GUIDE QUESTIONS AND ANSWERS ON ENERGY
29 August 2017
Compiled by:
Consumer Welfare and Promotion Office
Table of Contents
FOSSIL FUELS ...... 1
OIL AND GAS ...... 1
1. Why is there a need to explore for Oil and Gas resources? ...... 1 2. What is a seismic survey and how is it conducted? ...... 1 3. What is exploration drilling and why is it important? ...... 3 4. How are seismic surveys and exploration drilling permitted in the Philippines? ...... 3 5. How does an exploration company become the contractor of an SC and what activities does it have to perform? ...... 4 6. Is the DOE/Service Contractor's project covered by relevant environmental clearances? ...... 4 7. Are Local Government Units (LGUs) and Non-Governmental Organizations (NGOs) consulted on the Project? ...... 5 8. What are the benefits of the project for the local communities? ...... 5 9. When will LGUs share in the benefits of commercial resource extraction? ...... 5 10. What are the fiscal terms in the Philippines? ...... 6 11. What is the historical production of oil and gas? ...... 7 12. How many Service Contracts are currently being supervised and monitored by DOE?...... 8
COAL ...... 9
13. Where are the country's coal deposits and coal mines? ...... 9 14. How much is local coal production to date? ...... 9 15. What is the current coal demand/consumption? ...... 10 16. What is the Philippines' coal potential? ...... 10 17. Does the Philippines have high-quality coal? ...... 10 18. What programs are being undertaken by the department to spur coal exploration and development activities? ...... 11 19. What are the investment opportunities in the coal sector? ...... 11 20. How many Coal Operating Contracts (COCS) do we have in the Philippines? ...... 12 21. What are the incentives under the Coal Operating Contract (COC) system? ...... 12 22. How does coal use affect the environment and what are the mitigating measures? ...... 12 23. How do you plan to address mounting opposition to coal? ...... 13
RENEWABLE ENERGY ...... 14
RENEWABLE ENERGY ...... 14
24. What is Renewable Energy? ...... 14 i
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25. What is the state policy on Renewable Energy? ...... 14 26. What are the salient provisions of the 2008 RE law? ...... 14 27. What are the incentives being offered under RE law? ...... 15 28. What are the economic benefits in the RE law? ...... 16 29. How does RE become administratively feasible? ...... 16 30. Is RE politically feasible? ...... 16 31. Is there any study that the DOE has conducted that quantifies the losses and gains of the proposed measures or policy interventions that make the proposed incentives RE necessary for public good? ...... 17 32. The proposed measures are based on policies being implemented in Europe. Is there any study that reports the effectiveness of such policy measures? ...... 17 33. What about the impact of proposed measures to the rates of electricity? What will offset such impact? ...... 18 34. How many RE contracts have been awarded so far? And how much potential and installed capacities were incurred? ...... 18 35. What is Feed-in Tariff (FIT)? ...... 19 36. Why do we need the FIT? ...... 19 37. What are the rules governing the FIT system? ...... 19 38. What is “installation target”? And why do we need it in the FIT system? ...... 19 39. What is FIT rate? ...... 19 40. What is FIT-ALL? ...... 20 41. How is FIT-ALL calculated? ...... 20 42. What are the latest approved FIT rates? ...... 20 43. How to be FIT eligible RE Project? ...... 21 44. What is the FIT implementation process? ...... 21 45. What is Net Metering? ...... 21 46. Why is Net Metering an important incentive? ...... 21 47. How Net Metering works?...... 22 48. What is a typical Net Metering set-up? ...... 22 49. What types of power generating facilities are eligible for Net Metering? ...... 22 50. What benefit will I get if I go into Net Metering? ...... 22 51. What is the optimum size of an RE facility that I can install in my premises?...... 23 52. How can you apply for Net Metering services with your distribution utility? ...... 23
GEOTHERMAL ENERGY ...... 24
53. What is Geothermal Energy? ...... 24 54. What elements compose a geothermal system? ...... 24 ii
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55. What are the different manifestations of a geothermal system? ...... 25 56. How is geothermal resources being studied, developed and utilized as an energy source? ...... 25 57. How does a geothermal power plant differ from other power plants? ...... 25 58. Can a geothermal operation cause a volcanic eruption? ...... 26 59. What are the investment opportunities in the geothermal sector? ...... 26 60. What are the incentives under the Geothermal Service Contract System? ...... 26 61. What are the possible direct-use application in the Philippines? ...... 27 62. Why is Geothermal not included in the Feed-In-Tariff (FIT)? ...... 27 63. What is Renewable Energy Safety, Health and Environment Rules and Regulations (RESHERR)? ...... 28 64. What is the Department’s Position on the Issues being raised by Concerned Non-governmental Organization (NGOs)? ...... 28 65. How to avail additional investments for RE projects? ...... 30
HYDROPOWER ...... 30
66. What is a hydroelectric power resource? ...... 30 67. What is a hydroelectric power system? ...... 30 68. How are hydropower resources developed? ...... 31 69. What are the major components of a hydropower facility? ...... 31 70. What are the procedures in the development and operation of a hydropower facility/ (ies)? ...... 31 71. What are the documentary requirements for Service Contracts? ...... 32 72. How much is the investment requirement for hydropower project? ...... 33 73. Can a foreigner invest in hydropower projects? ...... 33 74. Are there any successful hydropower projects in the Philippines? ...... 33
BIOMASS ...... 33
75. What are biomass resources? ...... 33 76. What are the major biomass resources in the Philippines? (Source: Biomass Atlas of the Philippines 2000) ...... 34 77. What are the uses and availability of biomass resources in the country? ...... 36 78. What is the present capacity of biomass power plants and future capacity addition? ...... 37 79. Biomass Resource Assessment in the Philippines ...... 37
WIND RESOURCE ASSESSMENT PROGRAM (WRAP) ...... 38 iii
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80. What is Wind Resource Assessment Project (WRAP)? ...... 38 81. What is the project’s legal basis? ...... 39 82. What are the project’s major activities? ...... 39 83. What is the source of project funds? ...... 42 84. What are the criteria in the identification of project sites? ...... 42 85. What is the implementation strategy of the project? ...... 43 86. Since project inception, how many sites are/were assessed? ...... 44 87. What are the causes of delays encountered and the corresponding corrective measures undertaken? ...... 47 88. Who are the intended end-users of wind data? ...... 48
SOLAR AND WIND ENERGY ...... 48
89. What is Wind Resource Assessment Project (WRAP)? ...... 48 90. What is the project’s legal basis? ...... 49 91. What are the project’s major activities? ...... 50 92. What is the source of Project Funds?...... 52 93. What are the criteria in the identification of project sites? ...... 52 94. What is the implementation strategy of the Project? ...... 53 95. Since project inception, how many sites are/were assessed? ...... 54 96. What are the causes of delays encountered and the corresponding corrective measures undertaken? ...... 55 97. Who are the intended end-users of wind data? ...... 56 98. What is Household (Sitio) Electrification Program (HEP)? ...... 56 99. What is the legal basis? ...... 57 100. What are the criteria used in identifying project beneficiaries/areas under the HEP? ...... 57 101. What is the financing source of HEP projects? ...... 58 102. What is the implementation mechanism/institutional arrangement being adopted for HEP? ...... 58 103. What is the approval process for Expanded Rural Electrification (ER) Projects? ...... 59 104. Since its inception in 1999 how many Barangays have been implemented under the previous Barangay Electrification Program? ...... 60 105. What are the causes of delays/slippages? ...... 60 106. What were the corrective measures implemented by DOE- REMB? ...... 60 107. Since its inception in 1999 how much funds have already been allocated for the BEP? ...... 61 108. How much funds are proposed/allocated for HEP project and how many households are targeted for energization from 2010 to 2016? ...... 61
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109. How many households under the HEP were energized from 2011 to 2015? ...... 62 110. What is an Affiliated Renewable Energy Center (AREC)? ...... 62 111. What is the legal basis? ...... 62 112. What is the source of Project Funds?...... 63 113. What are the criteria in the establishment of AREC? ...... 63 114. What are the major activities of the AREC? ...... 63 115. What is the implementation arrangement of AREC Project? ...... 64 116. What are the State Universities and Colleges / Private Academic Institutions involved in the implementation of AREC project? ...... 65
ELECTRIC POWER INDUSTRY ...... 66
COMPETITIVE SELECTION PROCESS ...... 66
117. What is Competitive Selection Process (CSP)? ...... 66 118. What is the DOE’s policy on CSP? ...... 66 119. What are the salient features of DOE Department Circular No.2015-06-0008? ...... 66 120. What are the ERC issuances relating to CSP? ...... 66 121. What is the status of the CSP Implementing Guidelines (IG)? ...... 68 122. How is CSP implemented in off-grid areas? ...... 68 123. What are the salient features of DOE Department Circular 2004-01-001? ...... 69 124. What is the ERC issuance/s on CSP for off-grid areas? ...... 69 125. What is the status of the PSP program in off-grid areas? ...... 70 126. WHAT ARE NEW DEVELOPMENTS IN ENHANCING AND UPDATING CSP POLICIES? ...... 70
POWER DEVELOPMENT PLAN ...... 72
127. Why is there a need to prepare the Power Development Plan after the passage of EPIRA? ...... 72 128. What is the difference of the PDP before and after EPIRA? ...... 72 129. What is Peak demand, Co-incident peak demand and Non- coincident demand? ...... 73 130. What are the approaches being done by DOE in forecasting demand? ...... 73 131. When do we say that there is a power shortage? ...... 74 132. What are the considerations in coming up with the additional capacity requirement? ...... 76 133. What are the total committed and indicative capacities for Luzon, Visayas, and Mindanao? ...... 76 134. What is baseload, mid-range and peaking plants? ...... 77 v
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POWER GENERATION ...... 78
135. What are the major sources of power in the country? ...... 78 136. How much electricity is produced by fossil fuel and Renewable Energy? ...... 79 137. How much electricity is produced using local fuel against imported fuel? Or the country’s self-sufficiency level for power generation? ...... 80 138. What sector consumed most of the electricity? ...... 80 139. How much is the increase in electricity demand in 2015 from 2014 and 2016 from 2015? ...... 81
TRANSMISSION ...... 82
140. What is the National Transmission Corporation (TRANSCO)? ...... 82 141. What is the National Grid Corporation of the Philippines (NGCP)? ...... 82 142. What is Transmission Development Plan (TDP)? ...... 83 143. Who prepares the TDP? ...... 83 144. What is DOE’s responsibility on the TDP? ...... 83 145. How is the TDP prepared? ...... 83 146. What are the major sections of the TDP? ...... 84 147. What are the Major Drivers for Transmission Project Development? ...... 85 148. What is the status of the Visayas-Mindanao Interconnection Project (VMIP)? ...... 85 149. What is the Status of the proposed Batangas-Mindoro Interconnection Project (BMIP)? ...... 86
DISTRIBUTION ...... 86
150. What is a Distribution Development Plan? ...... 86 151. What is the legal basis of the DDP? ...... 86 152. What are the DOE issuances on DDP? ...... 86 153. What are the contents of the DDP? ...... 87 154. What is the DOE’s responsibility on the DDP under the EPIRA? ...... 87 155. What is NEA’s responsibility on the DDP under the EPIRA? ...... 87 156. What is the importance of the DDP in the PDP? ...... 87 157. What is a distribution utility? ...... 88 158. What is a distribution system? ...... 88 159. What are the types of distribution utilities? ...... 88 MISSIONARY ELECTRIFICATION DEVELOPMENT PLAN (MEDP) ...... 89
160. What is missionary electrification? ...... 89 vi
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161. What are off-grid systems/areas? ...... 89 162. What Is A Missionary Area? ...... 89 163. What is an unviable area? ...... 89 164. Who performs missionary electrification function? ...... 89 165. What is Missionary Electrification Development Plan (MEDP)? ...... 89 166. Where do missionary electrification funds come from? ...... 90 167. What is Missionary Electrification Universal Charge (UC-ME)?...... 90 168. Why is Private Sector Participation (PSP) encouraged in off- grid/unviable areas? ...... 90
EPIRA REFORM ...... 90
169. What is Retail Competition and Open Access (RCOA)? ...... 90 170. What are the main reasons behind RCOA? ...... 91 171. When was the initial commercial operation of RCOA? ...... 92 172. What is the status of commercial operation of RCOA to date? ...... 92 173. Who are the ERC Registered Retail Electricity Suppliers (RES)? ...... 93 174. Who are the ERC Registered Local Retail Electricity Suppliers? ...... 93 175. Was the EPIRA a result of an outcry for a cheaper electricity rate? ...... 94 176. What is the Electric Power Industry Reform Act of 2001 (R.A. 9136)? ...... 94 177. With RA 9136 in place, what reforms were instituted in the power industry? ...... 95 178. With restructuring, will the power industry be fully deregulated? ...... 96 179. How can government ensure that consumers will be protected from undue and frequent increases in power rates? ...... 96 180. Are there any safeguards in the law to prevent certain business groups or blocs from dominating the restructured power industry? ...... 97 181. What are the safety nets for the avoidance of "sweetheart" deals? ...... 97 182. What guides the sale schedule of the NPC generating plants? ...... 97 183. What is the status of the privatization of NPC generation assets in Luzon and Visayas? ...... 98 184. What is the schedule for privatization? ...... 100 185. What is the status of the transfer of the contracted energy outputs of NPC-IPPS to IPP administrators? ...... 101 186. Why was privatization started only in 2004 when the EPIRA was enacted in 2001? ...... 103 187. When was TransCo bidded out? ...... 103 188. What is the status of TransCo’s privatization? ...... 104
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189. What is the status of the sale of TransCo sub-transmission assets? ...... 104 190. How can the government ensure that the proceeds from the sale of NPC assets will be optimized? ...... 105 191. What is the current status of the power sector’s financial obligation to date? ...... 106 192. In terms of currency denomination, what composes the power sector loans?...... 106 193. What is the present status of electricity rates? ...... 107 194. What are the government’s initiatives to shield the marginalized from the high cost of electricity? ...... 107 195. What is the status of Universal Charges? ...... 108 196. What is the status of the condonation of loans of all electric cooperatives? ...... 109 197. What are the challenges for the continuing implementation of power sector reforms? ...... 109
WESM ...... 114
198. What is the Wholesale Electricity Spot Market (WESM)? ...... 114 199. What is the legal basis for the WESM? ...... 115 200. What benefits can be derived from the WESM? ...... 115 201. What is the governance structure for the WESM? ...... 116 202. What are the WESM rules? ...... 116 203. What are the key features of WESM? ...... 117 204. Who operates the WESM? ...... 117 205. Who can participate in the WESM? ...... 118 206. What are the membership requirements to participate in the WESM? ...... 118 207. What is the advantage of being a registered member of the WESM? ...... 118 208. How do generators compete in the WESM? ...... 118 209. How do customers compete in the WESM? ...... 119 210. How are dispatch schedules and spot prices determined in the WESM? ...... 119 211. What is the purpose of having a look-ahead projection? ...... 119 212. How is the look-ahead projection conducted? ...... 120 213. How are bilateral contracts dispatched in the WESM? ...... 120 214. Are we doing away with long-term contracts? ...... 120 215. How will the WESM provide the correct market signal to prospective investors? ...... 121 216. How will the WESM affect electricity rates? ...... 121 217. What are the safeguards in the WESM that assure competition and level-playing field among participants? ...... 121 viii
