2009 2010 2011 2012 2013 2013 2014 2015 2016 2017 2018

Actual Forecast I 000079 65 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Change in Energy Sales and Average Consumption Commercial Sector 5.00% Energy Sales 4.00% Average Consumption 3.00% 2.00% 1.00% 0.00% -1.00% -2.00% -3.00%

Annual Growth Rate Annual Growth -4.00% -5.00% 2008 2009 2010 2011 2012 2013 2013 2014 2015 2016 2017 2018

Actual Forecast cial energy sales will increase 1.5% in fiscal year 2014 2013 was a modest 0.3%. In fiscal year 2014 the aver- and increase at a five-year CAGR of 1.6% through age energy consumption per commercial client is pro- 2018. In 2013 the government commercial classes con- jected to decrease 0.4%. The Current Forecast projects sumed 32% of commercial energy sales. a CAGR of 0.4% in electric consumption per commer- Based on preliminary EIA data, U.S. commercial energy cial client over the five fiscal years through 2018. sales increased by 0.8% in calendar year 2012 and are According to EIA statistics, the average energy con- estimated to decrease by 1.5% in calendar year 2013. sumption of the Authority’s commercial clients is The preliminary five-year CAGR in U.S. commercial approximately 5.9% more than the commercial energy sales for calendar years 2007 through 2012 is clients of the East South Central Census Division of negative 0.1%. The projected five-year CAGR in U.S. the United States. commercial energy sales for calendar years 2013 through 2018 is 0.7%. INDUSTRIAL SECTOR CLIENTS ENERGY SALES During fiscal year 2013 the average number of com- Industrial energy sales for the fiscal year 2013 mercial clients was 126,735 which was a drop of 1.4% decreased 7.2% compared to the previous year; more from the previous fiscal year. According to the than the previous year’s decline of 3.6%. This past fis- Authority’s June 2013 Governing Board Report, gov- cal year marked the seventh consecutive year that ernment and government agency clients made up industrial energy sales have diminished. Following 18% of the total commercial sector. Over the past five- the client reclassification discussed below, between years the CAGR in commercial clients was negative fiscal years of 2010 and 2013, industrial energy sales 0.5%. In fiscal year 2014 the average number of com- decreased by 15.4%. mercial clients is projected to increase by 1.9%, with During fiscal year 2009 the Authority reclassified 612 continuous increase at a CAGR of 1.2% over the five government industrial clients from the industrial year forecast period through fiscal year 2018. General Service at Secondary Voltage tariff to com- CONSUMPTION mercial tariffs, to lower these clients’ rates. The trans- The average annual consumption per commercial fer of these clients from the industrial to commercial client during fiscal year 2013 was 68,136 kWh for an base reduced the size of the industrial sector by more increase of 5.6% over the previous year. In spite of last than 40%, however, the transferred clients accounted year’s boost, the Authority’s five-year CAGR in con- for less than 10% of the industrial class’s power consumption per commercial client through fiscal year sumption. Due to these changes the industrial sector 66 I 000080 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Change in Energy Sales and Average Consumption Industrial Sector 10.00% Energy Sales 5.00% Average Consumption

0.00%

-5.00%

Annual Growth Rate Annual Growth -10.00%

-15.00%

-20.00% 2008 2009 2010 2011 2012 2013 2013 2014 2015 2016 2017 2018

Actual Forecast chart shows annual average consumption data start- energy sales are forecasted to decrease at a CAGR of ing in fiscal year 2010. 0.5% for the five-year period through fiscal year 2018. To develop the projection of industrial sector electric Preliminary EIA data show total industrial U.S. sales in the Current Forecast the Authority analyzes energy sales increased 1.7% in calendar year 2012 and three groups: refineries and petrochemicals, cus- are estimated to decrease by 0.2% in calendar year tomers with their own generation, and all the other 2013. The preliminary five-year CAGR in U.S. indus- clients; the last group represents more than 93% of trial energy sales for calendar years 2007 through the sector sales. 2012 is negative 0.7%. The projected CAGR in U.S. The smallest group within the industrial sector is the industrial energy sales for calendar years 2013 refineries and petrochemicals plants whose consump- through 2018 is 2.6%. tion in the past fiscal year was approximately 0.4% of CLIENTS the sector total. The electric consumption of refineries and petrochemicals was based on actual data for the The average number of industrial clients served by first nine months of fiscal year 2013, with extrapola- the Authority at the end of fiscal year 2013 was 709, tion for the balance of the fiscal year. The actual con- which was a modest drop from 733 in the previous sumption totaled 9.3 million kWh, which was 19.7% fiscal year. Prior to the reclassification of more than less than the same period of the previous year. 40% of the clients out of the sector in fiscal year 2009, the number of industrial sector clients had been The estimated electric usage of clients with their own declining. During the period of fiscal years 2009 generation facilities for fiscal year 2014 was based on through 2013 the number of industrial clients fell by data from fiscal year 2012 applied uniformly over the 21%, or 189 clients. The Current Forecast projects five years of the forecast. The total projected con- the number of industrial clients will decrease by 28 sumption by the three clients that own generation is clients in 2014 and continue to decrease by approxi- 147.0 million kWh or 6.3% of the total industrial mately 25 clients per year over the next four years, sales in fiscal year 2014. The impact of net-metering resulting in an equivalent CAGR of negative 4.0%. and wheeling tariffs were not considered in the intermediate term projection. CONSUMPTION The Current Forecast projects that in fiscal year 2014 The average annual consumption of industrial clients industrial energy sales will continue to decrease by during fiscal year 2013 was 3,636,652 MWh, a 2.2%, followed by two more years of diminishing sales decrease of 4.1% from the previous year. The average then reversing the negative trend in 2017 gradually industrial consumption for the period from 2010 hitting 0.6% in fiscal year 2018. The industrial sector through 2013 declined 3.6%. The Current Forecast I 000081 67 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report projects the average industrial client consumption previous fiscal year. Total energy sales for the five- will increase by 1.9% in 2014 and will increase at a year period ended June 30, 2013 decreased at a CAGR five-year CAGR of 3.6% through fiscal year 2018. of 1.5%. In the Current Forecast total energy sales are According to EIA statistics, the average energy con- expected to increase by 1.3% for fiscal year 2014, and sumption of the Authority’s industrial clients is increase at a CAGR of 1.2% over the five-year period approximately 62% less than those of the East South ending in fiscal year 2018. Central Census Division of the U.S. The average number of clients that the Authority served during fiscal year 2013 increased by 0.8% to OTHER CLASSES 1,485,150. Over the five-year period ending in fiscal The “Other” sector is comprised of clients in the pub- year 2013 the CAGR in the number of clients was lic lighting, agricultural and other public authorities 0.2%. The total number of clients is projected to classes. In fiscal year 2013 energy sales in this sector increase approximately 1.1% annually throughout the represented approximately 1.9% of the Authority’s next five fiscal year forecast period ending in 2018. total energy sales, a decrease of 25.8% from the previ- The average electric consumption of the Authority’s ous year. Within this group public lighting represents clients in fiscal year 2013 was 12,269 kWh, a decrease approximately 76%, agricultural is 8% and public of 0.5% from the previous year. Over the past five- authorities 16%. The change in energy sales in fiscal year period the CAGR of average consumption was year 2013 was basically due to the drop in consump- negative 1.9%. The Current Forecast projects the tion for public lighting down to historical levels. The average consumption of the Authority’s clients will total number of public lighting clients increased by decrease in fiscal year 2014 by 0.1%, and the future 22% during the previous fiscal year, as the Authority five-year CAGR is projected to increase by 0.1% installed more meters. annually through fiscal year 2018. The Current Forecast projects no change in the num- The preliminary data for total U.S. energy sales show ber of clients in this group and only modest growth of a decrease of 0.3% in calendar year 2012. For calen- 0.3% CAGR over the five-year forecast period ending dar year 2013 total energy sales in the U.S. are esti- in 2018. mated to decrease by 0.6%. The CAGR for the U.S. preliminary total energy sales during the five-year TOTAL ELECTRIC ENERGY SALES period between calendar years 2007 and 2012 is neg- Total reported energy sales in fiscal year 2013 were ative 0.2% and is projected to be 1.1% for the five- 18,221.2 GWh, an increase of 0.6% from those of the year period ending in 2018.

20,000 Total Energy Sales & Number of Clients 1,600,000

MWh Sales 1,580,000 19,500 Clients 1,560,000

1,540,000 19,000 1,520,000

18,500 1,500,000 CLIENTS

MWh Sales 1,480,000 18,000 1,460,000

1,440,000 17,500 1,420,000

17,000 1,400,000 2008 2009 2010 2011 2012 2013 2013 2014 2015 2016 2017 2018

Actual Forecast 68 I 000082 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

RATES RATE SCHEDULES Section 706 of the 1974 Agreement charges the CLASSIFICATIONS AND REVENUES Consulting Engineers to prepare each year a report In order to serve different segments of its clientele, setting forth their recommendations as to any neces- the Authority provides electric service in six client sary or advisable revisions of rates and charges classifications. Ranking these classes in their order of Section 502 of the 1974 Agreement details the Authority’s revenue generated during fiscal year 2013, they are: responsibilities with respect to rates as follows: Commercial, Residential, Industrial, Public Lighting, Public Authorities, and Agricultural. Three of these The Authority further covenants that it will at all classifications—Commercial, Residential, and Indus- times fix, charge and collect reasonable rates and trial—represented 98.1 % of the kilowatt-hour sales charges for the use of the services and facilities fur- and 97.2% of the revenues from the sale of electricity. nished by the System and that from time to time, The remaining three classifications – Public Lighting, and as often as it shall appear necessary, it will Other Public Authorities, and Agricultural – collec- adjust such rates and charges so that the Revenues tively represented the balances of the Authority’s kilo- will at all times be sufficient. watt-hour sales and revenue from the sale of (B) after the outstanding 1947 Indenture Bonds have electricity. been paid or provision has been made for their pay- Four rate schedules apply to the large majority of the ment and the release of the 1947 Indenture: Authority’s client base. These four rate schedules are: (a) to pay the Current Expenses of the System, and GRS (General Residential Service), GSS (General (b) to provide an amount at least equal to one hun- Service at Secondary voltage), GSP (General Service dred twenty per centum (120%) of the aggregate at Primary voltage), and GST (General Service at Principal and Interest Requirements for the next fis- Transmission voltage). These four rate schedules cal year on account of all the bonds then outstand- serve the majority of the Authority’s clients because ing under this Agreement, reduced by any amount they were designed for wide applicability and they deposited to the credit of the Bond Service Account have few, if any, load characteristic requirements. To from the proceeds of bonds to pay interest to accrue broaden their usage, the GSS, GSP, and GST rate thereon in such fiscal year. schedules are available to both commercial and industrial clients. During fiscal year 2013 the core The revenues generated by the Authority’s various rate four rates accounted for 86.5% of the Authority’s kilo- schedules provide the moneys necessary for it to meet all of its obligations as detailed in the 1974 Agreement. watt-hour sales and 87.8% of its revenues from the Among its obligations are: paying the current expenses sale of electricity. of the System; financing future growth by issuing The following table shows the major contribution of Power Revenue Bonds; making deposits to specified these four rate schedules to the Authority’s electric funds; maintaining a minimum specified debt service sale and its total revenue. In each of the largest three ratio; and paying Contributions in Lieu of Taxes. classifications there is dominant rate schedule. For Typically, the client’s bill consists of the appropriate example, although four rate schedules apply to the base rate and an adjustment charge. The base rate Residential classification, the GRS rate schedule encompasses current expenses, i.e. operation and served 87.4 % of the Residential clients’ kilowatt-hour maintenance (O & M) expenses (excluding the cost sales and accounted for 90.0% of the Residential class of fuel and purchased power), monies for funding revenue in fiscal year 2013. Within the Commercial requirements, Contributions in Lieu of Taxes associ- classification seven rate schedules applied in fiscal ated with base rate revenue, depreciation and amorti- year 2013, however, the GSP rate schedule, which zation, insurance, and debt service. The base rate has served 8.1% of the Commercial clients, accounted for three components—a demand charge, a customer 53.4% of the Commercial class revenue. The GSS rate charge, and an energy charge, except for clients that schedule generated the second most revenue in the receive electric service at secondary voltage. The base Commercial classification; it served 91.4% of the rate for clients served at secondary voltage is com- Commercial clients and accounted for 28.4% of the prised of a customer charge and an energy-related Commercial class revenue. While thirteen rate sched- charge. The adjustment charge has two components: ules applied to the Industrial classification in fiscal the charge for purchased fuel and the charge for pur- year 2013, the GST rate schedule, which served chased power. (For a discussion of these charges see 30.7% of the Industrial clients, accounted for 45.7% Adjustment Charge below.) of the Industrial class revenue. I 000083 69 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

SUMMARY OF CORE RATE SCHEDULES The current rate schedules are comprised of more than ALL CLASSES 80 subcategories to accommodate various service levels and load profiles; the Authority presently serves all Per Cent of Per Cent Price Range• Total MWH Sold of Total Revenue cents/kWh clients under 42 of the subcategories. Six of the rate schedules are common to both the commercial and General the industrial classifications. Some of the rates serving Residential Service 31.9% 31.1% 25.78 few clients with low consumption are consolidated in General Service the Rates Table presented in this report. Secondary Voltage 12.4% 14.3% 30.47 – 31.54 As shown on the Rates Table, the average cost per General Service kWh for all power sold by the Authority was 26.46 Primary Voltage 26.0% 27.7% 28.25 – 28.63 cents during fiscal year 2013. The lowest average cost General Service among the four popular rate schedules was 23.87 Transmission Voltage 16.2% 14.7% 24.22 – 23.87 cents/kWh for GST - Industrial, with the highest aver- * Commercial – Industrial Classes age cost being 30.47 cents/kWh for GSS - Industrial.

RATES TABLE Average Total Average Average Total Average Total Total Rate Schedule Number Revenue Cost Rate Schedule Number Revenue Cost of Clients MWh ($000)1 Cents/kWh2 of Clients MWh ($000)1 Cents/kWh2 Residential Class3 Other Classifications 103-104 (RH-3) 7,624 21,763 5,291 24.31 Public Lighting 105-107 (RH-3) Revised 40,194 247,174 20,432 8.27 2-41 (Non Meter P/L) 877 235,313 104,274 44.31 109,110 (LRS) 162,459 566,651 140,998 24.88 72 (PLG Bus Shelter) 3 435 127 29.20 111,112 (GRS) 1,143,273 5,820,008 1,500,420 25.78 73 (PLG Police) 5 33 8 25.26 Total Residential Class 1,353,550 6,655,596 1,667,141 25.05 414 (LP-13) 10 3,065 984 32.11 Commercial Class 421 (PLG) 103 1,926 596 30.94 060 Telephone Booth 59 10 3 32.35 422 (PLG) 78 1,319 362 27.44 070-080 Cable TV 17 13,730 4,111 29.94 423 (PLG) 712 4,146 1,176 28.35 082 Security Cameras 166 96 38 39.58 424 (PLG) 1,138 19,163 5,283 27.57 211 (GSS) 115,866 2,252,521 686,272 30.47 050-056 (Dusk to Dawn) 0 2,922 726 24.85 212 (GSP) 10,270 4,567,496 1,290,545 28.25 Total Public Lighting 2,926 268,322 113,537 42.31 213 (GST) 357 1,793,680 434,508 24.22 Agricultural 862 1 7,632 2,004 26.26 711 (GAS) 1,227 27,277 7,585 27.81 Total Commercial Class 126,735 8,635,165 2,417,481 28.00 Total Agricultural 1,227 27,277 7,585 27.81 Industrial Class Public Authorities 311 (GSS) 135 4,841 1,527 31.54 513 (GST-Public Authority) 3 56,436 13,342 23.64 312 (GSP) 304 164,060 46,973 28.63 Total Public Authorities 3 56,436 13,342 23.64 313 (GST) 217 1,152,052 274,941 23.87 Total Other4 Classifications 4,156 352,035 134,463 38.20 333 (LIS) 2 214,301 47,024 21.94 Total 1,485,150 18,221,182 4,821,348 26.46 343 (PPBB) 2 1,157 1,865 161.24 1 Includes the Adjustment Charge. 2 363 (TOU-T) 13 422,922 96,843 22.90 Calculated differences are due to rounding. 3 Includes the residential fuel subsidy. 393 (SBS-T-TOU) 1 40,963 9,989 24.39 4 Includes Public Lighting, Agricultural and Public Authorities classes. 603 (SR-GST) 20 300,158 62,070 20.68 613 (SR-GST) 5 67,939 15,016 22.10 623 (SR-TOU-T) 1 13,202 2,675 20.26 653 (SR-TOU-T) 5 93,096 20,860 22.41 753 (SRTOU-T) 2 70,817 15,461 21.83 963 (TOU-T) 2 32,879 7,014 21.33 Total Industrial Class 709 2,578,386 602,263 23.36 70 I 000084 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

The Authority’s ten largest non-governmental agency sequently the second cogenerator, AES-PR; the pur- industrial clients accounted for 27.2 % of the classifi- chased power charge also applies to the renewable cation’s consumption and paid an average of 22.55 power sources that began to come on-line during the cents/kWh during fiscal year 2013. This was 3.5% less past fiscal year. The rate structure revision also than the industrial class average. removed the $2.00 per barrel fuel charge from the The Rates Table shows all the rate schedules in use base charge and included all fuel related charges in during fiscal year 2013 by the Authority’s clients, with the newly defined adjustment charge. The fuel charge the average number of clients, total annual power and the purchased power charge, both of which sales, total revenue and average pricing for each rate became effective June 5, 2000, are collectively shown schedule. on the client’s bill as the adjustment charge. RATE STABILIZATION FUND In May 2013 the Authority implemented revisions to recover the costs of renewable energy credits associ- Beginning in December 2011 the Authority imple- ated with the purchased renewable energy. At the mented a temporary program to provide a measure of same time the Authority revised the fuel adjustment rate relief to General Residential Service (GRS) clients to explicitly include natural gas. who were current in their payments, consumed more than 425 kWh per month, and did not otherwise The base rates and demand charges were not revised receive any other subsidy. This Rate Stabilization Fund with the adjustment charge discussed above and was funded as part of a line of credit from the have remained unchanged since they were estab- Government Development Bank (GDB) and was lished in 1989. directed to reducing the monthly fuel adjustment The Authority invoiced $3,707.3 million through the charges to maintain parity with the fuel charges from adjustment charge in fiscal year 2013: $2,862.0 mil- September 2011. The program was revised late in May lion for fuel and $845.3 million for purchased power. 2012, with the same general objective; the new fuel The adjustment charge constituted 76.9 % of the stabilization program was established for 180 days. Authority’s $4,821.3 million in electric revenue. During fiscal year 2013 the Authority used the Rate PRICE COMPARISONS Stabilization program to subsidize a total of $53.2 The Authority’s average price per kilowatt-hour varies million in residential client fuel adjustment credits. significantly among its client classifications. The RATE STRUCTURE Power Producers’ at Bus Bar Rate paid the highest average cost of 161.24 cents/kWh, which reflects the Prior to October 1999 the Authority’s electric service recurring high demand charges relative to infrequent rates consisted primarily of a base charge and a fuel consumption; the average cost for this service was adjustment charge. During that period the base 55.97 cents/kWh during the previous fiscal year. The charge included a fuel charge of $2.00 per barrel. The most expensive widely used rate was Commercial fuel adjustment charge recovered the Authority’s fuel- General Service at Secondary voltage, with an average related costs in excess of the $2.00 in the base charge. of 30.47 cents/hWh. The lowest cost service was the For clients served at secondary voltage (such as the Residential Public Housing Rate - Revised with the entire residential class) the base rate included a average cost of 8.27 cents/kWh. These price varia- demand component, whereas for clients served at pri- tions are attributable to the differences in the cost of mary and transmission voltages the demand charge providing public service and socioeconomic objec- was a separate component of the bill. tives of the Commonwealth government and the The fuel adjustment clause was revised by the Authority. Authority in November 1999 to recover the cost of The average prices in cents/kWh for the Authority, purchasing power from EcoEléctrica, a cogeneration Hawaii, and the U.S. are shown in the following table plant, during its test and start-up period. On March for the year ended June 30, 2013. The data for the 28, 2000, following the required public hearing, a State of Hawaii are provided because its geographical permanent revision of the Authority’s rate structure characteristics and fuel mix are similar to Puerto was approved that incorporated a purchased power Rico’s. The U.S. Department of Energy - Energy charge in the electric service rates to recover its cost Information Administration (EIA) data were used as of purchased power from the EcoEléctrica plant. a reference to derive the pricing for the State of Since then the purchased power charge has been Hawaii and the U.S. The U.S. data are comprised of all applicable for purchases from EcoEléctrica and, sub- fifty states and Washington D.C. I 000085 71 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

2013 AVERAGE PRICE COMPARISON over the previous fiscal year’s level. The (Cents/kWh) Commonwealth’s contribution to the fuel charge subsidy program is deducted from the electric energy Authority Hawaii U.S. sales Set Aside. (See Contributions in Lieu of Taxes Residential 25.05 33.87 11.97 and Other section). Commercial 28.00 32.30 10.19 Until fiscal year 1992, the residential fuel subsidy was Industrial 23.36 28.21 6.78 paid by the Commonwealth and was recorded as a All Classes 23.46 31.20 9.98 receivable by the Authority. By the end of fiscal year 1991, the Commonwealth owed the Authority $94.9 SUBSIDIES AND CREDITS million for the fuel charge subsidy program. In In accordance with various Commonwealth laws and October 1991, the Authority and the Commonwealth regulations, the Authority provides subsidies to low entered into a non-interest bearing, fifteen-year pay- consumption residential clients, energy conserving ment plan for payment of this past due amount. In hotels, charitable organizations, agricultural clients, June 2004, the Legislature of the Commonwealth of low-income clients with life sustaining equipment and Puerto Rico superseded the 1991 agreement with a small water companies distributing potable water. revised agreement containing an eight-year payment The Authority’s subsidies and credits benefited an schedule that totaled $55.7 million. This amount average of 484,227 clients in fiscal year 2013, which is includes an allocation for past due Commonwealth approximately 33% of its client base. The total cost to government account receivables and the unpaid bal- the Authority for the benefits credited to these clients ance of the fuel adjustment subsidy. The during fiscal year 2013 was $80.0 million. The partic- Commonwealth made its final payment to the ipation rate and cost to the Authority were unchanged Authority of $6.3 million in fiscal year 2013. from the previous fiscal year. Funds for these subsidies The Authority pays the entire fuel subsidy for all res- were drawn from the Set Aside moneys discussed in idential rate classifications until the price of oil the Contributions in Lieu of Taxes and Other section in reaches $18.00 per barrel. Once the price of oil the Financial section. exceeds $18.00 per barrel, the Commonwealth pays RESIDENTIAL FUEL SUBSIDY (by means of the electric energy sales Set Aside) the incremental price until it reaches $30.00 per barrel. Under provisions of Act No. 106 of the Legislature of This subsidy amount is capped at $100 million per Puerto Rico, approved on June 28, 1974, the year. The client pays the incremental amount over Commonwealth began to subsidize the fuel adjust- $30. For the other recipients of the residential fuel ment charge (now the fuel charge, a component of subsidy, the Commonwealth pays (once again, by the adjustment charge). In 1991 the subsidy qualifi- means of the electric energy sales Set Aside) the entire cation criteria were made more restrictive, to focus subsidy up to $30.00 per barrel. The Authority’s the subsidy on those clients truly in need. The new monthly average cost of fuel in fiscal year 2013 criteria are still in place and apply to the Authority’s ranged from a low of $105.69 per barrel in November residential clients who consume up to 425 kilowatt- 2012 to a high of $120.51 per barrel in February hours of electricity monthly or 850 kilowatt-hours bimonthly and meet the following criteria: those on 2013. The weighted average fuel cost for the fiscal the “Lifeline” residential rate (LRS), the government- year 2013 was $111.18 per barrel, which is down over administered public housing rate (RH-3), full-time 6% from the previous year. students, the handicapped, and those 65 years of age The residential fuel subsidy applies to the fuel adjust- or older. Additionally, all fuel subsidy recipients must ment charge for service at secondary voltage. The be permanent residents of the Commonwealth of subsidy for qualifying residential clients is a sliding Puerto Rico and may receive the subsidy on only one scale percentage that corresponds to their monthly dwelling. The subsidy is provided in the form of a consumption level. As shown on the table below, the credit against the recipient’s electric bill. During fiscal subsidy percentage decreases as monthly consump- year 2013, there were an average of 302,771 clients or tion increases. The subsidy is not cumulative through 22% of the total residential classification who quali- the incremental blocks of consumption; for example, fied for subsidization. The purchased power compo- a client with a monthly consumption of 325 kWh nent of the adjustment charge is not subsidized. would receive a 55% subsidy of the fuel adjustment The residential fuel subsidy was $26.4 million during charge. There is no subsidy if the monthly consump- fiscal year 2013, which represented a 9.6% decrease tion exceeds 425 kWh. 72 I 000086 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Monthly % of Total Fuel form of a credit on the client’s bill. During fiscal year Consumption Component 2013, an average of 210 establishments benefited (kWh) Subsidized from the $8.9 million in hotel subsidies. 0-100 90 CHARITABLE ORGANIZATIONS SUBSIDY 101-200 75 This subsidy applies to charitable organizations, such 201-300 65 as churches, which provide services to the commu- 301-400 55 nity at no charge. The subsidy enables any qualifying 401-425 * charitable organization to use the GRS rate (average cost of 25.78 cents/kWh during fiscal year 2013) in Over 425 0 place of the other applicable commercial rates (30.47 *For the first 400 kWh of consumption, 55% of the fuel charge will be cents/kWh for GSS or 28.25 for GSP). Applying the subsidized; over 400 kWh the client will be charged 100% of the fuel charge for each additional kilowatt-hour up to 25 kWh. GRS rate in place of the GSS rate reduced the client cost by almost 15% in fiscal year 2013, while the GRS RESIDENTIAL RATE SUBSIDY rate in place of the GSP rate saved 9%. The Authority serves its residential clients using four The Authority subsidized $4.7 million to serve an aver- rates—GRS, LRS (Lifeline), and RH-3 (Public age of 4,390 charitable organizations in fiscal year 2013. Housing) and a revised RH-3 rate. In fiscal year 2013, 84.5% of its residential clients were served using the LIFE PRESERVATION SUBSIDY GRS rate. The remaining residential clients were The Life Preservation subsidy is available to qualify- served using the LRS and RH-3 rates that are reserved ing low-income clients who require electrically pow- for those who qualify as low-income; these rates have ered essential medical equipment. The subsidy lower customer and energy charge components as provides full credit for the electrical consumption of compared to the GRS Rate. the medical device, based on the certification of need During fiscal year 2013 the Authority served on aver- and hours of operation established by a physician age 210,277 residential clients under the rates of LRS, from the Department of Health of Puerto Rico. RH-3, and RH-3 Revised, which is discussed in This subsidy served approximately 4,800 clients and Selected Rates. In the past fiscal year an average of amounted to $4.6 million in fiscal year 2013, a 165,726 clients or about 12% of the residential clients decrease from the $5.1 million cost in the previous received the base rate subsidy at a cost to the fiscal year. Authority of $15.6 million, little changed from the $15.4 million subsidy in fiscal year 2012.. AGRICULTURAL SUBSIDY The Agricultural service rate (GAS) is available to HOTEL SUBSIDY PROGRAM farmers, animal breeders and rural irrigation water Under Act No. 101 of July 9, 1985, the Authority suppliers. This rate is available for the clients whose started providing an 11% discount on its monthly load is up to 50 kVA. If the Authority did not provide electric bills to hotels that are certified by the Puerto the GAS rate to these clients they would be served Rico Tourism Company. This subsidy is designed to under the more expensive GSS-Commercial rate. In help conserve energy and promote tourism. In order fiscal year 2013 the average price differential between to qualify for this discount the hotels are obligated to: the GSS-Commercial and GAS rates provided approx- develop programs for conserving and using energy imately a 9% reduction in costs to qualified clients. more efficiently; submit evidence annually to the This subsidy served an average of 1,278 clients, with Commonwealth’s Energy Affairs Administration, their cost savings totaling $549,600 in fiscal year 2013. which administers the program, showing that they are implementing their programs; and remain current IRRIGATION SERVICE SUBSIDY in paying their electric bills. Small hotels are only The Authority originally was constituted as the required to demonstrate compliance every five years. Puerto Rico Water Resource Authority which gener- If a participating hotel does not pay its bill within 60 ated power from hydro-electric facilities. It included days, the hotel can be dropped from the program. dams and infrastructure that also provided most of Act No. 266 of November 16, 2002, amended several the island’s water. The Authority still maintains juris- articles of Act No. 101. The most notable change was diction over all dams on the island, however the the reduction in the number of rooms required to Puerto Rico Aqueducts and Sewers Authority qualify for the discount from fifteen to only two. This (PRASA) is the current public agency that is respon- subsidy, like the residential fuel subsidy, takes the sible for the water system on the island. I 000087 73 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

As part of its legacy responsibilities the Authority pro- The Authority provides a 10% credit for power, up to vides certain technical and maintenance services for a maximum of $40 per month, to small commercial dams that supply PRASA and some irrigation users. clients with less than seven employees on the weekly During fiscal year 2013 the Authority incurred costs payroll. This credit applies for up to three years. of $5.6 million for these services. During fiscal year 2013 the credit provided was approximately $1,790 to six clients. COMMON AREA LIGHTING SUBSIDY Act 1060 passed by the Commonwealth’s legislature SELECTED RATES in August 2008 established that lighting for common Over the last decade the Authority has developed a areas of condominiums will be served under a rate number of specialized rates to address certain pricing based on general service residential (GRS). In fiscal and operational issues for some of its residential pub- year 2013 the average cost savings per kWh was lic housing, large commercial and industrial clients. almost 15% and totaled $1.3 million for condo- By design, these rates have limited applications. The minium common area lighting. commercial and industrial rates are almost exclusively available to clients purchasing power at the OTHER SUBSIDIES AND CREDITS transmission level. The manufacturing industrial credit is provided to all PUBLIC HOUSING RESIDENTIAL RATE new manufacturing industry clients and to the clients who expand their business operation. During fiscal As shown in the Rates Table, approximately 3.5% of year 2013, the Authority provided its manufacturing the Authority’s residential clients are served by the RH-3 public housing rate. In August 2009 the industry users a credit of $10.8 million to an average Commonwealth enacted legislation, under Act No. 69, of 28 clients; the credit amounted to an increase of entitled Special Law for Pricing Justice of Utilities for approximately 7% over the previous fiscal year. This Public Residents. The Special Law provides simplified credit is discussed below in Special Rates. low cost water and electric utility rates for qualifying As discussed in the Contributions to the Common- low income residents of public housing. The new elec- wealth section, the Economic Incentives Act of 2008 tric rates went into effect in February 2010, under the requires the Authority to provide certain energy credits scope of RH-3 Revised. The rate structure establishes for qualifying businesses; the costs of the energy cred- flat monthly charges based on the number of rooms: its are shared between the Commonwealth and the $30 for one room, $40 for two or three rooms, and $50 Authority and are applied to the qualifying business’s for four or five rooms. The rate applies for usage up to income taxes. During the ten year term of the legisla- 425 kWh per month. For a client to transition from tion the Authority’s share steadily increases from zero RH-3 to the RH-3 Revised tariffs there must be an to 80% of the credit. In fiscal year 2013 the Authority’s agreed payment plan if there are any overdue invoices. costs associated with this legislation were $1.2 million, By the end of fiscal year 2013, over 84% of the total based on tax credits for seven qualifying businesses. RH-3 clients had opted for the RH-3 Revised rate. In 2004 a subsidy was established for cooperative During the last fiscal year the clients served under the water companies that provide potable water to rural RH-3 Revised rate consumed approximately 92% of communities which were either not served or inade- the total RH-3 power and contributed approximately quately served by PRASA. In order to qualify for the 79% of the total RH-3 revenue. subsidy, the rural water company must be registered SPECIAL RATES with the Commonwealth, its operation must meet In order to promote an increase in industrial develop- Commonwealth health standards and the water qual- ment in Puerto Rico, the Authority instituted five new ity must comply with US EPA criteria. During fiscal special rates. These special rates offered a discount for year 2013 an average of 14 rural water companies new industries and expansion of existing industrials took advantage of this subsidy and received a benefit on or after February 2002. New industrial clients of approximately $3,900. received a discount of approximately 11% on their Since July 2, 2007, the Authority has allowed a 10% total electric bill. Also, existing industrial clients that credit on its residential clients’ basic rate charge for expanded their operations received a discount of those clients who are current in their payments and approximately 11% on the demand, energy, and pay the Authority directly from their personal bank adjustment charges associated with its expansion. account. In fiscal year 2013 approximately 3,900 res- These rates were available for five years effective July idential clients took advantage of this credit and 30, 2003. While these rates expired on July 30, 2008, saved almost $128,400. they are available to existing users to complete the 74 I 000088 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report balance of their five year term. During fiscal year In May 1996, the Authority’s Governing Board 2013 these rates benefited qualifying industrial adopted Resolution Number 2160, which approved clients with savings of $14.3 million; the savings were revised load requirements, thereby increasing the $18.8 million in fiscal year 2012. The five special number of clients eligible for TOU rates. At the end of rates are designated as follows: fiscal year 2013, a total of 24 clients were served • General Service at Transmission Voltage- under these rates, resulting in $152.8 million in rev- Special (SR-GST) enues, which was approximately 25% of the total industrial classification’s revenue. One of these clients • Time of Use Rate at Transmission Voltage- was served under the SBS-T-TOU (standby service at Special (SR-TOU-T) transmission voltage) rate discussed below. • Large Industrial Service 115 kV-Special (SR- LIS) The average cost for all the TOU rates in fiscal year 2013 was 22.68 cents/kWh, however, the costs for • Standby Service at Transmission Voltage- separate rates varied considerably based on the pat- Special (SR-SBS) and tern of client utilization and load characteristics. • Time of Use Rate-Cool Storage Air Amongst this group of rates the most frequently used Conditioning Systems-Special (SR-TOU-C) was the TOU-T (time of use at transmission voltage) Only three of these rates —SR-GST, SR-TOU-T, and rate which accounted for more than 63% of the TOU SR-SBS-TOU-T— were used during fiscal year 2013. revenues. Thirteen clients were served using the The SR-GST rate was used by 25 clients with a com- TOU-T rate at an average cost of 22.90 cents/kWh. bined average cost of 20.94 cents/kWh. The SR-TOU- The second largest energy sales and revenues of this T Rate served six clients at a combined average cost group was the standby service rate discussed below, it of 22.14 cents/kWh; the SR-SBS-TOU-T Rate served provided almost 15% of the TOU revenue. two clients with an average cost of 21.83 cents/kWh.. The remaining TOU rates accounted for 21% of the LARGE INDUSTRIAL SERVICE RATE energy sales and revenues for this group. Six clients were served under SR-TOU-T rates. The SR-TOU-T In September 1997, the Authority adopted the Large Rates are available under Special Rates to manufactur- Industrial Service (LIS) rate in order to encourage ing clients who are either new or have added to their large industrial clients to remain part of its client electric load during the past fiscal year. The last TOU base. To be eligible for this rate clients must meet the rate utilized in fiscal year 2013 was the TOU-T rate, following criteria: receive service at 115 kV; have a which applies to industrial clients who have a load demand of 12,000 kW or greater; a minimum load demand of 1,000 KVA to 3,000 KVA. During fiscal factor of 50% (see following discussion); and an aver- year 2013 this TOU-T rate served two clients at an age monthly power factor of 95% or more. In view of average cost of 21.33 cents/kWh. the declining industrial client base, the Authority has relaxed the previously required 80% load factor to Another available TOU rate is the Cool Storage Air 50% for LIS and SR-LIS through January 2016. The Conditioning Systems (TOU-A/C) commercial rate. 50% load factor, however, is then the minimum basis Although this rate has been in existence for almost for monthly billing. The Authority has served two two decades, it attracted few clients and the last one industrial clients under the LIS rate for the past three changed to a conventional rate several years ago. fiscal years, up from only one client in fiscal year STANDBY SERVICE RATE 2010. The average cost per kWh for this rate was 21.94 cents/kWh in fiscal year 2013, up approxi- The Standby Service Rate (SBS) is applicable to indus- mately 2% over the previous fiscal year. trial or commercial clients who generate power for their own use and not for resale. This rate schedule TIME-OF-USE RATES provides four levels of service: supplementary, auxil- Time-of-Use (TOU) rates are a component of the iary, maintenance, and interruptible power. When the Authority’s Demand-Side Management (DSM) pro- client’s generator is unable to generate enough power gram. (For a discussion on the DSM program refer to needed to satisfy its load, whether because of a limi- the Demand and Energy Forecast section.) These rates tation or a scheduled or forced outage, then the client are designed to encourage shifting consumption from starts to receive its needed power automatically from on-peak hours to off-peak hours when the total system the Authority. The demand, customer, and energy- demand is otherwise lower. The Authority has several related costs for this rate are the same as those in the TOU rates; currently these rates are only offered to the corresponding service class that would apply, namely Authority’s commercial and industrial clients. GSP, GST, TOU-P, or TOU-T rates. I 000089 75 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