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218. How are ancillary services costs determined? ...... 123 219. What are Financial Transmission Rights (FTRS)? ...... 124 220. What is the difference between FTRS and wheeling charges? ...... 124 221. What has been done in preparation for the commencement of WESM operation? ...... 124 222. What benefits can be derived from the WESM? ...... 126 223. What is Independent Market Operator (IMO)? ...... 128 224. What is the legal basis for the establishment of the IMO? ...... 128 225. What are the requirements for the IMO? ...... 129 226. Does the PEMC qualify to be the IMO? ...... 129 227. What is the governance structure for the WESM? ...... 130 BENEFITS TO HOST COMMUNITIES PURSUANT TO ENERGY REGULATIONS 1-94, AS AMENDED FREQUENTLY ASKED QUESTIONS ...... 130
228. Legal and operational bases ...... 130 229. What is Energy Regulations (ER) 1-94? ...... 131 230. What are the policy objectives of ER 1-94? ...... 131 231. What is the scope of ER 1-94? ...... 131 232. Who are the direct beneficiaries under ER 1-94? ...... 132 233. When do LGUs or regions considered as ‘host” under ER 1-94? ...... 132 234. What is the nature of benefits under ER 1-94? ...... 132 235. How is the P0.01 per kWh financial benefits distributed or allocated to EF, DLF and RWMHEEF? ...... 133 236. How can the host LGUs/Region avail of the benefits under DLF and RWMHEEF? ...... 134 237. How can the ‘Host Community” avail of EF under the program? Is the process of availment is the same as under the DLF and RWMHEEF? ...... 136 238. What happens to the interest earnings from the three (3) trust funds? ...... 137 239. What agency establishes, administers, and monitors the EF, DLF, and RWMHEEF? ...... 137 240. What is the common cause/s of delays in the approval/implementation of projects? ...... 138 241. Can generation companies and/or energy resource developers advance financial assistance to the concerned host community? ...... 138 242. How can the generation companies and/or energy resource developers be engaged in the ER 1-94 Program of DOE? ...... 139
QUALIFIED THIRD PARTY ...... 139
243. What is a Qualified Third Party (QTP)? ...... 139 ix
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244. What are remote and unviable areas? ...... 139 245. What are “waived” areas? ...... 139 246. What is the legal basis for QTPs? ...... 139 247. What is DOE’s policy on QTP participation? ...... 140 248. What are the eligibility criteria for QTP participation? ...... 140 249. Are there limitations on pre-qualification (accreditation) of QTPs? ...... 141 250. How can an entity become a QTP? What is the proposed QTP process? ...... 142 251. What will happen to the existing informal service providers (ISPs) currently operating in the unviable areas of the DUs? ...... 143 252. What are the rights and obligations of QTPs? ...... 143 253. What will be the role of ERC, DOE and DUs in the QTP implementation and operations? ...... 144 254. Will these QTPs also receive subsidy from the government? ...... 146 255. What is the status of QTP implementation? ...... 146 NATIONWIDE INTENSIFICATION OF HOUSEHOLD ELECTRIFICATION (NIHE) 2015-2017 (GRANT ASSISTANCE FUNDS) ...... 148
256. What are the legal and operational bases? ...... 148 257. What is Nationwide Intensification of Household Electrification (NIHE) program? ...... 149 258. What is the policy objective of NIHE?...... 149 259. Who are the co-operating agencies involve in the implementation of NIHE? ...... 149 260. What are the expected work and financial outputs? ...... 150 261. Who are the direct beneficiaries under NIHE? ...... 150 262. What is the nature of grant subsidy under NIHE? ...... 150 263. What is NIHE’s implementation scheme? ...... 151 264. What is the flowchart of implementation procedure for the project? ...... 153
DOWNSTREAM OIL INDUSTRY ...... 154
265. How many new players are there in the Philippines at present? ...... 154 266. Market shares of oil players (YTDDecember2016) ...... 154 267. LPGMarket Share (YTD December 2016) ...... 154 268. How many active gasoline stations are there in the Philippines at present? ...... 154 269. What do we pay for a liter of gasoline? ...... 155 270. What do we pay for a liter of diesel? ...... 155 271. What do we pay for a liter of kerosene? ...... 156 x
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272. What is downstream oil deregulation? How does it affect the current pricing of petroleum products? ...... 156 273. What are the features of RA 8479? ...... 156 274. What are the prevailing petroleum product prices?Did the Philippines rush into deregulation without proper/enough transition? ...... 157 275. What are the benefits of deregulation to the average consumers/commuters? ...... 158 276. In the wake of rising oil prices, is the government considering re-establishing a subsidy mechanism, similar to the OPSF implemented during the 1980s? ...... 159 277. What are the mitigating measures of the government to cushion the impact of rising oil prices? ...... 159 278. In the midst of escalating oil prices, is the country assured of enough supply? Do we have contingencies should there be shortage in supply (e.g., rationing, coupons, etc.)? ...... 161 279. How can the government assure the public that the oil companies are not taking advantage of the high-price situation at the expense of the consuming public? ...... 162 280. Why did Caltex, after more than 85years of Operation in the Philippines, pull out its Refining Operation? Does It indicate dampened investor interests in the country’s Downstream Oil Industry? ...... 165 281. Aren’t oil refining companies required to go public under RA8479? Why are Shell and Caltex not yet listed even after more than 17 years of oil deregulation? ...... 165 282. What is the DOE’s opinion on the bills amending/ repealing oil deregulation law? ...... 166 283. On Liquid Fuels and Liquified Petroleum Gas, What is the total number of LPG refilling plants nationwide? ...... 166 284. What is DC no. 2000-06-010? ...... 166 285. What are the offenses and corresponding penalties in the DC 2000-06-010? ...... 167 286. Have there been instances when LPG players were penalized? ...... 168 287. What is EO 655? ...... 168 288. How many LPG establishments were inspected in 2015? What are the violations seen in the cylinders? ...... 168 289. What is the government doing to ensure the safety of consumers, specifically the households? What is the government’s program to curb the proliferation of underfilled, unsafe and substandard LPG cylinders? ...... 169 290. What are the administrative fines/sanctions against prohibited acts in D.C. on Auto-LPG? ...... 169 xi
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291. How many Auto-LPG dispensing stations are there in the country? ...... 169 292. What percentage is the compliance to PNS, biofuels law and clean air act of gasoline stations as of December 2015? ...... 170 293. Are there any instances that violators were apprehended under the retail rules? ...... 170 294. What is the concept of the Gasoline Station Lending and Financial Assistance Program (GSLFAP)? ...... 171 295. With the implementation of Republic Act (RA) no. 9367, also known as the "Biofuels Act of 2006”, what are the sources and volumes of imported ethanol for the bioethanol program? ...... 171 296. What are the Department Circulars issued relative to the implementation of "Biofuels Act of 2006”? ...... 171 297. What is the impact of the current tax proposals to the domestic oil prices? ...... 172
DOWNSTREAM NATURAL GAS ...... 173
298. What is the legal basis for the natural gas program? ...... 173 299. What are the current uses of natural gas in the country? ...... 174 300. What are the proposed projects for the natural gas industry? ...... 174 301. What is banked gas? Is there a possibility of using banked gas to spur development in the natural gas industry? ...... 175 302. Is Natural Gas, LNG, or CNG Safe to Use? ...... 176 303. Are there differences between LPG, LNG, and CNG? ...... 177 304. What are the comparative energy prices? ...... 179 305. How much has been collected by the government from the Malampaya Project? ...... 179 306. What is the basis of the 40% contractor’s share? ...... 180 307. In computing income tax, why do you have to divide the 40% contractor’s share to 70%? ...... 180 308. Why is the income tax of the contractor taken from the 60% government share? ...... 180 309. How much is the 40% projected source of LGU share for 2017 to 2019? ...... 180 310. How much is the projected net national government share for 2017 to 2019? ...... 180 311. What was the cost recovery rate used for each year in the projection of government share? ...... 181 312. How much was the collected government share for the period January 1 to March 31, 2017? ...... 181
ENERGY UTILIZATION ...... 182 xii
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THE ALTERNATIVE FUELS PROGRAM ...... 182
313. What is the significance of the alternative fuels program? ...... 182 314. What are the benefits of using alternative fuels? ...... 182 315. What programs are currently being implemented relative to alternative transport fuels development? ...... 182 316. Are there other initiatives being pursued aside from the programs mentioned above? ...... 182 THE NATURAL GAS VEHICLE PROGRAM FOR PUBLIC TRANSPORT (NGVPPT) ...... 183
317. What is Natural Gas? ...... 183 318. What are the advantages / benefits of using Natural Gas as fuel for transport? ...... 183 319. Why is it called “pilot project”? ...... 183 320. How promising is this CNG pilot project? Will it be the first step to energy self-sufficiency of the country? ...... 184 321. What is the extent of participation of the private sector in the pilot phase of the NGVPPT? ...... 184 322. How much is the investment being undertaken for the pilot project? ...... 185 323. Are there plans to expand the project’s coverage? ...... 185 324. How is the price of CNG per liter compared to Diesel? ...... 185 325. What is the extent of the users/bus driver’s training on CNG technical aspects and safety measures? ...... 185 326. What are the details of the CNG refilling station under the Pilot Project? ...... 185 327. What is the Status of the NGVPPT ...... 186 328. Which government agencies and private companies collaborate with the DOE in the CNG pilot project? ...... 186
THE AUTOLPG PROGRAM ...... 187
329. What is AutoLPG? ...... 187 330. What is the role of DOE in the AutoLPG Program? ...... 187 331. Is there an Available Technology for AutoLPG in the Market? ...... 188 332. What are the Benefits of Using AutoLPG? ...... 188 333. What is the current status on the use of LPG for vehicles in the Philippines? ...... 188 334. What is the number of vehicles fuelled by LPG in the Philippines? ...... 189 335. What are the incentives to promote the use of LPG in vehicles? ...... 189
336. What standards have been adopted or formulated to guide the xiii
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use of AutoLPG? ...... 189
THE ELECTRIC VEHICLES (EVS) PROGRAMS ...... 190
337. What is an Electric Vehicle? ...... 190 338. What are the benefits of driving an EV? ...... 190 339. Are EVs available in the market? ...... 190 340. How many potential local EV suppliers are there? ...... 191 341. Are EVs already in use locally? ...... 191 342. Is there a government initiative promoting the use of EVs in the Philippines? ...... 192 343. What is the status of the E-Trike Project (as of March 15, 2017)? ...... 193 344. Is there a DOE standard for E-Trikes? ...... 194 345. Is there a government policy on the use of EVs in the Philippines? ...... 194
ENERGY EFFICIENCY AND CONSERVATION ...... 195
346. What is Energy Efficiency? What is Energy Conservation? ...... 195 347. What is Minimum Energy Performance Standard? ...... 195 348. What is an ESCO? ...... 195 349. What is Green Building? ...... 195 350. What is the National Energy Efficiency and Conservation Program (NEECP) of the Department of Energy? ...... 196 351. What are the two major Information, Education and Communication Campaign Programs under the NEECP? ...... 196 352. What are the Administrative Orders that pertain to the 10% reduction on fuel and electricity in government buildings? ...... 196 353. How much saving was achieved for fuel and electricity through the Government Energy Management Program (GEMP) from September 2005 to December 2016? ...... 196 354. How many government agencies, including their attached agencies and instrumentalities, have been spot-checked as part of GEMP from 2005 to 2015? ...... 197 355. What is Low Carbon Model Town? ...... 197 356. What is the Carbon Footprint of a product? ...... 197 357. What is www.wattmatters.gov.ph of the DOE? ...... 197 358. How do you download Apps for wattmatters? ...... 197 359. What is system loss? ...... 197 360. Is there a law on anti-pilferage of electricity? ...... 198 361. What are the penalties involved in pilferage of electricity? ...... 198 362. What is the Magna Carta for Residential Electricity Consumers?...... 198 363. What is an Energy Audit? ...... 198 xiv
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364. What are the types of Energy Audit? ...... 198 365. What are the areas considered in an Energy Audit? ...... 198 366. What are the electrical measuring equipment and/or devices used to measure Power, Voltage, Current and Resistance? ...... 199 367. Is it advisable to turn off the refrigerator at night since nobody is using it? Why? ...... 199 368. Is there any truth about energy conservation and efficiency in inverter technology of airconditioners? ...... 199 369. How does an Inverter Air-condition works? ...... 199 370. What is the prescribed thermostat setting for air-conditioned buildings? ...... 200 371. Which of the two is energy efficient “electric stove” or “induction cooking”? ...... 200 372. Why is induction cooking energy-efficient? How does it work?...... 200 373. What is energy vampire/phantom load? ...... 200 374. Do “energy-saving devices” really save? ...... 200 375. How much electricity does a cellphone charger consume? ...... 200 376. Is turning on and off really recommendable for Compact Fluorescent Lamps? ...... 201 377. Is LED lighting safe? ...... 201 378. What is the meaning of power factor? ...... 201 379. At what speed (km/h) is the most fuel efficient in driving a vehicle? ...... 201 380. Is it better to fill up fuel in the morning and why? ...... 201 381. Are there any other factors affecting the rate of evaporation of fuel? ...... 201
NUCLEAR ...... 202
BATAAN NUCLEAR POWER PLANT (BNPP) ...... 202
382. What are the Legal Bases (Executive Orders) Supporting the BNPP’s Preservation and Maintenance? ...... 202 383. What Schemes are being Applied to Preserve the BNPP? ...... 202 384. What Efforts have been Undertaken to Rehabilitate the BNPP? ...... 203 385. What ensued after the IAEA Mission Review of 2008? ...... 203 386. What are the Highlights of KEPCO’s Feasibility Report? ...... 203 387. What is the Effect of the most recent Nuclear Power Plant Incident in 2011 on the BNPP Rehabilitation? ...... 204 388. What are the Recent Undertakings by the National Government regarding BNPP? ...... 204 389. What are the Current Issues on BNPP? ...... 205 390. Are there Proposals for the Rehabilitation/Conversion of BNPP? ...... 205 xv
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Yes. Among the proposals for the Rehabilitation/Conversion of BNPP are: ...... 205 391. What is NPC’s Position on BNPP as the Country’s Convenient Way to Go Nuclear? ...... 206
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FOSSIL FUELS
FOSSIL FUELS
OIL AND GAS
1. Why is there a need to explore for Oil and Gas resources?
Fossil fuels (oil and gas) are still the primary source of energy and are vital to the daily energy requirement for power, different industries, and transport, without which there can be no economic progress.
In 2008, worldwide oil prices reached its historic high of US$135/barrel in 2008 but at present are at $50/barrel price level. However, and due to rapid population increase, urban development, rapid technological advance requiring huge amounts of energy, it is widely expected that crude oil price will increase sometime in the future.
Philippines must exert extra effort to explore and discover oil and gas in its own backyard to reduce expensive oil importation. The country is still under-explored for hydrocarbon resources and finding these indigenous resources would greatly support the government’s program of energy self-sufficiency.
It is high time to fast track petroleum exploration activities in the country since the price of crude oil is low, the cost for exploration activities like seismic surveys, well drilling and other related operations is relatively cheaper than 2008 prices.
2. What is a seismic survey and how is it conducted?
Seismic surveying is a vital part of exploring for oil and gas. That makes it critical to producing the energy we need to power our homes and businesses.
Oil and gas explorers use seismic surveys to produce detailed images of the various rock types and their location beneath the Earth’s surface and they use this information to determine the location and size of oil and gas reservoirs.
Sound waves are bounced off underground rock formations and the waves that reflect back to the surface are captured by recording sensors. Analysing the time the waves take to return provides valuable information
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about rock types and possible gases or fluids in rock formations. This is similar to the use of ultrasound in medicine.
Seismic surveys can be conducted in offshore and onshore environments. In marine operations, a specialized vessel tows a “seismic streamer”, or a collection of cables with seismic sources and hydrophones (recorder) attached. The seismic sources use compressed air to produce acoustic energy. The hydrophones, which are highly sensitive recorders, are usually deployed in clusters to optimize the reception and recording of the returning sound waves. This provides information about the rock types and possible oil or gas deposits. The sound from seismic surveying is comparable to many naturally occurring marine sounds – including those made by the animals themselves.
Figure 1. Marine (offshore) seismic survey acquisition
Onshore seismic operations usually use specialized trucks that carry a heavy plate that is vibrated to generate a seismic signal. Geophones (recorders) are planted in ground to record the sound waves generated.
Seismic information is used to accurately plan locations for wells, reducing the need for further exploration and minimizing environmental impact. The oil and gas industry uses extensive environmental management plans to ensure all operations are conducted safely and responsibly.
The seismic data gathered from the seismic survey will undergo seismic processing. This requires powerful computers, sophisticated software and specialized skills. Once the seismic has been processed, it must be interpreted by geophysicists. The results will be compared with other data (such as rock samples, regional well/drilling results and known geology) to enhance the accuracy of the interpretation. This often produces detailed understanding of geology to depths of more than 10 kilometers.
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Figure 2. Seismic Image, processed and interpreted
3. What is exploration drilling and why is it important?
Seismic surveys can only provide information on the potential location of oil and gas accumulations in a geologic structure but cannot confirm their presence. The same way that a doctor has to extract blood from a patient to confirm the diagnosis made through x-rays, petroleum explorationists ultimately have to drill well/s to establish/confirm the presence, depth, and quality of hydrocarbon resources. Exploration drilling is the process of boring through rock formations to reach these resources/deposits and wells drilled for this purpose can range from 1 kilometer to more than 3 kilometers deep.If the result of an exploration drilling campaign is positive, it will be followed by drilling appraisal wells to determine the extent and volume of the resources which will be used as basis to warrant development of the field for commercial production.
4. How are seismic surveys and exploration drilling permitted in the Philippines?
Since seismic surveys and exploration drilling foroil and gas are high risk business ventures requiring huge capital investments, the government allows the private sector to undertake these vital tasks, through the Service Contract (SC) scheme provided for by Presidential Decree (P.D.) No. 87 (The Oil Exploration and Development Act of 1972). As a permit holder of a SC, the contractor is allowed to cost recover its expenditures, including ashare(40%) of future net proceeds in exchange for the capital,
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technology, and services provided. In 2003, DOE started the Philippines Energy Contracting Round (PCR or PECR), a public bidding round, to ensure transparency in the bidding process for selecting a service contractor/ operating for prospective areas. Under the SC scheme, the exploration phase wherein the contractor must undertake geophysical studies and exploration drilling can have duration for a maximum of ten (10) years.
Moreover, a speculative seismic survey or multi-client non-exclusive seismic survey can also be permitted by the DOE upon signing a Memorandum of Agreement (MOA) with a geophysical company. This is a business model wherein a seismic survey will be conducted at no cost to the DOE, but the proponent will have the exclusive rights, for a limited period, to market and license the data set acquired from the survey. Upon cost recovery, a percentage of the proceeds or income will be split between the DOE and the proponent. With this business model, the DOE can capitalize on new data to encourage more investments into the country.
5. How does an exploration company become the contractor of an SC and what activities does it have to perform?
By virtue of PD 87, as amended, an area can be awarded to a service contractor by the DOE after it has satisfied and pass through intensive financial, legal, and financial requirements set by the DOE during the conduct of a PECR. As part of its work commitment under the SC, an exploration company is committed to conduct geological and geophysical studies, including seismic surveys, to have a better understanding of the prospectivity of the SC area. These studies also aim to minimize the risk for exploration prior to drilling. Upon identifying a mature or drillable prospect/s, an exploration drilling campaign will be planned and executed next. Should the contractor confirm the presence of oil or gas in an area through drilling, it has the option to declare it as a discovery. Should a petroleum discovery be found to be economically viable to produce, the contractor can proceed with the development and production of the area.
6. Is the DOE/Service Contractor's project covered by relevant environmental clearances?
The DOE and its Service Contractors’ exploration operations are conducted in accordance to internationally-accepted health, safety, security, and environment (HSSE) standards. Prior to the conduct of seismic surveys and drilling, the contractor will seek permission or
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clearance from the DENR – Environmental Management Bureau (EMB). Environmental Compliance Certificate (ECC) or Certificate of Non- Coverage (CNC), whichever is applicable to the project, is awarded after a thorough and lengthy process of environmental study, evaluation, public hearing, and dialogue. A Review Committee that evaluates the exploration activity includes prominent scientists from respective institutions, including some Universities and Colleges.
7. Are Local Government Units (LGUs) and Non- Governmental Organizations (NGOs) consulted on the Project?
As an ECC requirement, public hearing and consultations with relevant local government units (LGUs), relevant government agencies, and non- governmental organizations (NGOs) shall be conducted. Depending on requirements of the project, public consultations can be conducted at provincial, municipal or barangay levels. Usually, the DOE endorse the projects to the host communities through letters and Information, Education, and Communications (IEC) campaign.
8. What are the benefits of the project for the local communities?
• One of the benefits include the provision of additional income opportunities to local residents such as hired labor, transport and facilities rentals, local (food) businesses and some domestic services. • Appropriate share in the net proceeds once the project undergoes commercial resource extraction if the project is within their jurisdiction.
9. When will LGUs share in the benefits of commercial resource extraction?
Should the exploratory drilling yield positive results, the contractor will proceed with field appraisal to determine commercial viability. Depending on the location and magnitude of the field around five (5) years of field development will follow before any commercial production commences. Only after production of the field, can the local government units have its share from the net proceeds of the production/exploitation of national resources.
Under Sections 291-292 of the Local Government Code of 1991, LGUs shall have a share of 40% from the net proceeds derived by the
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government agency or government-owned or controlled corporation from the development and production of national wealth. The local government share (40%) shall be distributed in the following manner:
Province: 20% Component City/Municipality: 45% Barangay: 35%
10. What are the fiscal terms in the Philippines?
Our fiscal system is considered as one of the most lenient and attractive in the world, considering the various provisions and incentives that a petroleum company can receive. The Philippines fiscal regime is defined as follows: No royalty paid Cost recovery is 70% of gross income Depreciation is double declining balance or straight line method The 32% income tax is paid out of government take/share Net revenue or profit oil is shared at 60% - 40% (government- contractor). This is way above than that of Indonesia, which is considered to be the most harsh fiscal regime, wherein a company can only take a minimum of 15% of the net revenue A Filipino Participation Incentive Allowance (FPIA) wherein a maximum of 7.5% is given to a contractor with a maximum of 30% Filipino company participation
A petroleum exploration company can bid or apply for a service contract in an area that ranges in size from 800 to 15,000 square kilometers in offshore, and 500 to 7,500 square kilometers over onshore areas.
The Service Contract (SC) term is seven (7) years of exploration activities that is extendible for another three (3) years, and 25 years of production period, which can be extended for additional fifteen (15) years. The maximum contract term or period is fifty (50) years.
Every service contract has a signature bonus of not less than US$50,000 depending on the prospectivity of the area. It is either in the form of cash or in kind. Other bonuses such as discovery and production bonus can be discussed during the initial stage of negotiation between the DOE and Petroleum Exploration Company/ies. A training fund of US$20,000 per
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year is an obligation by the petroleum exploration company during the exploration stage and will increase to US$50,000 annually throughout the production period.
11. What is the historical production of oil and gas?
Year Oil Condensate Gas (million barrels) (million barrels) (billion cubic feet) 1979 8.57 1980 3.62 1981 1.86 1982 3.57 1983 4.87 1984 3.89 1985 2.89 1986 2.52 1987 2.04 1988 2.18 1989 1.88 1990 1.73 1991 1.09 1992 3.26 1993 3.32 1994 1.67 0.19 1995 0.95 0.19 1996 0.33 0.32 1997 0.30 0.19 1998 0.29 0.33 1999 0.31 0.25 2000 0.42 0.38 2001 0.47 0.30 4.95 2002 2.02 3.33 62.20 2003 0.15 4.86 94.81 2004 0.14 4.40 87.56 2005 0.21 5.58 115.97 2006 0.18 5.12 108.61 2007 0.18 5.75 130.21 2008 0.96 5.61 137.07 2009 2.92 5.46 138.03 2010 2.86 4.89 130.01 2011 2.33 5.07 140.37 2012 1.64 4.59 134.49 2013 1.88 4.08 123.87 2014 3.08 4.17 130.32 2015 2.41 3.75 122.53 2016 2.01 4.15 140.52 2017* 0.43 0.68 23.27 TOTAL 75.44 71.81 1,826.62 *Production figures as of March 2017
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12. How many Service Contracts are currently being supervised and monitored by DOE?
As of March 2017, there are 24 active SCs.
SC No. Company/Operator Location Area Coverage 1 6A (Octon) The Philodrill Northwest 108,146.587 Corporation Palawan 2 6B (Bonita) The Philodrill Northwest 53,293.945 Corporation Palawan 14A (Nido) The Philodrill Northwest 2,383.85 Corporation Palawan 14B (Matinloc) The Philodrill Northwest 15,374.30 Corporation Palawan 14B1 (North Matinloc) The Philodrill Northwest 800.94 Corporation Palawan 14 (Tara) Phinma Energy Corp. Northwest 1,028.27 3 Palawan 14 (Libro) The Philodrill Northwest 162.94 Corporation Palawan 14C1 (Galoc) Galoc Production Northwest 16,300.95 Company Palawan 14C2 (West Linapacan) The Philodrill Northwest 17,649.54 Corporation Palawan 14D (Retention Area) The Philodrill Northwest 17,186.73 Corporation Palawan 4 37 PNOC-EC Cagayan 36,000.00
5 38 Shell Philippines Northwest 83,000.00 Exploration B.V. Palawan 6 40 Forum Exploration North 340,000.00 Inc. Cebu 7 44 Gas2Grid Ltd. Central 72,666.67.00 Cebu 8 49 China International South 197,000.00 Mining Petroleum Cebu 9 50 Frontier Oil Northwest 128,000.00 Corporation Palawan 10 51 Otto Energy Visayan 332,000.00 Investment Ltd. Basin 11 53 Pitkin Petroleum Ltd. Onshore 724,000.00 Mindoro 54A Northwest 87,616.15 Nido Petroleum 12 Palawan Philippines, Pty. Ltd. 54B Northwest 314,000.00 Palawan Page 8 of 207
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13 55 Otto Energy West 988,000.00 Investments Ltd. Palawan 14 56 Total Exploration Sulu Sea 622,000.00 Phils. B.V. Basin 15 57 PNOC-Exploration Northwest 712,000.00 Corporation Palawan 16 58 Nido Petroleum Phils Northwest 1,344,000.00 Pty Ltd. Palawan 17 59 PNOC-Exploration Southwest 1,476,000.00 Corporation Palawan 18 63 PNOC-Exploration Southwest 528,000.00 Corporation Palawan 19 69 Trans-Asia Visayan 528,000.00 Petroleum Basin 20 70 Polyard Petroleum Central 684,000.00 Int’l Company Ltd. Luzon 21 72 Forum (GSEC 101) Recto 880,000.00 Ltd. Bank 22 73 Otto Energy Mindoro- 1,164,000.00 Philippines Cuyo 23 74 PXP Enegy Northwest 426,800.00 Corporation. Palawan 24 75 PXP Energy Northwest 616,000.00 Corporation Palawan
COAL
13. Where are the country's coal deposits and coal mines?
Coal deposits are scattered all over the Philippines but the largest deposit is located in Semirara Island, Antique. The country's largest coal producer is Semirara Mining and Power Corporation (SMPC), which contributed about 98.56% of the local coal production for 2016. Coal mines are also located in Cebu, Zamboanga Sibugay, Albay, Surigao and Negros provinces.