During fiscal year 2013 there was only one standby COST OF SERVICE rate in use. It served one industrial client utilizing the A cost of service study is an analytical tool that deter- SBS-T-TOU rate, discussed above. The average cost of mines the proper allocation of capital investment and the SBS rate for this industrial client was 24.39 expenses associated with providing electric power to cents/kWh. The Authority received $10.0 million in various clients. The results of the studies are used revenue from the sale of 40,963 MWh under this rate. when designing various rate schedules. POWER PRODUCERS AT BUS BAR RATE The Authority’s most recent cost of service study was In March 2000, the Authority’s Governing Board, performed using data from fiscal year 2011. This under Resolution Number 2812 approved the Power study employed methodologies that are commonly Producers at Bus Bar (PPBB) rate. This rate, which accepted in the electric utility industry. The study became effective in June 2000, is only available to results included the allocation of costs and revenues, large power producers who are connected at 230 kV as well as an analysis based on rate base and its rate and have a power purchase agreement with the of return Authority for all its electrical output. In addition, the The revenues, expenses and recovered cost percent- power producer must have at least an 85% equivalent age from the cost of service study based on fiscal year availability. Under this rate a power producer can 2011 for the major classes of service are tabulated : purchase power from the Authority for startup, scheduled maintenance, and for backup power. COST OF SERVICE RESULTS BASED ON 2011 DATA Presently, only EcoEléctrica and AES-PR qualify for ($ millions) Cost to Recovered Cost this rate. The black-start energy requirements for Rate Schedule/Class Revenues these two power producers are 12.0 MW and 38.7 Serve Percentage MW, respectively. The Authority generated approxi- Residential 1,586.4 1,851.9 85.7 mately $1.9 million in revenues from the sale of 1,157 Commercial 2,115.4 2,050.6 103.2 MWh of power to the two cogenerators in fiscal year Industrial 598.7 590.6 101.4 2013. The average cost for this rate was 161.24 cents/kWh during the past fiscal year. Other Classes 125.1 201.9 62.0 It should be noted that the results of a Cost of Service SECURITY CAMERAS RATE study are not the only criteria used to design rates. As part of an increased public safety program The Authority uses other important criteria including throughout the Commonwealth, security camera sur- socioeconomic, energy conservation, and load man- veillance systems and wireless telecommunication agement objectives. equipment have been installed on the Authority’s poles and structures. CONSULTING ENGINEERS RECOMMENDATION The Authority instituted a temporary rate for The 1974 Agreement stipulates that after payment of unmetered small load service (USSL) in July 2007 all current expenses, the remaining net revenue and subsequently added this new rate in its rate struc- must equal or exceed 120 per centum of outstanding ture in January 2008. The rate is applicable to all debt service. The Consulting Engineers monitors on security cameras and communication equipment an ongoing basis that the Authority’s rate schedules installed on the Authority’s electric poles anywhere will generate sufficient revenues to pay its current on the island. Before installation of these security expenses and have adequate debt service coverage. devices, the client is required to provide all equip- The Authority’s debt service coverage ratio for fiscal ment specifications to the Authority’s Director of year 2013 was 1.38. The debt service coverage for Transmission and Distribution. The electric con- fiscal year 2014 is forecasted to be 141% based on sumption for each installed security camera may not the Authority’s Annual Budget discussed in the exceed 200 kWh per month. Financial section. During fiscal year 2013 an average of 166 clients used this rate. The average monthly consumption was 48 kWh per client, which was less than one-half the average consumption in the previous fiscal year. Their average cost was 39.58 cents per kWh for fiscal year 2013. 76 I 000090 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

FINANCIAL respectively. The Authority’s income statements (including interest income) for fiscal years 2013 The financial data used in this Annual Report are through 2018 are presented in Appendix II, Income based on statements in the Authority’s Audited Statement. Revenues from electric sales are shown on Financial Statements and on information provided by Appendix I, Intermediate-term Financial Planning the Authority. The Authority’s Audited Financial Forecast which breaks down the revenues by sector Statements prepared by the Authority’s Auditors for and the three components that the revenue is based fiscal year 2013 includes Schedules II through VI, on—the base revenue, the fuel adjustment charge and which present certain information in accordance with the purchase power adjustment charge—for the six the 1974 Agreement, including a reconciliation of Net year period 2013 through 2018. Revenues under generally accepted accounting prin- As shown on Appendix I, base revenues from sales of ciples with the 1974 Agreement. The primary differ- electricity for fiscal year 2013, excluding fuel and pur- ences are Net Revenues under the 1974 Agreement chased power costs that are included in the adjust- excludes depreciation expense, other post-employment charge, were $1,114,052,000 and are forecasted ment benefits and payment on Power Revenue Bonds to be $1,109,790,000 for fiscal year 2014 or a decrease debt service. The financial data in the Annual Report of 0.4%. The base revenue projections move with the are based on accrual basis accounting. forecasted energy sales for fiscal years 2015 through ANNUAL BUDGET 2018, shown in the first category of the appendix as kWh sales. The Annual Budget, prepared in conformance with Section 504 of the Trust Agreement, consists of four As discussed in the Rates section the Authority had a statements and two exhibits. The four Statements are: temporary rate stabilization program in effect during a pro forma income statement for the ensuing fiscal the first five months of fiscal year 2013. The program year; a projection of capital expenditures also for the effectively subsidized certain residential clients for ensuing fiscal year; a summary of capital expenditures $53.2 million. The reported revenues for the residential sector reflect this 3.2% reduction. and the sources of construction funds to support the expenditures; and a schedule of funds to be provided EXPENSES by the Government Development Bank for Puerto The Authority’s budget for Current Expenses for fiscal Rico (GDB). The two exhibits are a five-year projec- year 2013 and the amounts actually expended, as well tion of debt service and Contractual Obligations and as those budgeted for fiscal year 2014, are tabulated for Contributions in Lieu of Taxes and Other. The Annual reference. Expenses incurred during fiscal 2013 were Budget for fiscal year 2013 that is referenced in this more than those budgeted by 2.1%. Extracting fuel and report was prepared by the Authority during the last purchased power the variance was 10.7% more than quarter of fiscal year 2012. that budgeted. The Proposed Annual Budget of Current Expenses The current expenses for fiscal year 2014 are forecast to and Capital Expenditures – Fiscal Year 2013-2014 was be 10.3% less than actual expenses in fiscal year 2013. approved by the Consulting Engineers and adopted by The projected reduction in current expenses in fiscal the Governing Board in May 2013. year 2014 is based primarily on the cost of fuel pro- REVENUES jected to decrease by 17.6% and a 2.3% drop in the budget for other current expenses, except purchased Total revenues booked for fiscal year 2013 were power, which is projected to increase by 6.6%. Over the $4,850,816,378 or 4.0% less than the previous years’ five-year intermediate forecast current expenses other actual results, but within 0.2% of the forecasted rev- than fuel and purchased power are projected to enues. The decreased revenues were primarily the decrease by 2.4% in 2015, then increase by 1.1% in result of lower fuel costs and therefore lower fuel 2016, increase 0.3% in 2017 and be unchanged in 2018. adjustment charges. Total revenues for fiscal year 2014 are forecasted to be $4,494,211,000 or an annual OPERATING AND MAINTENANCE decrease of 7.4%. The Authority’s projected revenues EXPENSES for the five-year intermediate forecast include $30 mil- In fiscal year 2013, total Operating and Maintenance lion each year for billings of power lost to theft as a (O&M) expenses were $4,125,390,000 and for fiscal result of the significant initiative to recover these years 2014 through 2018 are forecasted to be losses. For fiscal years 2015 through 2018 total $3,700,008,000, $3,734,895,000, $3,716,576,000, revenues are forecasted to be $4,558,037,000, $3,749,204,000 and $3,671,427,000. Appendix III, $4,538,771,000, $4,589,252,000, and $4,519,866,000, Detail of Operating and Maintenance Expenses, I 000091 77 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report shows O&M expenses by category for fiscal years decrease by 2.3% in fiscal year 2014 from fiscal year 2013 through 2018. 2013 actual costs; the reductions are in operations, The cost of fuel is the largest component of O&M while the maintenance budget is increased 9.1% for expenses. During fiscal year 2013 approximately 65% the same time frame. The Authority’s Expenses of the System’s energy was generated by the budget is projected to drop 2.4% in fiscal year 2015, Authority’s fossil fuel plants, with a total fuel cost of then increase 1.1% and 0.3% in fiscal years 2016 and $2,603.6 million; this constituted 63.1% of the total 2017, and remain unchanged in 2018. The Authority O&M expenses for the year. The total cost of fuel for has identified various cost reduction programs which fiscal year 2014 is forecasted to be 17.6% less than the were being evaluated at the end of the last fiscal year. actual costs in fiscal year 2013, driven by forecasted Coupling these measures with reductions in the num- near term decreases in oil prices and the increased use ber of employees by attrition provides the bases for of natural gas at the Authority’s Costa Sur steam achieving the forecasted budgets of the Authority’s plant. The costs of fuel in fiscal year 2013 and the Expenses. forecasted costs during fiscal years 2014 through The ratio of O&M expenses to total operating rev- 2018, including the type of fuel, are discussed in the enues in fiscal year 2013 was 85.0%, but is projected Capacity and Energy Resource Planning section to be approximately 82% throughout the five-year above. In addition, Appendix IV, Annual Net forecast period, based in part on the reductions in Generation, Fuel Consumption, Fuel and Purchased Power Costs, shows the cost of fuel and the generat- O&M expenses discussed above. ing efficiency (kWh generated per barrel) for each NET REVENUES major generating facility. Actual data are shown for fiscal year 2013 and forecast data through 2018. Net Revenues, as defined under the Trust Agreement, are shown in Appendix II, Income Statement, as In reference to Appendix III, Detail of Operating and Balance to Revenue Fund. During fiscal year 2013 Net Maintenance Expenses, the forecasted breakdown of Revenues were $725,427,000, which was 13.8% more O&M expenses by category for fiscal years 2014 than the preceding year and 7.0% more than the aver- through 2018 reflect the Authority’s programs to con- age Net Revenues for the five fiscal years 2008 through tinue to control and modestly reduce its portion of these expenses from recent levels. As discussed 2012. For fiscal year 2014 net revenues are forecast to above, the O&M expenses excluding fuel and pur- increase by 9.5% to $794,203,000. Net Revenues are chased power (referred to here as the Authority’s forecasted to increase again in fiscal year 2015 by 3.6% Expenses) in fiscal year 2013 were 10.7% over the and remain relatively stable through 2018, with projec- budget, which had been set aggressively low. These tions of $823,142,000, $822,195,000, $840,048,000 actual costs in fiscal year 2013 effectively matched the and $848,439,000, respectively. Achieving these pro- Authority’s average Expenses over the prior three fis- jected Net Revenues will depend on the Authority cal years and form the bases for the projected maintaining tight control over the Authority’s Expenses. The Authority’s Expenses are budgeted to Expenses as discussed above.

COMPARISON OF FY 2013 & FY 2014 BUDGETED TO ACTUAL EXPENSES (in thousands) Current Expenses 2013 2013 Actual 2013 2014 2014 Budget Budget Expenses Variance Budget vs 2013 Actuals Fuel Cost $ 2,607,917 $ 2,603,578 $ (4,339) -0.2% $ 2,145,911 -17.6% Purchased Power 740,867 755,686 14,819 2.0% 805,414 6.6% Other Production (incl Hydro Plt) 55,181 71,655 16,474 29.9% 65,699 -8.3% Transmission & Distribution 140,445 172,318 31,873 22.7% 158,731 -7.9% Maintenance 212,872 213,890 1,018 0.5% 233,374 9.1% Customer Actng & Collection 105,559 116,351 10,792 10.2% 115,369 -0.8% Administrative & General 177,757 191,912 14,155 8.0% 175,510 -8.5% Interest Charges ––– –– Total $ 4,040,598 $ 4,125,390 $ 84,792 2.1% $ 3,700,008 -10.3% Current Expenses Minus Fuel + Purch Power $ 691,814 $ 766,126 10.70% $ 748,683 -2.3% 78 I 000092 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

DEBT SERVICE COVERAGE (reached in 2017) and $199 million below the obliga- Based on the amounts shown in Appendix II Income tion for fiscal year 2013. Statement, the Debt Service Coverage (DSC) was 1.38 The projected DSC data are based on the sinking fund in fiscal year 2013. The Debt Service Coverage is pro- payments steadily increasing from $527.4 million in jected to be 1.41, 1.42, 1.39, 1.34 and 1.35 for fiscal fiscal year 2013 to $626.2 million in fiscal year 2017. years 2014 through 2018, respectively. As part of each As discussed above and shown in Appendix II Income year’s budget the Authority develops a forecasted bor- Statement, the Authority’s forecasted growth in Net rowing schedule to support its Capital Improvement Revenues may not keep pace with the rate of increase Program through the subsequent five years. The pro- in the debt service which actually unfolds. jected annual debt service through fiscal year 2018 in the Authority’s budget and this report was prepared DEPRECIATION EXPENSE prior to the planned financing scheduled for early fis- The actual depreciation accrual for fiscal year 2013 cal 2014. In addition, the forecasted debt service was $342,437,000, as shown in Appendix IX, requirements include capitalized interest to reduce Depreciation Expense. The estimates for the ensuing early year obligations in future borrowings. These new five fiscal years are $353,129,000, $363,723,000, financings may incur higher interest rates than fore- $374,635,000, $385,874,000, and $397,450,000, casted and the ability to capitalize interest may be con- respectively. Depreciation Expense is excluded from strained as well. Both of these would increase the statements required for Trust Agreement purposes. Authority’s projected principal and interest require- The Consulting Engineers issued a comprehensive ments in the intermediate term, thereby lowering the depreciation review of the Authority’s Plant-in- Service forecasted debt service coverage ratio. as of June 30, 2009. The results were implemented in The Debt Service Coverage graph shows the five-year fiscal year 2013 by the Authority. Compared with the history and the five-year projection of the ratio of Net previous study the results show that there is no longer Revenues to Principal and Interest Requirements. The a deficiency between the theoretical and booked DSC in fiscal year 2012 was unusually high owing to depreciation reserves and the depreciation accrual rate the repayment schedule of the Series 2012 A/B financ- should be reduced. The review confirmed statistically ing in which capitalized interest and low early-year that the production plant’s average service life contin- principal and interest payments resulted in the debt ues to increase. It also showed that net negative sal- service being $267 million below the maximum vage (cost of removal less salvage) of retired capital

Debt Service Coverage Fiscal Years 2009-2018 2.00 1.95

1.90 1.85

1.80

1.70

1.60

1.50 1.47 1.45 1.41 1.42 1.39 1.40 1.38 1.34 1.35

1.30

1.20

1.10

1.00 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Actual Forecast I 000093 79 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report equipment was no longer escalating at the rate that legislature to request that a fund separate from the was shown in the previous study. General Fund be set up to make payment for monies owed by government agencies. ACCOUNTS RECEIVABLE The Authority reports its net accounts receivable for CONTRIBUTIONS TO THE fiscal year 2013 was $1,494.2 million after an COMMONWEALTH allowance of $251.3 million for uncollectable CONTRIBUTIONS IN LIEU OF TAXES accounts which is 16.8% more than the previous AND OTHER year’s amount. Of the $1,494.2 million, $603.0 mil- Since the Authority Act was originally enacted, the lion applied to government clients, an increase of Authority has been required to make certain payments 40.5% from the previous year, and $838.9 million to the Commonwealth government and the island’s applied to general clients, 2.4% less than the previous municipalities as contributions in lieu of taxes (CILT). year. The remaining balance was mostly for unbilled These payments were designed to be funded with an services. The non-current account receivables balance 11% mark up on electric sales— referred to as the Set for year end 2013 was $117.7 million or 15.7% more Aside—and to be paid or credited from Net Revenues, than the previous year’s balance. as defined by the 1974 Agreement. Over the years the At the end of fiscal year 2013 the following five gov- Commonwealth’s legislature has revised and added cer- ernment agencies accounted for approximately 25% tain subsidies and revised certain provisions of the pay- of Accounts Receivable balances owed to the ments to the municipalities, however, the basic Authority by Public Authorities: framework of these contributions has remained. In reference to the disposition of Net Revenues as shown on Client A/R Balance Appendix II, Income Statement, the Authority consid- Puerto Rico Sewer and Aqueduct Authority $57.8 million ers the total amount of CILT and Other to include its Department of Education $30.5 million contributions to the municipalities, plus three subsi- Ports Authority $31.6 million dies, an energy credit for qualifying businesses and the Cardiovascular Center $18.9 million amortization cost of a settlement with the municipali- Urban Train Administration $14.3 million ties regarding disputed CILT obligations prior to 2004. The Authority is continuing its aggressive effort to Although the intent of the Act was to have the collect overdue accounts. The actions taken to collect Authority invoice and collect from the municipalities from Public Authorities include working closely with their electric invoices, the Authority has opted to off- the Office of Management and Budget to expedite set monies owed for electric consumption with CILT. payments. Actions taken for general clients include For the last decade the contributions or credits to the disconnecting electrical service, referring clients to municipalities have constituted more than three quar- collection and credit rating agencies, and setting up a ters of the CILT and Other total. In fiscal year 2013 the payment schedule. In February 2011 the legislature total current annual amount of CILT and Others was of Puerto Rico approved Act 239-2011 that allows the equal to 25% of the Authority’s Net Revenues, com- Office of Management and Budget of the pared to the prior five-year average of 31%. As dis- Commonwealth to estimate the monthly electric cussed below, the most recent law establishing the invoices of agencies that depend on General Fund Authority’s CILT obligations provides for deferral of allocations and to coordinate with the Puerto Rico current year payments; since fiscal 2007 the Authority Treasury Department to submit payments to the has deferred partial payment of an accumulating por- Authority at the beginning of each month. Since its tion of the CILT. These obligations have been paid or adoption on December 11, 2011 the Treasury credited from the Authority’s Net Revenues after certain Department has been submitting current monthly defined expenditures, subject to compliance with its payments for the electric energy consumed by the obligations under the 1974 Agreement. While initially central agencies of the Commonwealth. Therefore the the contributions in lieu of taxes were paid to the accounts receivable of these government agencies Commonwealth’s Secretary of the Treasury for distribu- should not increase. As of June 30, 2013 the out- tion to the municipalities, for many recent years these standing balances of public corporations was $216.1 contributions have amounted to a full credit to the million of which 41% was for past due accounts. municipalities for their electric power consumption. In an effort to collect account receivables from gov- In 1998, the Municipality of Ponce filed a complaint ernment agencies, in June 2013 the Authority’s Exec- seeking payment from the Authority for the full utive Director appeared before the Commonwealth’s amount of the contributions in lieu of taxes, plus a 80 I 000094 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report potential addition based on available net revenues, for beginning in fiscal year 2014 as a result of provisions prior fiscal years. The island’s other 77 municipalities in Law 233. subsequently joined the suit. The complaint chal- The amount of $180.6 million for Contributions in lenged the Authority’s disposition of net revenues in Lieu of Taxes and Other shown on Appendix II, making deposits to certain funds under both the 1947 Income Statement, is the sum of the partial CILT Trust Indenture and the 1974 Agreement for the pur- credit for fiscal year 2013, plus the annual payments poses of paying the costs of capital improvements. The for the three previous year’s unpaid CILT, plus certain municipalities sought retroactive payment of the subsidies and an annual amortization cost described amount by which their share of the contributions in below. During fiscal year 2013 the Authority was cred- lieu of taxes had been reduced by such application. ited with $37.8 million in payments and services for The Authority settled this litigation with the munici- the current year’s obligations, the difference of $223.1 palities in 2004 by offering a monetary payment of million will be carried forward for payment by the $68 million and $57 million for electric infrastructure Authority over a maximum of three fiscal years. In fis- projects, for a total of $125 million. At the end of fiscal year 2013 the Authority was also credited with cal year 2013 the outstanding balance of the loan used $85.5 million towards the unpaid CILT balances from for the monetary settlement was $9.7 million. fiscal years 2010, 2011 and 2012 respectively; the In 2004 legislation was enacted that revised the for- installment for fiscal year 2010 completed the mula for computing contributions in lieu of taxes and Authority’s outstanding CILT obligations for that year. set aside. The amended legislation requires the 11% At the end of fiscal year 2013 the unpaid CILT balance mark up of the Authority’s gross electric energy sales totaled $323.6 million, an increase of $133.7 million be distributed to fund all government rate subsidies over the previous year. The deferred CILT balance has programs, to pay contributions in lieu of taxes to the grown steadily since the end of fiscal year 2007 when municipalities, to finance the Authority’s Capital it was $34.3 million. Improvement Program and for other legal purposes. The Contributions in Lieu of Taxes and Other for fis- The amendment changed the calculation of contribu- cal year 2013 includes a total of $54.4 million com- tion in lieu of taxes payable to the municipalities in prised of three subsidies and an energy credit totaling that it will be the greatest of the following three $43.9 million and a payment of $10.5 million to amor- amounts: tize the outstanding line of credit used in the settle- 1. twenty-percent of the Authority’s Adjusted Net ment of the lawsuit by the municipalities. As Revenues (Net Revenues, as defined in the discussed in the Rates section the three subsidies are 1974 Agreement), less the cost of government the hotel subsidy, the rural electrification and irriga- rate subsidies tion subsidy, and the residential fuel subsidy; the energy credit is the Authority’s contribution based on 2. the cost collectively of the actual annual elec- the Economic Incentive Act, Law 73 (discussed tric power consumption of the municipalities; below). The Authority’s escalating costs under Law 73 3. the prior five-year moving average of the con- for the fiscal years 2014 – 2018 are anticipated to be tributions in lieu of taxes paid to the munici- $2.2 million, $2.9 million, $3.7 million, $6.4 million, palities collectively. If the Authority does not and $9.2 million, respectively. have sufficient funds available in any year to In December 2011 the Commonwealth enacted Law pay the contributions in lieu of taxes then the 233 that clarified the scope of CILT by excluding the difference will be accrued and carried forward electrical consumption by municipalities used to sub- for a maximum of three years. sidize revenues from for-profit activities, rental prop- The Authority’s municipal CILT obligation for fiscal erty generating income, and activities involving an year 2013 was $260.8 million, which was the value of entrance fee. The Authority has a program to identify the electric power consumed by the municipalities and install additional meters to track this consump- during the fiscal year. This represented an increase of tion which will reduce the municipal consumption more than 6% in the value over the previous year. As subject to the CILT obligation; while identifying this discussed below, Commonwealth Law 233 passed in consumption will not increase reported revenues, it 2011 offers the Authority the ability to exclude certain will increase collectibles. The Authority has lowered activities from municipal consumption that would the projected CILT for fiscal years 2014 through 2018 qualify for the CILT obligation. The Authority is pro- by $49 million annually to account for the revenues jecting a marked decline in their CILT obligation that Law 233 will generate. I 000095 81 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Based on the adjusted municipal power consumption, energy consumption against income tax. Additional plus the subsidies and energy credit discussed above, credits are available based on the number of employ- the Authority forecasts the CILT and Other costs for ees and payroll cost up to a total maximum credit of fiscal years 2014 through 2018 will be $201.0, $205.8, 10% of the payments made to the Authority for energy $208.9, $193.3, and $201.7 million, respectively. consumed in the operation of the eligible business. The Authority’s projected budgets and CILT amounts The maximum credit will be reduced 1% per year are structured to avoid increasing the accumulated between 2013 and 2017. The aggregate amount for deferred CILT balance of $323.6 million discussed this tax credit is capped at $75 million per fiscal year above, assuming the forecasted annual CILT obliga- and $600 million through fiscal year 2018. The cost of the credits were borne by the Commonwealth’s Gen- tions are based on that current year’s municipal power eral Fund for the first year; beginning in fiscal year consumption. The applicable law, as discussed above, 2010 the Authority covered an escalating portion of provides for the CILT to be the greatest of three the credit starting at 4% with uniform annual amounts, however. With forecasted declines in increases to 20% in fiscal year 2014, then 35%, 50%, municipal consumption, the prior five-year moving 65% and 80% in fiscal years 2015 through 2018, average of the contributions in lieu of taxes paid to respectively. the municipalities collectively would be greater than either 20% of Net Revenues or the current year’s Under the Wheeling provision, the Authority was power consumption. Invoking the prior five year required to establish by January 2010 the technical average criteria would increase the Authority’s criteria and tariffs that would apply to qualifying gen- deferred CILT balance by $55.6 million in fiscal year erators for moving their power—wheeling—on the 2014 and $46.9 million the following year, based on Authority’s system to the generator’s clients or for the the budget for those years. These levels of CILT obli- Authority to purchase the generator’s power for gen- gation cannot be sustained. eral distribution to the Authority’s clients The Authority held public hearings in 2010 and 2011 ECONOMIC INCENTIVES ACT regarding proposed wheeling tariffs. Based on com- To spur economic development the Commonwealth ments from these hearings and the public examiner’s Government enacted the Economic Incentives for the recommendations, the Authority has been evaluating Development of Puerto Rico Act (Economic its wheeling tariffs and has begun revision to its tech- Incentives Act – Law 73) in May 2008. The Economic nical requirements for wheeling and interconnection. Incentive Act is scheduled to be in effect for ten years The Economic Incentive Act establishes a new starting on July 1, 2008. In comparison to the Tax administrative entity, the Energy Affairs Office, whose Incentives Act of 1998, which expired at the end of duties include overseeing the implementation of the fiscal year 2008, the Economic Incentive Act expands wheeling provision. The Energy Affairs Office has the the scope of businesses eligible for tax exemptions power to assign an arbitrator to establish rates and credits. The three sections of the Economic between the Authority and a qualifying generator if Incentive Act that may most affect the Authority are there is a disagreement between the two parties. the Energy Investment Credit, the Energy Cost Funding for the tax credits established by the Credit, and Wheeling. The tax credits in the Economic Incentive Act will be drawn from the Economic Incentive Act are based on the preferential Commonwealth’s General Fund and from payments income tax on Industrial Development Income. by the Authority, with the Authority’s portion increasing during the term of the Act, as described above. The Energy Investment Credit section establishes a The Authority’s payments will be based on reductions onetime tax credit of fifty percent for investments by in operating costs, improved efficiencies, revenues eligible businesses in systems and equipment for gen- from wheeling and lower costs in purchased power. erating electrical energy and for investments which Under the law, the Authority’s payments may not in improve efficiency. The energy generation may be for any way be subsidized or passed through to its clients self consumption or for commercial resale. The and the Authority is prohibited from reducing its amount of the tax credit for new self-generated capac- number of employees or payroll. The tax credit will ity is limited to 25% of the eligible firm’s income tax. end if the Authority’s average retail cost of power is 10 The tax credit for commercial generation is limited to cents/kWh for two consecutive years. Prior to fiscal $8 million per eligible business and $20 million per year 2012 the Authority had incurred only adminis- year in the aggregate. trative costs associated with the Economic Incentive The Energy Cost Credit allows eligible businesses to Act. In fiscal year 2012 the Authority contributed receive a credit of 3% of the cost of their industrial $866,000 for their 4% share of the total energy cred- 82 I 000096 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report its assigned to nine qualifying businesses for fiscal As shown in Appendix VII, Sources of Funds for year 2010. The Authority’s contribution in fiscal year Capital Expenditures, the Authority plans additional 2013 was $1.2 million. The escalating annual contri- financing in fiscal years 2014, 2016 and 2018 princi- butions under the Economic Incentive Act are pro- pally to fund the Authority’s Capital Improvement jected to cost the Authority $53.1 million during the Program and other purposes. ten years the Act is in effect through fiscal year 2018. INTERIM FINANCING FINANCING Lines of Credit and Notes Payable LONG-TERM CAPITAL FINANCING As of the end of fiscal year 2013 the Authority had The Government Development Bank for Puerto Rico four lines of credit and one term loan. (GDB) is the primary fiscal agent for the Commonwealth of Puerto Rico and is responsible for The term loan financing relates to settled litigation overseeing and maintaining the Commonwealth’s with the municipalities of Puerto Rico, which overall creditworthiness. In this capacity it coordi- amounted to $64.2 million. As of June 30, 2013 the nates all bond issues and lines of credit for the balance was $9.7 million. Authority as well as other agencies of the common- The first line of credit is for $25.4 million, intended wealth government and municipal governments. for the restoration of the Isabela Dam. The outstand- The Authority’s actual and forecasted capital expendi- ing balance as of June 30, 2013 was approximately tures for fiscal years 2013 through 2018 are summa- $743,000. This line of credit expires on June 30, rized by category in Appendix VI, Capital 2018. The Authority expects to be reimbursed by the Expenditures. The projected expenditures as shown Commonwealth Government for any payments made in Appendix X, Details of Capital Improvement for this term loan. Program are a breakdown by Budget Item Number of the expenditures shown in Appendix VI. The During fiscal year 2013 the Authority re-initiated a Authority’s sources of funds and anticipated financing $100 million line of credit with the GBD for covering needs for fiscal years 2014 through 2018, as well as collateral on its power revenue bonds that are based those realized in fiscal year 2013, are presented in on interest basis swaps. This line of credit expires on Appendix VII, Sources of Funds for Capital December 14, 2014. As of June 30, 2013 $6.1 million Expenditures. has been withdrawn and there was $93.9 million As of June 30, 2013, the Authority had available for withdrawal. $8,048,485,000 in Power Revenue Bonds outstand- The Authority has two other lines of credit to be used ing. (See Appendix V, Debt Service Coverage Under for fuel financing with two large commercial banks. the 1974 Trust Agreement.) The combined lines of credit amount to $750.0 mil- In April 2012 the Authority issued $650 million of lion of which $744.4 million has been withdrawn Power Revenue and Power Revenue Refunding leaving an available balance of $5.6 million. bonds. Ninety-three per cent of the proceeds were CAPITAL IMPROVEMENT PROGRAM used to fund the following: Construction Fund, $359.5 million; pay down GDB line of credit, $161.9 The fiscal year 2014 Capital Improvement Program million; and $82.6 million as capitalized interest. The (CIP) projects a five-year period of expenditures for approved amount of the line of credit issued by the extensions and improvements to the System. An GDB was $244 million of which $159 million had overview of the scope of these projects for fiscal year been used; the Authority paid $2.9 million in interest 2014 is provided below and is summarized by func- on the line credit, resulting in the $161.9 million total tional group in Appendix VI, Capital Expenditures. An payment. expanded presentation of the CIP is in Appendix X, Details of Capital Improvement Program, which lists Amongst other uses, in fiscal year 2012 the GDB line of credit had been used to fund the Rate Stabilization the extensions and improvements by Budget Item Account which provided $79.4 million in credits to Number (BIN) through fiscal year 2018. residential clients to reduce their fuel adjustment The Authority develops the CIP on the basis of sup- charges during fiscal year 2012 and for certain princi- porting its objectives of providing dependable electric pal and interest payments due under the 1974 power service to the island of Puerto Rico at the low- Agreement. The proceeds of Series 2012B bonds were est cost, consistent with applicable environmental used to refund Power Revenue Bonds Series II. and social obligations. I 000097 83 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Capital Improvement Program (in thousands) 2009-2018

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Actual Forecast The Authority’s capital expenditures reached a peak contributed by either the Authority’s clients, FEMA of $666.8 million in fiscal year 2008 when construc- or the Commonwealth Government for special con- tion of the Authority’s two newest production plant struction services. However, allowance for funds used projects, San Juan Units 5&6 and the new combus- during construction (AFUDC) and annual cost esca- tion turbines at Mayagüez, were in their final phases. lations are included. The capital expenditures in subsequent years The tabulated data show by functional group the dropped significantly. The average capital expendi- amounts budgeted for the Capital Improvement tures during the most recent past three fiscal years Program, the amounts actually expended in fiscal was $363.4 million which marked a decline of 46% year 2013 and the budget for fiscal year 2014. During from the 2008 peak. the course of the year the Authority occasionally real- Capital expenditures were projected to continue the locates certain budgets, staying within the total frame decline in fiscal year 2013 with a budget of $300 mil- work. The budget amounts shown in the table do not lion. Actual capital expenditures during fiscal year reflect any reallocations. 2013 were $327.7 million; these were 6.7% less than As indicated, the Authority’s total CIP budget for fis- the expenditures in fiscal year 2012, but 9.2% above cal year 2014 is unchanged from the previous fiscal the budget. During the next five fiscal years the year, but the allocations by function group have been Authority plans to reduce its level of annual capital revised to reflect completion of projects and current expenditures to an average of $310.0 million, which priorities; the budget for fiscal year 2014 is 8.4% less is consistent with the actual expenditures in the past than the previous year’s actual expenditures. two fiscal years. The CIP budgets in millions of dollars are projected to be $300.0, $300.0, $300.0, In the past fiscal year the Authority contributed $17.0 $325.0 and $325.0 for fiscal years 2014 through million from internal funds to the Capital Improve- 2018, respectively. The figures do not include the ment Fund, which was 5.2% of the total expenditures Contributions in Aid of Construction, i.e., capital for the year. During fiscal year 2014 the Authority

COMPARISON OF BUDGETED CIP TO ACTUAL CIP EXPENDITURES – FY 2013 (in thousands) Budget 2014 vs Budget Actual Difference 2014 Actual 2013 Production $118,898 $ 107,810 ($11,088) -9.3% $ 96,375 -10.6% Transmission 58,965 69,661 10,696 18.1% 66,347 -4.8% Distribution 91,097 127,926 36,829 40.4% 99,884 -21.9% Other 31,040 2,280 (8,761) -28.2% 37,394 67.8% Total $ 300,000 $ 327,677 $ 27,677 9.2% $ 300,000 -8.4% 84 I 000098 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report plans to contribute $22.7 million, which is 7.6%, to overhauls and plant system upgrades. A representative the Capital Improvement Program budget for the year. scope of these projects is discussed in the Production Funding for the Capital Improvement Program is dis- Plant section for each plant. Within the CIP for pro- cussed further in the Capital Improvement Fund sec- duction, boiler improvements account for approxi- tion of Funding Recommendations below. mately one quarter of the fiscal year 2014 budget. In The first year of the Authority’s five-year Capital addition to the fuel conversions discussed below, the Improvement Program is included in the Annual scope includes refurbishing major boiler components Budget of Current Expenses and Capital such as waterwalls and ductwork, refurbishing and Expenditures which is reviewed and approved by the improving boiler structural steel and platforms and Consulting Engineers prior to the beginning of each the procurement of a shared spare boiler feed pump fiscal year. The current CIP through fiscal year 2018 internals for the largest four steam plants. includes funds to complete the planned conversions Improvements to the steam turbines and the balances to dual fuel firing of oil and natural gas at the of the steam plants constitute approximately another Authority’s large steam-electric production units and quarter of the production CIP budget for fiscal year its combined cycle units. As discussed in the Capacity 2014. These activities include the planned improve- and Energy Resource Planning section, providing nat- ments to the steam turbine at Aguirre Unit 2, replac- ural gas to most of the converted units will require an ing four high pressure feedwater heaters at Costa Sur extensive gas supply infrastructure, with the excep- Unit 5 & 6, refurbishing water storage tanks, and the tion of the Costa Sur units for which the gas supply upgrade and expansion of the demineralized water pipeline is in service. Since the Authority plans that treatment plant at the Costa Sur station. The CIP proj- the gas supply infrastructure will be developed with ects at production plants include improvements to alternative sources, funds are not included in the various major systems at combined cycle, combustion Authority’s CIP for this work. turbine, and hydroelectric plants. We believe that the moneys shown in the CIP for The CIP for fiscal years 2014 through 2018 includes extensions and improvements to the System over the $70.2 million to complete the conversion to dual fuel forecast period are reasonable. The CIP is comprised firing capability, i.e. fuel oil and natural gas, at the of numerous budget items grouped into five general Authority’s eight largest steam plant units at Costa Sur categories. The largest expenditures are in production (already completed), Aguirre, Palo Seco and San Juan. plant, transmission plant, and distribution plant. The This is consistent with the Authority’s strategy for Capital Improvement Program chart shows the trends MATS compliance as discussed in the Environmental and relative values of these groups over the five-year section. The CIP for fiscal years 2014 through 2018 budget period. also includes $10.0 million for adding natural gas fir- PRODUCTION PLANT ing capability to the combined cycle plants at San Juan Units 5 & 6, which presently fires distillate. The CIP for fiscal year 2014 includes $96.4 million for production plant related projects. All of these are The Authority has identified projects within the reha- considered rehabilitation projects. The scope of these bilitation category that are for pollution control, or includes work associated with dual fuel conversion to for environmental issues, that have a total value of include natural gas, improvements to boilers and $10.8 million for fiscal year 2014. Environmental steam turbines, as well as environmental projects. projects include installing new continuous emissions monitoring systems (CEMS) at the steam plants in As discussed in Diesel Generators in the Production preparation for MATS compliance, cooling water pol- Plant section, the planned production plant CIP lution control projects, and oil spill containment, pre- includes replacing old diesel generator capacity on vention, control and countermeasures. the small island of Culebra with new equipment. Civil work on the project began in fiscal year 2013, TRANSMISSION PLANT with the full scope scheduled for completion in fiscal The CIP for fiscal year 2014 includes $66.3 million year 2015. The new generators will improve the reli- for transmission plant related projects. Expansion ability of service to Culebra, especially by reducing projects are budgeted at $26.7 million and rehabilita- service interruptions from heavy weather. tion projects have a budget of $39.7 million. The principal focus for rehabilitation projects is the The expansion projects are the new transmission major refurbishment work planned for the Authority’s lines, transmission centers, switchyards, high voltage operating production plants during scheduled major equipment, and extensions at existing facilities to I 000099 85 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report support the growth of the transmission system. The General land and buildings includes funds for the major planned projects for the 230, 115 and 38 kV acquisition of land and rights of way and for struc- systems are described in the Transmission section. tures. The land acquisition for new transmission line These projects include the new 230 kV line from rights of way represents approximately 40% of this Costa Sur to Cambalache, the new 115 kV GIS budget. Regarding structures and buildings, the gen- switchyard at San Juan steam plant, the new 115/38 eral plant funds are for improvements to technical kV transmission centers at Barranquitas and Bairoa offices, buildings, warehouses, workshops and cus- and new 38 kV underground projects in various tomer service facilities. The budget includes funds for municipalities around the island. the rehabilitation of facilities at the Authority’s head Improvements to the 230, 115 and 38 kV systems quarters, the Luchetti building in San Juan. constitute the rehabilitation projects. These include The equipment group is made up of five subgroups. replacement of structurally deteriorating lines and The CIP for fiscal year 2014 includes $619,000 for poles, especially in the 38 kV system, and the upgrad- office equipment. In fiscal year 2014 the computer ing of the supervisory control and data acquisition equipment budget is $5.0 million. Other equipment (SCADA) system. subgroups are transportation equipment (land and air) at $8.3 million, of which $7.8 million is for new DISTRIBUTION PLANT trucks and vehicles. The fiscal year 2014 budget for The distribution system CIP budget for fiscal year communications equipment is $4.2 million, which 2014 is $99.9 million and is comprised of $18.8 mil- includes $3.3 million for upgrading the fiber optic and lion for expansion projects and $81.1 million for microwave systems for SCADA. The budget for other rehabilitation projects. equipment is $8.5 million. This includes a wide range The distribution expansion projects include new sub- of specialized tools and equipment, such as construc- stations and increases to the capacity of existing sub- tion tools, directional drilling rigs, environmental and stations. These scopes are represented by the 13.2 kV planning analytical tools, and maintenance tools. substations at Sea Land (Caparra), Añasco and PRELIMINARY INVESTIGATIONS Charco Hondo. The expansion projects also include The final category in the CIP is for preliminary stud- new underground distribution lines, temporary sub- ies and surveys. The fiscal year 2014 budget for these stations and portable equipment, new 13.2 kV feed- activities is $3.6 million. These studies are principally ers, and work associated with service to new clients. performed by the engineering, planning and environ- The rehabilitation projects to the distribution system mental groups to support the evaluations of various include improvements to existing substations and system improvements and environmental compliance line facilities, replacement of distribution poles and alternatives. The scope of studies includes evaluating lines, and the improvement of underground distribu- the integration of renewable energy sources into the tion lines. Consistent with its widespread application, electric system. Other studies evaluate improvements approximately 31% of the distribution CIP budget is to the operation and maintenance of the transmission directed to improvements for aerial distribution lines and distribution system. throughout the island. The rehabilitation scope includes the underground work in the historic district FUNDING OF THE EMPLOYEES’ of Ponce, that is budgeted for $3.0 million in fiscal RETIREMENT SYSTEM year 2014. The largest project in this category is The Employees’ Retirement System of the Authority directed to the purchase of remote read meters, which is a separate trust fund created and administered by accounts for more than 9% of the distribution CIP the Authority. The Retirement System is funded by budget. The balance of the distribution projects contributions from both the Authority, based on addresses numerous miscellaneous requirements annual actuarial valuations, and plan members. The such as the purchase and installation of breakers, sec- Retirement System’s independent actuary prepared tionalizers, voltage regulators, capacitors, and similar an actuarial valuation for fiscal year 2012. The actu- distribution equipment and systems. arial evaluation concluded that: The valuation results indicate that the combined employer and member GENERAL PLANT contribution rates are sufficient to fund the normal The fourth category within the CIP is the general plant cost for all members and the unfunded accrued lia- which for fiscal year 2014 totals $33.8 million. This bility. The valuation report also states that the actu- category is composed of $7.2 million for general land arial assumptions meet the parameters for the and buildings and $26.6 million for equipment. disclosures under Governmental Accounting Stan- 86 I 000100 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report dards Board Statements No. 25 and 27 and that the duction plant the inventory includes: spare rotors for employer contribution rate is sufficient to finance units at the Aguirre and Costa Sur Steam Plants; and the promised benefit under Statements 25 and 27. a spare turbine rotor for Palo Seco Units No. 3 & 4. The Retirement System’s unfunded accrued liability For a (partial) list of spare components for the pro- had increased from $1,512.6 million as of the end of duction plant refer to the Spare Components section fiscal year 2011 to $1,700.9.6 million as of the end of in the System’s Operations section. fiscal year 2012. For future calculations the Actuarial INSURANCE assumptions are: an 8.5% annual rate of return on The Risk Management Office, within the Finance investments; projected annual salary increases of 4.1 – Directorate, manages the Authority’s Insurance 5.4% depending on age; 2 – 8% cost of living adjust- Program. It is responsible for managing and control- ments depending on the amount of benefit with a minimum of $25 per month and maximum of $50 per ling the Authority’s resources to minimize risks of month; and 3% inflation. accidental losses. In addition, it analyzes, assesses, and recommends insurance policies and bonds for con- The following table further summarizes the status of tracts and purchase orders. It settles property claims the Authority’s Pension Plan for the year ending June against the Authority valued at less than $10,000. 30, 2012: During fiscal year 2013 the Authority maintained a AUTHORITY’S PENSION PLAN layered set of All Risk Property and Boiler and Number of Active Members 8,600 Machinery policies that provided coverage of $750 million. The structure of the program includes inde- Number of Retired and Disabled Members and Survivors 10,975 pendent layers of $200 million each for coverage for Annual Benefits $191,526,901 all risks, and boiler and machinery losses. In excess of Actuarial Value of Assets (in millions) $1,285.4 these $200 million layers of coverage, the Authority’s Actuarial Accrued Liability (in millions) $2,986.3 insurance program includes a $350 million of combi- Unfunded Actuarial Accrued Liability (in millions) $1,700.9 nation of all risks and boiler and machinery coverage, Estimated Covered Payroll (in millions) $365.0 providing up to a $750 million limit of coverage for a combined all risks and boiler and machinery loss. Recommended Contributions for Fiscal Year Ending 2014 Transmission and distribution lines other than under- Total Contribution Rate: ground and fiber optic lines are excluded which is Normal 9.5% common in the electric utility industry. Unfunded Accrued Liability 30.2% The Authority retains the first $25 million in earth- Total Contribution Rate 39.7% quake losses, the first $25 million in windstorm loss, Average Member Contribution Rate 10.4% plus an additional $20 million of windstorm loss in Authority Contribution Rate 29.3% the $100 million excess of $100 million layer of cov- Amortization Period 28 years erage for a total of $45 million retention for windstorm damages, and $10 million in boiler and INVENTORIES AND OTHER PROPERTIES machinery losses. The retentions under all other cov- As part of the Finance Directorate, the Material ered losses include a $2 million deductible and, $7.5 Management Division’s mission is to support all of million of the first $25 million for coverage of all other the Authority’s installations with the material and covered loss retention totaling $9.5 million. equipment necessary to accomplish the Authority’s The business interruption coverage within the All goal of providing electric service to clients at the low- Risk Property Policy is capped at $300 million with est possible cost. The Warehouses subdivision uti- the Authority covering the costs from the first thirty lizes 32 warehouses and manages an extensive days of the interruption. inventory. At the end of fiscal year 2013 the inventory was worth $217.7 million of which $85.9 mil- In addition to the two policies cited above the lion was transmission and distribution material and Authority’s Insurance Program contains policies for $109.2 was related to its production plant spare Public Liability, Commercial Auto Policy-PREPA, inventory and $22.6 was general inventory. The Personal Auto Policy-Employees, Crime, Directors spare parts inventory for transmission and distribu- and Officers Liability, Fiduciary Liability, Employment tion plant includes the safekeeping of a number of Practices Liability, Aviation, Hull and Hull Risks, items, such as: transformers; poles; fuses; breakers; Personal Accident and Health, Owner Controlled structures; and insulators. Among the items for pro- Insurance Program (OCIP) Rolling Wrap-up, and I 000101 87 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Open Cargo. Among the policies included in the OCIP FUNDING are; Commercial General Liability, Builders Risk Installation Floater, Pollution Liability and RECOMMENDATIONS Professional Liability. The public liability coverage Section 706 of the 1974 Agreement reads in part: it remains at $75 million with the Authority holding $1 shall be the duty of the Consulting Engineers to million self-retention and $1 million deductible / $2 include in such report [this Annual Report] their rec- million annual aggregate deductible. ommendations as to the amount that should be The Eleventh Supplemental Agreement created the deposited monthly during the ensuing fiscal year to position of “Independent Consultant”, a consultant or the credit of the Reserve Maintenance Fund…, consulting firm or corporation to be employed by the deposited during the ensuing fiscal year to the credit Authority under Section 706 of this Agreement to of the Self-insurance Fund…and deposited during carry out the duties of said Independent Consultant. the ensuing fiscal year to the credit of the Capital Section 706 of the 1974 Agreement reads in part: Improvement Fund. The Authority covenants and agrees…it will, for the These three funds were created and funded in 1996 purpose of carrying out the duties imposed on the when the 1947 Trust Indenture was defeased. Independent Consultant by this Agreement, employ There have been four major events that have caused one or more independent firms having a wide and losses to the Authority since the Reserve Maintenance favorable repute in the United States for expertise in and Self-insurance Funds were created. risk management and other insurance matters The first was Hurricane Hortense in fiscal year 1997 related to the construction and operation of electric that caused an estimated $36.0 million in damages to systems. It shall be the duty of the Independent the Authority’s System. The entire loss of this event Consultant to prepare and file with the Authority was borne by the Authority. and the Trustee at least biennially, on or before the In fiscal year 1999 Hurricane Georges devastated the first day of November, beginning November, 1999, a island. Total damages to the System were estimated at report setting forth its recommendations, based on a $239.9 million of which $12.7 million was covered by review of the insurance then maintained by the insurance, $168.0 million was provided by the Authority in accordance with Section 707 of this Federal Emergency Management Agency (FEMA) Agreement and the status of the Self-insurance Fund, and the remainder of $59.2 million was the responsi- of any changes in coverage, including its recommen- bility of the Authority. dations of policy limits and deductibles and self- insurance, and investment strategies for the Tropical Storm Jeanne in fiscal year 2005 caused an Self-insurance Fund. estimated $60 million in damages to the System, of which FEMA provided $11.8 million in aid and the The cost of the Authority’s Insurance Program as balance of $42.8 million came from various funds of renewed with these changes is approximately $24.7 the Authority. million a 15% savings from the previous Insurance Program renewal. The fires at the Palo Seco Power Plant during fiscal year 2007 caused losses estimated to total $363.2 mil- The Tenth Supplemental Agreement created the Self- lion, of which insurance payments to the end of fiscal insurance Fund. This fund is to be used to pay for the year 2012 amounted to $301.3 million. cost of repairing, replacing, or reconstructing property damaged or destroyed from or extraordinary expenses In August 2011 Hurricane Irene (later Tropical Storm incurred as a result of a cause that is not covered by Irene as it traveled northward) passed by the north insurance. It can also be used, when approved by the coast of Puerto Rico. While the storm caused wind Consulting Engineers, to cover loss of income due to and flood damages and extensive power outages, its a cause which is not covered by insurance. The mon- impact was significantly less than the events eys in the Self-insurance Fund allow the Authority to described above. The Authority submitted claims to increase its insurance deductibles, thereby lowering its FEMA for $15.9 million, but had not received any insurance premiums. Refer to the Funding payments during the past fiscal year. Recommendations section for the status of the Self- The specific utilizations of money from the Reserve insurance Fund and the Consulting Engineer’s recom- Maintenance and Self-insurance Funds are discussed mendations concerning contributions. below. 88 I 000102 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

RESERVE MAINTENANCE FUND used to reduce the $53 million inter-fund debt; at the end of fiscal year 2013 this inter-fund debt was Section 512 of the 1974 Agreement reads in part: approximately $33 million. moneys held for the credit of the Reserve The Consulting Engineers recommends the Authority Maintenance Fund shall be disbursed only for the need not deposit any moneys into the Reserve purpose of paying the cost of unusual or extraordi- Maintenance Fund during fiscal year 2014. nary maintenance or repairs, maintenance or repairs not recurring annually and renewals and SELF-INSURANCE FUND replacements, including major items of equipment. Section 507 (g) of the 1974 Agreement reads in part: At the end of fiscal year 2013, the Reserve to the credit of the Self-insurance Fund...such Maintenance Fund’s balance was $15.8 million. The amount, if any, of any balance remaining after Reserve Maintenance Fund is a restricted fund in making the deposits under clauses (a), (b), (c), (d), which the moneys are held in trust by the Authority. (e), and (f) above, as the Consulting Engineers Since the fund was created in 1996 there have been shall from time to time recommend; and two instances when the Authority withdrew moneys Section 512A of the 1974 Agreement reads in part: from this fund. moneys held for the credit of the Self-insurance The first instance occurred in fiscal year 2005, when Fund (1) shall be disbursed...only for the purpose $7.1 million was withdrawn and applied as part of the of paying the cost of repairing, replacing or recon- $45 million costs to repair the System following dam- structing any property damaged or destroyed from ages caused by Tropical Storm Jeanne. Additional or extraordinary expenses incurred as a result of a sources of funds to restore the System came from cause which is not covered by insurance…or (2) FEMA and the Authority’s Self-insurance Fund. shall be transferred to the Revenue Fund in an The second instance began in April 2007 when the amount, approved by the Consulting Engineers, Authority sought the Consulting Engineers’ concur- equal to the loss of income from the System as a rence regarding the use of the Reserve Maintenance result of a cause which is not covered by insurance. Fund as an interim source of funds for increased costs Section 512A of the 1974 Agreement further reads: associated with the loss of the Palo Seco Steam Plant. If the Authority shall have determined that all or The Consulting Engineers concurred, but stipulated any portion of the moneys held to the credit of the that any moneys withdrawn from the Reserve Self-insurance Fund is no longer needed for the Maintenance Fund should be replenished using the purposes specified in the second preceding para- proceeds from the Authority’s insurance program graph, the Authority may withdraw an amount within a reasonable timeframe. Consistent with the equal to such portion from the Self-insurance Fund Consulting Engineers intent, the Authority borrowed and transfer such amount to the credit of the Bond $9.4 million from the Reserve Maintenance Fund Service Account; provided, however, that no such during fiscal year 2007 and $58.3 million during fis- transfer shall be made prior to the time that the cal year 2008, a total of $67.7 million. The with- Consulting Engineers shall have approved such drawals were carried as an inter-fund debt of the transfer in writing. General Fund as part of the Palo Seco Steam Plant As of the end of fiscal year 2013 the balance of the recovery project. During the same period the Self-insurance Fund was $92.2 million. Similar to the Authority returned $14.7 million from insurance pro- Reserve Maintenance Fund, the Self-insurance Fund ceeds, $5.0 million in fiscal year 2007 and $9.7 mil- is a restricted fund in which the moneys are held in lion in fiscal year 2008, netting a $53 million trust by the Authority. The Authority has withdrawn inter-fund debt of the General Fund to the Reserve moneys from this fund four times since its creation in Maintenance Fund. 1996. The first withdrawal, in fiscal year 1997 for $32 Consistent with the Consulting Engineers responsi- million, was for damages caused by Hurricane bilities under the 1974 Trust Agreement, the Hortense. The second withdrawal for $30 million in Consulting Engineers recommended that the fiscal year 1999 was for damages caused by Hurricane Authority deposit $5 million to the Reserve Georges. Then in fiscal year 2005 for damages caused Maintenance Fund in fiscal years 2009, 2010 and by Tropical Storm Jeanne $18.3 million was with- 2011. At the request of the Authority, the Consulting drawn. It should be noted that these amounts were Engineers agreed that the moneys would instead be used to supplement insurance payments and reim- I 000103 89 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report bursements from FEMA. They represented only a Section 512B of the 1974 Agreement reads in part: fraction of the moneys required to restore the Moneys held for the credit of the Capital Authority’s facilities. Improvement Fund shall be disbursed…only for In fiscal year 2007, at the request of the Authority, the paying the cost of anticipated extensions and Consulting Engineers authorized the withdrawal of Improvements of the System the cost of which has moneys from the Self-insurance Fund to cover unin- not otherwise been provided for from the proceeds sured losses associated with the Palo Seco Steam of bonds issued under the provisions of this Plant fires. During fiscal year 2008 the Authority Agreement. withdrew $25.4 million from this fund for the unin- The Consulting Engineers approves annually the sured losses associated with the Palo Seco Steam Authority’s budget for the ensuing fiscal year; the Plant fires. Also during fiscal year 2008 the Authority budget includes amounts for the first year of the five- deposited $5.0 million to this fund. The Authority year Capital Improvement Program (CIP). (for further deposited to the fund $10 million per year in fiscal discussion, refer to the Annual Budget in the Financial years 2009, 2010 and 2011 and $5 million in fiscal section) The budget for fiscal year 2013 projected that year 2012 in accordance with the Consulting the CIP expenditures would be $300.0 million, of Engineers recommendations. which $27.0 million of the Capital Improvement Fund would be generated internally. The actual CIP expen- In August 2011 Hurricane Irene (later Tropical Storm ditures for fiscal year 2013, however, totaled $327.7 Irene as it traveled northward) passed by the north million, of which $17.0 million, or 5.2%, was financed coast of Puerto Rico. While the storm caused wind internally through the Capital Improvement Fund. In and flood damages and power outages to more than the five fiscal years from 2009 through 2013 the aver- one million clients, its impact was significantly less age level of internal funding for the CIP was 5.9%; this than the events described above which required with- low average would have been even lower except for drawals from the Self-insurance Fund. During fiscal the contributions made in 2010. The levels of deposits year 2012 the Authority submitted claims to FEMA to the Capital Improvement Fund reflect the sensitiv- for $15.9 million. At the end of the past fiscal year the ity of this funding to the Authority’s compliance with Authority had not yet received any payments, but did operating budgets and its obligations of Contributions not plan to use the Self-insurance Fund for this event. in Lieu of Taxes. During fiscal year 2014 the Consulting Engineers rec- For fiscal year 2014 the Capital Improvement Program ommends the Authority need not deposit any moneys budget is $300.0 million, of which $22.7 million, or into the Self-insurance Fund. 7.6%, is projected to come from internal funds. The internally generated funds portions of the CIP for fis- CAPITAL IMPROVEMENT FUND cal years 2015 through 2018 are projected to be Section 507 (h) of the 1974 Agreement reads in part: 10.4%, 4.3%, 4.0% and 4.0%, respectively. The forecasted amount of internal funds will average 6.0% of to the credit of the Capital Improvement Fund such the CIP over the five years ending in fiscal year 2018. amount, if any, of any balance remaining after making the deposits under clauses (a), (b), (c), (d), The following table shows the Authority’s actual (e), (f), and (g) above, as the Consulting Engineers deposits to the Capital Improvement Fund for the shall recommend as provided by Section 706 of this most recent five fiscal years compared with that Agreement; provided, however, that if the amount so which was budgeted. deposited to the credit of said Fund during any fis- CAPITAL IMPROVEMENT FUND cal year of the Authority shall be less than the amount recommended by the Consulting Engineers, Fiscal Year Amount Amount Difference the requirement therefore shall nevertheless be Budgeted Deposited cumulative and the amount of any such deficiency 2013 $27.0 17.0 ($ 10.0) in any such fiscal year shall be added to the amount 2012 $77.3 15.1 ($ 62.2) otherwise required to be deposited in each fiscal 2011 $69.1 17.2 ($ 51.9) year thereafter until such time as such deficiency 2010 $0.0 63.4 $ 63.4 shall have been made up, unless such requirement shall have been modified by the Consulting 2009 $0.0 4.7 $ 4.7 Engineers in writing, a signed copy of such modifi- The Capital Improvement Fund also serves as an cation to be filed with the Authority. additional reserve for the payment of the principal of 90 I 000104 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report and the interest on the Power Revenue Bonds and meeting the amortization requirements to the extent that moneys in the 1974 Sinking Fund, including the 1974 Reserve Account, in the Reserve Maintenance Fund, and in the Self-insurance Fund are insufficient for such purpose. The chart presents the annual portions of internally generated funds for the total financing sources of capital expenditures since 2009 and those forecasted through 2018.

Internally Generated Funds Portion of Financing Sources Fiscal Years 2009-2018 18% 16% 16%

14%

12% 10% y 10% 8% 8%

6% 5% 4% 4% 4% 4% 4% 4%

2% 1% 0% 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Actual Forecasted

I 000105 91 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

HUMAN CAPITAL service was not eligible for a lifetime benefit of medical insurance for themselves or their spouse. An HUMAN RESOURCES employee retiring after that date with more than 30 On June 30, 2013, the Authority had a workforce of years of service received a lifetime benefit of medical 8,465 employees: 8,025 permanent employees, and insurance but received no medical insurance cover- 390 temporary or probationary employees who had age for their spouse. The Authority put in place a plan been employed by the Authority for less than 12 whereby former employees with 30 years of service months. The total number of employees on June 30, can purchase coverage for their spouse. The 2013 reflects a net decrease of 161 employees from Authority has negotiated an extension of the firm the previous year. This decrease includes one fixed price for the provision of medical care for employee who was classified as an emergency retirees and eligible spouses through December of employee in fiscal year 2012. During the past fiscal 2013. year the number of permanent employees declined by The Authority prepares its employees for their job 263, while the number of temporary employees assignments by providing a wide range of training increased by 103. Approximately 90% of those leav- programs and refresher training programs. The ing the Authority in the past fiscal year retired; in the Human Resources Directorate provides the same year the Authority hired 200 new employees. Authority’s employees with training in the areas of The Authority anticipates that the recent rate of safety, health, and computer usage. The training pro- decline in the number of permanent employees will grams offering job specific, technical knowledge of continue through fiscal year 2014. At the end of fiscal the type needed by the employee to effectively per- year 2012 the Authority had 8,626 employees; of which 8,338 were permanent and 287 were tempo- form their assigned work are provided by the direc- rary. torate within which they are employed. Bargaining and non-bargaining unit employees, supervisors and The Authority is comprised of eight directorates and managers participate in these programs. the Governing Board. The directorates are the Executive Directorate, the Generation Directorate, LABOR AFFAIRS the Transmission & Distribution Directorate, the Law The following paragraphs provide an overview of the Directorate, the Planning and Environmental Control bargaining units within the Authority and of the sta- Directorate, the Finance Directorate, the Client tus of the labor agreements applicable to these bar- Services Directorate, and the Human Resource and gaining units. Labor Affairs Directorate. Ninety–three percent of the Authority’s permanent employees were employed in During fiscal year 2013 four different unions repre- one of the following four directorates: 3,309 worked sented 70% of the Authority’s 8,465 permanent and in the Transmission & Distribution Directorate for a temporary employees. The largest union is the total of approximately 40% of the Authority’s employ- Electric Industry and Irrigation Workers Union, ees; 1,951 employees worked in the Generation known by its Spanish acronym (UTIER). At the end Directorate for a total of 24% of the Authority’s of the past fiscal year UTIER represented 4,717 employees; the Client Services Directorate employed employees engaged in operations and maintenance. 1,441 persons or 18% of the Authority’s workforce; The other three unions are the Insular Union of and 808 employees worked in the Executive Industrial Workers and Electrical Construction, Inc. Directorate, constituting approximately 10% of the (UITICE), with 839 construction workers; the Authority’s workforce. An additional 589 persons Independent Professional Employees Union (UEPI), were employed in one of the four other directorates with 360 professional employees, and the Puerto Rico or by the Governing Board. Electric Power Authority Pilots Union (UPAEE), with In an effort to achieve long term cost savings, in six pilots. The other 2,592 employees are members of September of 2009 the Authority implemented a the executive, managerial, and administrative staff: major change in the manner in which medical insur- the terms of employment for these employees are not ance would be provided for retirees and their spouses. established by a collective bargaining agreement. The Before September 1, 2009 an employee retiring with figures for fiscal year 2012 were similarly propor- 25 years of service received medical care insurance tional; 6,006 employees represented by unions, (70% for themselves and their spouse. After September 30, of the workforce), and 2,620 in executive, manage- 2009 an employee retiring with less than 30 years of rial, and administrative positions. 92 I 000106 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

The following paragraphs describe the status of the 2013. Negotiations were continuing at the end of fis- renegotiations of the Authority’s four collective bar- cal year 2013. gaining agreements. During these negotiations the EMPLOYEE SAFETY Authority has proposed language that reaffirms certain management rights, clarifies job descriptions, and Each of the Authority’s directors is responsible to the modifies the code of conduct in a manner that will Executive Director for the safety and health of the facilitate the management of its operations. The employees working within their respective direc- Authority is attempting to negotiate a reduction in torate. Subordinate managers, supervisors, and ulti- accident leave benefits to bring them more in line with mately the workers themselves share this the private sector and to reduce certain sick leave ben- responsibility. The Occupational Safety Division efits for new employees. The Authority has stressed assigns the safety and health professionals and certain that the current economy makes concessions on the of the other resources needed to assist the directors in part of the unions a prerequisite of a monetary offer. their efforts to prevent accidents and job-related ill- Nevertheless, during the collective bargaining process nesses. The Occupational Safety Division ensures that the Authority strives to negotiate reasonable and equi- the Authority’s workplace safety and health programs table terms for the Authority and its employees. comply with relevant Federal and Commonwealth statutes and are consistent with the objectives of the Labor agreements establishing wages, hours, and con- Authority. ditions of employment for three of the Authority’s four unions terminated during fiscal 2011; these The Division’s staff of 28, comprised largely of safety expirations were agreements with the Pilots and health professionals, provides assistance to man- (UPAEE), the Independent Professional Employees agers and supervisors in the day-to-day implementa- Union (UEPI), and Insular Union of Industrial and tion of safety and health programs. Fifteen of the 28 Electrical Construction Workers (UTICE). The agree- are assigned to other electric generating facilities and ment with Electric Industry and Irrigation Workers regional offices. The following is a sampling of the Union (UTIER), the largest union, expired in early distribution of safety and health professionals across fiscal year 2013. All renegotiations continued without the island. There are eight Safety and Industrial settlement during fiscal year 2013. Hygiene Officers, of these one is assigned to each of five generating stations, Central Aguirre Steam, The Authority and representatives of UTIER began Aguirre Combined Cycle, Central Costa Sur, Central the renegotiation of their collective bargaining agree- Palo Seco, and Central San Juan. Two Safety and ment during fiscal year 2011 approximately eighteen Industrial Hygiene Officers are based in Santurce. months prior to the agreement’s expiration in fiscal From these office locations they provide consulting year 2013. During fiscal year 2013 employees repre- services to the Cambalache Power Plant, gas turbine sented by UTIER held sporadic one day or partial day sites, the hydroelectric stations as well as to the other strikes, plus a two week work action beginning in directorates. A Health and Safety Officer is assigned in October 2012. each of the seven regional Transmission and The Authority began the renegotiation the collective Distribution offices in Arecibo, Carolina, Ponce, San bargaining agreement with the Pilots (UPAEE) in Juan, Bayamon, Caguas, and Mayagüez. One Health June 2010. The four-year agreement, which estab- and Safety Officer is assigned to the Line and lished wages, hours, and conditions of employment Substation Construction Subdivision. The Authority for the Authority’s six pilots, terminated in July 2010. has a single Safety Consultant based at the Costa Sur At the end of fiscal year 2013 the parties were still in Steam Plant who is responsible for the development negotiations. and implementation of safety programs for the Authority’s construction sites. The Hazard Negotiations for a new collective bargaining agree- Communication Section provides initial and refresher ment between the Authority and UEPI, which repre- training in hazardous waste operations and emer- sented 360 of the Authority’s employees, were gency response (HAZWOPER) to employees assigned continuing at the end of fiscal year 2013. The throughout the Authority. The training covers hazard Authority is seeking a three year agreement to replace recognition, hazard communication, and the use of the agreement that expired in December 2010. personal protective equipment. Additional resources The labor agreement with the construction workers include an attorney who assists the Authority in in UTICE terminated in January 2011. UTICE repre- responding to Puerto Rico OSHA (PR OSHA) cita- sented 10% of the Authority’s employees on June 30, tions, provides guidance with respect to safety laws, I 000107 93 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report and who chairs the Central Health and Safety Seco, and San Juan. In most cases, however, the first Committee with UTIER. aid and treatment provided by the Authority’s regis- The Division has a performance recognition program tered nurses were for a condition that was classified as for units and Directorates whose employees work in a non-occupational. high risk environment and a second recognition pro- Following a work related injury or illness almost all gram for those working in office environments where employees are referred from the Authority’s dispen- there is less risk of a work related injury or illness. sary or a first aid facility to one of the During the past year the Authority conducted 511 Commonwealth’s treatment clinics, which are a part training sessions for 6,637 employees in 32 different of the Corporación del Fondo del Seguro del Estado subject areas. The Authority’s supervisory training (CFSE) or Fondo for short. The physicians and med- focused on the importance of conducting and record- ical staff employed by Fondo provide the medical care ing job briefings to ensure that subordinates fully required for the Authority’s employees following a understood the exposures they might encounter in work related injury or illness and determine when the the performance of their tasks, the personal protec- employee is capable of returning to work. A long- tive equipment and actions necessary to safely com- term goal of the Authority has been to obtain the plete the assigned task. In addition the supervisory cooperation of Fondo’s representatives to expedite the training programs increased the awareness of the care being provided to their injured or ill employees. direct and indirect costs of accidents and illnesses and Since 1995 the Authority has had a random drug-test- their effect on the Authority’s cost of doing business. ing program, which has been implemented in steps. In calendar year 2013, the Authority reported to PR The random drug testing program applies to employ- OSHA that its employees worked a total of ees in safety sensitive positions, which constitutes 14,465,221 hours and sustained 1,355 incidents of more than 60% of its workforce. During the past year work related injury or illness that were recordable in approximately 25% of these employees were ran- accordance with OSHA’s requirements. There were domly tested. Employees who test positive and are twenty five serious accidents during the year. Since referred to a three month long treatment program, 2004 the Authority and other Puerto Rican public where they received treatment and counseling. corporations have been subject to financial penalties, Repeat violators are also referred to treatment, how- in the same manner as private corporations, for viola- ever, the Authority’s policy is an employee who tests tions of OSHA regulations. The Authority’s managers positive for drugs three times may be terminated. The and supervisors are routinely briefed annually on the Authority also administers drug tests to all candidates change in the OSHA penalty provisions. In calendar for employment. year 2013, the Authority was cited sixteen times for LEGAL AFFAIRS violating OSHA regulations. PR OSHA proposed fines totaling $41,975 for eight of the citations; the The thirty attorneys of the Legal Affairs Authority paid $8,500 in settlement of these citations. Directorate’s are responsible for a wide range of The proposed fines associated with the eight remain- contract and litigation related activities. The following citations from fiscal year 2013 total more than ing discussion summarizes the status of a number $65,000 and are being contested by the Authority. of the issues that the Authority litigated during fiscal year 2013. The employees of the Occupational Health Division, within the Human Resources and Labor Affairs During the past fiscal year the breach of contract lit- Directorate, are responsible for providing first aid, igation between Abengoa, Puerto Rico, S.E. and the medical treatment, training, and administrative serv- Authority continued in discovery in Superior ices to employees from the reported onset of a work Court, Court of First Instance in Puerto Rico. The related injury or illness until the employee returns to suit dates to an action in May 2000 when Abengoa, work, is reassigned, or reclassified. They provide a the prime contractor for the construction of two range of health related activities and training pro- combined cycle units at San Juan Steam Plant, ter- grams. An employee’s initial contact with this division minated their contract and left the construction is frequently at one of the eight dispensaries that are jobsite; Abengoa alleges $18 million in losses and staffed with registered nurses. The dispensaries are claimed as one basis that the Authority had not located at the Authority’s main office in Santurce, in obtained the required permits from the EPA that regional offices in Monacillos, Caguas, and Ponce and were necessary for the construction to proceed. The at the steam electric plants in Aguirre, Costa Sur, Palo Authority filed a counter claim for breach of con- 94 I 000108 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report tract and subsequently completed construction of meters can remotely disconnect service, when the units with another firm. The units went into appropriate. The Authority plans to install approxi- commercial operation in October 2008. The mately 60,000 upgraded meters in fiscal 2014 Authority in 2011 estimated their losses as a result bringing the total to 230,000. Larger Commercial of Abengoa’s alleged breach of contract to be and Industrial theft will be investigated and adjudi- approximately $250 million. In October 2007 the cated by the Puerto Rico Department of Justice, lawsuit was certified as complex litigation by the reducing the need and expense of administrative Superior Court of San Juan and a specially law judges in the recovery process. During fiscal appointed arbitrator was named to assist both par- year 2013 the Authority identified $19.1 million in ties in reaching a settlement. Subsequent failure of theft related lost revenue, of which, approximately the arbitration process moved the litigation to trial $5.0 million was recovered. The Authority’s finan- where the case will be adjudicated in two phases: cials shows an annual recovery of $30 million in liability, and wrongful termination and damages. A theft related lost revenues for each of the fiscal Status hearing was scheduled to be held in July years 2014 through 2018. 2013; it is anticipated that both parties will submit On August 23, 2007 Power Technologies Corp filed a Joint Pretrial Report in November 2013. suit against the Authority over the Authority’s deci- As part of the settlement in 2007 of the litigation sion not to proceed with a project to construct an over the Contributions in Lieu of Taxes, CILT, the electric generating plant in the Mayagüez area. Authority agreed to perform certain infrastructure Power Technologies Corp alleges that the project projects for the municipalities involved in the liti- was cancelled without justification; they are seek- gation. Work was continuing during the past fiscal ing recovery of damages of more than $51 million. year. The case was withdrawn by Power Technologies The Authority filed suit in Puerto Rican Court when both parties agreed to negotiate. seven years ago against the Brazilian manufacturer The Caribbean Petroleum Corporation’s and the manufacturer’s Puerto Rico agent over the (CAPECO), fuel storage depot in Bayamon caught failure of the more than 6,000 batteries in the fire in October 2009. The Authority had residual Sabana Llana Battery Energy Storage System, BESS. fuel oil and distillate stored at the depot. The fire The Authority claimed damages of more than $18 was extensive; it shut down the depot and caused million against the co-defendants, the manufacturer some amount of air and water contamination to the and their Puerto Rican partner. During fiscal year adjacent area. The Authority and numerous other 2010 the Brazilian battery manufacturer declared parties have been named in suits filed against bankruptcy. The Authority continued to litigate this CAPECO. Early in fiscal year 2011 CAPECO filed case against the Puerto Rican partner. The bonding for bankruptcy protection, staying the suits against company standing behind the Brazilian manufac- it. In December 2010 CAPECO sold its assets to turer and the Puerto Rican partner subsequently Puma Energy Caribe who commenced the recon- failed during 2011. The Authority has been advised struction of the damaged facility and environmental that recovery of more than $500,000 from the remediation. At the end of fiscal year 2013 the suit bonding company is unlikely. The Authority against the Authority and others continued in the expects to settle this litigation during fiscal year discovery stage of what could be a lengthy process 2014 and dispose of the batteries for salvage value. but one not material to the Authority. The Authority has increased its efforts to eliminate Following a heavy rainstorm in 2009 there was a the theft of electricity. Electricity theft is occurring mudslide that destroyed and damaged a number of across client classes, throughout the homes built by squatters on steep hillsides in the Commonwealth and has been identified as having a Ponce area. The mudslide occurred in an area where material impact on the Authority’s operations. there were Authority, PRASA, and other utility During fiscal year 2013 the Authority increased its structures. Six plaintiffs filed suit against the focus on smart grid technology to identify and dis- Authority and the other utilities, claiming $19.5 courage the theft of electricity. Continued imple- million in damages. Those bringing suit allege that mentation of upgraded meters and new smart data their losses were the result of soil instability that technology systems will allow the Authority to resulted from the installation of utilities, such as identify usage patterns and system disturbances tower foundations, underground services, utility consistent with electric energy theft. The upgraded poles and towers. The Authority alleges that the I 000109 95 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report utility installations predated the construction of the SUPPLEMENTARY homes. The case was stayed by the court following bankruptcy proceedings for PRASA’s insurer after INFORMATION which the Authority will continue with its defense. EXECUTIVE DIRECTOR CHANGES This suit is not likely to be resolved in fiscal year 2014. In January 2013 Ing Josué A. Colón Ortiz resigned from the Authority after serving as the Acting In 2005 fifty-five former workers, all of whom have Executive Director since June 2012. Prior to his a condition that can be associated with asbestos appointment Ing Colón was the Director of exposure and who were employed by the Authority Generation; his career with the Authority spanned 24 from 1960 to 2000, filed suit against the Authority. years, from design and maintenance engineering to They former workers claim they were exposed to management of production plant operations. asbestos during their employ and that the Authority did not provide adequate protection as required by Following Ing Colón’s resignation, Ing Juan Alicea federal and local laws. The plaintiffs are calming Flores was appointed Executive Director later that $320 million damages for health related illnesses. month. Ing Alicea has 30 years experience with the The Authority has filed a motion for dismissal Authority. During his tenure with the Authority he claiming immunity from suit since those bringing has held numerous senior management positions the suit were former employees and were covered including Acting Executive Director, Director of by workman’s compensation. Discovery is sched- Planning & Environmental Protection, General uled to end in fiscal year 2014. Power Plant Manager at the Palo Seco Steam Power Plant, Maintenance Department Head and Operations Department Head of the Aguirre Power Plant and Senior Shift Engineer. Ing Alicea graduated with a degree in Mechanical Engineering from the Mayaguez Campus of the University of Puerto Rico. In February 2013 the Authority’s Governing Board appointed Ing Roberto Garay González to the newly reopened the post of Vice Executive Director. Ing Garay has 25 years of experience at the Authority during which he has held senior positions such as Transmission and Distribution Technical Operations Director, and Transmission and Distribution Engineer. Ing Garay is an electrical engineer and has a Master Degree in Engineering Management. PREPA SUBSIDIARIES The Authority’ organization includes two component units—Puerto Rico Irrigation Systems and PREPA Holdings LLC. Both were active at the end of fiscal year 2013. The Puerto Rico Irrigation System operates various legacy portions of irrigation systems throughout the island. The condensed financial statement for Irrigation Systems as of June 30, 2013 showed $28.0 million in total assets and the annual revenue loss of $4.6 million, based on operating revenues of $6.9 million and operating expenses of $11.5 million. In addition, the Puerto Rico Irrigation System transferred $6.0 million to the Commonwealth government. PREPA Holdings, LLC is a subsidiary of the Authority that was created as the holding company for the