14. How much is local coal production to date?
Indigenous coal production in 2016 reached 12.084 million metric tons (MMMT), a 47.87 % increase from 2015 production of 8.172 MMMT. This is attributed to the expansion of mining operations of Semirara Mining and Power Corporation, the country's largest open pit mine, which contributed 11.910 MMMT or about 98.56 % of the 2016 total production while the remaining 1.44 percent came from other coal contractors and small-scale coal mine Page 9 of 207
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permittees. The increase in domestic coal production is expected in the coming years as the some Coal Operating Contracts (COCs) in exploration will be converted to development and production (d/p) stage as well as some COCs in d/p will be expanding their production.
15. What is the current coal demand/consumption?
With the cement factories, power generating plants and process industry as major coal users, the coal consumption for the year 2016 reached 24.794 MMMT, 12.7 percent higher than the 2015 consumption of 22 MMMT.
The power generation sector accounted for 78.19 percent of the total coal consumption while cement-manufacturing industry accounted for 15.70 percent and the remaining 6.11 percent for other industrial processes.
The country's 2016 coal requirements were sourced from domestic production and importation. For 2016, total importation reached 20.029 MMMT, 89.91 % of which came from Indonesia, 6.54 % from Australia, 2.17 % from Russia, 1.35 % from Vietnam and 0.94 % from Korea.
16. What is the Philippines' coal potential?
The Philippines has a vast coal resource potential. As of December 2016, our country has in-situ coal reserves amounting to 609.6 million metric tons (MMMT) or about 25.8 % of the country's total coal resource potential of 2.37 billion metric tons (BMT).
17. Does the Philippines have high-quality coal?
There are Philippine coals of high quality that can be used without the need for any coal preparation or blending with high-quality imported coals. Coal deposits of such type are being produced by the Philippine National Oil Company-Exploration Corp. (PNOC-EC) in Malangas, Zamboaga Sibugay; by Ibalong Resources and Development Corporation (IRDC) and Adalaon Energy Development Corporation (AEDC) in Dalaguete, Cebu; and by Batan Coal Resources Corporation (BCRC) in Batan Island, Albay. The coal deposits in Catanduanes and Polillo Island, Quezon are also of good quality.
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18. What programs are being undertaken by the department to spur coal exploration and development activities?
With the rising price of oil in the world market and its imminent threat to the worldwide energy supply and security, the Philippines through the Department of Energy (DOE) has implemented its program of accelerated exploration, development, production and utilization of the country's indigenous energy resources which include coal. The DOE continues its resource assessment particularly in unexplored and underdeveloped coal areas. Coal resources assessment is conducted through reconnaissance and detailed geological surveys depending on the availability of geological data in the areas under assessment.
Since 2005, the DOE through the Energy Resource Development Bureau (ERDB) has been awarding Coal Operating Contracts (COCs) to explore, develop and produce coal areas through a public contracting round known as the Philippine Energy Contracting Round (PECR). As a continuing strategy to optimize the exploration, development, production and utilization of domestic energy resources, the DOE launched the PECR 5 for coal which resulted to 7 new COCs being awarded to different winning bidders.
This 2017, the DOE’s Upstream Sector handled by the ERDB introduced a new system of awarding COC which is by nomination through publication known as the Philippine Conventional Energy Contracting Program (PCECP). The PCECP intends to implement a simpler and faster public contracting program to facilitate the acceptance of applications for COC from interested applicants at any given time. Applicant/s for COC can nominate the area/s of interest either by direct negotiation or modified public bidding. The PCECP Circular is set to be launched this year.
19. What are the investment opportunities in the coal sector?
For private companies, the key investment opportunities in the coal sector are: (1) development of vast low-rank coal reserves for mine- mouth power plant projects; and (2) joint venture projects with some existing coal contractors in development and production stage.
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20. How many Coal Operating Contracts (COCS) do we have in the Philippines?
As of June 2017, the country has 73 valid and existing Coal Operating Contracts (COCs), of which 42 are in exploration stage and 31 are in development and production phase.
21. What are the incentives under the Coal Operating Contract (COC) system?
The current coal operating contract (COC) system gives the following incentives to contractors:
Exemption from all taxes except income tax Exemption from payment of tariff duties and compensating tax on importation of machinery/equipment/spare parts/materials required for the coal operations Entry of alien technical personnel Recovery of operating expenses Accelerated depreciation of fixed assets
22. How does coal use affect the environment and what are the mitigating measures?
The combustion of coal and other fossil fuels emits oxides of Sulfur (SOx) and Nitrogen (NOx) as well as Carbon Dioxide (CO2) to the atmosphere but these gas emissions are minimized or maintained at tolerable levels using Clean Coal Technologies (CCTs) such as circulating fluidized bed boilers, efficient pulverized coal boilers, flue gas desulfurization, and electrostatic precipitator.
All energy projects, specifically coal projects, are required by the DENR- EMB to implement an Environmental Management Plan as well as Environmental Monitoring Plan. Projects proponents are required to submit a monthly Self-Monitoring Report (SMR) and Compliance Monitoring Report (CMR).
In addition, a multi-partite monitoring team composed of representatives of project proponent, DENR, DOE, DOH, DOLE, LGUs and NGOs monitors regularly the strict compliance of the project with environmental standards/requirements of the DENR.
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23. How do you plan to address mounting opposition to coal?
The DOE shall continue the intensive IEC campaign together with project proponents to educate the local residents, LGUs and NGOs on the socio- economic benefits of the coal mining and utilization projects. The direct benefits include employment generation, LGU shares from national wealth/coal sales, benefits from power generation per ER 1-94, real estate/business/income taxes, social development programs, and stable electricity supply. The indirect benefits include attractive business climate, infrastructure, social services and micro businesses.
The DOE shall also explain in the IEC that the environmental impacts of said projects are properly addressed by the identified mitigating measures using the available mine rehabilitation and environmental protection technologies in coal mining in order to properly restore the mined-out areas to a safe and productive condition. Coal mining contractors are required to prepare and submit rehabilitation and abandonment plan, prior to the end of their mine life, which are subject for approval by the DOE.
Moreover, clean coal technologies are adopted in coal utilization particularly in power generation in order to minimize or maintain emissions of gases and total suspended particulates at tolerable levels set by the DENR as well as to properly impound and dispose ash using environmentally-sound ponds.
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RENEWABLE ENERGY
24. What is Renewable Energy?
Renewable Energy is an energy generated from natural resources such as hydro, ocean, wind, solar, biomass and geothermal. This is naturally replenished and could be developed to generate power.
25. What is the state policy on Renewable Energy?
Pursuant to the provision of R.A. 9513 (“Renewable Energy Act of 2008”), it is the policy of the State to accelerate the exploration and development of renewable energy sources such as, but not limited to, biomass, solar, wind, hydro, geothermal and ocean energy sources including hybrid systems:
a. to achieve energy self-reliance, through the adoption of sustainable energy development strategies to reduce the country's dependence on fossil fuels; b. to minimize the country's exposure to price fluctuations in the international markets, the effects of which spiral down to almost all sectors of the economy; and c. to effectively prevent or reduce harmful emissions thereby balance the goals of economic growth and development with the protection of health, safety and the environment.
26. What are the salient provisions of the 2008 RE law?
The 2008 RE Law provides the framework of legal and institutional conditions necessary for the private sector to move RE technologies into the market as well as policies that create markets, and ensure a fair rate of return for investors.
a. The Renewable Portfolio Standards (RPS) - a market-based policy that requires electricity suppliers to source an agreed portion of their supply from eligible RE resources. While creating a demand for RE, the RPS generates competition among RE developers, thereby, allowing the mandated parties to meet their targets in a least-cost manner.
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b. The Renewable Energy Certificate is the certification issued by the RE Registrar which can be traded in the RE Market in complying with the RPS. RE Market on the other hand is where RE certificates can be traded equivalent to an amount of power generated from RE sources.
c. The Green Energy Option which empowers the end-users to choose RE in meeting their energy requirements.
d. The Net Metering system which is appropriate for Distributed Generation. The mechanics provide the distribution grid user a two-way connection to the grid and is only charged for his net electricity consumption and is credited for any overall contribution to the electric grid.
27. What are the incentives being offered under RE law?
The RE law offers two forms of incentives, the Fiscal and Non-Fiscal Incentives.
Fiscal Incentives:
a. Incentives for RE Projects and Activities 1) Income Tax Holiday (ITH) 2) Duty-free Importation of RE Machinery, Equipment and Materials 3) Special Realty Tax Rates on Equipment and Machinery not exceeding 1.5 % 4) Net Operating Loss Carry-Over (NOLCO) 5) Corporate tax of ten percent 6) Accelerated Depreciation 7) Zero Percent Value-Added Tax Rate 8) Cash Incentive of RE Developers for Missionary Electrification 9) Tax Exemption of Carbon Credits 10) Tax Credits on Domestic Capital Equipment and Services
b. Incentives for RE Commercialization 1) Tax and Duty-free Importation of Components, Parts and Materials 2) Tax Credit on Domestic Capital Components, Parts and Materials 3) Income Tax Holiday and Exemption 4) Zero-rated Value-added Tax Transactions c. Incentives for Farmers Engaged in the Plantation of Biomass Resources d. Tax Rebate for Purchase of RE Components Page 15 of 207
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Non-Fiscal Incentives:
a. The Renewable Portfolio Standards (RPS) b. The Renewable Energy Certificates c. The Green Energy Option d. The Net Metering
28. What are the economic benefits in the RE law?
The country stands to realize significant benefits in the greater use of renewable energy in the power sector. Among the benefits identified are:
• Avoided foreign exchange (FOREX) expenditures or fuel costs; • Avoided social welfare costs (e.g., public health expenditures) and environmental costs due to emissions from conventional plants using fossil fuels; and • Sale of carbon emissions trading credits.
29. How does RE become administratively feasible?
Thru the DOE which remains the lead agency to implement the provisions of the 2008 RE law. Under the same law, the following were created:
a. Renewable Energy Management Board (REMB) is mandated to implement policies, plans and programs related to the accelerated development, transformation, utilization and commercialization of RE resources and technologies, among others.
b. National Renewable Energy Board (NREB) acts as a collegial body primarily tasked with recommending policies to the DOE and monitoring the implementation of the Act. As such, its private sector members shall not be required to divest. However, to avoid conflict of interest, the NREB shall adopt its own Code of Ethics that shall be observed by all its members.
30. Is RE politically feasible?
Yes. RE resources are mostly located in rural or less developed areas in the country.
These resources are site-specific compared with conventional/ fossil fuel-
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based facilities which can be installed in urban areas and near load centers (including Special Economic Zones). Thus, development and utilization of RE resources will bring socio-economic development in remote areas and has the potential of providing labor and livelihood opportunities.
31. Is there any study that the DOE has conducted that quantifies the losses and gains of the proposed measures or policy interventions that make the proposed incentives RE necessary for public good?
Yes. As stated in item no. 28, a cost-benefit analysis has been conducted for the policy measures provided in the RE Law. In all, the benefits that will be gained from developing RE for power substantially outweigh any costs to be incurred and strongly justify proposed efforts to encourage the use of RE for power generation.
32. The proposed measures are based on policies being implemented in Europe. Is there any study that reports the effectiveness of such policy measures?
The DOE has conducted policy studies on the various measures included in the RE Law. In particular, the Renewable Portfolio Standards (RPS) basically simplifies and utilizes the dynamics of supply and demand by creating a demand for RE in the face of the present restructuring of the electric power industry under EPIRA. This mechanism is deemed a more sustainable approach to increasing RE's market share than the short-term incentives approach.
The RPS is a cost-effective, market-based policy that requires electricity suppliers to get an agreed portion of their energy supply from renewable energy such as geothermal, hydro, wind, solar, and biomass. It establishes certain numeric targets for the supply of renewable energy and applying these targets to generators, utilities or retail electricity suppliers. This creates competition among renewable developers to meet the targets in a least-cost manner.
RPS is intended to encourage the development of new, environmentally beneficial resources and, thereby, reduce the environmental impacts of power production, and contribute to the development of rural areas by creating new RE business opportunities.
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The DOE study shows that sourcing RPS compliance from RE technologies would yield a decrease in power generation cost ranging from 0.06 % - 11.5% for an oil-fired power plant.
33. What about the impact of proposed measures to the rates of electricity? What will offset such impact?
Several options have been identified to meet the RPS obligation, i.e., by putting up their own RE-based plant (i.e., for generating companies), contracting with an RE-based plant or trading for RE in the WESM-REM (RE Market). As the measure shall work within the market-based structure of EPIRA, the party concerned should ensure that its price remains competitive. As indicated above, initial studies show that with the current oil prices, sourcing RPS compliance for certain RE technologies will, in fact, decrease the generation cost of oil and natural gas-fired plants.
Moreover, market forces will dictate the price offers of RE-based plants. The demand for RE will eventually create competition among RE-based plants, thereby further lowering its cost.
Moreover, given prevailing generation costs in the Philippines, particularly in the Luzon Grid, increased sourcing from RE-based plants is not expected to lead to an increase in retail rates to end-users.
34. How many RE contracts have been awarded so far? And how much potential and installed capacities were incurred? As of 30 June 2016
Awarded Projects Potential Capacity Installed Capacity (MW) (MW) Renewable Energy Grid Own-Use Grid Own-Use Grid Own-Use
Hydropower 39 - 8,037.04 - 820.82 - Ocean Energy 7 - 26.00 - - - Geothermal 41 - 610.00 - 1,906.19 - Wind 55 1 1,180.80- 426.90 0.006 Solar 144 16 4,399.714.286 538.45 3.218 Biomass 40 22 237.383.12 295.07 140.66 Sub-total 685 39 14,490.933.12 3,987.43 143.88 TOTAL 724 14,498.34 4,131.31
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35. What is Feed-in Tariff (FIT)?