96 I 000110 No. CEPR-AP-2015-0001 URS I June 2013 Annual Report

Authority’s four other subsidiaries: PREPA Networks, During fiscal year 2008 PREPA.net acquired LLC (merged from and PREPA.NET); InterAmerican Ultracom, one of three submarine cable firms on the Energy Sources, LLC; PREPA Utilities, LLC; and island, to obtain international fiber optic cable capac- PREPA Oil & Gas, LLC. The latter two were not oper- ity and satellite teleport facilities. The acquisition was ating in fiscal year 2013. financed with a term loan of $10.1 million due in Based on the independent consolidated financial February 2023. The balance of the loan as of the end statements prepared for PREPA Holdings, LLC, at the of fiscal year 2013 was $8.1 million. end of fiscal year 2013 the total consolidated assets of In November 2011 PREPA.NET entered into a 10 PREPA Holdings were $46.5 million and its consoli- year Indefeasible Right to Use purchase agreement dated liabilities were $29.6 million. PREPA Holdings’ with PRASA in the amount of $13.7 million. The operating revenues were $14.5 million and its operat- agreement allows PRASA an Indefeasible Right to Use ing expenses were $8.2 million; this resulted in an (IRU) for the fiber optic communication network. operating income of $4.1 million after interest and Also in fiscal year 2012 PREPA.net acquired property the transfer to the Commonwealth government of in Isla Verde for the development of a facility to sup- $2.0 million. The consolidated operating revenues in port its telecommunications business; the facility is fiscal year 2013 were up $0.9 million over the previ- scheduled for completion in fiscal year 2014. ous year primarily from the amounts received from the local telecommunications company for the joint On March 12, 2012 PREPA Networks, Corporation pole attachments in the three prior fiscal years and PREPA .NET merged to form PREPA Holdings, through 2012. LLC. In 2000 the Authority began the acquisition of a fiber Also in March 2012, PREPA holdings entered into an optic cable system to modernize the Authority’s inter- 18 year IRU sale agreement with Cable and Wireless nal communication systems and thereby provide of Panama, S.A. (CWP) for the amount of $2.3 mil- faster and more secure data transmission for opera- lion. The agreement grants PREPA Holdings an IRU tions, load management, system protection, and secu- for the fiber optic communication network owned by rity. In order to meet its optical fiber cable CWP. requirements, the Authority entered into a long-term During fiscal year 2013 the following subsidiaries agreement with Puerto Rico Information Networks, were not in operation: Inc. (PRIN) a private, independent, non-profit corpo- PREPA Utilities was formed to financially participate ration incorporated in Puerto Rico. Under the agree- in, develop, construct and operate industrial projects ment, PRIN designed and built a fiber optic cable and other related infrastructure to improve the elec- system that was installed on the Authority’s rights-of- tric infrastructure of the Authority. way (mainly its transmission lines). The fiber-optic cable is an integral part of the overhead ground wires PREPA Oil & Gas was established to provide a mech- which protect transmission lines from lightning anism for the Authority to participate in a wide range strikes. When completed in August 2002, title to the of financial, commercial and operational projects for system was transferred to the Authority. fuel supply and infrastructure. The Authority financed its acquisition of the fiber optic system from PRIN by selling $43.7 million of Subordinate Obligations in October 2002. In June 2005 the Authority created PREPA Networks, LLC (PREPA.Net) to replace PRIN and market the excess communication capacity of the fiber optic network. PREPA.Net owns, operates and maintains the fiberoptic network that offers next generation telecommunications (NGT) service to carriers, internet service providers (ISPs), and large enterprises. PREPA.net’s network has optical technology that is used by service providers to communicate with submarine cable landing stations, wireless network towers and island wide locations.

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APPENDICES

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I 000116 APPENDIX I INTERMEDIATE-TERM FINANCIAL PLANNING FORECAST I 000117

Actual Forecast 2013 2014 2015 2016 2017 2018 Increase Increase Increase Increase Increase Increase Amount % Amount % Amount % Amount % Amount % Amount % kWh SALES (000) Residential 6,655,596 1.46 6,929,613 4.12 6,941,706 0.17 7,022,449 1.16 7,138,391 1.65 7,276,068 1.93 Commercial 8,635,165 4.04 8,591,133 (0.51) 8,668,240 0.90 8,799,775 1.52 8,961,607 1.84 9,143,746 2.03 Industrial 2,578,386 (7.20) 2,337,478 (9.34) 2,317,024 (0.88) 2,312,026 (0.22) 2,316,079 0.18 2,329,938 0.60 Public Lighting 268,322 (32.51) 249,796 (6.90) 249,796 0.00 250,480 0.27 249,796 (0.27) 249,796 0.00 Agricultural 27,277 0.17 26,633 (2.36) 26,633 0.00 26,706 0.27 26,633 (0.27) 26,633 0.00 Others 56,436 14.08 64,377 14.07 64,377 0.00 64,554 0.27 64,377 (0.27) 64,377 0.00 TOTAL 18,221,182 0.60 18,199,030 (0.12) 18,267,776 0.38 18,475,990 1.14 18,756,883 1.52 19,090,558 1.78

CUSTOMERS (12 month average) Residential 1,353,550 0.98 1,368,861 1.13 1,383,721 1.09 1,398,580 1.07 1,413,440 1.06 1,428,300 1.05 Commercial 126,735 (1.44) 129,144 1.90 131,535 1.85 132,496 0.73 133,458 0.73 134,420 0.72 Industrial 709 (3.27) 681 (3.95) 654 (3.96) 628 (3.98) 603 (3.98) 579 (3.98) Public Lighting 2,926 22.12 2,924 (0.07) 2,924 0.00 2,924 0.00 2,924 0.00 2,924 0.00 Agricultural 1,227 (3.23) 1,228 0.08 1,228 0.00 1,228 0.00 1,228 0.00 1,228 0.00 Others 3 50.00 3 0.00 3 0.00 3 0.00 3 0.00 3 0.00 TOTAL 1,485,150 0.80 1,502,841 1.19 1,520,065 1.15 1,535,859 1.04 1,551,656 1.03 1,567,454 1.02 kWh PER CUSTOMER Residential 4,917 0.48 5,062 2.95 5,017 (0.90) 5,021 0.09 5,050 0.58 5,094 0.87 Commercial 68,136 5.56 66,524 (2.37) 65,901 (0.94) 66,415 0.78 67,149 1.10 68,024 1.30 Industrial 3,636,652 (4.06) 3,432,420 (5.62) 3,542,850 3.22 3,681,570 3.92 3,840,927 4.33 4,024,073 4.77 Public Lighting 91,703 (44.74) 85,430 (6.84) 85,430 0.00 85,663 0.27 85,430 (0.27) 85,430 0.00 Agricultural 22,231 3.52 21,688 (2.44) 21,688 0.00 21,748 0.27 21,688 (0.27) 21,688 0.00 Others 18,812,000 (23.95) 21,459,000 14.07 21,459,000 0.00 21,518,000 0.27 21,459,000 (0.27) 21,459,000 0.00 TOTAL 12,269 (0.20) 12,110 12,018 12,030 12,088 12,179 BASE REVENUE ($000) Residential$ 341,774 1.28 $ 348,110 1.85 $ 349,004 0.26 $ 353,046 1.16 $ 358,762 1.62 $ 365,512 1.88 Commercial 600,768 5.67 601,732 0.16 607,132 0.90 616,345 1.52 627,680 1.84 640,437 2.03 Industrial 115,896 (3.83) 106,733 (7.91) 105,799 (0.88) 105,571 (0.22) 105,756 0.18 106,389 0.60 Public Lighting 51,762 4.69 48,509 (6.28) 48,509 0.00 48,642 0.27 48,509 (0.27) 48,509 0.00 Agricultural 1,677 0.12 1,659 (1.07) 1,659 0.00 1,663 0.24 1,659 (0.24) 1,659 0.00 Others 2,175 1.87 3,047 40.09 3,047 0.00 3,056 0.30 3,047 (0.29) 3,047 0.00 TOTAL$ 1,114,052 3.18 $ 1,109,790 (0.38)$ 1,115,150 0.48 $ 1,128,323 1.18 $ 1,145,413 1.51 $ 1,165,553 1.76 FUEL OIL ADJUSTMENT ($000) Residential$ 1,010,924 (10.90)$ 942,633 (6.76)$ 920,260 (2.37)$ 894,815 (2.76)$ 895,305 0.05 $ 847,674 (5.32) Commercial 1,411,558 (8.03) 1,143,691 (18.98) 1,125,256 (1.61) 1,097,972 (2.42) 1,100,607 0.24 1,043,116 (5.22) Industrial 378,049 (16.23) 285,209 (24.56) 275,801 (3.30) 264,519 (4.09) 260,821 (1.40) 243,723 (6.56) Public Lighting 47,981 (5.67) 35,226 (26.58) 34,326 (2.55) 33,084 (3.62) 32,475 (1.84) 30,165 (7.11) Agricultural 4,580 (13.99) 3,755 (18.01) 3,662 (2.48) 3,529 (3.63) 3,465 (1.81) 3,218 (7.13) Others 8,874 9.11 7,809 (12.00) 7,610 (2.55) 7,336 (3.60) 7,200 (1.85) 6,688 (7.11) No. CEPR-AP-2015-0001 TOTAL$ 2,861,966 (10.15)$ 2,418,323 (15.50)$ 2,366,915 (2.13)$ 2,301,255 (2.77)$ 2,299,873 (0.06)$ 2,174,584 (5.45) PURCHASED POWER ($000) Residential$ 314,443 10.37 $ 352,179 12.00 $ 394,553 12.03 $ 407,508 3.28 $ 421,512 3.44 $ 436,022 3.44 Commercial 405,155 12.44 428,278 5.71 482,444 12.65 500,030 3.65 518,169 3.63 536,552 3.55 Industrial 108,317 1.94 106,938 (1.27) 118,247 10.58 120,465 1.88 122,796 1.94 125,365 2.09 Public Lighting 13,794 15.31 13,194 (4.35) 14,717 11.54 15,066 2.37 15,289 1.48 15,516 1.48 Agricultural 1,328 7.01 1,410 6.17 1,570 11.35 1,607 2.36 1,631 1.49 1,655 1.47 Others 2,293 22.69 2,920 27.34 3,263 11.75 3,340 2.36 3,390 1.50 3,440 1.47 TOTAL$ 845,330 10.28 $ 904,919 7.05 $ 1,014,794 12.14 $ 1,048,016 3.27 $ 1,082,787 3.32 $ 1,118,550 3.30 REVENUES ($000)-incl. adj. charge Residential$ 1,667,141 (5.11)$ 1,642,921 (1.45)$ 1,663,817 1.27 $ 1,655,368 (0.51)$ 1,675,579 1.22 $ 1,649,208 (1.57) Commercial 2,417,481 (1.88)$ 2,173,702 (10.08) 2,214,831 1.89 2,214,347 (0.02) 2,246,456 1.45 2,220,105 (1.17) Industrial 602,262 (11.18) 498,879 (17.17) 499,847 0.19 490,555 (1.86) 489,373 (0.24) 475,477 (2.84) Public Lighting 113,537 1.13 96,930 (14.63) 97,552 0.64 96,792 (0.78) 96,273 (0.54) 94,190 (2.16) Agricultural 7,585 (7.96) 6,824 (10.03) 6,891 0.98 6,799 (1.34) 6,755 (0.65) 6,532 (3.30) Others 13,342 9.93 13,776 3.25 13,920 1.05 13,731 (1.36) 13,637 (0.68) 13,175 (3.39) TOTAL$ 4,821,348 (4.18)$ 4,433,032 (8.05)$ 4,496,858 1.44 $ 4,477,592 (0.43)$ 4,528,073 1.13 $ 4,458,687 (1.53) APPENDIX II INCOME STATEMENT I 000118 Actual1 Forecast 2013 2014 2015 2016 2017 2018 REVENUES Revenues from Appendix I$ 4,821,348,190 $ 4,433,032,000 $ 4,496,858,000 $ 4,477,592,000 $ 4,528,073,000 $ 4,458,687,000 Add'l Revenues from Theft Recovery - 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 From Sales of Electricity 4,821,348,190 4,463,032,000 4,526,858,000 4,507,592,000 4,558,073,000 4,488,687,000 Other Operating Revenue-Net 30,166,264 - - - - - Total Operating Revenue 4,851,514,454 4,463,032,000 4,526,858,000 4,507,592,000 4,558,073,000 4,488,687,000 Other Income-Net (698,076) 31,179,000 31,179,000 31,179,000 31,179,000 31,179,000 Total Revenues $ 4,850,816,378 $ 4,494,211,000 $ 4,558,037,000 $ 4,538,771,000 $ 4,589,252,000 $ 4,519,866,000 CURRENT EXPENSES Operating Expenses $ 4,125,389,640 $ 3,700,008,000 $ 3,734,895,000 $ 3,716,576,000 $ 3,749,204,000 $ 3,671,427,000 Miscellaneous Interest and Other ------Total Current Expenses 4,125,389,640 3,700,008,000 3,734,895,000 3,716,576,000 3,749,204,000 3,671,427,000 Balance to Revenue Fund $ 725,426,738 $ 794,203,000 $ 823,142,000 $ 822,195,000 $ 840,048,000 $ 848,439,000 1974 SINKING FUND Interest on Bonds $ 332,503,272 $ 358,463,000 $ 364,096,000 $ 368,753,000 $ 388,867,000 $ 376,697,000 Bond Redemption 194,920,000 204,305,000 214,410,000 224,035,000 237,365,000 249,535,000 Reserve Account ------Total Sinking Fund Payments2 $ 527,423,272 $ 562,768,000 $ 578,506,000 $ 592,788,000 $ 626,232,000 $ 626,232,000 Balance$ 198,003,466 $ 231,435,000 $ 244,636,000 $ 229,407,000 $ 213,816,000 $ 222,207,000 TRANSFERS Reserve Maintenance Fund ------Self Insurance Fund ------

1974 Capital Improvement Fund 16,986,499 22,677,000 31,321,000 12,920,000 12,920,000 12,920,000 No. CEPR-AP-2015-0001 Interest on Notes 457,798 7,731,000 7,552,000 7,552,000 7,552,000 7,552,000 Total $ 17,444,297 $ 30,408,000 $ 38,873,000 $ 20,472,000 $ 20,472,000 $ 20,472,000 Balance $ 180,559,169 $ 201,027,000 $ 205,763,000 $ 208,935,000 $ 193,344,000 $ 201,735,000 Contributions in Lieu of Taxes and Other 180,559,169 201,027,000 205,763,000 208,935,000 193,344,000 201,735,000 Balance $ - $ -$ -$ -$ -$ -

1. Audited 2. Principal and Interest requirements are net of capitalized interest from previous bond issues. APPENDIX III I

000119 DETAIL OF OPERATING and MAINTENANCE EXPENSES

Actual1 Forecast 2013 2014 2015 2016 2017 2018

OPERATION Thermal and Gas Production Fuel Expense Fuel2 $ 2,603,577,000 $ 2,145,911,000 $ 2,100,801,000 $ 2,044,913,000 $ 2,044,304,000 $ 1,934,695,000 Purchased Power 755,686,000 805,414,000 903,208,000 932,776,000 963,724,000 995,556,000 Other Production Costs 69,718,000 63,943,000 56,739,000 57,361,000 57,538,000 57,538,000 Hydroelectric Plant Production 1,937,000 1,756,000 1,558,000 1,575,000 1,580,000 1,580,000 Transmission 19,272,000 26,132,000 24,427,000 24,695,000 24,771,000 24,771,000 Distribution 153,046,000 132,599,000 123,950,000 125,306,000 125,695,000 125,695,000 Client Accounting and Collection 116,351,000 115,370,000 111,521,000 112,742,000 113,091,000 113,091,000 Administrative and General 191,913,000 175,510,000 187,797,000 189,851,000 190,440,000 190,440,000 Total Operation $ 3,911,500,000 $ 3,466,635,000 $ 3,510,001,000 $ 3,489,219,000 $ 3,521,143,000 $ 3,443,366,000

MAINTENANCE Thermal and Gas Production$ 99,355,000 $ 108,694,187 $ 104,745,067 $ 105,892,216 $ 106,220,107 $ 106,220,107 Hydroelectric Plant 2,860,000 3,629,869 3,497,987 3,536,296 3,547,246 3,547,246

Transmission 30,058,000 17,437,081 16,803,550 16,987,580 17,040,181 17,040,181 No. CEPR-AP-2015-0001 Distribution 74,716,000 94,850,155 91,404,022 92,405,063 92,691,191 92,691,191 General Plant 6,901,000 8,761,708 8,443,374 8,535,845 8,562,275 8,562,275

Total Maintenance $ 213,890,000 $ 233,373,000 $ 224,894,000 $ 227,357,000 $ 228,061,000 $ 228,061,000

TOTAL O & M $ 4,125,390,000 $ 3,700,008,000 $ 3,734,895,000 $ 3,716,576,000 $ 3,749,204,000 $ 3,671,427,000 1. Audited 2. Projections excludes interest, transportation and handling charges No. CEPR-AP-2015-0001

APPENDIX IV Page 1 of 2 ANNUAL NET GENERATION, FUEL CONSUMPTION, FUEL and PURCHASED POWER COSTS

Actual Forecast 2013 2014 2015 2016 2017 2018 AGUIRRE STEAM PLANT Net MWh-Generated 4,226,411 4,353,000 4,439,000 5,078,000 4,823,000 4,989,000 Barrels of Fuel Oil Used 7,087,884 6,954,000 7,209,000 8,757,000 8,288,000 8,589,000 MBTUx1000 44,654 43,810 44,870 51,030 48,292 50,046 kWh Per Barrel 596 626 616 580 582 581 Cost of Fuel $ 800,803,249 $ 671,600,000 $ 669,920,000 $ 678,072,934 $ 633,956,000 $ 630,726,567 Cost of Fuel Per Barrel $ 112.98 $ 96.58 $ 92.93 $ 77.43 $ 76.49 $ 73.43 $/Mbtu $ 17.93 $ 15.33 $ 14.93 $ 13.29 $ 13.13 $ 12.60 COSTA SUR STEAM PLANT Net MWh-Generated 3,120,018 4,752,000 4,778,000 3,839,000 3,571,000 3,226,000 Barrels of Fuel Oil Used or Equivlent 5,528,530 8,459,000 8,534,000 6,908,000 6,420,000 5,801,000 MBTUx1000 34,830 50,285 50,756 41,142 38,191 34,480 kWh Per Barrel 564 562 560 556 556 556 Cost of Fuel $ 521,197,048 $ 676,126,000 $ 691,105,000 $ 567,905,000 $ 525,286,000 $ 465,395,000 Cost of Fuel Per Barrel $ 94.27 $ 79.93 $ 80.98 $ 82.21 $ 81.82 $ 80.23 $/Mbtu $ 14.96 $ 13.45 $ 13.62 $ 13.80 $ 13.75 $ 13.50 PALO SECO STEAM PLANT Net MWh-Generated 2,689,532 2,016,000 1,785,000 1,992,000 2,089,000 2,028,000 Barrels of Fuel Oil Used or Equivlent 4,575,037 3,324,000 2,943,000 3,286,000 3,511,000 3,617,000 MBTUx1000 28,823 20,936 18,540 20,698 21,702 21,075 kWh Per Barrel 588 606 607 606 595 561 Cost of Fuel $ 511,036,274 $ 319,444,000 $ 284,424,000 $ 318,402,000 $ 335,828,000 $ 316,710,984 Cost of Fuel Per Barrel $ 111.70 $ 96.10 $ 96.64 $ 96.90 $ 95.65 $ 87.56 $/Mbtu $ 17.73 $ 15.26 $ 15.34 $ 15.38 $ 15.47 $ 15.03 SAN JUAN STEAM PLANT Net MWh-Generated 2,002,269 998,000 640,000 716,000 778,000 627,000 Barrels of Fuel Oil Used or Equivlent 3,616,511 1,808,000 1,161,000 1,301,000 1,436,000 1,195,000 MBTUx1000 22,784 11,393 7,316 8,199 8,904 7,177 kWh Per Barrel 554 552 551 550 542 525 Cost of Fuel $ 404,852,726 $ 174,765,000 $ 110,134,000 $ 125,714,000 $ 138,864,000 $ 110,041,000 Cost of Fuel Per Barrel $ 111.95 $ 96.66 $ 94.86 $ 96.63 $ 96.70 $ 92.08 $/Mbtu $ 17.77 $ 15.34 $ 15.05 $ 15.33 $ 15.60 $ 15.33 AGUIRRE COMBINED-CYCLE UNITS Net MWh-Generated 309,354 226,000 220,000 618,000 922,000 700,000 Barrels of Fuel Oil or Equivalent 595,728 397,000 387,000 1,063,000 1,580,000 1,206,000 MBTUx1000 3,753 2,305 2,248 6,195 9,208 7,030 kWh Per Barrel (or equivalent) 519 569 568 581 584 580 Cost of Fuel $ 82,931,254 $ 56,069,000 $ 46,037,000 $ 81,118,376 $ 119,958,059 $ 88,873,042 Cost of Fuel Per Barrel $ 139.21 $ 141.23 $ 118.96 $ 76.31 $ 75.92 $ 73.69 $/Mbtu $ 22.10 $ 24.32 $ 20.48 $ 13.09 $ 13.03 $ 12.64 COMBUSTION-TURBINES & DIESELS Net MWh-Generated 11,439 1,000 1,000 1,000 1,000 1,000 Barrels of Fuel Oil Used 31,862 1,588 1,494 2,045 2,217 2,037 MBTUx1000 201 9 9 12 13 12 kWh Per Barrel 359 630 669 489 451 491 Cost of Fuel $ 4,424,965 $ 222,565 $ 210,428 $ 295,774 $ 331,558 $ 314,000 Cost of Fuel Per Barrel $ 138.88 $ 140.15 $ 140.85 $ 144.63 $ 149.55 $ 154.15 $/Mbtu $ 22.04 $ 24.73 $ 23.38 $ 24.65 $ 25.50 $ 26.17 CAMBALACHE Net MWh-Generated 62,236 5,000 6,000 3,000 5,000 3,000 Barrels of Fuel Oil or Equivalent 128,558 11,587 12,876 6,375 11,205 5,921 MBTUx1000 810 67 75 37 65 34 kWh Per Barrel 484 432 466 456 446 507 Cost of Fuel3 $ 18,387,724 $ 1,611,000 $ 1,784,000 $ 905,000 $ 1,668,000 $ 900,000 Cost of Fuel Per Barrel $ 143.03 $ 139.04 $ 138.55 $ 141.96 $ 148.86 $ 152.00 $/Mbtu $ 22.70 $ 24.04 $ 23.79 $ 24.46 $ 25.66 $ 26.47 MAYAGUEZ TURBINES Net MWh-Generated 110,179 104,000 56,000 20,000 25,000 22,000 Barrels of Fuel Oil or Equivalent 201,497 173,752 94,811 33,483 41,790 36,453 MBTUx1000 1,269 174 95 33 42 36 kWh Per Barrel 547 599 591 597 598 604 Cost of Fuel $ 28,238,082 $ 25,129,000 $ 13,633,000 4,912,000 6,384,000 5,740,000 Cost of Fuel Per Barrel $ 140.14 $ 144.63 $ 143.79 $ 146.70 $ 152.76 $ 157.46 $/Mbtu $ 22.24 $ 144.42 $ 143.51 $ 148.85 $ 152.00 $ 159.44 REPOWERED SAN JUAN UNITS. 5 & 6 Net MWh-Generated 1,159,293 1,017,000 1,305,000 1,170,000 1,518,000 2,529,000 Barrels of Fuel Oil or Equivalent 1,654,843 1,469,000 1,910,000 1,731,000 2,166,000 3,459,000 MBTUx1000 10,426 8,522 11,083 10,046 12,596 20,158 kWh Per Barrel 701 692 683 676 701 731 Cost of Fuel $ 231,705,894 $ 212,439,000 $ 274,401,000 255,881,000 269,704,000 301,769,774 Cost of Fuel Per Barrel $ 140.02 $ 144.61 $ 143.67 $ 147.82 $ 124.52 $ 87.24 $/Mbtu $ 22.22 $ 24.93 $ 24.76 $ 25.47 $ 21.41 $ 14.97

I 000120 No. CEPR-AP-2015-0001

APPENDIX IV Page 2 of 2 ANNUAL NET GENERATION, FUEL CONSUMPTION, FUEL and PURCHASED POWER COSTS

Actual Forecast 2013 2014 2015 2016 2017 2018 Continued from previous page TOTAL THERMAL 2014 MBTU Net MWh-Generated 13,690,731 13,472,000 13,229,000 13,437,000 13,732,000 14,125,000 Barrels of Fuel Oil 23,420,450 22,597,927 22,253,181 23,087,903 23,456,212 23,911,411 MBTUx1000 147,550 137,501 134,992 137,392 139,013 140,048 kWh Per Barrel 585 596 594 582 585 591 Fuel Cost $ 2,603,577,216 $ 2,137,405,565 $ 2,091,649,428 $ 2,033,205,084 $ 2,031,980,617 $ 1,920,471,367 Fuel Financing Credit Line Interest $ 16,611,020 $ 15,000,000 $ 15,000,000 $ 15,000,000 $ 15,000,000 $ 15,000,000 Fuel Cost incl Credit Line Interest $ 2,620,188,236 $ 2,152,405,565 $ 2,106,649,428 $ 2,048,205,084 $ 2,046,980,617 $ 1,935,471,367 Cost of Fuel Per Barrel $ 111.17 $ 95.25 $ 94.67 $ 88.71 $ 87.27 $ 80.94 $/Mbtu$ 17.65 $ 15.54 $ 15.49 $ 14.80 $ 14.62 $ 13.71 PURCHASED POWER-ECOELECTRICA Net MWh-Generated 3,570,315 3,724,000 3,675,000 3,698,000 3,744,000 3,741,000 Cost $ 407,552,844 $ 358,010,577 $ 381,442,274 $ 400,162,000 $ 421,410,500 $ 443,200,215 $/MWH $ 114.15 $ 96.14 $ 103.79 $ 108.21 $ 112.56 $ 118.47 PURCHASED POWER-AES Net MWh-Generated 3,513,485 3,362,521 3,362,522 3,372,499 3,362,522 3,362,522 Cost $ 327,509,327 $ 344,813,719 $ 351,050,291 $ 359,631,000 $ 367,774,199 $ 374,660,460 $/MWH$ 93.21 $ 102.55 $ 104.40 $ 106.64 $ 109.37 $ 111.42 PURCHASED POWER Net MWh-Generated 7,083,800 7,086,521 7,037,522 7,070,499 7,106,522 7,103,522 Cost $ 735,062,171 $ 702,824,296 $ 732,492,565 $ 759,793,000 $ 789,184,699 $ 817,860,675 $/MWH$ 103.77 $ 99.18 $ 104.08 $ 107.46 $ 111.05 $ 115.13 RENEWABLE ENERGY SOURCES Total Renewable Sources Net MWh-Generated 143,580 621,769 994,960 997,671 994,964 994,959 Cost$ 20,623,661 $ 102,589,786 170,714,558 172,983,000 174,538,737 177,694,649 $/MWH$ 143.64 $ 165.00 $ 171.58 $ 173.39 $ 175.42 $ 178.59 HYDROELECTRIC Net MWh-Generated 90,860 126,170 126,170 126,170 126,170 126,170 TOTAL (Including Hydro & PP) Net MWh-Generated 21,008,971 21,306,460 21,387,652 21,631,340 21,959,656 22,349,651 Cost $ 3,359,263,048 $ 2,942,819,647 $ 2,994,856,551 $ 2,965,981,084 $ 2,995,704,053 $ 2,916,026,691

Forecast based on ABC '13 projections Cost of fuel includes shipping and handling charges.

I 000121 APPENDIX V Page 1 of 2 DEBT SERVICE COVERAGE UNDER THE 1974 TRUST AGREEMENT Adjusted Net Revenues Average Net Revenues I

000122 Date Principal Amount Maximum 12 Consecutive 5 Years of After Payments Principal Months Preceding Percent Following Percent Issue Series and Refunding & Interest Date of Issue Coverage Current Year Coverage

1/3/2002 JJ 134,095,000 1 415,641,309 636,368,000 153.11 746,303,000 179.55 (Refunding) 7/2/2002 KK 186,790,000 2 415,923,000 627,086,000 150.77 746,303,000 179.43 (Refunding) 7/2/2002 LL 98,125,000 415,923,000 627,086,000 150.77 746,303,000 179.43 10/3/2002 MM 61,180,000 3 415,918,000 630,219,000 151.52 746,303,000 179.44 (Refunding) 8/19/2003 NN 171,525,000 4 442,399,978 664,780,000 150.27 728,160,000 164.59 8/26/2004 OO 120,470,000 5 442,395,314 635,751,000 143.71 711,111,000 160.74 (Refunding) 8/26/2004 PP 85,850,000 6 442,395,314 635,751,000 143.71 711,111,000 160.74 (Refunding) 4/4/2005 QQ 95,270,000 473,784,011 612,777,000 129.34 711,111,000 150.09 (Refunding) 4/4/2005 RR 236,265,000 7 473,784,011 612,777,000 129.34 711,111,000 150.09 4/4/2005 SS 426,415,000 8 473,784,011 612,777,000 129.34 711,111,000 150.09 (Refunding) 5/3/2007 TT 643,530,000 455,022,444 698,001,000 153.40 723,100,000 158.92 5/3/2007 UU 857,565,000 9 455,022,444 698,001,000 153.40 723,100,000 158.92 (Refunding) 5/30/2007 V V 557,410,000 455,022,444 698,001,000 153.40 723,100,000 158.92 (Refunding) 6/26/2008 W W 663,660,000 10 476,874,792 662,928,000 139.02 756,405,000 158.62 4/7/2010 XX 822,210,000 520,073,371 722,064,000 138.84 794,200,000 152.71 No. CEPR-AP-2015-0001 4/29/2010 YY 320,175,000 532,820,338 722,064,000 135.52 794,200,000 149.06 (Refunding) 5/5/2010 ZZ 587,200,000 528,945,786 740,862,000 140.06 794,200,000 150.15 (Refunding) 5/5/2010 AAA 363,075,000 528,945,786 740,862,000 140.06 794,200,000 150.15 5/26/2010 BBB 76,800,000 549,321,366 740,862,000 134.87 794,200,000 144.58 5/26/2010 CCC 316,920,000 549,321,366 740,862,000 134.87 794,200,000 144.58 10/14/2010 DDD 218,225,000 549,316,970 739,106,000 134.55 856,100,000 155.85 (Refunding) 12/29/2010 EEE 355,730,000 563,367,710 708,449,000 125.75 856,100,000 151.96 5/1/2012 2012A 630,110,000 594,844,190 699,667,000 117.62 837,000,000 140.71 5/1/2012 2012B 19,890,000 11 594,844,190 699,667,000 117.62 837,000,000 140.71 (Refunding) APPENDIX V Page 2 of 2 DEBT SERVICE COVERAGE UNDER THE 1974 TRUST AGREEMENT Continued from previous page I 000123 The total debt issued under the Trust Agreement is $17,782,028,431 which includes refunding totalling $7,872,068,473. As of June 30, 2013, the outstanding debt under the 1974 Trust Agreement is $8,048,485,000.