FIT refers to a renewable energy policy that offers guaranteed payments on a fixed rate per kWh for emerging renewable energy sources, excluding any generation for own use.
36. Why do we need the FIT?
a. Allow RE developers to recover their investments and provide them with internationally acceptable ROI’s during the FIT period b. Accelerate the development of emerging/competitive RE technologies c. Not unduly burden the consumers with heavy pass-on charges
37. What are the rules governing the FIT system?
a. FIT Rules b. The FIT System shall only applied to On-grid areas c. For the Off-Grid areas, the ERC may consider through a separate issuance d. Priority connection to the grid e. Priority purchase and transmission of and payment for by grid system operators f. Fixed tariff for 20 years g. Only for biomass, run-off river hydropower, solar, wind, ocean and emerging RE technologies as may be identified by NREB.
38. What is “installation target”? And why do we need it in the FIT system?
a. Installation target are the RE rated capacities per technology projected based on the awarded RESC’s for a given period certified by DOE. b. To pre determine the impact of the FIT rates in a given period.
c. Pre determination of the maximum penetration of RE capacities to the grid.
39. What is FIT rate?
It is the rate (generation cost) per RE technology approved by the ERC in consideration of all the parameters (no premium added) in the development of an RE project.
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40. What is FIT-ALL?
Electricity consumers who are supplied with electricity through the distribution or transmission network shall share in the payments of the FITs in part through a uniform charge (in PhP/kWh) to be referred to as the FIT All and applied to all billed kWh.
41. How is FIT-ALL calculated?
Total FIT Revenue – (Market Rate x RE kWh) + others FIT-ALL (simplified) = ------Forecasted National Electricity Sales (kWh)
Note:
• ERC Term is FIT Differential and Forecast Cost Recovery Revenue • Others include: Working Capital Allowance; Administration Allowance; Disbursement Allowance • Total Fit Revenue = ∑(Forecast Annual RE Generation X Fit Rate)
42. What are the latest approved FIT rates?
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43. How to be FIT eligible RE Project?
“First Come-First Served Basis” Department Circular No. DC 2013-05-0009: “Guidelines for the Selection Process of Renewable Energy Projects Under Feed-In Tariff System and the Award of Certificate for Feed-In Tariff Eligibility” First to comply with the 100% electromechanical completion, subject for the availability of installation target .
44. What is the FIT implementation process?
RESC Conversion Construction and Endorsements FIT Eligibility Commissioning
Conversion of Renewable Energy Service RE developers DOE issues ERC issues Contracts (RESC) from pre‐development 4 then construct Certificate of 7 Certificate of 1 to development/commercial stage facilities and Endorsement Compliance commissioning 6 (COE) to Energy (COC) under FIT Submission of RE developers of the activities Regulatory documentary requirements for Commission (ERC) 2 affirmation of Declaration of DOE affirms for qualification 5 successful under FIT system TRANSCO and Commerciality (DOC) RE developer commissioning and indicating the 8 certify date of start capacity and with FIT eligible DOE affirms and approves the DOC and of commercial endorsement to projects sign 3 issue Certificate of Confirmation of operation TRANSCO for the REPA Commerciality Renewable Energy Payment DOE in coordination with National Renewable Energy Board (NREB) Agreement (REPA) will conduct a review of the next Installation Target if full or under subscription occurred within the period targeted.
45. What is Net Metering?
Net metering is a policy mechanism which allows consumers who own renewable energy facilities (such as, solar PV) to use electricity whenever needed while contributing their excess production to the grid.
46. Why is Net Metering an important incentive?
a. It provides incentives to End-users to generate electricity from eligible on-site RE generating facility and deliver excess to the local distribution grid. b. It generates employment for installers of solar panels, micro wind turbines and other on-site RE equipment.
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47. How Net Metering works?
Net metering allows qualified customers of Distribution Utilities (DUs) to install an on-site Renewable Energy (RE) facility not exceeding 100 kilowatts (kW) in capacity so they can generate electricity for their own use. Any electricity generated that is not consumed by the customer is automatically exported to the DU’s distribution system. The DU then gives a peso credit for the excess electricity received equivalent to the DU’s blended generation cost, excluding other generation adjustments, and deducts the credits earned to the customer’s electric bill.
48. What is a typical Net Metering set-up?
49. What types of power generating facilities are eligible for Net Metering?
RE facilities such as solar, wind, biomass or biogas energy systems, or such other RE Systems not exceeding 100 kW in power generating capacity, capable of being installed within the customer’s premises, are eligible to participate in the net metering program.
50. What benefit will I get if I go into Net Metering?
a. By generating electricity for own use, you reduce the amount of electricity you buy from your local DU. The rate of savings (or avoided cost)realized on electricity generated for own use is equivalent to the DU’s retail rate consisting of charges for generation, transmission, system loss, distribution, subsidies, taxes and other charges.
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b. You also earn peso credits on any excess electricity exported to the DU equivalent to the DU’s blended generation cost, excluding other generation adjustments. The peso credits earned are then used to reduce your electric bill/s.
51. What is the optimum size of an RE facility that I can install in my premises?
a. If you consume all of your RE production, you avoid 100% of the retail rate of your electric bill.
b. If you export any excess RE to your DU, you only offset the blended generation cost (or weighted average power production cost) of your DU. This is about 40%-45% of the retail rate of your electric bill.
c. So for an RE facility like a solar roof top system, the optimum capacity that you should install in your premises should not exceed your daytime peak demand for electricity so that you can maximize your savings/avoided cost on electricity, and shorten to the extent possible the payback period of your investment in the solar roof top facility.
52. How can you apply for Net Metering services with your distribution utility?
The customer goes to his Distribution Utility (DU) to request to participate in the Net Metering Program. Upon receipt of the request, the DU will provide the customer the following list of required documents:
• Net Metering Application Form, Identification Document, Detailed Planning Data, List of Certified Equipment, Plant Parameters Form.
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GEOTHERMAL ENERGY 53. What is Geothermal Energy?
Geothermal comes from Greek words, “Geo” which means earth, and “thermos” which means heat. Therefore, Geothermal energy is natural heat from the earth.
In many areas below the earth’s crust occurs a very hot molten rock called magma. The deepest part is its core, which is the hottest of all.
54. What elements compose a geothermal system?
Heat source is the magma that comes close to the surface of the earth in volcanic areas. Permeable reservoir rock which can hold or store the water. Solid Cap Rock which maintains pressure and does not allow the heat or water or steam to escape. Geothermal Fluid (Water) which serves as a medium for carrying the heat.
Conceptual Model of a typical Geothermal Reservoir
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The Kettle Concept
55. What are the different manifestations of a geothermal system?
Altered ground Hot Springs Mud pools
56. How is geothermal resources being studied, developed and utilized as an energy source?
Geology- to study the rock types, structures, volcanic history and geohydrology of the area LandSat Imageries Interpretation Geological investigations Geochemistry - to estimate from the water and gas samples the temperature and chemistry of the underground reservoir fluids Geophysics- to identify the flow of the fluids at the subsurface and estimate the shape and size of the reservoir If geothermal resource is suspected at depth, exploratory drilling follows to confirm with confidence the size and available power at depth.
57. How does a geothermal power plant differ from other power plants?
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In other types of the thermal plants, the steam has to be processed. This is done by burning fuels like petroleum (gasoline, diesel, bunker, fuel, or LPG), coal or natural gas to boil water and produce steam.
58. Can a geothermal operation cause a volcanic eruption?
Scientists agree that no man-made activity can cause a volcanic eruption. Scientific studies have shown that the drilling of wells or other geothermal operations have never caused any volcanic eruption. Geothermal drilling up to 3 km. depth is too shallow and narrow to affect a magma chamber, which typically occurs at a depth of about 15 km.
59. What are the investment opportunities in the geothermal sector?
Geothermal energy is a proven indigenous and friendly alternative energy source. The Philippines remains the second largest geothermal producer next only to the United States of America and efforts shall continue to increase geothermal capacity in line with the government’s thrust of energy self-reliance and environmental preservation. The government, aside from the large-scale geothermal development, is taking initiatives to develop the small-scale power and nonpower applications.
Based on the National Renewable Energy Program (NREP) as part of the Philippine Energy Plan (PEP) update, the geothermal capacity addition of 1,415 MW includes development of geothermal greenfields and optimization projects. Only the 50 MW Biliran Geothermal Power Project is committed in the pipeline for the next 5 years while the remaining potential capacity additions of about 1,365 MW are envisioned to be commissioned within the planning horizon until 2030.
60. What are the incentives under the Geothermal Service Contract System?
Under Republic Act No. 9513, otherwise known as the “Renewable Energy Act of 2008”, the fiscal incentives for existing and new Renewable Energy Project and activities are as follows:
Income Tax Holiday (ITC) for seven (7) years from the start of commercial operations Exemption from Duties on RE Machinery, Equipment, and Materials within the first ten (10) years from the issuance of Certificate of Registration to an RE Developer
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1.5% Special Realty Tax Rates on Equipment and Machinery Seven (7) years Net Operating Loss Carry-Over (NOLCO) Ten percent (10%) Corporate Tax Rate after availment of the ITH Accelerated Depreciation Zero Percent (0%) Value-Added Tax Rate Tax Exemption on Carbon Credits Tax Credit on Domestic Capital Equipment and Services related to the Installation of Equipment and Machinery Hybrid and Co-generation systems Exemption from the Universal Charge Cash Incentive of Renewable Energy Developers for Missionary Electrification Payment of Transmission Charges
61. What are the possible direct-use application in the Philippines?
62. Why is Geothermal not included in the Feed-In-Tariff (FIT)?
Only the emerging technologies such as biomass, solar, run-of-river hydro, ocean and wind, excluding generation for own use, can avail the Feed in Tariff (FIT) as stated in the provisions under the RE Act, IRR & FIT Rules. In addition, Geothermal is a baseload generating facility which is available 24/7 and the geothermal project’s Return on Investment (ROI) is favorable as the generator can compete in the electricity market.
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63. What is Renewable Energy Safety, Health and Environment Rules and Regulations (RESHERR)?
To ensure the safety and protection against hazards to health, life and property as well as pollution of air, land and water from Renewable Energy (RE) operations, the Department formulated and implemented the Department Circular No. 2012-11-0009, known as RESHERR, on November 21, 2012. Subsequently, the Department strictly monitors the compliance of all the RE contractors in the implementation of the safety policy in their operation, even if the projects are still under pre- development or development stage.
Non-compliant with the provisions under the RESHERR, an administrative fines and penalties shall be imposed.
64. What is the Department’s Position on the Issues being raised by Concerned Non-governmental Organization (NGOs)?
Geothermal project is not socially acceptable to communities, hence according to “Department of Energy Act of 1992” under section 5 [i] of Rules and Regulations Implementing Section, states that the power producer during the pre-operation stage or before the start of commercial operation should secure favourable endorsement of the community and people affected or of the host local government/s.
While Section 2(c) of the Local Government Code requires consultation to the LGUS of the various projects and program being implemented by the National Government Agencies, Section 26 of the same Code otherwise states that only projects that will have significant environmental impacts to the ecology and health welfare of the people and depletion of non-renewable energy resources will be subjected to consultation process.
The project is located near populated areas which can affect health of the people.
The activities done during the exploration stage consist of geological mapping, geochemical sampling and geophysical survey are being conducted in open areas, in undisturbed places and away from residential areas such neither houses nor health of individual will be affected.
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ECC requires that a scoping and community consultation process be held in a community where the project is located. However, should the power plant and steam field will be located in the populated area, the law requires the Geothermal Developer to come out with the relocation plan and just compensation scheme for the local residents and lands that would be affected by the developmental activities.
The project is near and if not within a Natural Park
NIPAS Act of 1992 or otherwise known as the Republic Act 7586, requires the establishment of buffer zone adjacent or immediately outside the designated protected areas to minimize harm and provide special development control to the protected area.
It is within a fragile/vulnerable ecosystem (active volcanoes, within earthquake fault lines, frequented by strong typhoons, prone to erosions and lahar flows) which can be aggravated by climate change.
Siltation, landslide and lahar flows common in an active volcanic areas such as Mts. Mayon, Pinatubo and Parker. These are seldom and rarely occur in the existing geothermal fields because of engineering interventions implemented by the RE developers such as reforestation, and slope stabilization among others. Various engineering measures as well the soil condition in these terrains are studied by geologist, chemist, botanists and forester to determine suitable trees and plant species for the area.
Hence, if a geothermal power plant is built in an active seismic zone, the facilities is designed to withstand earthquake. While built in volcanic terrain where the heat is beyond the normal gradient its facilities such as wells, pipelines and FCRS, were designed to withstand and accommodate large amount of heat.
Geothermal Operations exhibited decline in the water level, thus affecting agricultural production and tourism economy (hot and cold resorts)
Geothermal plants are benign with respect to water pollution. Nowadays, geothermal fluids used for electricity are injected back into geothermal reservoirs using wells with thick casing to prevent cross- contamination of brines with groundwater systems. The reinjection technology neatly solves the water-disposal problem and helps bolster the reservoir pressure and prolong the resource’s productive existence.
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Moreover, to protect the resource from over exhaustion and depletion, the operator is not allowed to just drill a well anywhere and put it on line to production without proper authorization from the DOE. The operator must seek first clearance from the DOE and that evaluation should be done first to determine if the said drilling will not in any way affect production field performance.
65. How to avail additional investments for RE projects?
RE developers may avail additional incentives provided by RA 9513 by infusing additional investments in their development/operation activities. Additional incentives may cover investments for improvement, modernization, or rehabilitation duly registered with the DOE, which may or may not result in increased capacity, subject to the conditions to be determined by the DOE, such as, but not limited to the following:
• Identification of the phases or stages of production scheduled for modernization/rehabilitation; and • Improvements such as reduced production/operational costs, increased production/ operation efficiency, and better product quality of RE facilities.
Procedure/Requirements: 1. Letter requesting for certification for additional investment. 2. Work program for such improvements/rehabilitation/modernization (including costs) 3. Proof showing the increase in capacity 4. Site verification/validation by DOE and BOI.
HYDROPOWER
66. What is a hydroelectric power resource?
Refers to water resources found technically feasible for development of hydropower projects, which include rivers, lakes, waterfalls, irrigation canals, springs, ponds and other water bodies.
67. What is a hydroelectric power system?
Refers to a water-based energy systems, which produce electricity by utilizing the kinetic energy of falling or running water to turn a water turbine and generator to produce electricity.
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68. How are hydropower resources developed?
The hydropower resource is being developed through a series of studies called pre-feasibility, feasibility and detailed engineering studies. The pre-feasibility study is an initial assessment of the potential site to have an idea if the project is feasible or not. It will also guide the developer to decide whether to undergo or not into the full-blown feasibility study. The feasibility study will determine the technical and economic viability of the proposed project, and the detailed engineering is the actual design and layout of the scheme of development and the over-all picture of the project.
69. What are the major components of a hydropower facility?
The major components of a hydropower plant are diversion weir and/or dam, headrace or power canal, penstock, power house, substation and transmission lines.
70. What are the procedures in the development and operation of a hydropower facility/ (ies)?
a. Project conceptualization and/or consultation with the DOE for proper procedures; b. Secure pre-development contract with the DOE; c. Conduct pre-feasibility study, feasibility study and detailed engineering; while doing the feasibility study, secure permits and licenses from different government agencies and local government units (e.g. water rights, ECC, FPIC, Brgy., Municipal and Provincial endorsements); d. Negotiate with energy sales agreement with distribution utilities or electric cooperatives; e. Submit financial approval/commitment from financing institutions to fund the project; f. After completing all the above requirements, apply for hydropower service contract with the DOE by informing the DOE of project’s commerciality; g. Secure Accreditation from Energy Regulatory Commission; and h. Operate the Hydropower Plant
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71. What are the documentary requirements for Service Contracts?
Pre-Development Stage:
a. Legal Requirements 1) Certificate of Registration from Securities and Exchange Commission for corporations or Joint Venture; 2) Department of Trade and Industry Certificate for single proprietorship; 3) By Laws and Articles of Incorporation – SEC certified; and 4) Organizational Chart and Profile of the Compan
b. Technical Requirements 1) Work Program with financial commitment per activity in doing the feasibility study; 2) Track record or experience of the company on hydropower projects; 3) Company profile of key personnel; 4) List of consultants and corresponding contract with the project developer if the applicant is not capable of developing the hydropower project; 5) List of company-owned and leased equipment; and 6) Vicinity/location Maps of the proposed project with appropriate coordinates of weir and power house showing the applied area.
c. Financial Requirement 1) Audited financial Statement for the last two (2) years and unaudited Financial Statement if the filing date is three (3) months beyond the date of the submitted Audited Financial Statement; 2) Bank Certification to substantiate the cash balance; 3) Projected cash flow statement for two (2) years; and 4) Memorandum of Agreement or Energy Sales Agreement between the developer and the distribution utilities or electric cooperatives;
d. Other Requirements 1) Letter of Intent/application 2) Processing Fee; PhP 2.50 per KW
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Development Stage:
1) Letter of Declaration of Commerciality 2) Comprehensive Feasibility Study and/or detailed engineering 3) FPIC Certification – CNO /CNC from NCIP 4) Environmental Compliance Certificates - DENR 5) Water rights permit - NWRB 6) Endorsement letter from host Barangay, Municipal and Province 7) Power Purchase Agreement with the buyer of electricity 8) Proof of Financial closing 9) DTI registration for Availment of Incentives
72. How much is the investment requirement for hydropower project?
The UP Solar Lab study in cooperation with World Wildlife Fund show that investment of hydropower projects cost USD 2,000 – 3,500 per Kilowatt
73. Can a foreigner invest in hydropower projects?
Foreign investor could invest up to 40% of the total investment.
74. Are there any successful hydropower projects in the Philippines?
As of April 11, 2017, hydropower has an installed capacity of 3,873.47 MW composed of 22 large hydropower plants and 74 mini-hydropower plants operated by government and private corporations.
BIOMASS
75. What are biomass resources?
Biomass resources – refers to non-fossilized, biodegradable organic material originating from naturally occurring or cultured plants, animals and micro-organisms, including agricultural products, by-products and residues such as, but not limited to, biofuels except corn, soya beans and rice but including sugarcane and coconut, rice hulls, rice straws, coconut husks and shells, corn cobs, corn stovers, bagasse, biodegradable
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organic fractions of industrial and municipal wastes that can be used in bioconversion process and other processes, as well as gases and liquids recovered from the decomposition and/or extraction of non-fossilized and biodegradable organic materials.
76. What are the major biomass resources in the Philippines? (Source: Biomass Atlas of the Philippines 2000)
The Philippines is largely an agricultural country with the agricultural sector contributing about one-third of the gross domestic product. The total land area is about 30 million hectares and about one-third is classified as agricultural land and the remaining devoted to shrub land, wetland and forestland. Rice, corn and coconut are the most abundant crop planted with an area of approximately 3 million hectares each. The major biomass waste resources include rice hull, livestock manure, sugarcane bagasse, coconut wastes, forestry residues and urban waste.
Rice Hull
The Filipinos are among the world's biggest rice consumers. The average Filipino consumes about 100 kilograms per year of rice. Metro Manila alone consumes up to 22,000 tons per day of rice or 16% of the country's rice consumption according to figs compiled by the Asia Rice Foundation (ARF). Rice consumption is increasing at an average of two percent per year. With the population of the Philippines surpassing the 80 million- mark (based on 2009 figures), rice will continue to be grown and should match production with corresponding increase in population.
Rice hull is the by-product of rice milling and accounts for about 20% of the rice production. The country also has more than 12,000 rice mills spread throughout the regions. These processing centers are the point sources of rice hull each year.
Livestock Manure
The livestock and poultry industries in the Philippines continue to grow to address the demand for animal protein to support the increasing population. The animal population showed a positive growth rate between 0.76% to 5.19% during the last 15 years.
The estimated amount of wastes from the animal population alone was more than 30 million metric tons per year. The waste treatment processes in the country have been minimal and continue to pose serious problem
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of environmental pollution in many growth areas in the country. The change is the pattern of livestock and poultry production from small to medium and large-scale operations and the increased concentration of livestock and poultry establishments in a few animal production areas resulted to environmental pollution problems.
Sugarcane Bagasse
The sugar industry in the Philippines is still thriving despite the decline in the price of raw sugar in the world market making the local production cost higher than those of imported sugar. The reason is still the vast tracts of land devoted to sugarcane areas amounting to more than 368,168 hectares.
Bagasse is a major biomass wastes produced and mostly utilized by the sugar mills for their boilers amounted to more than 5.9 million metric tons per year. Cane trash is another biomass wastes from sugar production that have not been utilized in the same scale as that of bagasse.
Coconut Wastes
The Philippines has the largest number of coconut trees in the world. Half a billion of these grow on three million hectares across the Philippine Islands. The country produces most of the world market for coconut oil and copra meal. In the Philippine setting, the coconut palms are also called the "tree of life" from the numerous products and by-products that could be derived from it.
The major coconut wastes include coconut shell, coconut husks and coconut coir dust. Among the three forms, coconut shell is the most widely utilized but the reported utilization rate is very low. The most common use is shell charcoal that are also exported and converted into activated carbon.
Forestry Residues
More than 15 million hectares of land in the Philippines is devoted to forestland and the actual forest cover totals 5.4 million hectares only. The Philippines must devote a great portion of its program to rehabilitate this industry and thereby significantly contribute to the biomass production.
The logging wastes and residues amounted to only 104 thousand cubic meters compared with more than 5,200 thousand cubic meters in 1979. If
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the area previously devoted to forest cover is to be replanted, this would be a significant addition to the country's sustainable energy resource from biomass.
Urban Solid Wastes
The Philippines generates more than 11,000 tons of solid wastes per day. About half of that is produced in Metro Manila alone. This translates to more than 4 million metric tons of solid wastes each year and concentrated in many growth areas of the country. Major key cities such as Cebu, Davao and Cagayan de Oro have been experiencing problems of solid wastes disposal similar to that experienced in Metro Manila.
77. What are the uses and availability of biomass resources in the country?
At present, biomass technologies utilized in the country vary from the use of bagasse as boiler fuel for cogeneration, rice/coconut husks dryers for crop drying, biomass gasifiers for mechanical and electrical applications, fuel wood and agri-wastes for oven, kiln, furnace and cook stoves for cooking and heating purposes. Others are using livestock manure to generate biogas. Methane from municipal solid waste are collected and utilized to generate electricity.
Fuel wood remains the largest part of the energy forms being used by the household sector. While there is a growing trend in the consumption of fuel wood, the government is instituting measures and programs that would rationalize the utilization of this resource, with the view of reducing the negative impact on the environment. Such measures and programs to be instituted would include but not limited to the use of LPG and electricity for cooking and solar driers for crop drying, which would encourage rural households to shift to alternative fuels. Biomass will still be the most important fuel for rural households particularly in their cooking and agriculture activities such as crop drying.
Based on information from the Department of Agriculture (DA) and the Department of Environment and Natural Resources (DENR), the Philippines could generate substantial volumes of residues which can be utilized as energy fuel. Latest estimates reveal that the country's agriculture sector can potentially produce 271.7 MMBFOE of biomass in 2003, increasing moderately by 1.9 % annually. By 2012, biomass supply potential is expected to reach 323.1 MMBFOE. Based on geographical consideration on biomass supply, there is an abundant supply of bagasse
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in Regions III, IV, VI and VII. Coconut residues abound in Regions IV, VIII, IX and XI while ricehull is abundant in Regions II, III, IV and VI.
78. What is the present capacity of biomass power plants and future capacity addition?
Total installed capacity of biomass power plants is 252.85 MW (315.48 MW) using bagasse, rice hull, biogas and municipal solid waste. Rice hull
is also being used as fuel for direct heating equivalent to 15 MWth (61.4 MWth). A capacity addition of 264.90 MW (370.4 MW) and 32 MWth (0 MW) of electricity and direct heat, respectively, is expected from various biomass resources between 2011-2014 (2015) (see table below).
Installed Capacity and Future Capacity Addition* Installed Capacity (MW) Future Biomass Capacity Total Resource For Commercial Addition Own Use (MW) Operation (MW)
Bagasse 220.47 33.00 54.00 307.47 18.20 Rice hull and 61.4 15.50 70.40 85.90 MWth(thermal) Biogas 1.86 0.40 2.80 4.66 MSW 3.00 17.00 67.00 87.00 Coco Waste 2.20 21.20 23.40 Bamboo Chips 2.00 2.00 Wood waste 2.00 18.00 20.00 Napier Grass 2.00 18.00 20.00 Multi 0.05 0.20 119.00 119.25 685.88 and 61.40 315.48 and 61.40 MWth (thermal) 370.40 MWth (thermal) *Note: Includes Awarded Biomass Contracts and Pending Biomass Projects
79. Biomass Resource Assessment in the Philippines
The US Agency for International Development (USAID) has an on-going Biomass Resource Assessment in the Philippines which started in 2012 and will end in September 2013. USAID had awarded the conduct of the said activity to Pampanga Agricultural College (for Luzon), CETI Philippines (for Visayas) and First Bukidnon Electric Cooperative, Inc. (FIBECO) (for Mindanao).
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The main objective of the project is to update the Biomass Resource Assessment in the Philippine done by the United Nations Development Program (UNDP)-Capacity Building to Remove Barriers to Renewable Energy Development in the Philippines (CBRED), University of the Philippines-Los Baños (UPLB) and US National Renewable Energy Laboratory (NREL).
WIND RESOURCE ASSESSMENT PROGRAM (WRAP)
80. What is Wind Resource Assessment Project (WRAP)?
The Project started as component activity of the “Capacity Building to Remove Barriers to Renewable Energy Development in the Philippines (CBRED) Project” funded by the Global Environment Facility (GEF) and implemented by the United Nations Development Program (UNDP) and the Department of Energy (DOE). The activity aimed to address the gaps of the country’s wind database which would be utilized by developers, implementers, regulators and policy makers in the conceptualization, design, implementation, evaluation, planning and policy formulation relevant to wind energy projects. It also sought to conduct additional data collection, survey and process these new data and integrate in the wind database.
The CBRED project completed the procurement of five (5) meteorological masts (met-masts), the primary equipment that measure, collect and record wind and other relevant meteorological data. Four (4) met-masts were installed in the following areas:
a. Brgy. Tagbak, Lubang Island, Occidental Mindoro in January 2010 b. Brgy. Malasin, San Jose City, Nueva Ecija in January 2011 c. Brgy. Fatima, Pantabangan, Nueva Ecija in June 2011 d. Brgy. East Poblacion, Pantabangan, Nueva Ecija in June 2011
CBRED Project was concluded in 2011, correspondingly, the DOE prepared a proposal that aimed to sustain and elevate the activity into a full-blown project. The DOE was able to secure the approval of Department of Budget and Management (DBM) and Congress in 2012. The WRAP Project formally started in 2013 with approved budget amounting to PhP 2,894,000.00.
Generally, the project envisions to identify viable sites for wind power development in the country. Specifically, it intends to:
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a. Undertakes and sustains the conduct of detailed wind resource assessment in potential sites, on-shore and off-shore, of the country through the employment of anemometry and remote sensing technologies;
b. Updates the national database containing wind resource data;
c. Builds local capability/expertise on various activities of wind resource assessment as well as in the development of wind power projects; and
d. Offers viable areas for utility-scale wind power projects to prospective developers through open and competitive selection process (OCSP) pursuant to Republic Act No.9513.
81. What is the project’s legal basis?
The Republic Act No. 9513 (Act) otherwise known as the “Renewable Energy Act of 2008” was enacted to accelerate the exploration and development of RE resources to achieve energy self-reliance, through the adoption of sustainable energy development strategies to reduce the country’s dependence on fossil fuels, thereby balancing the goals of economic growth and development with the protection of health and environment.
As the lead agency in the implementation of the Act, the DOE is tasked, among others, to develop and maintain a centralized, comprehensive and unified data and information base on RE resources to ensure the efficient evaluation and analysis and dissemination of data and information on RE resources, development, utilization, demand and technology application.