The superscripted Principal Amounts in the table reflect the effects of refunding described below: 1. $690,000 refunded by Series ZZ and deducted from the original $205,065,000 Series JJ issue. 2. $7,765,000 refunded by Series SS, $19,000,000 refunded by Series ZZ and deducted from the original $401,785,000 Series KK issue. 3. $11,000,000 refunded by Series SS, $1,045,000 refunded by Series ZZ and deducted from the original $105,055,000 Series MM issue. 4. $288,590,000 refunded by Series VV; $57,190,000 refunded by Series UU and deducted from original amount $517,305,000 Series NN issue. 5. $3,535,000 refunded by Series ZZ and deducted from original $136,105,000 Series OO issue. 6. $235,000 refunded by Series ZZ and deducted from original $86,595,000 Series PP issue. 7. $273,255,000 refunded by Series VV and deducted from original $509,520,000 Series RR issue. 8. $9,190,000 refunded by Series ZZ and deducted from original $483,930,000 Series SS issue. 9. $1,885,000 refunded by Series ZZ, $434,190,000 refunded by Series AAA and deducted from original $1,300,035,000 Series UU issue. 10. $10,685,000 refunded by Series ZZ and deducted from original $697,345,000 Series WW issue. 11. $21,345,000 refunded by Series 2012B and deducted from original $515,305,000 Series II issue. No. CEPR-AP-2015-0001 APPENDIX VI I 000124 CAPITAL EXPENDITURES

Actual1 Forecast 2013 2014 2015 2016 2017 2018

Production Plant $ 107,810,000 $ 96,375,000 $ 115,850,000 $ 110,365,000 $ 128,502,000 $ 124,650,000 Transmission Plant 69,661,000 66,347,000 61,262,000 66,859,000 62,613,000 72,391,000 Distribution Plant 127,926,000 99,884,000 87,532,000 88,836,000 96,112,000 92,774,000 General Land and Buildings 4,520,000 7,217,000 9,131,000 7,569,000 9,227,000 9,276,000 General Equipment 17,805,000 26,552,000 22,191,000 22,288,000 23,583,000 22,934,000 Preliminary Surveys and Investigations (45,000) 3,625,000 4,034,000 4,083,000 4,963,000 2,975,000 SUBTOTAL $ 327,677,000 $ 300,000,000 $ 300,000,000 $ 300,000,000 $ 325,000,000 $ 325,000,000

Construction Costs in Previous Year Reimbursed in Current Year 265,910,000 316,774,000 309,043,000 309,043,000 309,293,000 321,668,000

Construction Costs in Current

Year to be Reimbursed Next Year (316,774,000) (309,043,000) (309,043,000) (309,293,000) (321,668,000) (327,606,000) No. CEPR-AP-2015-0001

TOTAL FUNDS REQUIRED $ 276,813,000 $ 307,731,000 $ 300,000,000 $ 299,750,000 $ 312,625,000 $ 319,062,000

1. Actual expenditures are net of adjustments from previous years. APPENDIX VII SOURCES OF FUNDS FOR CAPITAL EXPENDITURES I 000125

Actual1 Forecast 2013 2014 2015 2016 2017 2018

FUNDS FROM BOND ISSUES AND NOTES REVENUE BONDS2 Balance in Fund Start of Fiscal Year $ 276,207,000 $ 50,473,000 $ 279,650,000 $ 22,471,000 $ 301,141,000 $ 10,436,000 $573.1M Series "2013A" Aug '13 500,000,000 - $557M Series "2015A" Aug '15 - 557,000,000 $500M Series "2017A" Sep '17 - 500,000,000 Balance in Fund End of Fiscal Year (50,473,000) (279,650,000) (22,471,000) (301,141,000) (10,436,000) (213,794,000) PAID FROM REVENUE BONDS$ 225,734,000 $ 270,823,000 $ 257,179,000 $ 278,330,000 $ 290,705,000 $ 296,642,000

NOTES Notes Paid (6,672,000) - - - - Notes Issued-Regular Financing ------PAID FROM NOTES$ (6,672,000) $ - $ - $ -$ - $ -

FUNDS FROM OTHER SOURCES Transfers from General Fund (Net)3 2,921,000 22,677,000 31,321,000 12,920,000 12,920,000 12,920,000 Interest earned on Construction Fund 966,000 6,500,000 4,500,000 2,000,000 2,000,000 2,000,000 Capitalized Interest on Sinking Fund 14,065,000 7,731,000 7,000,000 6,500,000 7,000,000 7,500,000 No. CEPR-AP-2015-0001 Grants and other (Principally From FEMA)4 39,799,000 - - - - - PAID FROM OTHER SOURCES 57,751,000 36,908,000 42,821,000 21,420,000 21,920,000 22,420,000

GRAND TOTAL$ 276,813,000 $ 307,731,000 $ 300,000,000 $ 299,750,000 $ 312,625,000 $ 319,062,000

1. Audited 2. Net proceeds from past bond issues 3. Net of Capital Improvement Funds less capitalized interest transferred to the General Fund. 4. Amounts available to finance the CIP from FY2009-2012 which was not transferred from the General Fund to the Construction Fund. APPENDIX VIII

I SYSTEM CAPABILITY

000126 MW OF GENERATING CAPACITY AT THE END OF THE FISCAL YEAR

Actual Forecast 2013 2014 2015 2016 2017 2018 STEAM-ELECTRIC UNITS Aguirre 900 - - - - - Costa Sur 990 - - - - CS Unit's 3 & 4 - - - Palo Seco 602 San Juan 400 - - - - - Total 2,892 - - - - - COMBUSTION-TURBINE UNITS Aguirre 42 - - - - - Cambalache 248 - - - - - Costa Sur 42 - - - - - Palo Seco 126 - - - - - Other 168 - - - - - Total 626 - - - - - NEW POWER PLANT Repowering (San Juan Units No. 5 & 6) 440 - - - - - New Mayaguez Combustion Turbines 220 - -

Non-System Sources Cogenerators (Net) 961 - - - - - Small Power Producers 1 ------COMBINED-CYCLE UNITS Aguirre 592 - - - - - DIESEL UNITS Culebra & Vieques 8 - - - - - HYDROELECTRIC CAPACITY (Total) 100 - - - - -

EXISTING CAPACITY (End of Previous Fiscal Year) 5,839 5,839 5,839 5,839 5,839 5,839 No. CEPR-AP-2015-0001 CAPACITY INSTALLED ------CAPACITY RETIRED ------CUMULATIVE TOTAL CAPACITY (MW) 5,839 5,839 5,839 5,839 5,839 5,839 Less: PEAK LOAD (MW)* 3,265 3,304 3,339 3,377 3,438 3,492 RESERVE CAPACITY (MW) 2,574 2,535 2,500 2,462 2,401 2,347

RESERVE MARGIN (%) 79 77 75 73 70 67

* Peak load forecast from IAU Global Insight projection

1 Energy renewable projects are recognized as energy resources; none of the projects, however, meet the criteria for firm and reliable capacity. I

000127 APPENDIX IX DEPRECIATION EXPENSE

Actual1 Forecasted 2013 2014 2015 2016 2017 2018

DEPRECIATION Steam Production Plant $ 65,739,000 $ 67,711,170 $ 69,742,505 $ 71,834,780 $ 73,989,824 $ 76,209,518 Gas-turbine Production Plant 55,887,000 57,563,610 59,290,518 61,069,234 62,901,311 64,788,350 Hydroelectric Production Plant 1,291,000 1,329,730 1,369,622 1,410,711 1,453,032 1,496,623 Transmission Plant 52,774,000 54,357,220 55,987,937 57,667,575 59,397,602 61,179,530 Distribution Plant 119,847,000 123,442,410 127,145,683 130,960,052 134,888,854 138,935,521 General Plant2 47,306,000 48,725,180 50,186,935 51,692,544 53,243,320 54,840,619 Total Depreciation Expense $ 342,844,000.00 $ 353,129,320 $ 363,723,200 $ 374,634,896 $ 385,873,943 $ 397,450,161

Amortization of Leasehold Improvements, (407,000) No. CEPR-AP-2015-0001 TOTAL APPROPRIATION $ 342,437,000 $ 353,129,320 $ 363,723,200 $ 374,634,896 $ 385,873,943 $ 397,450,161

1. Audited 2. Includes clearing accounts APPENDIX X Page 1 of 4

I Budget DETAILS OF CAPITAL IMPROVEMENT PROGRAM 000128 Item Estimated Expenditures by Fiscal Year Number 2014 2015 2016 2017 2018 PRODUCTION PLANT THERMAL PRODUCTION PLANT 100 New Generation $ - $ - $ - $ 30,000,000 $ 70,000,000 110 Renewable Energy - 1,250,000 - - - 150 Fuel Handling and Storage Infrastructure 3,050,000 2,800,000 2,000,000 2,000,000 2,000,000 160 Boiler Improvements 23,150,000 34,560,000 30,500,000 32,137,000 8,000,000 165 Steam Turbines and Generators Improvements 11,400,000 16,500,000 12,500,000 17,000,000 10,400,000 170 Improvements to Balance of Steam Plant 14,150,000 9,450,000 2,765,000 2,850,000 2,500,000 173 Environmental Contamination Treatment and Removal 1,500,000 1,000,000 2,000,000 2,000,000 2,000,000 175 Pollution Control Projects 11,100,000 15,200,000 17,700,000 7,700,000 2,550,000 Total Thermal Production Plant $ 64,350,000 $ 80,760,000 $ 67,465,000 $ 93,687,000 $ 97,450,000 HYDROELECTRIC PRODUCTION PLANT 180 Hydroelectric Plant Improvements $ 3,200,000 $ 4,000,000 $ 6,000,000 $ 8,000,000 $ 6,000,000 Total Hydroelectricic Production Plant $ 3,200,000 $ 4,000,000 $ 6,000,000 $ 8,000,000 $ 6,000,000 OTHER PRODUCTION PLANT 185 Combustion Turbine Improvements $ 2,500,000 $ - $ - $ - $ - 187 Improvements to Balance of Simple Cycle Gas Turbines 2,700,000 3,700,000 3,700,000 2,700,000 2,700,000 190 Combined Cycle Steam Turbine Improvements 5,000,000 3,300,000 3,000,000 3,915,000 - 195 Improvements to Combined Cycle Balance of Plant 2,100,000 6,700,000 10,800,000 1,500,000 1,200,000 196 Combined Cycle Gas Turbine Improvements 12,225,000 13,060,000 15,000,000 16,000,000 12,500,000 198 Combined Cycle Heat Recovery Boiler Improvements - 500,000 2,000,000 500,000 2,800,000 199 Other Production Plant Improvements 4,300,000 3,830,000 2,400,000 2,200,000 2,000,000 Total Other Production Plant $ 28,825,000 $ 31,090,000 $ 36,900,000 $ 26,815,000 $ 21,200,000 TOTAL PRODUCTION PLANT $ 96,375,000 $ 115,850,000 $ 110,365,000 $ 128,502,000 $ 124,650,000 TRANSMISSION PLANT 205 New 230 kV Lines $ 8,100,000 $ - $ - $ 889,000 $ 5,000,000 207 New 115 kV Lines - - 2,752,000 6,221,000 8,861,000 210 New 38 kV Lines 1,525,000 960,000 538,000 1,602,000 646,000 215 38 kV Underground System 130,000 - 4,587,000 7,110,000 6,203,000 No. CEPR-AP-2015-0001 225 230/115 kV Transmission Centers & Capacity Increase - - - - 443,000 230 115/38 kV Transmission Centers & Capacity Increase 9,000,000 6,141,000 6,157,000 4,000,000 3,975,000 235 New 230 kV Switchyards & Expansions - 802,000 2,293,000 444,000 1,772,000 237 New 115 kV Switchyards & Expansions 2,700,000 802,000 1,377,000 1,776,000 6,202,000 242 New 38 kV Switchyards & Expansions 4,365,000 7,404,000 6,835,000 2,221,000 4,988,000 245 New 115kV Capacitor Banks - 641,000 - - - 255 Energy Management System (SCADA) 370,000 - - 378,000 443,000 267 115 kV Line Rehabilitation 17,450,000 24,818,000 20,505,000 17,397,000 13,292,000 275 38 kV Line Rehabilitation 15,132,000 12,288,000 14,228,000 12,100,000 12,074,000 APPENDIX X Page 2 of 4

I Budget DETAILS OF CAPITAL IMPROVEMENT PROGRAM 000129 Item Estimated Expenditures by Fiscal Year Number 2014 2015 2016 2017 2018 TRANSMISSION PLANT (Cont'd.) 280 Transmission Pole Replacement $ 1,000,000 $ 1,800,000 $ 1,835,000 $ 1,777,000 $ 1,800,000 285 Increasing Breaker Capacity 500,000 401,000 459,000 444,000 443,000 288 Reconstruction of Grounding Mat 225,000 204,000 234,000 227,000 226,000 290 Misc. Transmission Plant Improvements—Engrg. Div. 400,000 - - - - 292 Misc. Transmission Plant Improvements—Elec. System 4,500,000 4,000,000 4,000,000 5,000,000 5,000,000 294 Other Transmission Plant 950,000 1,001,000 1,059,000 1,027,000 1,023,000 TOTAL TRANSMISSION PLANT $ 66,347,000 $ 61,262,000 $ 66,859,000 $ 62,613,000 $ 72,391,000 DISTRIBUTION PLANT 300 New Distribution Substations $ 5,750,000 $ 6,411,000 $ 6,398,000 $ 7,109,000 $ 1,772,000 305 Increase Substation Capacity - 401,000 3,211,000 2,222,000 - 310 Emergency Substations - - - 955,000 975,000 315 New 13 kV Substation Feeders 7,235,000 5,805,000 5,292,000 5,798,000 6,936,000 316 4.16 kV - 8.32 kV Feeders 1,275,000 1,225,000 1,187,000 845,000 1,087,000 320 Distribution System Expansion - - - 222,000 199,000 330 Line Extension to Serve New Customers 1,950,000 1,760,000 1,812,000 1,755,000 1,750,000 335 Construction of Urban Underground Lines-13.2 kV 1,090,000 1,085,000 1,260,000 1,243,000 1,197,000 337 Construction of Urban Underground Lines-4.16 - 8.32 kV 600,000 401,000 - 468,000 89,000 340 Installation of New Service Drops 912,000 960,000 1,104,000 1,200,000 1,200,000 360 Substation Rehabilization 4,750,000 5,000,000 4,500,000 5,000,000 5,000,000 363 Substation Improvements 500,000 801,000 161,000 889,000 886,000 368 Residential &Commercial Service Drop Replacements 456,000 480,000 552,000 600,000 600,000 370 Distribution System Improvements 26,633,000 26,036,000 23,660,000 26,389,000 26,095,000 374 13 kV Distribution System Improvements 4,115,000 3,408,000 4,349,000 3,459,000 3,859,000 378 Underground Line Improvements and Extensions - 13.2 kV 7,550,000 8,141,000 7,943,000 4,419,000 6,571,000 379 4.16 - 8.32 kV Underground System Improvements 9,407,000 6,822,000 8,003,000 9,199,000 9,230,000 382 Street Lighting 6,500,000 5,300,000 5,391,000 5,332,000 5,400,000 383 Line Transformers 1,215,000 1,134,000 1,115,000 1,413,000 1,276,000 385 Meters 12,286,000 4,912,000 5,470,000 9,890,000 10,890,000 No. CEPR-AP-2015-0001 390 Brakers, Sectionalizers, & Reclosers 1,475,000 862,000 987,000 955,000 953,000 392 Voltage Regulators 275,000 397,000 454,000 440,000 439,000 395 Distribution Line Capacitors 325,000 381,000 436,000 422,000 421,000 397 Line Voltage Converter 635,000 509,000 528,000 555,000 563,000 398 Distribution Automated Systems 500,000 801,000 917,000 889,000 886,000 399 Other Distribution Projects 4,450,000 4,500,000 4,106,000 4,444,000 4,500,000 TOTAL DISTRIBUTION PLANT $ 99,884,000 $ 87,532,000 $ 88,836,000 $ 96,112,000 $ 92,774,000 APPENDIX X Page 3 of 4

I Budget DETAILS OF CAPITAL IMPROVEMENT PROGRAM 000130 Item Estimated Expenditures by Fiscal Year Number 2014 2015 2016 2017 2018 GENERAL PLANT GENERAL LAND AND BUILDINGS 400 Land and Rights-of-Way $ 3,000,000 $ 2,404,000 $ 2,752,000 $ 2,666,000 $ 2,658,000 430 New Technical Office Construction - 2,985,000 895,000 3,213,000 - 462 Minor Improvements to Technical Offices 600,000 721,000 711,000 422,000 532,000 468 Warehouse Improvements 350,000 781,000 1,011,000 633,000 654,000 470 Workshop Improvements 300,000 600,000 400,000 500,000 550,000 472 Improvements to Other Buildings 625,000 320,000 436,000 333,000 332,000 476 Improvements to Other Buildings & Grounds-Elect. System 500,000 - - - 3,000,000 478 Buildings & Grounds Improvements--Admin. Serv. 1,310,000 760,000 720,000 760,000 850,000 480 Buildings & Grounds Improvements--Cust. Serv. Offices 532,000 560,000 644,000 700,000 700,000 TOTAL GENERAL LAND AND BUILDINGS $ 7,217,000 $ 9,131,000 $ 7,569,000 $ 9,227,000 $ 9,276,000 EQUIPMENT OFFICE EQUIPMENT 509 Finance $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 510 Administration Services 15,000 - - - - 513 Client Service 304,000 280,000 322,000 100,000 100,000 514 Transmission & Distribution 285,000 200,000 230,000 67,000 89,000 Total Office Equipment $ 619,000 $ 495,000 $ 567,000 $ 182,000 $ 204,000 COMPUTER EQUIPMENT 520 Executive Offices $ 25,000 $ 25,000 $ 25,000 $ 25,000 $ 25,000 521 Information Systems 2,800,000 3,600,000 4,000,000 4,000,000 4,000,000 522 Legal 25,000 20,000 25,000 30,000 30,000 523 Planning & Environmental 450,000 225,000 270,000 120,000 170,000 525 Finance 625,000 625,000 125,000 125,000 125,000 526 Administrative Services 15,000 25,000 50,000 25,000 25,000 527 Human Resources 250,000 90,000 90,000 90,000 90,000 528 Electric System 250,000 300,000 - 480,000 500,000 529 Client Service 281,000 336,000 386,000 420,000 420,000

530 Transmission & Distribution 250,000 481,000 550,000 867,000 620,000 No. CEPR-AP-2015-0001 Total Computer Equipment $ 4,971,000 $ 5,727,000 $ 5,521,000 $ 6,182,000 $ 6,005,000 TRANSPORTATION EQUIPMENT 540 Air Transportation Equipment $ 500,000 $ 300,000 $ 350,000 $ 500,000 $ 500,000 545 Land Transportation Equipment 7,800,000 5,000,000 6,000,000 6,000,000 6,000,000 Total Transportation Equipment $ 8,300,000 $ 5,300,000 $ 6,350,000 $ 6,500,000 $ 6,500,000 APPENDIX X Page 4 of 4

I Budget DETAILS OF CAPITAL IMPROVEMENT PROGRAM 000131 Item Estimated Expenditures by Fiscal Year Number 2014 2015 2016 2017 2018 GENERAL PLANT (Cont'd) COMMUNICATIONS EQUIPMENT 550 Communications Equipment-Electric System $ 800,000 $ 1,000,000 $ 1,000,000 $ 1,000,000 $ 1,000,000 551 Communications Equipment-Client Services 38,000 40,000 46,000 50,000 50,000 553 Communications Equipment-T&D 75,000 60,000 69,000 89,000 89,000 555 Telephone and Data lines 3,250,000 3,800,000 3,250,000 3,000,000 4,500,000 Total Communication Equipment $ 4,163,000 $ 4,900,000 $ 4,365,000 $ 4,139,000 $ 5,639,000

OTHER EQUIPMENT 560 Planning and Environmental $ 893,000 $ 1,330,000 $ 1,400,000 $ 900,000 $ 850,000 562 Engineering 4,000,000 581,000 665,000 644,000 642,000 564 Administrative Services 380,000 380,000 485,000 285,000 225,000 565 Transportation Workshop 175,000 175,000 200,000 275,000 275,000 566 Human Resources 10,000 10,000 10,000 10,000 10,000 568 Electric System 1,150,000 575,000 600,000 2,500,000 600,000 570 Client Services 391,000 412,000 474,000 350,000 350,000 572 Transmission and Distribution 1,000,000 1,806,000 1,151,000 1,116,000 1,134,000 576 Purchase Other Equipment - Corporate Security 500,000 500,000 500,000 500,000 500,000 Total Other Equipment $ 8,499,000 $ 5,769,000 $ 5,485,000 $ 6,580,000 $ 4,586,000 TOTAL EQUIPMENT $ 26,552,000 $ 22,191,000 $ 22,288,000 $ 23,583,000 $ 22,934,000 TOTAL GENERAL PLANT $ 33,769,000 $ 31,322,000 $ 29,857,000 $ 32,810,000 $ 32,210,000

PRELIMIN. SURVEYS & INVESTIGATIONS 600 Engineering $ 1,975,000 $ 2,384,000 $ 2,730,000 $ 3,533,000 $ 1,750,000 605 Administrative Services $ 50,000 $ 50,000 $ 50,000 $ 30,000 $ 25,000 610 Planning and Environmental 1,200,000 1,200,000 1,100,000 1,200,000 1,200,000 611 Renewable Energy Sources 400,000 400,000 203,000 200,000 - TOTAL PRELIMIN. SURVEYS & INVESTIGATIONS $ 3,625,000 $ 4,034,000 $ 4,083,000 $ 4,963,000 $ 2,975,000 NET CAPITAL IMPROVEMENT PROGRAM $ 300,000,000 $ 300,000,000 $ 300,000,000 $ 325,000,000 $ 325,000,000 No. CEPR-AP-2015-0001 No. CEPR-AP-2015-0001

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I 000132 No. CEPR-AP-2015-0001

F INANCIAL S TATEMENTS, R EQUIRED S UPPLEMENTARY I NFORMATION AND S UPPLEMENTAL S CHEDULES

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico) Years Ended June 30, 2014 and 2013 With Report of Independent Auditors

1501-1384337 I 000133 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Financial Statements, Required Supplementary Information and Supplemental Schedules

Years Ended June 30, 2014 and 2013

Contents

Financial Section

Report of Independent Auditors...... 1 Management’s Discussion and Analysis ...... 4

Audited Financial Statements

Statements of Net Position ...... 27 Statements of Revenues, Expenses and Changes in Net Position ...... 29 Statements of Cash Flows ...... 30 Notes to Audited Financial Statements ...... 32

Required Supplementary Information

Schedule I – Supplementary Schedule of Funding Progress ...... 128

Report on Internal Control

Report of Independent Auditors on Internal Control Over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements Performed in Accordance with Government Auditing Standards ...... 129

Supplemental Schedules

Notes to Schedules II-VI – Information Required by the 1974 Agreement ...... 131 Schedule II – Supplemental Schedule of Sources and Disposition of Net Revenues under the Provisions of the 1974 Agreement ...... 132 Schedule III – Supplemental Schedule of Sources and Disposition of Net Revenues under the Provisions of the 1974 Agreement ...... 133 Schedule IV – Supplemental Schedule of Funds under the Provisions of the 1974 Agreement...... 134 Schedule V – Supplemental Schedule of Changes in Cash and Investments by Funds – June 30, 2014 ...... 135 Schedule V – Supplemental Schedule of Changes in Cash and Investments by Funds – June 30, 2013 ...... 136 Schedule VI – Supplemental Schedule of Changes in Long-Term Debt and Current Portion of Long-Term Debt ...... 137

1501-1384337 I 000134 No. CEPR-AP-2015-0001

Financial Section

1501-1384337 I 000135 No. CEPR-AP-2015-0001

Ernst & Young LLP Tel: +1 787 759 8212 Plaza 273, 10th Floor Fax: +1 787 753 0808 273 Ponce de León Avenue ey.com San Juan, PR 00917-1951

Report of Independent Auditors

To the Governing Board of the Puerto Rico Electric Power Authority

Report on the Financial Statements

We have audited the accompanying financial statements of Puerto Rico Electric Power Authority (the “Authority” or “PREPA”), a component unit of the Commonwealth of Puerto Rico as of and for the years ended June 30, 2014 and 2013, and the related notes to the financial statements, which collectively comprise the basic financial statements listed in the table of contents.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of PREPA Holdings LLC (a blended component unit), which financial statements reflect total assets constituting approximately .64% and .46% of total assets as of June 30, 2014 and 2013, and revenues constituting .65% of total revenues for the years then ended. Those financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for PREPA Holdings, is based solely on the reports of the other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States, and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

1501-1384337 1 I 000136 A member firm of Ernst & Young Global Limited No. CEPR-AP-2015-0001

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, based on our audits and the reports of the other auditors, the financial statements referred to above present fairly, in all material respects, the financial position of the Puerto Rico Electric Power Authority as of June 30, 2014 and 2013, and the changes in its financial position and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

The Authority’s Ability to Continue as a Going Concern

The accompanying financial statements have been prepared assuming that the Authority will continue as a going concern. As discussed in Note 19 to the financial statements, the Authority does not have sufficient funds available to fully repay its various obligations as they come due and has entered a process to restructure its long-term debt. The financial difficulties experienced by the Authority, including the uncertainty as to its ability to fully satisfy its obligations, raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Notes 19 and 20. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to this matter.

Adoption of GASB Statement No. 65, Items Previously Reported as Assets and Liabilities

As discussed in Notes 2 and 18 to the financial statements, the Authority changed its method for accounting for bond issue costs and deferred losses related to bond refunding as a result of the adoption of GASB Statement No. 65, Items Previously Reported as Assets and Liabilities, effective for periods beginning after July 1, 2012. Our opinion is not modified with respect to this matter.

Required Supplementary Information

U.S. generally accepted accounting principles require that management’s discussion and the supplementary schedule of funding progress on pages 4 through 26 and 128, respectively, be presented to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board which considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

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Supplementary Information

Our audit was conducted for the purpose of forming an opinion on the financial statements that collectively comprise the Puerto Rico Electric Power Authority’s basic financial statements. The supplemental schedules listed in the table of contents are presented for purposes of additional analysis and are not a required part of the financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the basic financial statements.

The information has been subjected to the auditing procedures applied in the audit of the basic financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the basic financial statements or to the basic financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States. In our opinion, the information is fairly stated in all material respects in relation to the basic financial statements as a whole.

Other Reporting Required by Government Auditing Standards

In accordance with Government Auditing Standards, we have also issued our report, dated January 28, 2016, on our consideration of the Authority’s internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other matters. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standards and should be considered in assessing the results of our audits.

January 28, 2016

Stamp No. E201502 affixed to original of this report.

1501-1384337 3 I 000138 A member firm of Ernst & Young Global Limited No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis

Year Ended June 30, 2014

This section of the financial report of the Puerto Rico Electric Power Authority (the Authority) presents the analysis of the Authority’s financial performance during the fiscal years ended June 30, 2014, 2013 and 2012. As management of the Authority, we offer readers of the financial statements this narrative overview and analysis of the financial activities. We recommend readers to consider the information herein presented in conjunction with the financial statements that follow this section.

Financial Highlights

. Operating income for fiscal year ended June 30, 2014 was $223.0 million representing a decrease of 37.0 percent from the fiscal year ended June 30, 2013. For the fiscal year ended June 30, 2013 operating income was $354.0 million representing an increase of 37.7 percent from the fiscal year ended June 30, 2012. For the fiscal year ended June 30, 2012 operating income was $257.0 million representing a decrease of 21.4 percent from the fiscal year ended June 30, 2011.   . Operating expenses decreased by $243.1 million or 5.4 percent for the fiscal year ended June 30, 2014; decreased by $300.5 million or 6.3 percent for the fiscal year ended June 30, 2013, and increased by $693.4 million or 16.9 percent for the fiscal year ended June 30, 2012.

. The Authority’s Net Utility Plant for the fiscal year ended June 30, 2014 increased by $8.9 million or 0.1 percent. For the fiscal year ended June 30, 2013 net utility plant increased by $39.4 million or 0.6 percent. For the fiscal year ended June 30, 2012 the net utility plant decreased by $13.4 million or 0.2 percent.   . Total assets and deferred outflows increased by $285.4 million, decreased by $108.0 million and increased by $323.0 million, or 2.8 percent increase, 1.0 percent decrease and 3.3 percent increase, respectively, for the fiscal years ended June 30, 2014, 2013 and 2012.   . For the fiscal year ended June 30, 2014, as compared to the fiscal year ended June 30, 2013 and fiscal year ended June 30, 2012, accounts receivable net increased by 7.2 percent from $1,511.9 million to $1,620.6 million, increased by 10.8 percent from $1,364.6 million to $1,511.9 million, and increased by 6.8 percent from $1,277.9 million to $1,364.6 million, respectively. The increases in fiscal year 2014 and 2013 were mainly due to government sector accounts. 

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Financial Highlights (continued)

. Accounts receivable from the governmental sector increased 30.1 percent from $617.6 million on June 30, 2013 to $803.7 million on June 30, 2014, and increased 43.9 percent from $429.3 million on June 30, 2012 to $617.6 million on June 30, 2013, and decreased 75 percent from $464.1 million on June 30, 2011 to $429.3 million on June 30, 2012.

. The Authority’s net position decreased by $419.9 million (49.6 percent) and $272.1 million (47.3 percent) and $344.7 million (149.6 percent) as a result of operations during fiscal years ended June 30, 2014, 2013 and 2012, respectively. The Authority has been in a net deficit position since June 30, 2011.   . Ratios of fuel and purchased power adjustment revenues to total operating revenues were 78.9 percent, 76.5 percent and 78.3 percent for years ended June 30, 2014, 2013 and 2012, respectively.

Ratios of fuel oil and purchased power expense to total operating expense (excluding depreciation expense) were 80.3 percent, 81.1 percent and 82.0 percent for fiscal years ended June 30, 2014, 2013 and 2012, respectively.

. The decrease in the fuel adjustment revenues and fuel expense for fiscal year 2014 as compared to 2013 of $228.7 million and $258.6 million, respectively, was mainly due to a decrease in the average fuel oil price per barrel of $4.46 (4.2%) and a decrease of 1.4 million barrels of fuel consumption. The decrease in the fuel adjustment revenues and fuel expense for fiscal year 2013 as compared to 2012 of $323.1 million and $298.2 million, respectively, was mainly due to a decrease in the average fuel oil price per barrel of $7.22 (6.1%). The increase in the fuel adjustment revenues and fuel expense for fiscal year 2012 as compared to 2011 of $606.2 million and $610.5 million, respectively, was mainly due to an increase in the average fuel oil price per barrel of $22.48 (23.4%).  

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Financial Highlights (continued)  . The increase in the purchased power adjustment revenue and expense of $58.7 million and $51.9 million, respectively, was due to an increase of price per kWh of purchased power by 1 cent (or 9.1%) for fiscal year 2014 when compared to fiscal year 2013. The increase in the purchased power adjustment revenue and expense of $78.8 million and $71.5 million, respectively, was due to an increase of 593,183 MWh (or 8.9 percent) in amount of purchase power for fiscal year 2013 when compared to fiscal year 2012. The increase in the purchased power adjustment revenue and expense of $26.3 million and $23.3 million, respectively, was due to an increase in the average cost per kWh of (10.6%) purchase power from 9 cents for fiscal 2011 to 10 cents for fiscal 2012.

Financial Condition and Liquidity

The Authority does not currently have sufficient funds available to fully repay its various obligations as they come due, and is working on extending the due date of the obligations and obtaining other concessions from its creditors, including pursuant to an exchange offer that would reduce the principal amount of some of its debts, obtaining more favorable covenants and other terms under its Trust Agreement via a consent solicitation, and obtaining new financing to provide relief and/or funds to repay the existing amounts of principal and interest or bring the outstanding balances current at the various due dates as well as to continue to operate and to finance capital improvement projects. The Commonwealth and its instrumentalities are also experiencing significant financial difficulties and may be unable to continue to repay amounts due to the Authority or to extend, refinance or otherwise provide the necessary liquidity to the Authority as and when needed. The Authority has receivables of over $803.7 million payable by the Commonwealth and related entities and is subject to significant uncertainty with regard to its ability to collect on such receivables. As a consequence, the Authority may not be able to avoid future defaults on its obligations. Management has plans to address the Authority’s liquidity situation and continue providing services and believes the Authority will be able to repay or refinance its obligations, as described in Note 19 and Note 20. However, there can be no assurance that the affiliated or unaffiliated creditors will be able and willing to refinance or modify the terms of the Authority’s obligations, that management’s current plans to repay or refinance the obligations or extend their terms will be achieved or that certain services will not have to be terminated, curtailed or modified.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Plans to Address the Authority’s Challenges

The Authority faces a number of business challenges that have been exacerbated by the Commonwealth’s economic recession and financial difficulties. Its principal challenges, some of which are interrelated, include: (i) addressing its relatively high cost of the type of fuel it uses compared to other energy sources and aging generation fleet; (ii) compliance with applicable environmental regulations; (iii) declining electric energy sales; (iv) addressing government accounts receivables; (v) improving liquidity; and (vi) taking steps to ensure the Authority’s long-term fiscal sustainability, including its ability to satisfy its financial obligations.

In July 2014, the Authority began discussions with its financial stakeholders in an effort to stabilize the Authority’s liquidity situation and address its financial position. The Authority subsequently engaged legal, financial and operational advisors, including a chief restructuring officer, to assist it in those efforts. In the period since July 2014, the Authority has entered into various agreements with certain of its financial stakeholders as discussed below.

Forbearance Agreements

On August 14, 2014, the Authority entered into forbearance agreements (the “Forbearance Agreements”) with certain insurers of the Authority’s Power Revenue Bonds (“Bonds”) and beneficial owners of the Bonds controlling, collectively, more than 60% of the principal amount of the Bonds then outstanding (comprising the Ad Hoc Group (as defined below)) and the monoline insurers providing credit support for certain of the Authority’s Bonds not owned by the Ad Hoc Group (the “monoline bond insurers” and together with the Ad Hoc Group, the “Forbearing Bondholders”), banks that provide revolving lines of credit used to pay for purchased power, fuel and other expenses (together, with their transferees, as applicable, the “Forbearing Lenders”) and Government Development Bank for Puerto Rico (“GDB,” and together with the Forbearing Bondholders and the Forbearing Lenders, the “Forbearing Creditors”).

Under the Forbearance Agreements, the Forbearing Creditors agreed to forbear from the exercise of certain rights and remedies under their applicable debt instruments. The Forbearance Agreements were originally scheduled to terminate on March 31, 2015, but were extended by certain of the Forbearing Creditors on numerous occasions, most recently through November 5, 2015. The Forbearance Agreements expired on November 5, 2015, but the agreement of the Forbearing Creditors to refrain from exercising of certain rights and remedies was extended under the RSA (as defined below).

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Forbearance Agreements (continued)

Under the Forbearance Agreements with the Forbearing Bondholders, the Authority’s obligations to pay any and all principal and interest payments on the Bonds were required to continue; however, the Forbearing Bondholders agreed that the Authority was not required to make transfers to the Revenue Fund or the Sinking Fund pursuant to sections 506 and 507 of the Trust Agreement while that agreement remained in effect. The Authority has not made monthly cash deposits into the Sinking Fund since July 2014. This agreement was extended and continued under the RSA. Since entry into the Forbearance Agreements, the Authority has paid all principal and interest payments due on the Bonds.

Under the Forbearance Agreements with the Forbearing Lenders, the Authority was permitted until November 5, 2015 to delay certain payments that became due to the Forbearing Lenders in July and August 2014. Under the RSA, the Authority was permitted to delay such payments further until June 30, 2016; however, the Authority has continued to pay interest to the Forbearing Lenders while those agreements remain in effect.

In connection with the Forbearance Agreements and in order to address the Authority’s liquidity challenges, on August 27, 2014, the Trust Agreement was amended to permit the Authority to use approximately $280 million held in its construction fund for payment of current expenses in addition to capital improvements. The amendment also provided for an increase in the thresholds required for the exercise of remedies under the Trust Agreement. Those amendments expired on March 31, 2015.

In connection with an extension of the Forbearance Agreements executed on June 30, 2015 and the Authority’s agreement to pay approximately $415.8 million of principal and interest due on July 1, 2015 on the Bonds, the Trust Agreement was again amended to increase the thresholds for the exercise of remedies under the Trust Agreement and to allow for the issuance of $130.7 million in Bonds to the monoline bond insurers (the “2015A Bonds”) that matured on January 1, 2016. Those amendments expired on September 1, 2015. On December 15, 2015, the Authority defeased the outstanding principal and interest requirements on the 2015A Bonds, and the 2015A Bonds were paid in full on the first business day of January 2016 (January 4, 2016) in accordance with their terms.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Bond Payments

On July 1, 2014, the Authority paid $413.7 million to satisfy the principal and interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves.

On January 2, 2015, the Authority paid $204.4 million to satisfy the interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves.

On July 1, 2015, the Authority paid $415.8 million, to satisfy the principal and interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves, and a $153.0 million transfer from the General Fund.

On July 31, 2015, pursuant to the Trust Agreement and as agreed with Forbearing Creditors, the Authority issued Power Revenue Bonds Series 2015A, in a par amount of $130.7 million (the Series 2015 A Bonds), to replenish the Authority’s working capital. The Series 2015 A Bonds were bought in their entirety by the monoline bond insurers, and the maturity date of this issue was January 1, 2016. The Authority paid $6.1 million, $5.9 million, $5.8 million, $5.8 million and $6.4 million for the first five months that ended on November 1, 2015 to redeem a portion of the Series 2015 A Bonds.

On December 15, 2015, the Authority deposited $103.5 million in escrow to satisfy the remaining principal and interest requirements on the Series 2015 A Bonds, which deposit was funded by $100.9 million from Self-insurance Fund and $2.6 million from General Fund. These amounts were paid to holders of the 2015 A Bonds on January 4, 2016 in accordance with their terms.

On January 4, 2016, the Authority paid $198.0 million, to satisfy the interest payments on its other Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, and a $171.0 million transfer from the General Fund.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Agreements with Certain Forbearing Creditors

Agreement in Principle with Ad Hoc Group

On September 2, 2015, PREPA announced an agreement in principle regarding the economic terms of a restructuring with an ad hoc group of bondholders that were Forbearing Bondholders (the “Ad Hoc Group Agreement”) and which group held, at that time, approximately 35% in principal amount of the outstanding Bonds (the “Ad Hoc Group”).

Under that agreement, the Ad Hoc Group will have the option to receive securitization bonds that will pay cash interest at a per annum rate of 4.0% - 4.75% (depending on the rating obtained) (“Option A Bonds”) or convertible capital appreciation securitization bonds that will accrete interest at a per annum rate of 4.5% - 5.5% for the first five years and pay current interest in cash thereafter at those per annum rates (“Option B Bonds”). Option A Bonds will not pay principal for the first five years (interest only), and Option B Bonds will accrete interest but not receive any cash interest or principal during the first five years. All of PREPA’s uninsured bondholders will have an opportunity to participate in the exchange. Both Option A and Option B Bonds would be issued at an exchange ratio of 85% (i.e., with a 15% reduction in principal amount of current holdings of outstanding Bonds).

Under the extension to the Forbearance Agreement with the Ad Hoc Group executed on September 1, 2015, PREPA agreed to work collaboratively and in good faith with the Ad Hoc Group to reach agreement on a recovery plan incorporating these terms. The Ad Hoc Group Agreement was included in the RSA.

Agreement in Principle with Forbearing Lenders of Notes Payables

On September 22, 2015, PREPA announced an agreement in principle regarding economic terms with its Forbearing Lenders (the “Fuel Line Agreement”).

Under that Agreement, the Forbearing Lenders, which hold all of the approximately $696 million of matured debt (Notes Payable), will have the option to either (1) convert their existing credit agreements into term loans, with a fixed interest rate of 5.75% per annum, to be repaid over six years in accordance with an agreed amortization schedule or (2) exchange all or part of principal due under their existing credit agreements for new securitization bonds to be issued on the same terms as the Ad Hoc Group.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Agreement in Principle with Forbearing Lenders of Notes Payables (continued)

Under the extensions to the Forbearance Agreements with the Forbearing Lenders executed on September 22, 2015, PREPA agreed to work collaboratively and in good faith with the Forbearing Lenders to reach agreement on a recovery plan incorporating these terms. The Fuel Line Agreement was included in the RSA.

Terms and Status of Restructuring Support Agreement

On November 5, 2015, PREPA announced its entry into a restructuring support agreement (the “Initial RSA”) with both the Ad Hoc Group (representing at that time approximately 40% in principal amount of the outstanding Bonds) and the Forbearing Lenders setting forth the agreed- upon terms of PREPA’s recovery plan which terms were amended to extend the milestone dates therein on numerous occasions. The economic terms set forth in the Initial RSA are consistent with the Ad Hoc Group Agreement and the Fuel Line Agreement. In addition, pursuant to the Initial RSA, GDB would receive substantially the same treatment on $35.9 million owed by PREPA to it as the Forbearing Lenders will receive. The monoline bond insurers were not party to the Initial RSA.

On December 23, 2015, certain of the monoline bond insurers along with the Ad Hoc Group (representing together at that time approximately 66% in principal amount of the outstanding Bonds), the Forbearing Lenders and GDB, all signed an amended and restated restructuring support agreement (the “A&R RSA” and together with the Initial RSA and the Revised RSA (as defined below), the “RSA” and the Ad Hoc Group, the monoline bond insurers, the Forbearing Lenders and the GDB, together the “Supporting Creditors”) with terms and conditions substantially similar to those in the Initial RSA outlined above (including the agreement to exchange Bonds held by the Ad Hoc Group for new securitization bonds at an 85% exchange ratio with a 5-year principal holiday and fixed interest rates).

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Terms and Status of Restructuring Support Agreement (continued)

amount determined by the Authority after consulting with the Authority’s advisors; (4) amending the Trust Agreement to increase to at least a majority the percentage of Bondholders required to direct the Trustee to take certain actions under the Trust Agreement, including upon a default by the Authority and continue the waiver of the Authority’s obligation to make monthly Sinking Fund deposits, among other things; and (5) obtaining approval and reaching agreement with all Supporting Creditors regarding the definitive documentation of the various restructuring transactions.

The RSA contains a number of termination or withdrawal events in favor of the Supporting Creditors, including if there is a material amendment to certain terms of the recovery plan, if the Authority commences any proceeding under bankruptcy or insolvency law or the Recovery Act (except to implement the recovery plan in accordance with the RSA), as well as the failure to achieve certain milestones by specific dates, including the enactment of legislation containing substantive provisions to implement the recovery plan contemplated by the RSA, among other events, which would result in termination of the RSA or withdrawal from the RSA by individual Supporting Creditors.

On January 23, 2016, the RSA terminated when the PREPA Revitalization Act was not enacted into law and the Ad Hoc Group did not agree to the Authority’s request to extend the related RSA milestone. PREPA continued to engage in discussions with the Ad Hoc Group and the other Supporting Creditors regarding a potential extension of the RSA and the transactions contemplated therein and described below.

Under the RSA, certain of the Supporting Creditors had agreed to purchase approximately $115 million in Bonds to refund a portion of the interest payments on the Bonds made on January 4, 2016, subject to certain conditions including enactment of the PREPA Revitalization Act in acceptable form. This agreement was formalized in a Bond Purchase Agreement (the “Initial Bond Purchase Agreement”) executed on December 29, 2015. The Initial Bond Purchase Agreement also terminated on January 23, 2016 when the A&R RSA terminated. PREPA continued to engage in discussions with the Supporting Creditors regarding the transactions contemplated by the Initial Bond Purchase Agreement.

On January 23, 2016, certain of the Forbearing Lenders agreed to enter into a short form forbearance agreement by which they agreed to forbear from exercising enforcement rights against the Authority under the applicable Fuel Line Agreements through February 12, 2016.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Terms and Status of Restructuring Support Agreement (continued)

On January 27, 2016, PREPA and the Supporting Creditors executed a revised RSA (“Revised RSA”) and a revised Bond Purchase Agreement (the “Revised Bond Purchase Agreement”). The Revised RSA is substantially the same as the A&R RSA, with minor adjustments to address delays in legislative consideration of the PREPA Revitalization Act. The milestone date for legislative approval of the PREPA Revitalization Act was extended to February 16, 2016, and other related milestones were also adjusted accordingly. The Revised Bond Purchase Agreement is substantially the same as the Initial Bond Purchase Agreement, except for certain changes to the timing, conditions and total amount of the contemplated Bond purchase. Under the Revised Bond Purchase Agreement, 50% of the total purchased Bonds will be purchased upon a determination by the applicable Supporting Creditors that the PREPA Revitalization Act satisfies the standards set forth in the RSA and 50% of the total purchased Bonds will be purchased upon the filing of a petition with the Energy Commission seeking approval of a securitization charge that satisfies the standards under the RSA. Under the Revised Bond Purchase Agreement, the total amount of purchased Bonds is approximately $111 million. There can be no assurance, however, that the transactions contemplated by the Revised Bond Purchase Agreement will be consummated.

Under the RSA, the Ad Hoc Group has agreed to exchange 100% of its uninsured Bonds for securitization bonds at an 85% exchange ratio. The monoline bond insurers agreed to provide up to $462 million of reserve surety bonds at the time the transaction closes and forward commitments for additional surety capacity to be provided at a later time during the term of the transaction, as credit support for the securitization bonds, that would be available to be drawn upon in the event certain cash reserves and transition payments from PREPA’s customers are insufficient to pay current debt service on the securitization bonds. In return for this, (1) the SPV (defined below – see PREPA Revitalization Act) would issue $2.086 billion additional securitization bonds, which amount is subject to adjustment in accordance with the RSA, as credit support for outstanding Authority’s insured Bonds to be held in escrow for the benefit of holders of the Authority’s insured Bonds and (2) PREPA and the SPV would attempt to refinance certain outstanding Bonds insured by such insurers with securitization bonds during a 6-month period starting 3 years after the date the above exchange closes. The surety bonds provided by the monoline bond insurers would be replaced by SPV cash (derived from transition payments) beginning in FY2019 over a period of nine years, subject to earlier replacement in accordance with certain conditions set forth in the RSA. Among the primary purposes for this transaction are to refinance at a lower cost a portion of the Authority’s outstanding Bonds and to improve the Authority’s liquidity position during the first five years after issuance. There can be no assurance, however, that the transactions contemplated by the RSA will be consummated.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Terms and Status of Restructuring Support Agreement (continued)

It should be noted that Bondholders holding beneficially approximately $2.73 billion in principal amount of outstanding Bonds representing approximately 34% in principal amount of the outstanding Bonds, have not agreed to the terms of the RSA, and without access to a statutory restructuring regime the terms of their Bonds also cannot be amended until an agreement with such Bondholders has been reached. As discussed below, the Authority is currently not in compliance with certain terms of its Trust Agreement and such Bondholders, who are not covered by the agreements described above, could direct the trustee to take certain actions, or otherwise exercise enforcement actions, against the Authority, each in accordance with the Trust Agreement, which actions could result in a default being declared.

Trust Agreement Covenants

As a result of the Authority’s non-compliance with certain covenants existing under the Trust Agreement, Bondholders not covered by the agreements described above could direct the trustee to take certain actions, or otherwise exercise enforcement actions, against the Authority, including declaring an event of default as a result of covenant violations, each in accordance with the terms of the Trust Agreement.

Under the Trust Agreement, upon a covenant violation, no remedies may be exercised by the trustee on behalf the Bondholders until the trustee notifies the Authority of the particular violation and the Authority does not cure the violation within 30 days after receipt of such notice. The Authority has not received any such notice from the trustee.

PREPA Revitalization Act

On November 4, 2015, the Governor submitted the PREPA Revitalization Act to the Legislative Assembly to facilitate the Authority’s ongoing transformation and recovery plan. The PREPA Revitalization Act sets forth a framework for PREPA to execute on the agreements with creditors reached to date. Among other things, the PREPA Revitalization Act would (1) enhance PREPA’s governance processes; (2) adjust PREPA’s practices for hiring and managing management personnel; (3) change PREPA’s processes for collecting outstanding bills from public and private entities; (4) improve the transparency of PREPA’s billing practices; (5) implement a competitive bidding process for soliciting third party investment in PREPA’s infrastructure; (6) authorize the refinancing of outstanding Bonds through a securitization that would reduce PREPA’s indebtedness and cost of borrowing; and (7) set forth an expedited process for the Energy Commission to approve or reject PREPA’s proposal for a new rate structure that is consistent

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

PREPA Revitalization Act (continued)

with its recovery plan. The Legislative Assembly is currently considering various amendments to the PREPA Revitalization Act. There can be no assurance, however, that the PREPA Revitalization Act will be enacted into law or that it will contain provisions that are acceptable to the Authority’s various creditors.

As described above, if enacted the PREPA Revitalization Act would provide a legal framework to reduce the Authority’s cost of borrowing and its passage in the form contemplated by the RSA is one of the conditions to the execution of the restructuring transactions contemplated by the RSA and described above. The legislation would authorize creation of a bankruptcy-remote, special purpose public corporation (the “SPV”), entirely separate from the Authority, with the power to issue securitization bonds for limited purposes related to the Authority’s recovery plan, and to impose non-by passable, transition charges on the Authority’s customers. The assessment and periodic automatic adjustments of the transition changes on the Authority’s customers would serve as the source of repayment for the securitization bonds.

U.S. Congress Consideration of Bankruptcy Amendment

Commonwealth officials have been urging the U.S. Congress to amend the federal bankruptcy code to eliminate an exclusion that currently bars any municipality or other instrumentality of the Puerto Rico government from restructuring under the federal bankruptcy code. U.S. legislative discussions on this are expected to continue in January 2016 and beyond.

Operational Improvements

The Authority has also made significant investments in evaluating and implementing various operational improvements and strategies in an effort to address its ongoing financial challenges.

In an effort to diversify its fuel supply, the Authority has entered into agreements necessary for the construction of an offshore gas port terminal to receive natural gas off the southern part of the island for use in the Aguirre Power Complex. The permitting process for the project is ongoing, and construction has not yet begun. Once operational, the gas port will provide a method to utilize liquefied natural gas at Aguirre.

The Authority reduced its number of employees through a combination of attrition from voluntary retirement and the elimination of temporary and vacant positions. In addition, the Authority continues to enforce the new employee hiring freeze implemented in January 2009.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Operational Improvements (continued)

On September 4, 2014, the Authority appointed a chief restructuring officer whose mandate includes providing overall leadership to the Authority’s restructuring process, developing a business plan, implementing revenue improvement and cost reduction plans, overseeing and implementing cash and liquidity management activities, improving the Authority’s ability to analyze, track and collect accounts receivable, improving the Authority’s capital expenditure plan, and developing plans to improve the Authority’s generation, transmission, distribution and other operations.

Overview of Financial Report

Management’s Discussion and Analysis (MD&A) of operating results serves as an introduction to the basic financial statements and supplementary information. Summary financial statement data, key financial and operational indicators used in the Authority’s strategic plan, projected capital improvement program, operational budget and other management tools were used for this analysis.

Required Financial Statements

The financial statements report the financial position and operations of Puerto Rico Electric Power Authority and its blended component units, Puerto Rico Irrigation Systems and PREPA Holdings LLC as of and for the year ended June 30, 2014, which include a Statement of Net Position, Statement of Revenues, Expenses and Changes in Net Position, Statement of Cash Flows and the notes to financial statements.

PREPA Networks, LLC issued a separate financial report that includes audited financial statements. That report may be obtained by writing to PREPA Networks, Corp. City View Plaza Suite 803, Guaynabo, Puerto Rico 00968.

The Statement of Net Position presents the financial position of the Authority and provides information about the nature and amount of resources and obligations at year-end.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Required Financial Statements (continued)

The Statement of Revenues, Expenses and Changes in Net Position present the results of the business activities over the course of the fiscal year and information as to how the net assets changed during the fiscal year.

The Statement of Cash Flows shows changes in cash and cash equivalents, resulting from operating, non-capital and capital financing, and investing activities, which include cash receipts and cash disbursement information, without consideration of the depreciation of capital assets.

The notes to the financial statements provide information required and necessary to the understanding of material information of the Authority’s financial statements. These notes present information about the Authority’s significant accounting policies, significant account balances and activities, risk management, obligations, commitments and contingencies, and subsequent events.

The financial statements were prepared by the Authority’s management from detailed accounting books and records.

Financial Analysis

The Authority’s net position decreased by $419.8 million, $272.1 million and $344.7 million for the fiscal years ended June 30, 2014, 2013 and 2012, respectively. Our analysis below focuses on the Authority’s net position and changes in net position during the year.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Financial Analysis (continued)

Authority’s Net Position (In thousands )

Year Ended June 30 2014 2013 2012 (as restated) (as restated)

Current, non-current and other assets $ 3,504,903 $ 3,177,881 $ 3,283,933 Deferred outflows 126,812 177,283 218,648 Capital assets 6,847,456 6,838,558 6,799,176 Total assets and deferred outflows $ 10,479,171 $ 10,193,722 $ 10,301,757

Long-term debt outstanding $ 9,413,195 $ 8,987,971 $ 9,042,843 Other liabilities 2,332,981 2,052,946 1,834,036 Total liabilities $ 11,746,176 $ 11,040,917 $ 10,876,879

Net position (deficit): Net investments in utility plant $ (253,448) $ (32,432) $ (21,314) Restricted – – 18,299 Unrestricted (1,013,557) (814,763) (572,107) Total net position (deficit) $ (1,267,005) $ (847,195)$ (575,122)

A portion of the Authority’s net position reflects its net investment in utility plant, which decreased from $23.4 million to $3.6 million as of June 30, 2013 and 2014, respectively.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Financial Analysis (continued)

Changes in the Authority’s net position can be determined by reviewing the following condensed Statements of Revenues, Expenses and Changes in Net Position.

Authority’s Changes in Net Position (In thousands)

Year Ended June 30 2014 2013 2012 (as restated) (as restated)

Operating revenues $ 4,468,922 $ 4,843,016 $ 5,046,494 Other income 21,157 26,329 24,344 Total revenues 4,490,079 4,869,345 5,070,838 Operating expenses 4,245,892 4,488,979 4,789,469

Interest expense, net 431,180 386,867 380,424 Total expenses 4,677,072 4,875,846 5,169,893 Loss before contribution in lieu of taxes (186,993) (6,501) (99,055) and other and contributed capital Contribution in lieu of taxes and other (277,776) (297,551) (283,111) Loss before contributed capital (464,769) (304,052) (382,166)

Contributed capital 44,959 31,979 37,494 Change in net position (419,810) (272,073) (344,672)

Net position at beginning of year (847,195) (575,122) (230,450) Net position at end of year $ (1,267,005) $ (847,195) $ (575,122)

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Financial Analysis (continued)

For fiscal year ended June 30, 2014, as compared to June 30, 2013, net position decreased by $419.8 million, a $147.7 million decrease when compared to the decrease for fiscal year ended June 30, 2013. The reduction in net position was mainly due to a combination of factors that included, among others, a decrease in operating revenues of $374.1 million, mainly due to a decrease in energy sales per kWh from 18.2 million in 2013 to 17.6 million in 2014 (3.3%), representing a $16.8 million basic revenue decrease, and an increase in the reserve for uncollectible accounts of $191.5 million during the fiscal year 2014, due to a change in the assumptions related to collections, as a result of the recent economic situation facing Puerto Rico, net of a decrease in operating expenses of $243.1 million, mainly as a result of a decrease in fuel prices.

For fiscal year ended June 30, 2013, as compared to June 30, 2012, net position decreased by $272.1 million. The reduction in net position was mainly due to a combination of factors that included, among others, a decrease in operating revenues of $203.5 million and operating expenses of $300.5 million, resulting in a net decrease in operating income of $97.0 million. Decreases in fuel oil prices, a decrease in depreciation expense of $69.9 million due to the implementation of a new depreciation study, offset by increases in interest expense, and contributions in lieu of taxes contributed to the reduction in operating income. In addition, the Authority’s net revenues were reduced by $53.2 million in fuel adjustment revenues not billed to customers, which reduction was financed by the revenue stabilization fund.

For fiscal year ended June 30, 2012, as compared to June 30, 2011, net position decreased by $344.7 million. The reduction in net position was mainly due to a combination of factors that included, among others, an increase in operating revenue of $623.5 million and operating expenses of $693.4 million, resulting in a net decrease in operating income of $69.9 million. Increases in fuel oil prices and an increase in depreciation expense of $63.9 million, as well as increases in interest expense, and contributions in lieu of taxes contributed to the reduction in operating income. In addition, the Authority’s net revenues were reduced by $79.4 million in fuel adjustment revenues not billed to customers, which was financed by the revenue stabilization fund and $37.2 million of costs related to the abandoned Vía Verde Project (Natural Gas Pipeline Project), which were registered as operating expenses.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Capital Assets and Debt Administration

Net Investment in Utility Plant

Net investment in utility plant in fiscal years as of June 30, 2014, 2013 and 2012, amounted to approximately $6,847 million, $6,839 million, and $6,799 million (net of accumulated depreciation), respectively. This net investment in utility plant includes land, generation, transmission and distribution systems, buildings, fixed equipment, furniture, fixtures and equipment. The Authority’s net investment in utility plant increased by 0.1 percent, increased by 0.6 percent and decreased by 0.2 percent for years ended June 30, 2014, 2013 and 2012, respectively.

A substantial portion of the capital expenditures for production plant in fiscal years ended June 30, 2014, 2013 and 2012, was spent on the rehabilitation and life extension of generating plants in order to maintain availability, reliability and efficiency.

Major capital assets projects undertaken by Authority during fiscal years 2014 and 2013 included the following:

. Conversion of units 5 and 6 at the Costa Sur Power Plant to dual fuel, representing approximately 820 MW of generating capacity. Improvements to boiler’s internal components to burn 100% of natural gas have been completed for unit 6 as well as for unit 5. These capital improvement projects were completed during summer 2013.   . Regular scheduled comprehensive maintenance of its steam unit fleet, combined-cycle units and combustion turbine peaking units. Boilers and turbine-generators are included in this comprehensive maintenance program.   . Projects for the supply of water for industrial processes and generation. The new demineralized water plant at Costa Sur Power Plant, is an example of a key capital improvements focused on reliability and natural resources protection.  

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Capital Assets and Debt Administration (continued)  . Water infrastructure projects in order to comply with the current and future NPDES Discharge permits at San Juan Power Plant and Aguirre Power Complex. The integration of advanced water treatment technologies for reusing process wastewater will benefit the surrounding environment and reduce the process water - with the exception of the non- contact cooling water discharge – will be achieved with this project. In addition, the Aguirre Water Supply Project will substitute the underground water extraction from Southern Aquifer – which is currently experiencing salt infiltration – to superficial water supply from the Patillas Irrigation Channel and will supply a fresh water supply to a deteriorated black mangrove area in Jobos Bay for restoration. The expected date to complete the Aguirre Water Supply Project is July 2017. The San Juan Power Plant Project will reuse the process wastewater of two main outfalls. Phase I – reuse of the feed water heater condensations – the expected in service date is December 2015. Phase IV, which includes the integration of microfiltration and reverse Osmosis treatment technologies, is under a bid adjudication process. The San Juan Power Plant Project expected in service date is at end of 2017.   . New RO (Reverse Osmosis) and EDI (Electrode ionization) System installed at South Coast Power Plant is currently commissioned and will provide high reliability and water quality assurance to PREPA’s only natural gas burning power plant. 

. The Authority is constructing a 230 kV transmission line (38 mile long) between the South Coast Steam Plant and Cambalache Gas Turbines Plant’s switchyard. The first stage of this project consists of the reconstruction and conversion to 230 kV of an existing 115 kV circuit line between the South Coast Steam Plant and Dos Bocas Hydroelectric Power Plant. The second stage of the project consists of the construction of a new 230 kV line from Dos Bocas to the Cambalache facilities. The expected service date is December 2015. The estimated cost of this project is $50 million. Once in operation, this major infrastructure project will significantly enhance the reliability and security margins of the transmission system, and permit the increase of power transfers from the South of Puerto Rico to the Northern and Western regions.  

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Capital Assets and Debt Administration (continued)  . Reconstruction and rehabilitation of 115 and 38 kV circuit lines throughout the whole island. It includes the reconstruction of a 42 miles of 115 kV transmission line interconnecting the Bayamon Transmission Center (TC), Cana 115 kV switchyard, Barrio Piñas 115 kV switchyard, Dos Bocas Hydroelectric Plant as well as important substations in the municipalities of Bayamon, Toa Baja, Toa Alta, Corozal, Morovis and Ciales. This project consists of seven phases. The first is the reconstruction of 3.7 miles of 115 kV transmission line with a 556.6 MCM conductor from Piñas Switchyard to the Monterrey Substation, completed in April 2014. The second is the reconstruction of 3.7 miles of 115 kV transmission line with a 556.6 MCM conductor from Monterrey Substation to the Unibon Substation, in service since October 2015. The third is the reconstruction of 4.7 miles of 115 kV transmission line with a 556.6 MCM conductor from Unibon Substation to the Morovis Substation, expected in service date is December 2017. The fourth is the reconstruction of 6.5 miles of 115 kV transmission line with a 1,119.5 MCM conductor from Bayamon TC to the Cana TC, expected in service date is February 2016. The Fifth is the reconstruction of 3 miles of 115 kV transmission line with a 1,119.5 MCM conductor from Cana TC to the Piñas Switchyard, expected in service date is October 2016. The Sixth is the reconstruction of 3.9 miles of 115 kV transmission line with a 556.6 MCM conductor from Morovis to the Ciales Substation, expected in service date is December 2017. The Seventh is the reconstruction of 17 miles of 115 kV transmission line with a 556.6 MCM conductor from Ciales Substation to the Dos Bocas Hydroelectric Plant, expected in service date is fiscal year 2024. The reconstruction and rehabilitation of four 115 kV transmission line interconnecting the Palo Seco power plant with relevant 115/38 kV transmission centers located in the metropolitan area are also included, expected in service date is the fiscal year 2022. Sub-transmission circuits interconnecting substations in the municipalities of Orocovis, Barranquitas, Maricao, Las Marías and Mayaguez, located in the central and west regions of the island, are part of this major reconstruction and rehabilitation plan.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Capital Assets and Debt Administration (continued)

. Program to improve the 38 kV sub-transmission systems continues, including the construction of underground 38 kV line in Medical Center of Puerto Rico, eliminating the tap on line 8900 and integrating a new circuit in Centro Medico Sectionalizer. This project consists of the interconnection of the 38 kV sectionalizer to the critical loads of University Hospital, Cardiovascular Center and the Medical Sciences hospitals, expected in service date is 2017. In addition, major reconstruction project of aerial 38 kV lines in the central and western part of the Island will significantly improve the reliability of the sub-transmission system. The 38 kV line required increasing the capacity to meet load on Barranquitas and provide the interconnection to Toro Negro Hydroelectric Plant, Comerío Transmission Center and the new transmission center in Barranquitas, expected in service date is the fiscal year 2016. In addition, the 38 kV 1500 and 2000 Line increase reliability by line improvement due to structural, line hardware deterioration, expected in service date is the fiscal year 2017.   . New air insulated 115/38 kV transmission center in the municipality of Barranquitas, which improves the reliability and efficiency of the System while increasing its power transfer capability and improving voltage regulation of the sub-transmission system under normal conditions and contingency situations was completed in June 2015.   . Construction of two additional insulated 115/38 kV switchyards in the municipalities of San Juan and Caguas expected to be completed in August 2016. The Buen Pastor Transmission Center will contribute to improve the reliability of the commercial and industrial loads in Río Piedras under certain contingency situations in the southern metropolitan area. The Bairoa Transmission Center will significantly improve the reliability at Caguas and nearby municipalities, by providing backup to 115/38 kV transformer contingencies located at the Caguas Transmission Center. Additional projects are planned to increase the power transfer capability from the 115 kV transmission systems to the subtransmission system by adding transformation capacity in existing switchyards such as San Juan Steam Plant, Bayamón TC and Monacillo TC.

. San Juan GIS 38 kV and 115 kV switchgears expected to enter into service in fiscal year 2017. This will be one of the Authority’s major gas insulated 115/38 kV switchyards with direct interconnection through the existing air insulated 115 kV bus to approximately more than 850 MW of generating capability. 

1501-1384337 24 I 000159 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Capital Assets and Debt Administration (continued)

These projects were funded from cash reserves, excess-operating revenues (when available), grants, and debt issued for such purposes.

Long-Term Debt

At the end of the fiscal years 2014, 2013 and 2012, the Authority had total debt outstanding of $9,413.2 million, $8,987.9 million, and $8,935.5 million, respectively, comprised of revenue bonds and notes payable.

Authority’s Outstanding Debt (In thousands)

2014 2013 2012

Power revenue bonds, net $ 8,668,425 $ 8,218,912 $ 8,419,030

Notes payable 744,770 769,059 623,813

9,413,195 8,987,971 9,042,843

Current portion (1,166,189) (1,175,311) (1,000,255)

Long-term debt, excluding current portion $ 8,247,006 $ 7,812,660 $ 8,042,588

During fiscal year 2014, power revenue bonds increased mainly as a result of the issuance of Series 2013A, with a principal amount of $675.1 million, net of related debt payments of principal and interest. Notes payable decreased $24.3 million mainly as a result of paying down revolving lines of credit to finance working capital.

The Authority’s bond ratings were downgraded to “Caa3” by Moody’s, “CC” by S&P and “CC” by Fitch.

Additional information on the Authority’s long-term debt can be found in Notes 8 and 11 to the financial statements.

1501-1384337 25 I 000160 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Management´s Discussion and Analysis (continued)

Economic Factors and Next Year’s Budgets and Rates

In the last five years, Puerto Rico’s economy has shown different behavior compared with the U.S economy in terms of the annual Gross Domestic Product (GDP). As published by the U.S Department of Commerce, the real GDP adjusted for price changes increased at an annual rate of 2.5% in the fourth quarter of 2014, according to the advance estimate released by the Bureau of Economic Analysis (BEA) in January 30, 2015. In the third quarter of 2014, real GDP figures increased 2.9%. Real GDP increased 2.4% in 2014, compared with an increase of 1.5% in 2013. According to IHS Global Insight (GI), the U.S economy will grow 3.5% in the period from January to March and 3.4% between October and December 2015. Projections for the years 2014 and 2015 estimate increases of 2.7% in 2014 and 3.3% in 2015.

By law, the Puerto Rico Planning Board (PRPB) is the local government agency that gathers and studies the official economic data. In Puerto Rico, the economy is measured by the Gross National Product (GNP). Puerto Rico's economy in fiscal year 2013 reached a real growth of 0.3%, compared to fiscal year 2012.

The Authority adopted the 2015 fiscal year budget on October 9, 2014. The total revenues for fiscal year 2014-2015 are projected to be approximately $4,630.7 million. In addition, the Capital Improvement Program amounted to approximately $244.7 million. The 2015 consolidated budget increased by $166.5 million (3.7 percent) when compared to the consolidated budget approved for fiscal year 2013-2014, mainly due to an increase in projected fuel oil prices per barrel from $94.96 for 2013-2014 to $108.48 for 2014-2015, representing a 14.2 percent increase.

Request for Information

This financial report is designed to provide a general overview of the Authority’s finances. Questions concerning any of the information provided in this report or requests for additional financial information should be addressed to the Authority’s Chief Financial Officer. The executive offices of the Authority are located at 1110 Ponce de León Avenue, San Juan, Puerto Rico 00907.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Statements of Net Position (In thousands)

June 30 2014 2013 Assets (as restated) Current assets: Cash and cash equivalents $ 147,236 $ 122,130 Receivables, net 1,500,545 1,394,199 Fuel oil, at average cost 194,073 323,730 Materials and supplies, at average cost 196,887 197,786 Prepayments and other assets 463 5,082 Total current assets 2,039,204 2,042,927

Other non-current receivables, net 120,045 117,653

Restricted assets: Cash and cash equivalents held by trustee for payment of principal and interest on bonds 328,532 369,381 Investments held by trustee 674,395 553,602 Construction fund and other special funds 325,924 83,420 Total restricted assets 1,328,851 1,006,403

Utility plant: Plant in service 12,281,158 11,937,375 Accumulated depreciation (6,422,226) (6,098,403) 5,858,932 5,838,972 Construction in progress 988,524 999,586 Total utility plant, net 6,847,456 6,838,558

Deferred expenses 16,803 10,898 Total assets 10,352,359 10,016,439

Deferred outflows of resources Accumulated decrease in fair value of hedging derivatives 48,864 85,004 Deferred loss resulting from debt refunding 77,948 92,279 Total deferred outflows of resources 126,812 177,283 Total assets and deferred outflows $ 10,479,171 $ 10,193,722

(Continued)

27 1501-1384337 I 000162 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Statements of Net Position (continued) (In thousands)

June 30 2014 2013 Liabilities and net position (as restated) Current liabilities: Notes payable $ 733,908 $ 755,665 Accounts payable and accrued liabilities 1,586,390 1,301,028 Customers' deposits 15,726 14,532 Total current liabilities 2,336,024 2,071,225

Current liabilities payable form restricted assets: Current portion of long-term debt 432,281 413,546 Notes payable from restricted assets – 6,100 Accrued interest 218,839 187,432 Other current liabilities payable from restricted assets 60,614 39,594 Total current liabilities payable from restricted assets 711,734 646,672

Noncurrent liabilities: Long-term debt, excluding current portion 8,247,006 7,812,660 Fair value of derivative instruments - interest, basis and commodity swaps 48,864 85,004 Customers' deposits (excluding current portion) 168,855 166,950 Sick leave benefits to be liquidated after one year 114,518 122,356 Accrued unfunded other post-employment benefits liability 119,175 136,050 Total noncurrent liabilities 8,698,418 8,323,020 Total liabilities 11,746,176 11,040,917

Net position (deficit): Invested in utility plant, net of related debt (253,448) (32,432) Restricted for capital and debt service – – Unrestricted (1,013,557) (814,763) Total net position (deficit) (1,267,005) (847,195) Total liabilities and net position $ 10,479,171 $ 10,193,722

See accompanying notes.