In pursuit of this task, the DOE is conducting various activities and projects that assessed potential RE resources of the country, these include the WRAP Project.
82. What are the project’s major activities?
To achieve the project objectives, the following major activities are being conducted:
a. Site Selection. The DOE developed criteria in the selection of areas for wind resource assessment based on internationally accepted best practices approach in wind power development. The basis for site selection is mainly the indicative wind power density
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which can be found in the 2014 Philippine Wind Atlas, Geospatial Toolkit for the Philippines and other site prospecting tools. There should be no other wind energy development initiatives in the area.
The DOE conducts preliminary assessment (desk study and on-site validation) to identify potential sites, both in onshore and offshore areas, for detailed wind resource assessment. Priority provinces for preliminary assessment are those areas with practical wind resources as identified by WWF Study. Assessed sites are ranked and prioritized according to their respective points using the aforementioned criteria.
b. Processing of Memorandum of Agreement (MOA) and Permits. Agreements, permits and other documentary requirements are secured from concerned entities prior to the installation of met- mast. These include, but not limited to, the following:
b.1. Memorandum of Agreement (MOA) with the concerned Local Government Unit (LGU) securing clearance and support, applicable for both private and public lands;
b.2. Certificate of Non-Coverage (CNC) from the Department of Environment and Natural Resources (DENR), required for private and public land;
b.3. Board Resolution (BR) from the Protected Area Management Board (PAMB) granting the conduct of the study in area declared as forest reserved, watershed or national park pursuant to Republic Act 7586 otherwise known as the “National Integrated Protected Areas (NIPAS) Act of 1992”;
b.4. Permit from the National Commission on Indigenous People (NCIP) for area declared as ancestral domain;
b.5. Clearance from the Civil Aviation Authority of the Philippines (CAAP) for site within the 10km radius from the airport; and
b.6. Authority to Install (ATI) from land owner for private land. This individual is also hired to secure and protect the met-masts against vandalism and theft.
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c. Procurement of Materials and Equipment. Materials and equipment needed for the installation, monitoring, data gathering/transmission/analysis, repair and maintenance as well as for health and safety of the SWEMD Technical Team are being acquired/procured.
d. Installation, Testing and Commissioning of Meteorological Mast. With the assistance from the concerned LGUs and Affiliated Renewable Energy Centers (ARECs), the SWEMD Technical Team installs and maintains met-masts in selected areas to measure/record the average wind speed, wind direction and temperature within a period of at least one (1) year.
Necessary personnel (i.e., laborers, haulers and helpers) are hired to assist the SWEMD technical staff during the installation of met- mast. Also, maintenance personnel are hired on a Job Order (JO) status to conduct regular on-site monitoring, inspection and maintenance.
e. Data Collection, Processing and Analysis. The DOE is responsible in the collection, processing, analysis and management of data recorded by the met-mast. Data quality and integrity are the prime consideration of the activity. As much as possible, the operation of the met mast shall be monitored from time to time.
Dedicated personal computer will be used in the encoding and processing of the collected/recorded data. Data analysis/interpretation will be undertaken thru WAsPs, WindPro and other computer applications. The said computer shall be equipped with legally-sourced anti-virus software to protect the database from virus and other malware infection. As a standard operating procedure, the database shall be maintained with a least two (2) backup files.
f. Monitoring and Maintenance. Regular on-site monitoring and preventive maintenance are conducted to ensure continuous and smooth operation of the met-mast.
g. Decommissioning, Transfer, Testing and Re-Commissioning of Met-Mast. After the prescribed period of data collection, the met mast will be transferred to other eligible areas.
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h. Capacity Building Activities. The project is envisioned to create local capabilities not only in wind resource assessment but also in the whole process of wind energy development.
A continuous and sustained capacity building activities shall be conducted to further strengthen the technical capability of DOE and other concerned personnel. DOE should have at least three (3) accredited WAsP and WindPro-operators to assert its authority on wind power project evaluation.
i. Commercialization Activity. Offer the identified viable wind sites to prospective wind developers for commercial project development in accordance with the rules and guidelines set under RA 9513.
j. Reporting. Reports are generated on a quarterly, semi-annual and annual basis.
The abovementioned activities were undertaken by five (5) technical staff from SWEMD with support from concerned ARECs.
83. What is the source of project funds?
The WRAP Project Funds is sourced from the Locally Funded Project (LFP) or Fund 151 of the DOE’s Annual Budget. Budget proposal is submitted to Congress annually for deliberation and approval.
The approved budgets of the Project since inception are as follows:
PhP 2,894,000.00 for CY 2013 PhP 4,940,000.00 for CY 2014 PhP 7,175,000.00 for CY 2015
84. What are the criteria in the identification of project sites?
The general selection criteria for the installation of met-mast are the following:
a. Wind resource density based on 2014 Philippine Wind Atlas (W/m2) b. Availability of on-site wind measurement to confirm wind resource c. Quality of on-site measured wind speed data d. Proximity to transmission line e. Upgrades required for existing transmission lines
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f. Terrain and terrain orientation of prevailing wind g. Accessibility h. Security i. Land classification j. Vegetation over 10m k. PAGASA rank in frequency of typhoon passages over province l. Other environmental issues (i.e., erosion, corrosion, humidity, etc.) m. Concerns on birds and bats sanctuary n. Intensity of cultural or environmental concerns o. Aviation and telecommunication conflicts
85. What is the implementation strategy of the project?
Due to scarcity of local firms experienced in wind power development, the DOE is fully hands-on in the implementation of the Project - from procurement of hardware, selection of site, installation and commissioning, operation and maintenance of met-mast, and management and analysis of data. DOE expertise is gained through self- help approach, knowledge sharing, participation to international training programme, and over years of actual experiences. Its limited personnel is augmented by technical staff from concerned ARECs in the conduct of ground work activities and other relevant tasks.
The “Bayanihan” tradition likewise serves as a counterpart of the host LGU who would normally provide security, labor and companion during the installation of met-mast. “Sense of Ownership” is being inculcated in land-owner/tenant as they are the primary beneficiaries of development once the study prospers and progresses to a wind energy project. The Project hires this entity as security and maintenance personnel during the entire course of wind resource assessment campaign in the area.
The Project conducts ladderized training program on wind resource assessment (WRA) as part of its strategy to create local capabilities. It is carried through the “Hands-On On-site Skills Training Strategy” using in- house expertise of DOE as trainers. The training is divided into two levels: Level I which focuses on the installation, testing and commissioning of met-mast, while Level II provides training on data management and analysis. The DOE will issue a certificate to successful participants who completed the proficiency requirements in both levels.
The Project started with Level I training participated in by seven (7) and four (4) personnel from DOE and CLSU-AREC, respectively. The first run
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of this training was conducted from May 6 to June 13, 2015 in tandem with the actual decommissioning, repair and maintenance, installation, testing and re-commissioning of three (3) met-masts in the Provinces of Nueva Ecija and Pangasinan. The final run will cover the installation, testing and commissioning of new met-mast in the Province of Bataan,which is scheduled sometime in September 2015. The activity will also serve as avenue for the awarding of certificates for the first batch of met-mast technicians.
Level II training will be conducted upon the acquisition of necessary equipment.
86. Since project inception, how many sites are/were assessed?
For the period 2010 to present, the WRAP Project covers eleven (11) sites for detailed wind resource assessment. The assessment entails the installation of meteorological mast (met-mast). The met-mast is tubular or lattice-type tower equipped with sensors, logger and internet modem devices that measures and records wind data and other meteorological information.
Met-mast sites are as follows:
PERIOD OF NO. SITES DATA STATUS/REMARKS GATHERING 1 Brgy. Tagbac, January 2010 . The 50-m high density tubular met-mast was Lubang, to November procured under the concluded UNDP/GEF/DOE Occidental 2013 CBRED Project in 2009; Mindoro . The SWEMD personnel, with assistance from LGU - Lubang, installed the met-masts in January 2010; . The met-mast collapsed during the devastation of Super Typhoon Yolanda in November 2013. Consequently, SWEMD and CvSU - AREC personnel decommissioned the met-mast in the same month; and . Since the area is under the missionary electrification, the 4-year wind data was endorsed to NPC-SPUG for further analysis and possible development of wind energy facility.
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PERIOD OF NO. SITES DATA STATUS/REMARKS GATHERING 2 Brgy. Malasin, January 2011 . The 50-m high density tubular met-mast was San Jose, to present procured under the concluded UNDP/GEF/DOE Nueva Ecija CBRED Project in 2009; . A team composed of SWEMD, CLSU-AREC and LGU – San Jose personnel installed the met-mast in January 2011; and . The same team refurbished the met-mast in May 2015. 3 Brgy. East June 2011 to . The 50-m extra high density tubular met-mast Poblacion, present was procured under the concluded Pantabangan, UNDP/GEF/DOE CBRED Project in 2009; Nueva Ecija . A team composed of SWEMD and LGU – Pantabangan installed the met-mast in June 2011; and . SWEMD together with CLSU-AREC refurbished the met-mast in May 2015. 4 Brgy. Fatima, June 2011 to . UNDP/GEF/DOE CBRED Project procured a Pantabangan, May 2015 50-m extra high density tubular met-mast in Nueva Ecija 2009; . SWEMD together with local folks installed the met-mast in June 2011; . In May 2015, SWEMD and CLSU-AREC decommissioned, refurbished and transferred the met-mast to Brgy. Malacapas, Dasol, Pangasinan; and . The Project will commence with the detailed feasibility study upon acquisition of necessary tools and equipment (particularly WindPro 3.0 and SODAR) before the end of 2017. 5 Brgy. June 2015 to . SWEMD and CLSU-AREC team installed the Malacapas, present 50-m extra high density tubular met-mast Dasol, meters in June 2015; and Pangasinan . SWEMD refurbished the met-mast in December 2016. 6 Brgy. Ibis, November . UNDP/GEF/DOE CBRED Project procured a Bagac, 2015 to 50-m extra high density tubular met-mast in Bataan present 2009; . SWEMD together PSAU installed the met- mast in November 2015; . The met-mast is scheduled for refurbishment by second semester of the year. 7 Brgy. Puro, August 2016 . The 60-m extra high density painted met-mast Magsingal, to present is the first tubular tower procured by the WRAP Ilocos Sur Project in 2016; and . It was installed by SWEMD and PSAU team sometime in August 2016.
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PERIOD OF NO. SITES DATA STATUS/REMARKS GATHERING 8 Brgy. Happy July 2016 to . The site is part of the technical assistance Valley, San present from ADB’s Quantum Leap in Wind Power Isidro, Development in Asia and the Pacific (QLW); Northern . Supply and installation of 60-m lattice-type Samar met-mast was done by ADB Contractor in July 2016; . The ADB Contractor is undertaking rectification works using the DOE Inspection Report as a baseline; . The DOE will validate/inspect the rectification works of ADB Contractor on May 4-5, 2017; and . The DOE, through the WRAP Project, will assume the ownership of the met-mast upon phase-out of QLW Project. 9 Brgy. July 2016 to . The site is part of the technical assistance Mahawan, present from ADB’s Quantum Leap in Wind Power Kananga, Development in Asia and the Pacific (QLW); Leyte . Supply and installation of 60-m lattice-type met-mast was done by ADB Contractor in July 2016; . The ADB Contractor is undertaking rectification works using the DOE Inspection Report as a baseline; . The DOE will validate/inspect the rectification works of ADB Contractor on May 6-7, 2017; and . The DOE, through the WRAP Project, will assume the ownership of the met-mast upon phase-out of QLW Project. 10 Brgy. Pandan, June 2016 to . The site is part of the technical assistance Cabusao, present from ADB’s Quantum Leap in Wind Power Camarines Development in Asia and the Pacific (QLW); Sur . Supply and installation of 60-m lattice-type met-mast was done by ADB Contractor in July 2016; . The met-mast collapsed during the devastation of Typhoon Nina on midnight of December 25, 2016; . ADB Contractor recently completed the reworks; . The DOE will validate/inspect the reworks of ADB Contractor on May 2-3, 2017; and . The DOE, through the WRAP Project, will assume the ownership of the met-mast upon phase-out of QLW Project.
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PERIOD OF NO. SITES DATA STATUS/REMARKS GATHERING 11 Brgy. Centro July 2016 to . The site is part of the technical assistance Norte, Culasi, present from ADB’s Quantum Leap in Wind Power Antique Development in Asia and the Pacific (QLW); . Supply and installation of 60-m lattice-type met-mast was done by ADB Contractor in July 2016; . The ADB Contractor is undertaking rectification works using the DOE Inspection Report as a baseline; . The DOE will validate/inspect the rectification works of ADB Contractor on April 26-27, 2017; and . The DOE, through the WRAP Project, will assume the ownership of the met-mast upon phase-out of QLW Project.
87. What are the causes of delays encountered and the corresponding corrective measures undertaken?
Below are the major causes of delays and corresponding corrective measures being undertaken:
NO. CAUSE OF DELAYS CORRECTIVE MEASURES
1 High attrition rate of target sites. In The project shifted to areas the on-set of implementation, project with less resource but developers applied for service foreseen to be commercially contracts in most areas preliminarily viable in the next five (5) assessed by the DOE (for met-mast years because of continuous installation). advancement in the technology.
2 Protracted procurement of needed Advance procurement equipment and materials. strategy is being adopted. And, the project tapped the services of concerned ARECs to procure the necessary equipment and materials.
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NO. CAUSE OF DELAYS CORRECTIVE MEASURES
3 The DBM recently disapproved the The DOE filed petition for proposed funds for the acquisition of reconsideration, however, necessary scientific and IT equipment DBM affirmed its decision. (SODAR, WindPro 3.0 and WAsP 11) Second request for absolutely indispensable in the reconsideration will be filed in detailed analysis of wind data sets, Congress. siting of wind turbines and preparation of feasibility study. This will entail extension of project timeline.
88. Who are the intended end-users of wind data?
Primarily, the data is intended for the development of wind energy projects. The data will be offered to interested project developers through Open and Competitive Selection Process (OCSP) pursuant to RA 9513, its IRR and Department Circular No. DC2009-07-0011.