1501-1384337 28 I 000163 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Statements of Revenues, Expenses and Changes in Net Position (In thousands)

Year Ended June 30 2014 2013 (as restated)

Operating revenues $ 4,468,922 $ 4,843,016

Operating expenses: Operations: Fuel 2,345,000 2,603,577 Purchased power 807,620 755,686 Other production 70,557 72,384 Transmission and distribution 175,754 175,461 Customer accounting and collection 111,475 116,605 Administrative and general 192,031 201,663 Maintenance 201,944 218,950 Depreciation 341,511 344,653 Total operating expenses 4,245,892 4,488,979 Operating income 223,030 354,037

Interest income and other 21,157 26,329 Income before interest charges, contribution in lieu of taxes and contributed capital 244,187 380,366 Interest charges: Interest on bonds 431,021 399,641 Interest on notes payable and other long-term debt 7,181 741 Amortization of debt discount, issuance costs and refunding loss 2,737 550 Allowance for funds used during construction (9,759) (14,065) Total interest charges, net 431,180 386,867 Loss before contribution in lieu of taxes and contributed capital (186,993) (6,501)

Contribution in lieu of taxes and other (277,776) (297,551) Loss before contributed capital (464,769) (304,052)

Contributed capital 44,959 31,979 Change in net position (419,810) (272,073)

Net position (deficit), beginning balance, as restated (847,195) (575,122) Net position (deficit), ending balance $ (1,267,005) $ (847,195)

See accompanying notes.

1501-1384337 29 I 000164 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Statements of Cash Flows (In thousands)

Year Ended June 30 2014 2013 (as restated) Cash flows from operating activities Cash received from customers $ 4,176,780 $ 4,665,529 Cash paid to suppliers and employees (3,549,714) (4,272,003) Net cash flows provided by operating activities 627,066 393,526

Cash flows from noncapital financing activities Proceeds from notes payable 116,527 32,921 Principal paid on notes payable (92,454) (92,053) Interest paid on notes payable (1,163) (566) Principal paid on fuel line of credit (1,630,600) (1,264,351) Proceeds from fuel line of credit 1,582,238 1,468,736 Interest paid on fuel line of credit (27,197) (16,611) Net cash flows (used in) provided by noncapital financing activities (52,649) 128,076

Cash flows from capital and related financing activities Construction expenditures (288,746) (315,764) Proceeds received from contributed capital 4,358 10,898 Power revenue bonds: Proceeds from issuance of bonds, net of original discount 658,336 – Principal paid on revenue bonds maturities (194,920) (185,605) Interest paid on revenue bonds (409,847) (397,700) Swap termination fees paid (37,873) – Net cash flows used in capital and related financing activities (268,692) (888,171)

Cash flows from investing activities Purchases of investment securities (3,131,639) (4,085,709) Proceeds from sale and maturities of investment securities 3,012,296 4,165,974 Interest on investments 41,828 24,531 Net cash flows (used in) provided by investing activities (77,515) 104,796 Net increase (decrease) in cash and cash equivalents 228,210 (261,773)

Cash and cash equivalents at beginning of year 553,251 815,024 Cash and cash equivalents at end of year $ 781,461 $ 553,251

(Continued)

1501-1384337 30 I 000165 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Statements of Cash Flows (continued) (In thousands)

Year Ended June 30 2014 2013 (as restated) Cash and cash equivalents Unrestricted $ 147,236 $ 122,130 Restricted: Cash and cash equivalents held by trustee for payment of principal and interest on bonds 328,532 369,381 Cash and cash equivalents within construction and other special funds 305,693 61,740 $ 781,461 $ 553,251

Reconciliation of operating income to net cash provided by operating activities Operating income $ 223,030 $ 354,037 Adjustments to reconcile operating income to net cash provided by operating activities: Depreciation 341,511 344,653 Provision for uncollectible accounts and other 191,523 15,740 Changes in assets and liabilities: Receivables (334,556) (342,632) Fuel oil 156,854 (78,438) Materials and supplies 899 580 Prepayments and other assets 4,619 (5,027) Other deferred debits (6,649) (6,881) Noncurrent liabilities, excluding revenue bonds and notes payable (24,713) (12,210) Accounts payable and accrued liabilities 71,448 118,370 Customer's deposits 3,100 5,334 Total adjustments 404,036 39,489 Net cash flows provided by operating activities $ 627,066 $ 393,526

Supplemental cash flows information Noncash transactions: Capital contributions $ 40,601 $ 21,081 Change in fair value of derivative instruments $ 36,140 $ 26,303 Changes in deferred loss resulting from debt refunding $ (14,331) $ (15,062)

See accompanying notes.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements

June 30, 2014 and 2013

1. Reporting Entity

Puerto Rico Electric Power Authority (the Authority) is a public corporation and governmental instrumentality of the Commonwealth of Puerto Rico (the Commonwealth) created on May 2, 1941, pursuant to Act No. 83, as amended, re-enacted, and supplemented, of the Legislature of Puerto Rico (the Act) for the purpose of conserving, developing and utilizing the water, and power resources of Puerto Rico in order to promote the general welfare of the Commonwealth. Under the entity concept, the Authority is a component unit of the Commonwealth. The Authority transmits and distributes, substantially, all of the electric power consumed and produces a majority of the electricity generated in Puerto Rico.

The Authority has broad powers including, among others, to issue bonds for any of its corporate purposes subject to the limitations set forth in a Trust Agreement dated as of January 1, 1974, as amended (the 1974 Agreement). The Authority is required, under the terms of the 1974 Agreement and the Act, to determine and collect reasonable rates for electric service in order to produce revenues sufficient to cover all operating and financial obligations, as defined.

On August 18, 2003, the Commonwealth approved Act No. 189, which authorizes the Authority to create, acquire and maintain corporations, partnerships or subsidiary corporations, for profit or non-profit entities.

On May 27, 2014, the Commonwealth approved Act No. 57, which authorizes the Puerto Rico Energy Commission to approve electric rates proposed by the Authority among other matters.

Basis of Presentation – Blended Component Units

The financial statements of the Authority as of the fiscal years ending June 30, 2014 and 2013, include the financial position and operations of the Puerto Rico Irrigation Systems (Irrigation Systems) and PREPA Holdings LLC (PREPA Holdings). The Irrigation Systems operate pursuant to the provisions of the Act, and Acts Nos. 83 and 84, approved on June 20, 1955, regarding the Puerto Rico Irrigation Service, South Coast, and Isabela Irrigation Service, respectively, and the Lajas Valley Public Irrigation Law, approved on June 10, 1953, as amended. PREPA Holdings, a wholly owned subsidiary of the Authority, was created for the sole purpose of acting as a holding company and has no current operations. PREPA Holdings is the direct parent of the following entities: PREPA Networks, LLC (PREPA.Net), Inter American Energy Sources, LLC, and Consolidated Telecom of Puerto Rico, LLC.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

1. Reporting Entity (continued)

Basis of Presentation – Blended Component Units (continued)

The Irrigations Systems and PREPA Holdings conform to the requirements of Governmental Accounting Standards Board (GASB) No. 61, The Financial Reporting Entity: Omnibus-an amendment of GASB Statements No. 14 and No. 34, and No. 39, Determining Whether Certain Organizations are Component Units, on its stand-alone financial statements. GASB No. 39 establishes standards for defining and reporting on the financial reporting entity. It also establishes standards for reporting participation in joint ventures. It applies to financial reporting by primary governments, and other stand-alone governments; and it applies to the separately issued financial statements of governmental component units. In addition, this Statement should be applied to governmental and non-governmental component units when they are included in a governmental financial reporting entity.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

1. Reporting Entity (continued)

Basis of Presentation – Blended Component Units (continued)

Condensed financial information as of June 30, 2014 and 2013 and for the fiscal years then ended for the Irrigation Systems is as follows:

2014 2013 (In thousands) Statements of net position: Assets: Receivables, net $ 6,062 $ 7,383 Prepayments and other assets 240 240 Utility Plant, net of depreciation 20,556 20,408 Total assets $ 26,858 $ 28,031

Liabilities: Accounts payable, net $ 1,066 $ 1,066

Statements of revenues, expenditures and changes in net position: Operating revenues $ 6,284 $ 6,875 Operating expenses (7,457) (11,523) (1,173) (4,648) Transfer to primary government – (5,999) Net position, beginning balance 26,965 37,612 Net position, ending balance $ 25,792 $ 26,965

1501-1384337 34 I 000169 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

1. Reporting Entity (continued)

Basis of Presentation – Blended Component Units (continued)

Pursuant to the Act, the Authority is authorized to create subsidiaries in order to, among other things, delegate or transfer any of its rights, powers, functions or duties. The Authority currently has four principal subsidiaries organized in a holding company structure.

PREPA Holdings, a wholly owned subsidiary of the Authority, was organized on October 26, 2009 as a Delaware limited liability company for the sole purpose of acting as a holding company and has no current operations. PREPA Holdings is the direct parent of the following entities: PREPA.Net, InterAmerican Energy Sources, LLC and Consolidated Telecom of Puerto Rico, LLC.

PREPA.Net, a subsidiary of the Company, was formed for the purpose of merging two local not- for-profit entities – PREPA Networks, Corp, and PREPA.Net International Wholesale Transport, Inc.

PREPA.Net markets the excess communication capacity of the Authority’s fiber optic cable system. PREPA.Net currently offers next generation telecommunications services to carriers, internet service providers, and large commercial enterprises. These services include data transmission via Synchronous Optical Network (SONET), metro and long haul Ethernet transport services, wireless last mile, and internet protocol services optimized for voice over internet protocol. PREPA.Net also offers international fiber optic cable capacity and satellite teleport facilities through the submarine fiber optic cable capacity acquired in 2008.

InterAmerican Energy Sources, LLC was created on May 25, 2007, as a Delaware limited liability company, for the purpose of investing, developing, financing, constructing and operating renewable energy projects and other infrastructure related to the optimization of the Authority’s electric infrastructure. InterAmerican Energy Sources, LLC is currently not operating.

Consolidated Telecom of Puerto Rico, LLC was created on October 27, 2009, as a Delaware limited liability company, for the purpose of developing, financing, constructing and operating a telecommunications business within or outside of the Commonwealth, directly or indirectly, in relation to the operations of the Authority.

1501-1384337 35 I 000170 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

1. Reporting Entity (continued)

Basis of Presentation – Blended Component Units (continued)

Condensed financial information for PREPA Holdings, LLC as of June 30, 2014 and 2013 and for the year then ended is as follows:

2014 2013 (In thousands) Statement of net position: Assets: Cash and cash equivalents $ 8,297 $ 7,871 Certificates of deposit 1,638 1,635 Receivables, net 2,258 5,481 Prepayments and other assets 72 62 Utility plant, net of depreciation 29,356 16,869 Other receivables 11,086 14,623 Total assets $ 52,707 $ 46,541

Liabilities: Accounts payable, net $ 21,423 $ 22,350 Notes payable 10,862 7,294 Total liabilities $ 32,285 $ 29,644

Statements of revenues, expenditures and changes in net position: Operating revenues $ 18,029 $ 14,550 Operating expenses (14,504) (10,438) 3,525 4,112

Net position, beginning balance 16,897 12,785 Net position, ending balance $ 20,422 $ 16,897

1501-1384337 36 I 000171 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

1. Reporting Entity (continued)

Basis of Presentation – Blended Component Units (continued)

2014 2013 (In thousands)

Statement of cash flows: Cash flows from operating activities $ 10,553 $ 6,707 Cash flows from noncapital financing activities 4,428 (1,125) Cash flows from capital and related financing activities (14,567) (11,136) Cash flows from investing activities 12 1,604 Net increase in cash 426 (3,950)

Cash at beginning of year 7,871 11,821 Cash at end of year $ 8,297 $ 7,871

2. Summary of Significant Accounting Policies

The following is a summary of the most significant accounting policies followed by the Authority in preparing its financial statements:

Basis of Accounting

The accounting and reporting policies of the Authority conform to the accounting rules prescribed by the Governmental Accounting Standards Board (GASB). As such, it functions as an enterprise fund. The Authority maintains its accounting records on the accrual basis of accounting in conformity with U.S. generally accepted accounting principles. Although the Authority is not subject to all Federal Energy Regulatory Commission (FERC) regulations, the Authority has adopted the uniform system of accounts prescribed by FERC.

The accounting and reporting policies of the Authority conform to the accounting rules prescribed by the Governmental Accounting Standards Board (GASB).

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Basis of Accounting (continued)

The Authority accounts for its operations and financings in a manner similar to private business enterprises; the intent is that costs of providing goods or services to the general public on a continuing basis be financed or recovered primarily through user charges. Such accounts and these financial statements have been prepared on the basis that the Authority will continue as a going concern. Additional disclosures within the Notes to these financial statements, particularly in Notes 8, 11, 19 and 20, should be read in connection with consideration of the future ability of the Authority to continue as such.

Cash and Cash Equivalents

The Authority considers all highly liquid debt instruments with maturities of three months or less when purchased to be cash equivalents. Cash and cash equivalents included in the restricted funds are considered cash equivalents for purposes of the statements of cash flows.

Receivables

Receivables are stated net of estimated allowances for uncollectible accounts, which are determined, based upon past collection experience and current economic conditions, among other factors. The Authority establishes a general or specific reserve for each group of customers (i.e., residential, commercial, industrial, and governmental). The Authority has significant amounts receivable from the Commonwealth’s and its instrumentalities. There is significant uncertainty in regards to the collection of such receivables due to the financial challenges these entities are facing. The Authority has considered this in its estimate of the specific governmental reserve for uncollectible accounts. Because of uncertainties inherent in the estimation process, management’s estimate of credit losses inherent in the existing accounts receivable and related allowance may change in the future.

Materials, Supplies and Fuel Oil

Materials, supplies and fuel oil inventories are carried at average cost and are stated at the lower of cost or market.

1501-1384337 38 I 000173 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Investments

The Authority follows the provisions of GASB Statement No. 31, Accounting and Financial Reporting for Certain Investments and for External Investment Pools, which require the reporting of investments at fair value in the statement of net position and recording changes in fair value in the statements of revenues, expenses and changes in net position. The fair value is based on quoted market prices and recognized pricing services for certain fixed income securities.

The funds under the 1974 Agreement may be invested in:

. Government obligations, which are direct obligations of, or obligations whose principal and interest is guaranteed by the U.S. Government, or obligations of certain of its agencies or instrumentalities.

. Investment obligations of any of the states or territories of the United States or political subdivisions thereof (other than obligations rated lower than the three highest grades by a nationally recognized rating agency) and repurchase agreements with commercial banks fully secured by U.S. Government obligations.

. Time deposits with Government Development Bank for Puerto Rico (GDB) or the Authority’s Trustee under the 1974 Agreement or any bank or trust company member of the Federal Deposit Insurance Corporation having a combined capital and surplus of not less than $100 million.

Effective April 1999, the 1974 Agreement was amended to provide that permitted investments of moneys to the credit of the Self-insurance Fund be expanded (subject to the Authority’s adoption of an investment policy with the consent of GDB) to coincide with the investments permitted for the pension fund for employees of the Commonwealth of Puerto Rico and its instrumentalities.

Such investments include various debt instruments, such as mortgage loans and leases, common and preferred stock, real property and various other financial instruments.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Utility Plant

Utility plant is carried at cost, which includes labor, materials, overhead, and an allowance for the cost of funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds used to finance construction work in progress. AFUDC is capitalized as an additional cost of property and as a reduction of interest expense. Capitalized interest expense is reduced by interest income earned on related investments acquired with proceeds of tax-exempt borrowings. Such costs are recovered from customers as a cost of service through depreciation charges in future periods. Capitalized interest during the years ended June 30, 2014 and 2013 amounted to $9.8 million and $14.1 million, respectively. These amounts are net of interest income earned on investments amounting to $4.0 million and $1.0 million, respectively.

Capital expenditures of $1,200 or more are capitalized at cost at the date of acquisition. Maintenance, repairs, and the cost of renewals of minor items of property units are charged to operating expenses. Replacements of major items of property are charged to the plant accounts. The cost of retired property, together with removal cost less salvage, is charged to accumulated depreciation with no gain or loss recognized.

The Authority follows the provisions of GASB Statement No. 42, Accounting and Financial Reporting for Impairment of Capital Assets and for Insurance Recoveries. This statement establishes guidance for accounting and reporting for the impairment of capital assets and for insurance recoveries.

Depreciation

Depreciation is computed on the straight-line method at rates considered adequate to allocate the cost of the various classes of property over their estimated service lives. The annual composite rate of depreciation, determined by the Authority’s consulting engineers, was approximately 3.58% for 2014 and 2013.

Unamortized Debt Issuance Expense

Debt issuance costs are presented as expense during the year they are incurred. Premium and discounts incurred in the issuance of bonds are deferred and amortized using the straight-line method, which approximates the interest method, over the term of the related debt.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Unamortized Debt Issuance Expense (continued)

For debt refunding debt, the excess of reacquisition cost over the carrying value of long-term debt is deferred and amortized to operating expenses using the straight-line method over the remaining life of the original debt or the life of the new debt, whichever is shorter.

Bonds payable are reported net of applicable bond premium or discount. For fiscal year 2013 and 2014, as a result of the adoption of GASB Statement No. 65, the deferred loss from debt refunding is reported as deferred outflows of resources in the accompanying statements of net position.

Pension Plan and Other Postemployment Benefits

Pension and other postemployment benefits (OPEB) expenses are equal to the statutory required contribution to the employees’ retirement system. A pension liability or asset is reported equal to the cumulative difference between annual required contributions and actual contributions.

Accounting for Compensated Absences

Employees earn annual vacation leave at the rate of 30 days per year up to a maximum permissible accumulation of 60 days for union employees and management personnel.

Employees accumulate sick leave at the rate of 19 days per year. Sick leave is only payable if the regular employee resigns and has more than 10 years of employment, or retires and takes a pension. Maximum permissible accumulation for sick leave is 90 days for all employee and the excess shall be lost if an employee does not use such excess from January to June of the next year.

The Authority records as a liability and as an expense the vested accumulated vacation and sick leave as benefits accrue to employees. The cost of vacation and sick leave expected to be paid in the next twelve months is classified as current and accrued liabilities while amounts expected to be paid after twelve months are classified as noncurrent liabilities.

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Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Revenue Recognition, Fuel Costs and Purchased Power

Clients are billed monthly. Revenues are recorded based on services rendered during each accounting period, including an estimate for unbilled services. Revenues include amounts resulting from a fuel and purchased power cost recovery clause (Fuel Adjustment Clause), which is designed to permit full recovery through customer billings of fuel costs and purchased power. Fuel costs and purchased power are reflected in operating expenses as the fuel and purchased power are consumed.

Contributions in Lieu of Taxes and Governmental Subsidies

The Act exempts the Authority from all taxes that otherwise would be levied on its properties and revenues by the Commonwealth and its Municipalities, except to the extent net revenues, as defined, are available, wherein the Authority is required under the Act to make a contribution in lieu of taxes of 11% to the Commonwealth and the Municipalities of gross electric sales as follows:

Municipalities

The Authority is required under the Act to make a contribution in lieu of taxes to municipalities of the greater of:

a) Twenty percent of the Authority’s Adjusted Net Revenues (Net Revenues, as defined in the 1974 Agreement, less the cost of the Commonwealth rate subsidies); b) The cost collectively of the actual electric power consumption of the municipalities; or c) The prior five-year moving average of the contributions in lieu of taxes paid to the municipalities collectively.

If the Authority does not have sufficient funds available in any year to pay the contribution in lieu of taxes, the difference is accrued and carried forward for a maximum of three years. The contribution in lieu of taxes to Municipalities can be used to offset accounts receivable balance owed by the Municipalities to the Authority as permitted by law.

1501-1384337 42 I 000177 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Contributions in Lieu of Taxes and Governmental Subsidies (continued)

Commonwealth of Puerto Rico

To the extent net revenues are available, the Authority is also required under the Act to set aside the remainder of contribution in lieu of taxes of gross electric sales for the purpose of (i) financing capital improvements, (ii) offsetting other subsidies (other than cost of fuel adjustments to certain residential clients) of the Commonwealth, and (iii) any other lawful corporate purpose. Amounts assigned to (ii) above, are classified as a contribution in lieu of taxes in the accompanying statements of revenues, expenses and changes in net position and reduce the related accounts receivable in the statements of net position.

Contributed Capital

The Authority records contributed capital as income in the year earned. The Authority receives contributed capital in the form of cash and property from residential projects developed by third parties during recent years and local and federal agencies. During the years ended June 30, 2014 and 2013, the Authority received non-cash contributed capital in the amount of $40,601 and $21,081, respectively.

Risk Management

The Authority purchases commercial insurance covering casualty, theft, tort claims, natural disaster and other claims covering all risk property (excluding transmission and distribution lines), boiler and machinery, boiler, machinery and public liability. In addition, the Authority has a self-insured fund to pay the cost of repairing, replacing or reconstructing any property damaged or destroyed from, or extraordinary expenses incurred as a result of a cause, which is not covered by insurance required under 1974 agreement.

1501-1384337 43 I 000178 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Estimates

The preparation of the basic financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets (including related allowances for uncollectible accounts) and liabilities and disclosure of contingent assets and liabilities at the date of the basic financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Interest-Rate Swap Agreements

The Authority follows the provisions of GASB Statement No. 53, Accounting and Financial Reporting for Derivative Instruments. This statement establishes guidance for the recognition, measurement, and disclosure of information regarding derivative instruments.

The interest-rate swaps are used in the area of debt management to take advantage of favorable market interest rates and to limit interest rate risk associated with variable rate debt exposure.

Under the interest-rate swap programs, the Authority pays fixed and variable rates of interest based on various indices for the term of the variable interest rate Power Revenue Bonds and receives a variable rate of interest, which is also based on various indices. These indices are affected by changes in the market. The net amount received or paid under the swap agreements is recorded as an adjustment to interest expense on the statements of revenues, expenses and changes in net position. The interest rate swaps are reported at fair value in the Statement of Net Positions. The changes in fair value for effective hedges are recorded as deferred inflows or outflows of resources in the Statement of Net Positions. The changes in fair value for ineffective hedges are reported in investment income.

The Authority accounts for its derivative instruments at fair value. The changes in fair values of the effective hedging derivative instruments are reported as either deferred inflows or deferred outflows of resources. The changes in fair value of investment derivative instruments (which include ineffective hedging derivative instruments) are reported as part of investment income in the current reporting period.

1501-1384337 44 I 000179 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

2. Summary of Significant Accounting Policies (continued)

Restricted Assets

Funds set aside for construction, debt service payments or other specific purposes are classified as restricted assets since their use is limited for these purposes by the applicable agreements.

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

Claims and Judgment

The estimated amount of the liability for claims and judgments is recorded on the accompanying statement of net position based on the Authority’s evaluation of the probability of an unfavorable outcome in the litigation of such claims and judgments. The Authority consults with legal counsel upon determining whether an unfavorable outcome is expected. Because of uncertainties inherent in the estimation process, management’s estimate of the liability for claims and judgments may change in the future.

3. Cash and Cash Equivalents

The 1974 Agreement established the General Fund, the Revenue Fund, and certain other funds (see Note 5). All revenues (other than income from investments and construction funds obtained from financing) are deposited in these funds. The moneys held in these funds are presented as unrestricted cash and cash equivalents in the statement of net position.

1501-1384337 45 I 000180 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

3. Cash and Cash Equivalents (continued)

At June 30, 2014 and 2013, the carrying amount and bank balance of cash deposits held by the Authority and restricted cash deposits held by the Trustee under the 1974 Agreement are as follows (in thousands):

2014 2013 Carrying Bank Carrying Bank Amount Balance Amount Balance

Unrestricted $147,236 $158,517 $122,130 $49,499 Restricted: Held by the Trustee 328,532 328,532 369,381 369,381 Held by the Authority 305,693 305,693 61,740 61,740 $781,461 $792,742 $553,251 $480,620

Custodial Credit Risk - Deposits

Custodial credit risk is the risk that in the event of a bank failure, the Bank’s deposits may not be returned. The Commonwealth requires that public funds deposited in commercial banks in Puerto Rico must be fully collateralized. Deposits maintained in GDB or the Economic Development Bank (EDB) are exempt from the collateral requirements established by the Commonwealth and thus represents custodial credit risk because in the event of GDB’s or EDB’s failure the Authority may not be able to recover the deposits. The Authority’s policy is to deposit funds with either institution which provides insurance or securities as collateral. Such collateral is held by the Department of the Treasury of the Commonwealth.

All moneys deposited with the Trustee or any other Depository hereunder in excess of the amount guaranteed by the Federal Deposit Insurance Corporation or other federal agency are continuously secured by lodging with a bank or trust company approved by the Authority and by the Trustee as custodian, or, if then permitted by law, by setting aside under control of the trust department of the bank holding such deposit, as collateral security, Government Obligations or other marketable securities.

1501-1384337 46 I 000181 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

4. Accounts Receivable

At June 30, receivables consist of (in thousands):

2014 2013 Current: Electric and related services: Government agencies and municipalities $ 638,637 $ 499,996 Residential, industrial, and commercial 928,277 884,776 Recoveries under fuel adjustment clause under billed 67,766 10,144 Unbilled services 220,104 195,278 Miscellaneous accounts and others 9,334 14,611 1,864,118 1,604,805 Allowance for uncollectible accounts - current (397,705) (251,283) 1,466,413 1,353,522 Receivable from insurance companies and other 29,818 37,819 Accrued interest on investments 4,314 2,858 $1,500,545 $1,394,199 Noncurrent: Electric and related services: Government agencies and municipalities $ 165,090 $ 117,653 Allowance for uncollectible accounts – noncurrent (45,045) – $ 120,045 $ 117,653

The Authority has other subsidies and reimbursable costs receivable from the Commonwealth, which are reduced by means of charges (accounted for as a contribution in lieu of taxes and to the extent net revenues, as defined, are available) against a portion of the 11% of gross electric sales, after the contribution in lieu of taxes to municipalities, it is required to set aside under the Act. The Authority has the right to offset amounts receivable from municipalities amounting to $555 million and $321 million as of June 30, 2014 and 2013, respectively with contribution in lieu of taxes payable to such municipalities. The portion of accounts receivable and other governmental receivables not expected to be collected during the next fiscal year are reflected in the accompanying statement of net position as other noncurrent receivables. Further, the Authority has recorded an allowance for uncollectible accounts estimated at $68 million and $12 million, for 2014 and 2013, respectively, in consideration of the financial difficulty being experienced by the Commonwealth and related entities and the risk receivables (both current and long term) from such entities are uncollectible.

1501-1384337 47 I 000182 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

5. Restricted Assets

At June 30, 2014 and 2013, certain investments and cash deposits of the Authority were restricted to comply with long-term principal and interest debt service requirements (sinking funds) as well as for self-insurance. These restricted assets are held by the Trustee under the 1974 Agreement (see Note 3) in the following funds:

1974 Reserve Account – Reserve for payment of principal of and interest on Power Revenue Bonds in the event moneys in Bond Service Account or Redemption Account are insufficient for such purpose. During fiscal year 2013-2014, the Authority deposited $46.4 million into 1974 Reserve Account from the proceeds of Power Revenue Bonds Series 2013 A.

1974 Self-Insurance Fund – Fund to pay the cost of repairing, replacing or reconstructing any property damaged or destroyed from, or extraordinary expenses incurred as a result of a cause, which is not covered by insurance required under the 1974 Agreement. The 1974 Self- Insurance Fund also serves as an additional reserve for the payment of the principal of and interest on the Power Revenue Bonds, and meeting the amortization requirements to the extent that moneys in the Bond Service Account, the Redemption Account and the 1974 Reserve Account are insufficient for such purpose. The Authority did not make any deposits into the 1974 Self Insurance Fund during fiscal years 2012-2013 and 2013-2014.

Bond Service Account and Redemption Account (1974 Sinking Fund) – Current year requirements for principal of and interest on Power Revenue Bonds. The Authority did not make required deposits into 1974 Sinking Fund Principal and Interest for May 2014.

Please see further discussion regarding the forbearance agreements in Note 20.

1501-1384337 48 I 000183 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

5. Restricted Assets (continued)

At June 30, cash, cash equivalents and investments held by the Trustee consist of (in thousands):

2014 2013 Cash and Cash Cash and Cash Equivalents Investments Equivalents Investments 1974 Sinking Fund - Principal $188,508 $ – $194,920 $ 569 1974 Sinking Fund – Interest and Capitalized Interest 140,024 124,992 174,461 62,344 1974 Reserve Account – 453,323 – 398,472 1974 Self-Insurance Fund – 96,080 – 92,217 $328,532 $674,395 $369,381 $553,602

Investments held by Trustee under the 1974 Agreement are invested exclusively in securities of the U.S. Government and its agencies.

The Authority also has cash and investment securities held by the trust department of a commercial bank restricted for the following purposes:

1974 Construction Fund – Special fund created by the 1974 Agreement. The proceeds of any Power Revenue Bonds issued for the purpose of paying the cost of acquiring or constructing improvements, together with the money received from any other source for such purpose, except proceeds which are (i) applied to the repayment of advances, (ii) deposited in the 1974 Reserve Account, (iii) deposited in the Bond Service Account as capitalized interest or (iv) used for the payment of financing expenses, shall be deposited in the 1974 Construction Fund and held by the Authority in trust. During fiscal year 2013-2014, the Authority deposited $500 million into 1974 Construction Fund from the proceeds of Power Revenue bonds Series 2013 A.

Reserve Maintenance Fund – Fund to pay the cost of unusual or extraordinary maintenance or repairs, not recurring annually, and renewals and replacements, including major items of equipment. The Reserve Maintenance Fund also serves as an additional reserve for the payment of principal and interest on the Power Revenue Bonds and meeting the amortization requirements to the extent that moneys in the 1974 Sinking Fund, including money in the 1974 Reserve Account, are insufficient for such purpose. The Authority did not make any deposits into the 1974 Reserve Maintenance Fund during fiscal years 2014 and 2013.

1501-1384337 49 I 000184 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

5. Restricted Assets (continued)

At June 30, 2014 and 2013, the 1974 Construction Fund, Reserve Maintenance Fund and other restricted funds consist of (in thousands):

2014 2013 Cash and Cash Cash and Cash Equivalents Investments Equivalents Investments

1974 Construction Fund $303,793 $ 1,105 $49,370 $ 1,103 Reserve Maintenance Fund – 15,949 – 15,818 Other Restricted Funds 1,900 – 12,370 – PREPA Client Fund – 3,177 – 4,759 $305,693 $20,231 $61,740 $21,680

Following is the composition of the investments in the 1974 Construction Fund and other special funds (in thousands):

2014 2013

U.S. Government obligations $ 1,105 $ 1,103 Certificate of deposit 19,126 20,577 $20,231 $21,680

1501-1384337 50 I 000185 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

5. Restricted Assets (continued)

Investments

The following table provides a summary of the Authority’s investments by type at June 30, 2014 (in thousands):

June 30, 2014 % of

Maturity Total

Coupon Rate Dates Face Value Fair Value Portfolio

1974 Reserve Maintenance Fund

Federal Home Loan Bank 0.87% 05/12/17 $ 5,000 $ 5,011 31.4%

Federal Home Loan Mortgage Corp. 1.00% 06/26/17 5,000 5,007 31.4%

Certificate of Deposits Various 08/29/14 5,931 5,931 37.2%

Total Portfolio 15,949

1974 Self Insurance Fund

Federal Home Loan Mortgage Corp. .90 to 6.50% 12/2017 to 11/2028 8,443 8,791 9.1%

Federal Home Loan Bank .87 to 1.625% 03/2017 to 04/2017 30,675 30,642 31.9%

Federal National Mortgage Association .50 to 6.00% 05/2016 to 03/2030 12,436 13,152 13.7%

Federal Farm Credit Bank 0.87% May-17 15,000 15,034 15.6%

Corporate Issues .03 to 5.75% 07/2014 to 05/2024 3,057 3,258 3.4%

U.S. Bank Money Market 0.30% Aug-14 387 387 0.4%

U.S. Treasury Note 2.00 to 4.75% 08/2017 to 02/2022 6,710 6,821 7.1%

U.S. Treasury Bonds 1.75 to 8.13% 08/2021 to 05/2022 4,185 4,206 4.4%

Domestic Common Stocks Various Various 9,316 12,252 12.8%

Certificate of Deposit Various Aug-13 1,538 1,537 1.6%

Total Portfolio 96,080

1974 Reserve Account

Federal Home Loan Mortgage Corporation .90 to 5.00% 02/2016 to 12/2017 48,980 48,856 10.8%

Federal Home Loan Bank .95 to 2.00% 01/2018 to 04/2019 15,000 14,893 3.3%

Federal National Mortgage Association .813 to 5.00% 01/2017 to 12/2018 51,202 53,545 11.8%

Federal Farm Credit Bank .082 to 2.28% 02/2017 to 04/2019 37,000 36,947 8.1%

U.S. Bank Money Market .03 to .04% Various 2,354 2,354 0.5%

U.S. Treasury Note .50 to 4.625% 08/2016 to 02/2018 50,145 50,817 11.2%

Corporate Issues .25 to 4.00% 01/2014 to 04/2018 14,960 15,521 3.4%

Certificates of Deposits .20 to 1.00% Various 230,390 230,390 50.8%

Total Portfolio 453,323

Sinking Fund - Capitalized Interest

Federal Home Loan Mortgage Corporation .625 to .75% 11/2014 to 12/2014 1,800 1,804 1.4%

Federal National Mortgage Association .75 to 2.625% 11/2014 to 12/2014 4,000 4,019 3.2%

U.S. Bank Money Market 0.300% Various 35,022 35,022 28.0%

Certificates of Deposits 1.20 to 1.90% 12/2014 to 12/2015 69,658 69,658 55.7%

Municipal Issues .515to 5.50% 07/2014 to 12/2023 14,410 14,489 11.6%

Total Portfolio 124,992

1974 PREPA Client

Certificates of Deposits 3,177 3,177 100.0%

Total Portfolio 3,177

1974 Construction Fund

Other - Rural Electrification Administration (REA) 1,105 1,105 100.0%

Total Portfolio 1,105

$ 694,626

1501-1384337 51 I 000186 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

5. Restricted Assets (continued)

Investments (continued)

The following table provides a summary of the Authority’s investments by type at June 30, 2013 (in thousands):

June 30, 2013 % of

Maturity Total

Coupon Rate Dates Face Value Fair Value Portfolio

1974 Reserve Maintenance Fund

Federal National Mortgage Association 0.52% 16-Feb $ 5,000 $ 4,972 31.4%

Federal Farm Credit Bank 0.44% 15-Oct 5,000 4,983 31.5%

Certificate of Deposits 0.15% 13-Sep 5,863 5,863 37.1%

Total Portfolio 15,818

1974 Self Insurance Fund

Federal Home Loan Mortgage Corp. 5.00 to 6.50% 08/2021 to 11/2028 4,294 4,642 5.0%

Federal National Mortgage Association .52 to 6.00% 02/2016 to 03/2030 20,432 21,186 23.0%

Federal Farm Credit Bank .42 to .45% 10/2015 to 05/2016 45,000 44,724 48.5%

Corporate Issues 3.45 to 8.50% 12/2017 to 02/2023 8,770 9,387 10.2%

U.S. Bank Money Market 0.10% 13-Aug 754 754 0.8%

U.S. Treasury Note 8.13% 21-Aug 290 429 0.5%

Domestic Common Stocks Various Various 8,549 9,787 10.6%

Certificate of Deposit 0.140% 13-Aug 1,309 1,308 1.4%

Total Portfolio 92,217

1974 Reserve Account

Federal Home Loan Mortgage Corporation .90 to 5.00% 02/2016 to 12/2017 48,195 47,688 12.0%

Federal Home Loan Bank .05 to 5.625% 02/2015 to 06/2018 24,431 25,097 6.3%

Federal National Mortgage Association .50 to 4.625% 10/2013 to 08/2021 78,677 80,532 20.2%

Federal Farm Credit Bank .235 to 1.08% 05/2013 to 02/2018 25,700 25,193 6.3%

U.S. Bank Money Market .04 to .10% Various 4,421 4,421 1.1%

U.S. Treasury Note .25 to 4.625% 03/2014 to 02/2018 122,915 122,874 30.9%

Corporate Issues .30 to 6.375% 07/2013 to 06/2018 72,595 74,873 18.8%

Certificates of Deposits .25 to .45% 13-Jul 17,794 17,794 4.5%

Total Portfolio 398,472

1974 Sinking Fund – Principal

U.S. Bank Money Market 0.040% 13-Jul 569 569 100.0%

Total Portfolio 569

Sinking Fund - Capitalized Interest

Federal Home Loan Mortgage Corporation .625 to .75% 11/2014 to 20/2014 1,800 1,808 3.9%

Federal National Mortgage Association .75 to 4.625% 10/2013 to 12/2014 7,530 7,586 16.3%

U.S. Bank Money Market 0.100% 08/2013 to 09/2013 2,268 2,268 4.9%

Municipal Issues .30 to 6.875% 07/2013 to 01/2015 49,750 50,182 108.2%

Corporate Issues 0.438% 13-Nov 500 500 1.1%

Total Portfolio 62,344

1974 PREPA Client

Certificates of Deposits 4,759 100.0%

Total Portfolio 4,759

1974 Construction Fund

Other - Rural Electrification Administration (REA) 1,103 100.0%

Total Portfolio 1,103

$ 575,282

1501-1384337 52 I 000187 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

5. Restricted Assets (continued)

Credit Risk

Credit risk is the risk that an issuer of an investment will not fulfill its obligation to the holder of the investment. This is measured by the assignment of a rating by a nationally recognized statistical rating organization. The 1974 Trust Agreement limits investments in:

. Government obligations, which are direct obligations of or obligations whose principal and interest is guaranteed by the U.S. Government, or obligation of certain of its agencies or instrumentalities.

. Investment obligation of any of the states or territories of the United States or political subdivisions therefore (other than obligations rated lower than the three highest grades by a nationally recognized rating agency) and repurchase agreements with commercial banks fully secured by U.S. Government Obligations.

. Time deposits with GDB or the Authority’s Trustee under the 1974 Agreement or any bank or trust company member of the Federal Deposit Insurance Corporation having a combined capital and surplus of not less than $100 million.

. Self-insurance fund (sinking fund) and PREPA client fund are allowed to invest in corporate issues, with certain restrictions (40% of the total fixed income portfolio).

As of June 30, 2014, the Authority’s investments in Federal Home Loan Mortgage, Federal Home Loan Bank, Federal National Mortgage Association and Federal Farm Credit Bank and Freddie Mac were rated AA+ by Standard & Poor’s (S&P) and Aaa by Moody’s Investors Service.

Concentration Credit Risk

Concentration of credit risk is the risk of loss attributable to the magnitude of investment in a single issuer by five percent or more of total investment. The Authority’s investment policy does not contain a limitation to invest in the securities of single issuer. As of June 30, 2014, more than 5% of the Authority’s total investments are in Federal Home Loan Mortgage, Federal Home Loan Bank, Federal National Mortgage Association, Federal Farm Credit Bank, and Certificate of Deposits.

1501-1384337 53 I 000188 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

5. Restricted Assets (continued)

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates will adversely affect the fair value of an investment. Generally, the longer the maturity of an investment, the greater the sensitivity of its fair value to changes in market interest rates. Information about the sensitivity of the fair values of the Authority’s investment to market interest fluctuations is provided by the following tables that show the distribution of the investments by maturity as of June 30, 2014 and 2013 (in thousands):

June 30, 2014 Investment Maturities Investment Type Fair Value Less than 1 year 1-5 years More than 5 years Total

Federal Home Loan Mortgage Corporation $ 64,458 $ 1,804 $ 58,360 $ 4,294 $ 64,458 Federal Home Loan Bank 50,546 – 50,546 – 50,546 Federal National Mortgage Association 70,715 4,019 45,510 21,186 70,715 Federal Farm Credit Bank 51,981 – 46,211 5,770 51,981 Certificate of Deposits 310,694 310,694 – – 310,694 Other-REA Investment 1,105 – 1,105 – 1,105 US Treasury Note 57,638 – 57,638 – 57,638 US Treasury Bonds 4,206 4,206 – 4,206 US Bank Money Market 37,763 37,763 – – 37,763 Municipal Issues 14,489 14,184 305 – 14,489 Domestic Common Stocks 12,252 – 12,252 – 12,252 Corporate Issues 18,779 14,871 3,908 – 18,779 Total Investments $ 694,626

1501-1384337 54 I 000189 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

6. Utility Plant

As of June 30, utility plant consists of:

2014 2013 (In thousands)

Distribution $ 3,996,392 $ 3,770,419 Transmission 2,242,637 2,168,381 Production 2,830,980 2,764,986 Other production 1,534,943 1,472,402 Hydroelectric 139,266 136,182 General 1,465,866 1,563,236 Irrigation systems 34,824 34,324 Fiber Network 36,250 27,445 12,281,158 11,937,375 Less accumulated depreciation (6,422,226) (6,098,403) 5,858,932 5,838,972 Construction in progress 988,524 999,586 $ 6,847,456 $ 6,838,558

1501-1384337 55 I 000190 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

6. Utility Plant (continued)

Utility plant activity for the fiscal years ended June 30, 2014 and 2013 was as follows (in thousands):

2013 2014 Beginning Ending Balance Increases Decreases Transfers Balance

Utility plant $ 11,937,375 $ – $ (17,688) $ 361,471 $ 12,281,158 Construction work in progress 999,586 350,409 – (361,471) 988,524 Total utility plant, as restated 12,936,961 350,409 (17,688) – 13,269,682

Less: Accumulated depreciation (6,098,403) (341,511) 17,688 – (6,422,226) Total utility plant, net as restated $ 6,838,558 $ 8,898 $ – $ – $ 6,847,456

2012 2013 Beginning Ending Balance Increases Decreases Transfers Balance

Utility plant $ 11,703,301 $ – $ (14,345) $ 248,419 $ 11,937,375 Construction work in progress 863,970 384,035 – (248,419) 999,586 Total utility plant 12,567,271 384,035 (14,345) – 12,936,961

Less: Accumulated depreciation (5,768,095) (344,653) 14,345 – (6,098,403) Total utility plant, net $ 6,799,176 $ 39,382 $ – $ – $ 6,838,558

Construction work in progress at June 30, 2014 and 2013 consists principally of expansions and upgrades to the electric generation, distribution and transmission systems.

1501-1384337 56 I 000191 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

7. Defeasance of Debt

In prior years, the Authority has refunded in advance certain Power Revenue Bonds and other obligations by placing the proceeds of new debt in an irrevocable trust to provide for future debt service payments on such bonds. Accordingly, the trust accounts, assets, and liabilities for the defeased bonds are not included in the Authority’s financial statements. At June 30, 2014, $3.7 million of Power Revenue Bonds which remain outstanding were considered defeased.

8. Notes Payable

The following is a summary of notes payable as of June 30, 2014 (in thousands):

June 30, 2014

Effective Current Long-Term

Maturity Date Interest Rate Liabilities Debt Total

Notes payable, unrestricted:

Revolving line of credit of $250 million to finance

working capital Jan-15 7.25% $ 146,042 $ – $ 146,042

Revolving line of credit of $500 million to finance

working capital Aug-14 7.25% 549,976 – 549,976 Line of credit of $25 million to finance improvements

to Isabela Irrigation System Jun-18 7.00% (F) 743 – 743 Revolving line of credit of $100 million to fund

swap's collateral posting Dec-14 6.00% (F) 35,136 – 35,136

P.R. (ULTRACOM) Feb-23 3.25% (V) 842 6,452 7,294

PREPA Holdings (IT Solution) May-17 3.50% (F) 1,169 4,410 5,579

Total notes payable $ 733,908 $ 10,862 $ 744,770

______(V) – variable interest rate (F) – fixed interest rate

1501-1384337 57 I 000192 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

8. Notes Payable (continued)

The following is a summary of notes payable as of June 30, 2013 (in thousands):

June 30, 2013

Effective Current Long-Term

Maturity Date Interest Rate Liabilities Debt Total

Notes payable, unrestricted:

Line of credit of $64.2 million to fund payments required

under a settlement agreement with municipalities Jun-14 .70%+LIBOR (V) $ 9,700 $ – $ 9,700

Revolving line of credit of $250 million to finance working

Capital Oct-14 2.80%+LIBOR (V) 249,138 – 249,138

Revolving line of credit of $500 million to finance working

Capital Aug-14 2.25%+LIBOR (V) 495,242 – 495,242

Line of credit of $25 million to finance improvements to

Isabela Irrigation System Jun-18 7.00% (V) 743 – 743

P.R. (ULTRACOM) Feb-23 3.25% (F) 842 7,294 8,136

755,665 7,294 762,959

Notes payable, restricted:

Revolving line of credit of $100 million to fund

swap’s collateral posting 6,100 – 6,100

Total notes payable $ 761,765 $ 7,294 $ 769,059

______(V) – variable interest rate (F) – fixed interest rate

Short-term debt activity for the years ended June 30, 2014 and 2013 was as follows:

2014 2013 (In thousands)

Balance at beginning of year $ 761,765 $ 605,219 Proceeds and transfers from long-term debt 734,029 1,512,950 Payment of short-term debt (761,886) (1,356,404) Balance at end of year $ 733,908 $ 761,765

Notes payable – short-term: Unrestricted $ 733,908 $ 755,665 Restricted – 6,100 Total of notes payable $ 733,908 $ 761,765

1501-1384337 58 I 000193 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

9. Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at June 30, 2014 and 2013 were as follows:

2014 2013 (In thousands) Accounts payable, accruals, and withholdings in process of payment $ 836,640 $ 791,680 Additional accruals and withholdings: Injuries and damages and other 5,305 20,400 Accrued vacation and payroll benefits 57,301 56,179 Accrued sick leave and payroll benefits - exclusive of benefits to be liquidated after one year of approximately $114.5 million in 2014 and $122.4 million in 2013 30,628 31,576 Accrued compensation 9,484 26,432 Accrued pension plan contribution and withholding from employees: Employees’ Retirement System 19,096 18,054 Employees health plan 27,831 6,275 Contribution in lieu of taxes 572,385 323,622 Other accrued liabilities 27,720 26,810 $1,586,390 $ 1,301,028

10. Other Current Liabilities Payable from Restricted Assets

2014 2013 (In thousands)

Contract retainage $ 6,165 $ 7,173 Other liabilities 54,449 32,421 $ 60,614 $ 39,594

1501-1384337 59 I 000194 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt

At June 30, 2014 and 2013, long-term debt consists of:

2014 2013 (In thousands) Power Revenue Bonds payable: Publicly offered at various dates from 2002 to 2013, interest rates ranging from 2.5 to 7.25%, maturing to 2043 $8,526,710 $8,048,485 Plus unamortized premium/discount, net 141,715 170,427 Revenue bonds payable, net 8,668,425 8,218,912 Notes payable and bond anticipation notes 744,770 769,059 9,413,195 8,987,971

Less current portion of long-term debt: Notes payable from unrestricted assets 733,908 755,665 Notes payable from restricted assets – 6,100 Power revenue bonds 432,281 413,546 Total current portion of long-term debt 1,166,189 1,175,311 $8,247,006 $7,812,660

1501-1384337 60 I 000195 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Long-term debt activity for the years ended June 30, 2014 and 2013 was as follows:

2014 2013 (In thousands)

Long-term debt excluding current portion at beginning of year $ 8,987,971 $ 9,042,843 New issues: Power revenue bonds 673,145 – Debt discount on new bond issues, net (14,806) – Notes payable 1,709,900 1,501,656 11,356,210 10,544,499 Payments: Power revenue bond – July 1 (194,920) (185,605) Notes payable (1,734,188) (1,356,411) Total payments (1,929,108) (1,542,016)

Amortization of debt discount (13,907) (14,512) Balance at end of year $ 9,413,195 $ 8,987,971

Current portion of notes payable $ 733,908 $ 761,765 Current portion of power revenue bonds 432,281 413,546 Total current portion of long-term debt $ 1,166,189 $ 1,175,311

1501-1384337 61 I 000196 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Power Revenue Bonds Payable

During fiscal year 2014, the Authority issued its Power Revenue Bonds, Series 2013A. A summary of the net proceeds of the Power Revenue Bonds, Series 2013A and the application of the proceeds follows (in thousands):

Sources: Principal amount of the bonds $ 673,145 Net original issue discount (10,502) Total sources $ 662,643

Application of net proceeds: Deposit to 1974 Construction Fund $ 500,000 Deposit to 1974 Reserve Account 46,439 Payment of line of credit and accrued interest 109,647 Underwriting discount and estimated legal, printing and other financing expenses 6,557 Total application of proceeds $ 662,643

Maturities of the Power Revenue Bonds Series 2013A, issued during fiscal year 2014 range July 1, 2030 to July 1, 2043. The Series 2013A bear fixed interest rates ranging from 6.75% to 7.25%. Interest on the Series 2013A is payable on the first day of each July and January.

The Authority has issued Power Revenue Bonds pursuant to the 1974 Agreement principally for the purpose of financing the cost of improvements; as such term is defined in the 1974 Agreement, and subject to the conditions and limitations set forth therein.

In the 1974 Agreement, the Authority covenants to fix, charge, and collect rates so that revenues will be sufficient to pay current expenses and to provide the greater of (i) the required deposits or transfers under the Sinking Fund, the 1974 Self-insurance Fund and the Reserve Maintenance Fund or (ii) 120% of the aggregate principal and interest requirements for the next fiscal year on account of all outstanding Power Revenue Bonds. See further discussion in Note 20.

1501-1384337 62 I 000197 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Power Revenue Bonds Payable (continued)

Gross revenues, exclusive of income on certain investments, less current expenses as defined in the 1974 Agreement have been pledged to repay Power Revenue Bonds principal and interest.

Bond Anticipation Notes

Bond anticipation notes (BANs) are used primarily to provide interim construction financing and are usually retired with the proceeds of long-term debt.

Swap Agreements

To protect against the potential of rising interest rates, the Authority entered into quarterly separate pay-fixed, receive-variable interest-rate, basis and commodity swap agreements at a cost anticipated to be less than what the Authority would have paid to issue fixed-rate debt. On June 30, 2014, the Authority had the following derivative instruments outstanding (in thousands):

Effective Maturity Counterparty Notional Item Type Objective Date Date Terms Credit Rating Amount

Pay-Fixed Interest Hedge of changes in cash flows on the Pay 4.08%; receive 67% A 5/3/2007 7/1/2029 Aa3/A+ $ 169,532 Rate Swap Series UU Bonds 3M LIBOR + 0.52% Pay-Fixed Interest Hedge of changes in cash flows on the Pay 4.08%; receive 67% B 5/3/2007 7/1/2029 Aa3/A+ 83,343 Rate Swap Series UU Bonds 3M LIBOR + 0.52% $ 252,875

1501-1384337 63 I 000198 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Swap Agreements (continued)

On June 30, 2013, the Authority had the following derivative instruments outstanding (in thousands):

Effective Maturity Counterparty Notional Item Type Objective Date Date Terms Credit Rating Amount

A Pay-Fixed Interest Hedge of changes in cash flows on the 5/3/2007 7/1/2017 Pay 4.014%; receive Aa3/A+ $ 25,525 Rate Swap Series UU Bonds 5Y SIFMA B Pay-Fixed Interest Hedge of changes in cash flows on the 5/3/2007 7/1/2018 Pay 4.054%; receive Aa3/A+ 17,000 Rate Swap Series UU Bonds 5Y SIFMA C Pay-Fixed Interest Hedge of changes in cash flows on the 5/3/2007 7/1/2020 Pay 4.124%; receive Aa3/A+ 29,055 Rate Swap Series UU Bonds 5Y SIFMA D Pay-Fixed Interest Hedge of changes in cash flows on the 5/3/2007 7/1/2025 Pay 4.232%; receive 67% Aa3/A+ 14,570 Rate Swap Series UU Bonds 3M LIBOR + 0.68% E Pay-Fixed Interest Hedge of changes in cash flows on the 5/3/2007 7/1/2029 Pay 4.08%; receive 67% Aa3/A+ 169,532 Rate Swap Series UU Bonds 3M LIBOR + 0.52% F Pay-Fixed Interest Hedge of changes in cash flows on the 5/3/2007 7/1/2031 Pay 4.286%; receive 67% Aa3/A+ 72,800 Rate Swap Series UU Bonds 3M LIBOR + 0.70% G Pay-Fixed Interest Hedge of changes in cash flows on the 5/3/2007 7/1/2029 Pay 4.08%; receive 67% A2/A 83,343 Rate Swap Series UU Bonds 3M LIBOR + 0.52% HBasis Swap Hedges tax risk on underlying fixed rate 7/1/2008 7/1/2037 Pay SIFMA; receive 62% A2/A 500,000 Go ldman bonds (various) and provides expected 3M LIBOR + 0.29% + Sachs positive cash flow accrual 0.4669% IBasis Swap Hedges tax risk on underlying fixed rate 5/10/2012 7/1/2037 Pay SIFMA; receive 62% A2/A 200,000 Deutsche bonds (various) and provides expected 3M LIBOR + 0.29% + Bank positive cash flow accrual 0.4669% J Basis Swap Royal Hedges tax risk on underlying fixed rate 5/10/2012 7/1/2037 Pay SIFMA; receive 62% Aa3/AA- 300,000 Bank of Canada bonds (various) and provides expected 3M LIBOR + 0.29% + positive cash flow accrual 0.4669% K Commodity Swap Hedge Fuel Cost 10/1/2012 10/1/2013 N.Y. Harbor No. 6 1% Aa3/A+ 1,675 JP Morgan Cargo L Commodity Swap Hedge Fuel Cost 7/1/2012 7/1/2013 N.Y. Harbor No. 6 1% A2/A 120 Macquire Bank Cargo M Commodity Swap Hedge Fuel Cost 10/1/2012 10/1/2013 N.Y. Harbor No. 6 1% Baa2/A- 225 Morgan Stanley Cargo N Commodity Swap Hedge Fuel Cost 7/1/2012 7/1/2013 N.Y. Harbor No. 6 1% Aa2/A+ 175 Scotiabank Cargo $ 1,414,020

1501-1384337 64 I 000199 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Swap Agreements (continued)

Derivative instruments A and B hedge changes in cash flows of the underlying bonds – floating rate notes with coupons based on 5-year SIFMA or 67% of 3-month LIBOR index, and maturities equal to the maturities of the corresponding swaps. As such they are considered hedging derivative instruments. The total fair value of these instruments as of June 30, 2014 is negative $48.9 million.

The following tables include summary information for the Authority’s effective hedges related to the outstanding swap agreements for fiscal years 2014 and 2013.

Changes in Fair Value Fair Value at June 30, 2014 Instrument Type Classification Amount Classification Amount Notional

Interest Rate Swap Deferred Outflows $ 22,106 Fair value of derivative instruments $ (48,864) $ 252,875 Basis Swap Investment income 7,612 Fair value of derivative instruments – – Commodity Swap Investment income 6,422 Fair value of derivative instruments – – Total $ 36,140 $ (48,864) $ 252,875

Changes in Fair Value Fair Value at June 30, 2013 Instrument Type Classification Amount Classification Amount Notional

Interest Rate Swap Deferred Outflows $ 37,468 Fair value of derivative instruments $ (70,970) $ 411,825 Basis Swap Deferred Outflows (4,743) Fair value of derivative instruments (7,612) 1,000,000 Commodity Swap Deferred Outflows (6,422) Fair value of derivative instruments (6,422) 2,195 Total $ 26,303 $ (85,004) $ 1,414,020

As of June 30, 2014 and 2013, negative fair values of the derivative instruments are $48.9 million and $85.0 million, respectively.

1501-1384337 65 I 000200 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Swap Agreements (continued)

Interest-Rate Swap Agreements

The terms, fair values and credit ratings of the outstanding interest-rate swaps as of June 30, 2014 and 2013, were as follows (in thousands):

Fair Value

Associated Power Effective Fixed

Maturity Date

Revenue Bonds 6/30/2014 Date Rate 2014 2013

Libor Bonds, Series UU $ 169,532 3-May-07 1-Jul-29 4.08% $ (32,835) $ (31,846)

Libor Bonds, Series UU 83,343 3-May-07 1-Jul-29 4.08% (16,029) (15,621)

Libor Bonds, Series UU – 3-May-07 1-Jul-25 4.23% – (2,441)

Libor Bonds, Series UU – 3-May-07 1-Jul-31 4.29% – (14,529)

Muni-BMS Bonds, Series UU – 3-May-07 3-Jul-17 4.01% – (2,071)

Muni-BMS Bonds, Series UU – 3-May-07 2-Jul-18 4.05% – (1,523)

Muni-BMS Bonds, Series UU – 3-May-07 1-Jul-20 4.12% – (2,939)

Total $ 252,875 $ (48,864) $ (70,970)

The notional amounts of the swaps match the principal amounts of the associated Power Revenue Bonds.

During fiscal years 2014 and 2013, the payments of fixed rate interest from the Authority exceeded the amount received as variable interest rate from swap counterparties by $15.7 million and $16.9 million, respectively.

Using rates as of June 30, 2014, debt service requirements of the variable-rate debt and net swap payments, assuming current interest rates remain the same for their term. These debt service requirements are included in the scheduled maturities of long-term debt disclosed further in this note. As rates vary, variable-rate bond interest payments and net swap payments will vary.

1501-1384337 66 I 000201 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Swap Agreements (continued)

Interest-Rate Swap Agreements (continued)

Fiscal Year Interest-Rate Ending June 30 Principal Interest Swap, Net Total (In thousands)

2015 $ – $ 2,108 $8,209$ 10,317 2016 – 2,108 8,209 10,317 2017 – 2,108 8,209 10,317 2018 – 2,108 8,209 10,317 2019 – 2,108 8,209 10,317 2020-2029 252,875 21,081 82,092 356,048 Total $ 252,875 $ 31,621 $123,137$ 407,633

On June 4, 2014, the Authority terminated $158.9 million in notional amounts with J.P. Morgan. Pursuant to the agreement the Authority paid $21.3 million in order to partially terminate the interest rate swap. As of June 30, 2014, the current outstanding notional amount of this swap is $252.9 million.

As of June 30, 2014 and 2013, the swaps had a negative fair value of approximately $48.9 million and $70.9 million, respectively. The negative fair value of the swaps may be countered by a reduction in future net interest payments required on the variable-rate Power Revenue Bonds, creating higher synthetic rates.

As of June 30, 2014 and 2013, the Authority was not exposed to credit risk because the swaps had a negative fair value. However, should interest rates change and the fair value of the swap become positive, the Authority would be exposed to credit risk in the amount of the derivative’s fair value. The swaps counterparties were rated A2 and Aa3 as issued by Moody’s Investor Services (Moody’s), AA- and A+ by Standard & Poors (S&P), and A and A+ by Fitch Ratings.

1501-1384337 67 I 000202 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Swap Agreements (continued)

Interest-Rate Swap Agreements (continued)

The derivative contract uses the International Swaps and Derivatives Association, Inc. Master Swap Agreement, which includes standard termination events, such as failure to pay and bankruptcy. The Authority or the counterparties may terminate the swaps if the other party fails to perform under the terms of the contracts. Also, the swaps may be terminated by the Authority if the counterparties’ credit quality rating falls below Baa1 as determined by Moody’s or BBB+ as determined by S&P. If at the time of termination the swap has a negative fair value, the Authority would be liable to the counterparty for a payment equal to the swap’s fair value.

Basis Swap Agreement

In March 2008 (with effective date of July 1, 2008), the Authority entered into a basis swap agreement in the notional amount of $1,375 million with an amortization schedule matching certain maturities of the Authority’s outstanding power revenue and revenue refunding bonds issued in various years from 2027 to 2037 (the 2008 basis swap). Under the terms of the Master Swap Agreement, the Authority receives from its counterparty (Goldman Sachs Capital Markets, L.P., an affiliate of Goldman, Sachs & Co.) quarterly, commencing on October 1, 2008, a floating amount applied to said notional amount at a rate equal to 62% of the taxable London Inter-Bank Offering Rate (LIBOR) index reset each week plus 29 basis points (hundredths of a percent) and a fixed rate payment of 0.4669% per annum (the “basis annuity”), quarterly for the term of swap in return for quarterly payments by the Authority, commencing also on October 1, 2008, on such notional amount at a rate based on the Securities Industry and Financial Markets Association (SIFMA) municipal swap index.

During the last quarter of fiscal year 2014, the Authority terminated the basis swap with a $1.0 billion notional amount that was outstanding. As agreed upon, the Authority paid $16.5 million to the counter party in order to terminate the basis swap.

The basis swap hedges the portion of the fair value of the underlying liabilities attributable to the relative value/basis risk between tax-exempt and taxable rates. Because of the tax-exemption, tax-exempt bonds trade at yields lower than taxable yields. The percent at which tax-exempt yields trade relative to taxable yields (UST or LIBOR) is referred to as MMD ratios or muni- bond ratios.

1501-1384337 68 I 000203 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Swap Agreements (continued)

Basis Swap Agreement (continued)

In order to assess effectiveness of the basis swap as a hedge, the Authority ran a regression of SIFMA ratios (as an independent variable) and MMD ratios (as dependent variable), adjusting to the specific circumstances. The result showed a high correlation. The method used can be qualified as Other Quantitative Method.

Because the MMD ratios and SIFMA ratios reflected respectively the change in the relationship of tax-exempt rates to taxable rates in the bond market and the SIFMA swap market, the Authority concluded that the regression showed that the SIFMA swap could effectively hedge the basis risk between tax-exempt and taxable rates and, therefore, the basis swap was considered an effective hedge instrument under GASB 53.

By using derivative financial instruments to hedge the exposure to changes in interest rates, the Authority exposes itself to credit risk, market-access risk and basis risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Authority, which creates a credit risk for the Authority. When the fair value of the derivative contract is negative, the Authority owes to the counterparty and, therefore, does not pose credit risk to the Authority. The Authority minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties whose credit rating is acceptable under the investment policies of the Authority and of GDB, its fiscal agent.

Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. The market risk associated with an interest rate swap contract is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Authority assesses market risk by continually identifying and monitoring changes in interest rate exposures that may adversely affect expected interest rate swap contract cash flows and evaluating other hedging opportunities. The Authority and GDB maintain risk management control systems to monitor interest rate cash flow risk attributable to both the Authority’s outstanding or forecasted debt obligations as well as the Authority’s offsetting hedge positions.

1501-1384337 69 I 000204 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Swap Agreements (continued)

Basis Swap Agreement (continued)

Basis risk arises when different indices are used in connection with a derivative instrument such as an interest rate swap contract. The 2008 basis swap exposes the Authority to basis risk should the relationship between LIBOR and the SIFMA municipal swap index converge. If a change occurs that results in the relationship moving to convergence, the expected financial benefits may not be realized. The Authority assesses basis risk by following the aforementioned market risks control system.

During fiscal years 2014 and 2013, the Authority received from its counterparty $4.7 million and $9.1 million, respectively. The following table shows the cash flow benefit of the basis annuity in exchange for the Authority taking tax and other basis risks tied to the change in the relationship between LIBOR and the SIFMA municipal swap index.

2014 2013 (In thousands)

Basis annuity received $ 1,167 $ 2,510 LIBOR index amounts received 3,869 8,188 SIFMA index amounts paid (300) (1,589) Net amount received $ 4,736 $ 9,109

According to the Credit Support Annex of the Master Swap Agreement, the Authority shall post eligible collateral on the next business day upon notification from its counterparty, if the fair value of the 2008 basis swap is negative and exceeds the threshold amount. This amount is determined by the Authority’s credit ratings with Moody’s Investors Service and Standard & Poor’s. Based on the Authority’s ratings, the collateral posting threshold is zero.

The Authority and GDB entered into an agreement for a $100 million revolving line of credit to meet collateral posting requirements from the 2008 basis and interest rate swaps. As of June 30, 2014, there was a $35.1 million outstanding balance in this line of credit. This balance is mainly related to the amounts paid under the termination agreements of the swap.

1501-1384337 70 I 000205 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Swap Agreements (continued)

Commodity Swap Agreement

During fiscal year 2012, the Authority entered into a 2012 Commodity Swap Agreement that provided it with protection against increases in the price of fuel of oil No. 6 covering contracts for 10.2 million barrels from June 2012 through October 2013. The notional amount of the swaps matches the barrel of fuel.

The premium amount established for this swap was $29.2 million, which was amortized from June 2012 to October 2013.

The Authority paid to its counterparties $6.4 million and $21.9 million for fiscal years 2014 and 2013, respectively. This derivative instrument expired in October 2013, as a result it had no outstanding balance as of June 30, 2014, and a negative fair value of $6.4 million as of June 30, 2013.

1501-1384337 71 I 000206 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

11. Long-Term Debt (continued)

Scheduled Maturities of Long-Term Debt

The scheduled maturities of long-term debt with interest thereon as of June 30, 2014, are as follows:

Fiscal Year Ending June 30, Principal Interest Total

2015 $ 1,152,623 $ 426,505 $ 1,579,128 2016 229,287 415,395 644,682 2017 238,207 403,730 641,937 2018 250,377 391,530 641,907 2019 262,355 378,923 641,278 2020-2024 1,525,286 1,682,360 3,207,646 2025-2029 1,895,140 1,268,457 3,163,597 2030-2034 1,458,545 829,573 2,288,118 2035-2039 1,381,460 446,711 1,828,171 2040-2043 878,200 107,127 985,327 Total 9,271,480 6,350,311 15,621,791 Less: Unamortized premium/discount, net 141,715 – 141,715 Interest – (6,350,311) (6,350,311) Total long-term debt 9,413,195 – 9,413,195

Current portion, net of discount (432,281) – (432,281) Current portion of notes payable (733,908) – (733,908) Total current portion (1,166,189) – (1,166,189) Long-term debt, excluding current portion $ 8,247,006 $ – $ 8,247,006

1501-1384337 72 I 000207 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

12. Employees’ Retirement Benefits

Pension Plan

Plan Description

All of the Authority’s permanent full-time employees are eligible to participate in the Authority’s Pension Plan, a single employer defined benefit pension plan (the Plan) administered by the Employees’ Retirement System of the Puerto Rico Electric Power Authority (the System). The System issues a publicly available financial report that includes financial statements and required supplementary information for the Plan. That report may be obtained by writing to the Retirement System of the Puerto Rico Electric Power Authority, PO Box 13978, San Juan, Puerto Rico 00908-3978.

Benefits include maximum retirement benefits of 75% of average basic salary (based on the three highest annual basic salaries) for employees with 30 years of service; with reduced benefits available upon early retirement. The Plan was amended on February 9, 1993 to provide revised benefits to new employees limiting the maximum retirement basic salary to $50,000. The plan was further amended in January 1, 2000 to provide improved retirement benefits to employees with 25 years or more of credited service. Disability and death benefits are also provided. Separation benefits fully vest upon reaching 10 years of credited service.

If a member’s employment is terminated before he becomes eligible for any other benefits under this Plan, he shall receive a refund of his member contribution plus interest compounded annually. The Plan is not subject to the requirements of the Employees Retirement Income Security Act of 1974 (ERISA).

Funding Policy and Annual Pension Cost

The contribution requirements of plan members and the Authority are established and may be amended by the Authority. The Annual Pension Cost (APC) and the Annual Required Contribution (ARC) were computed as part of an actuarial valuation performed as of June 30, 2013 and projected to June 30, 2014, based on current year demographic data.

1501-1384337 73 I 000208 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

12. Employees’ Retirement Benefits (continued)

Funding Policy and Annual Pension Cost (continued)

The contribution requirements to the System of plan members and the Authority are established and may be amended by the Authority. The Authority’s annual pension cost to the System for the fiscal years ended June 30, 2014 and 2013 is as follows:

Fiscal Year Ending June 30 2014 2013

Annual required contribution $ 99,971,184 $ 89,405,009 Interest on net pension obligation 1,276,170 1,249,465 Adjustment to annual required contribution (972,705) (935,293) Annual Pension Cost 100,274,649 89,719,181

Contributions made and accruals (99,971,184) (89,405,009) Increase (decrease) on net pension obligation 303,465 314,172

Net pension obligation, beginning of year 15,013,760 14,699,588 Net pension obligation, end of year $ 15,317,225 $ 15,013,760

1501-1384337 74 I 000209 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

12. Employees’ Retirement Benefits (continued)

The Authority’s annual pension cost for the year ended June 30, 2014 and related information for the Plan and supplemental benefits follows:

Pension Plan

Contribution rates:

Authority 29.29%

Average Plan members 10.44%

Annual pension cost (thousands) $100,275

Contributions made and accruals (thousands) $99,971

Actuarial valuation date 6/30/2012

Actuarial cost method Individual: Entry Age Normal

Amortization method Level percentage of pay, closed

(4% payroll increases per year)

Remaining amortization period 28 years

Asset valuation method 5-year smoothed market

Actuarial assumptions:

Investment rate of return (net of

administrative expenses)* 8.5%

Projected salary increases* 4.10% – 5.40% depending on age

*Includes inflation at 3.0%

Cost-of-living adjustments 8% per year for yearly pension up

to $3,600 and 4% per year for

yearly pension between $3,600

and $7,200, 2% per year for

yearly pension in excess of

$7,200. The minimum

adjustment is $300 per year. The

maximum is $600 per year.

1501-1384337 75 I 000210 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

12. Employees’ Retirement Benefits (continued)

Supplemental Benefits not Funded Through the System

Trend Information (In millions) Annual Percentage Pension of APC Net Pension Fiscal Year Ended Cost (APC) Contributed Obligation

Pension Plan: 06/30/12 84.6 99.6% 14.7 06/30/13 89.7 99.7% 15.0 06/30/14 100.3 99.7% 15.3

The annual required contribution amounted to $100.0 million and $89.4 million in 2014 and 2013, respectively. The net pension obligation is included in accounts payable and accrued liabilities in the Statements of Net Position.

Supplemental benefits were unfunded and such benefits were reimbursed to the System when paid as of December 31, 1999. Effective January 1, 2000, the Board of Trustees of the System approved the transfer of the obligation for supplemental benefits provided by the Authority and not funded through the System (supplemental pension obligations exchanged for forfeited sick leave benefits and the supplemental spousal survivor benefits) to the Retirement System. Also, the Board of Trustees of the System accepted an amortization period for the Plan of 40 years, which commenced on June 30, 1996.

1501-1384337 76 I 000211 No. CEPR-AP-2015-0001

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Notes to Audited Financial Statements (continued)

12. Employees’ Retirement Benefits (continued)

Supplemental Benefits not Funded Through the System (continued)

Supplemental Pension Obligations Exchanged for Forfeited Sick Leave Benefits

The Authority’s employees with over 20 years of service are entitled to exchange accrued sick leave for supplemental pension benefits just to complete merit annuity (30 years of service) and/or be paid in cash the value of such sick leave upon separation from employment.