SOLAR AND WIND ENERGY
89. What is Wind Resource Assessment Project (WRAP)?
The Project started as component activity of the “Capacity Building to Remove Barriers to Renewable Energy Development in the Philippines (CBRED) Project” funded by the Global Environment Facility (GEF) and implemented by the United Nations Development Programme (UNDP) and the Department of Energy (DOE). The activity aimed to address the gaps of the country’s wind database which would be utilized by developers, implementers, regulators and policy makers in the conceptualization, design, implementation, evaluation, planning and policy formulation relevant to wind energy projects. It also sought to conduct additional data collection, survey and process these new data and integrate in the wind database.
The CBRED project completed the procurement of five (5) meteorological masts (met-masts), the primary equipment that measure, collect and record wind and other relevant meteorological data. Four (4) met-masts were installed in the following areas:
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a. Brgy. Tagbak, Lubang Island, Occidental Mindoro in January 2010; b. Brgy. Malasin, San Jose City, Nueva Ecija in January 2011; c. Brgy. Fatima, Pantabangan, Nueva Ecija in June 2011; and d. Brgy. East Poblacion, Pantabangan, Nueva Ecija in June 2011.
CBRED Project was concluded in 2011, correspondingly, the DOE prepared a proposal that aimed to sustain and elevate the activity into a full-blown project. The DOE was able to secure the approval of Department of Budget and Management (DBM) and Congress in 2012. The WRAP Project formally started in 2013 with approved budget amounting to PhP2,894,000.00.
Generally the project envisions to identify viable sites for wind power development in the country. Specifically, it intends to:
a. Undertakes and sustains the conduct of detailed wind resource assessment in potential sites, on-shore and off-shore, of the country through the employment of anemometry and remote sensing technologies; b. Updates the national database containing wind resource data; c. Builds local capability/expertise on various activities of wind resource assessment as well as in the development of wind power projects; and d. Offers viable areas for utility-scale wind power projects to prospective developers through open and competitive selection process (OCSP) pursuant to Republic Act No.9513.
90. What is the project’s legal basis?
The Republic Act No. 9513 (Act) otherwise known as the “Renewable Energy Act of 2008” was enacted to accelerate the exploration and development of RE resources to achieve energy self-reliance, through the adoption of sustainable energy development strategies to reduce the country’s dependence on fossil fuels, thereby balance the goals of economic growth and development with the protection of health and environment.
As the lead agency in the implementation of the Act, the DOE is tasked, among others, to develop and maintain a centralized, comprehensive and unified data and information base on RE resources to ensure the efficient evaluation and analysis and dissemination of data and information on RE resources, development, utilization, demand and technology application.
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In pursuance of this task, the DOE is conducting various activities and projects that assessed potential RE resources of the country, this include the WRAP Project.
91. What are the project’s major activities?
To achieve the project objectives, the following major activities are being conducted:
a. Site Selection. The DOE developed criteria in the selection of areas for wind resource assessment based on internationally accepted best practices approach in wind power development. The basis for site selection is mainly the indicative wind power density which can be found in the 2014 Philippine Wind Atlas, Geospatial Toolkit for the Philippines and other site prospecting tools. There should be no other wind energy development initiatives in the area.
The DOE conducts preliminary assessment (desk study and on-site validation) to identify potential sites, both in onshore and offshore areas, for detailed wind resource assessment. Priority provinces for preliminary assessment are those areas with practical wind resources as identified by WWF Study. Assessed sites are ranked and prioritized according to their respective points using the aforementioned criteria.
b. Processing of Memorandum of Agreement (MOA) and Permits. Agreements, permits and other documentary requirements are secured from concerned entities prior to the installation of met-mast. These include but not limited to the following:
b.7. Memorandum of Agreement (MOA) with the concerned Local Government Unit (LGU) securing clearance and support, applicable for both private and public lands;
b.8. Certificate of Non-Coverage (CNC) from the Department of Environment and Natural Resources (DENR), required for private and public land;
b.9. Board Resolution (BR) from the Protected Area Management Board (PAMB) granting the conduct of the study in area declared as forest reserved, watershed or national park pursuant to Republic Act 7586 otherwise known as the “National Integrated Protected Areas (NIPAS) Act of 1992”;
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b.10. Permit from the National Commission on Indigenous People (NCIP) for area declared as ancestral domain;
b.11. Clearance from the Civil Aviation Authority of the Philippines (CAAP) for site within the 10km radius from the airport; and
b.12. Authority to Install (ATI) from land owner for private land. This individual is also hired to secure and protect the met-masts against vandalism and theft.
c. Procurement of Materials and Equipment. Materials and equipment needed for the installation, monitoring, data gathering/transmission/analysis, repair and maintenance as well as for health and safety of the SWEMD Technical Team are being acquired/procured.
d. Installation, Testing and Commissioning of Meteorological Mast. With the assistance from the concerned LGUs and Affiliated Renewable Energy Centers (ARECs), the SWEMD Technical Team installs and maintains met-masts in selected areas to measure/record the average wind speed, wind direction and temperature within a period of at least one (1) year.
Necessary manpower (laborers, haulers and helpers) are hired to assist the SWEMD technical staff during the installation of met-mast. Also, maintenance personnel are hired on a Job Order (JO) status to conduct regular on-site monitoring, inspection and maintenance.
e. Data Collection, Processing and Analysis. The DOE is responsible in the collection, processing, analysis and management of data recorded by the met-mast. Data quality and integrity are the prime consideration of the activity. As much as possible, the operation of the met mast shall be monitored from time to time.
Dedicated personal computer will be used in the encoding and processing of the collected/recorded data. Data analysis/interpretation will be undertaken thru WAsPs, WindPro and other computer applications. The said computer shall be equipped with legally- sourced anti-virus software to protect the database from virus and other malware infection. As a standard operating procedure, the database shall be maintained with a least two (2) backup files.
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f. Monitoring and Maintenance. Regular on-site monitoring and preventive maintenance are conducted to ensure continuous and smooth operation of the met-mast.
g. Decommissioning, Transfer, Testing and Re-Commissioning of Met-Mast. After the prescribed period of data collection, the met mast will be transferred to other eligible areas.
h. Capacity Building Activities. The project is envisioned to create local capabilities not only in wind resource assessment but also in the whole process of wind energy development.
A continuous and sustained capacity building activities shall be conducted to further strengthen the technical capability of DOE and other concerned personnel. DOE should have at least three (3) accredited WAsP and WindPro operators to assert its authority on wind power project evaluation.
i. Commercialization Activity. Offer the identified viable wind sites to prospective wind developers for commercial project development in accordance with the rules and guidelines set under RA 9513.
j. Reporting. Reports are generated on a quarterly, semi-annual and annual basis.
The abovementioned activities were undertaken by three (5) technical staff from of SWEMD with support from concerned ARECs.
92. What is the source of Project Funds?
The WRAP Project Funds are sourced from the Locally Funded Project (LFP) or Fund 151 of the DOE’s Annual Budget. Budget proposal is submitted to Congress annually for deliberation and approval.
The approved budgets of the Project since inception are as follows: PhP 2,894,000.00 for CY 2013; PhP 4,940,000.00 for CY 2014; and PhP 7,175,000.00 for CY 2015.
93. What are the criteria in the identification of project sites?
The general selection criteria for the installation of met-mast are the following:
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a. Wind resource density based on 2014 Philippine Wind Atlas (W/m2); b. Availability of on-site wind measurement to confirm wind resource; c. Quality of on-site measured wind speed data; d. Proximity to transmission line; e. Upgrades required to existing transmission lines; f. Terrain and terrain orientation to prevailing wind; g. Accessibility; h. Security; i. Land classification; j. Vegetation over 10m; k. PAGASA rank in frequency of typhoon passages over province; l. Other environmental issues (erosion, corrosion, humidity, etc.); m. Concerns in birds and bats sanctuary; n. Intensity of cultural or environmental concerns; and o. Aviation and telecommunication conflicts.
94. What is the implementation strategy of the Project?
Due to scarcity of local firms experienced in wind power development, the DOE is fully hands-on in the implementation of the Project - from procurement of hardware, selection of site, installation and commissioning, operation and maintenance of met-mast, and management and analysis of data. DOE expertise is gained through self- help approach, knowledge sharing, participation to international training programme, and over years of actual experiences. Its limited manpower is augmented by technical staff from concerned ARECs in the conduct of ground work activities and other relevant tasks.
The “Bayanihan” tradition likewise serves as a counterpart of the host LGU who would normally provide security, labor and companion during the installation of met-mast. “Sense of Ownership” is being inculcated to land-owner/tenant as they are the primary beneficiaries of development once the study prospers and progress to wind energy project. The Project hires this entity as security and maintenance personnel during the entire course of wind resource assessment campaign in the area.
The Project conducts ladderized training program on wind resource assessment (WRA) as part of its strategy to create local capabilities. It is carried through the “Hands-On On-site Skills Training Strategy” using in- house expertise of DOE as trainers. The training is divided into two levels: Level I which is focus on the installation, testing and commissioning of met-mast, whilst Level II provides training on data management and Page 53 of 207
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analysis. The DOE will issue a certificate to successful participants completed the proficiency requirements in both level.
The Project started with Level I training participated by seven (7) and four (4) personnel from DOE and CLSU-AREC, respectively. The first run of this training was conducted from May 6 to June 13, 2015 in tandem with the actual decommissioning, repair and maintenance, installation, testing and re-commissioning of three (3) met-masts in the Provinces of Nueva Ecija and Pangasinan. The final run will cover the installation, testing and commissioning of new met-mast in the Province of Bataan, which is scheduled sometime in September 2015. The activity will also serve as avenue for the awarding of certificates for the first batch of met-mast technicians.
Level II training will be conducted upon the acquisition of necessary equipment.
95. Since project inception, how many sites are/were assessed?
For the period 2010 to 2015, the project able to cover five (5) sites detailed below:
PERIOD OF STATUS/REMARKS NO SITES DATA GATHERING 1 Brgy. Tagbac, January 2010 to Completed 4-year data Lubang, Occidental November 2013 gathering. The same is Mindoro endorsed to NPC-SPUG for possible development of wind energy facility.
2 Brgy. Malasin, San January 2011 to Met-mast recently repaired Jose City, Nueva present and maintained. Ecija 3 Brgy. Fatima, June 2011 to Completed 4-year data Pantabangan, June 2015 gathering. Met-mast was Nueva Ecija decommissioned and transferred to Brgy. Malacapas, Dasol, Pangasinan.
4 Brgy. East June 2011 to Met-mast recently repaired Poblacion, present and maintained. Pantabangan, Page 54 of 207
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PERIOD OF STATUS/REMARKS NO SITES DATA GATHERING Nueva Ecija 5 Brgy. Malacapas, June 2015 to Met-mast recently installed. Dasol, Pangasinan present
The Project will cover two (2) additional sites in the Provinces of Bataan and Zambales before the end of 2015.
96. What are the causes of delays encountered and the corresponding corrective measures undertaken?
Below are the major causes of delays and corresponding corrective measures being undertaken:
CORRECTIVE MEASURES NO CAUSE OF DELAYS 1 High attrition rate of target The project shifted to areas with sites. In the on-set of less resource but foreseen to be implementation, project commercially viable in the next five developers applied for service (5) years because of continuous contracts in most areas advancement in the technology. preliminary assessed by the DOE (for met-mast installation). 2 Protracted procurement of Advance procurement strategy is needed equipment and being adopted. And, the project materials. tapped the services of concerned ARECs to procure the necessary equipment and materials.
3 The DBM recently dis- The DOE filed petition for approved the proposed funds reconsideration, however, DBM for the acquisition of affirmed its decision. Second necessary scientific and IT request for reconsideration will be equipment (SODAR, WindPro filed to Congress. 3.0 and WAsP 11) absolutely indispensable in the detailed analysis of wind data sets, siting of wind turbines and
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CORRECTIVE MEASURES NO CAUSE OF DELAYS preparation of feasibility study. This will entail extension of project timeline.
97. Who are the intended end-users of wind data?
Primarily, the data is intended for the development of wind energy projects. The data will be offered to interested project developers through Open and Competitive Selection Process (OCSP) pursuant to RA 9513, its IRR and Department Circular No. DC2009-07-0011.
98. What is Household (Sitio) Electrification Program (HEP)?
The Household Electrification Program (HEP) involves the provision of household lighting in off-grid areas (sitios) using mature renewable energy technologies such as photovoltaic solar home systems (PV-SHS), PV streetlights and micro-hydro systems. The HEP is a continuation of the Department of Energy’s (DOE’s) Barangay Electrification Program (BEP) which started in 1998 and had contributed to the attainment of a one hundred percent (100%) barangay level electrification in 2010. The HEP aims to contribute to the National Government’s goal to attain ninety percent (90%) household electrification level by 2017.
For consistency, the meaning of “household” as a unit of physical target of the HEP is actually a “house connection” which is the unit of physical target used by the National Electrification Administration’s (NEA) electrification program. This was agreed during one of the meetings of the DOE and NEA in relation to the Department of Budget and Management (DBM) request for a common unit of physical target for the government’s electrification programs during one of the budget consultations for the proposed 2013 budget appropriations.
Generally, solar PV system is the most common renewable energy technology being for household lighting purposes. However, micro-hydro system is a better strategy when hydropower resource is available within a reasonable distance from clustered household beneficiaries.
The implementation of the HEP entails the following major activities:
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a. Rapid Rural Appraisal to determine the potential renewable energy (RE) resource (such as solar, micro-hydro, biomass, etc.) options that can be tapped for the HEP. This also entails the initial coordination with the local government units, electric cooperatives and community. b. Community organizing to select the qualified household beneficiaries. c. Procurement of RE systems and services. This entails the bidding for the supply and installation of the required RE systems for the program. d. Conduct social preparation activities which include but not limited to the formation and registration to the Securities and Exchange commission or Cooperative Development Authority (CDA) or to the Department of Labor and Employment, of the recipient households into Sitio Power Association (SOPA), conduct trainings on basic accounting and auditing procedures for the officers of the SOPA, load management and maintenance and safety for the household beneficiaries and technicians’ training for the LGUs and electric cooperatives. e. Supervise the installation and commissioning of PV Systems. f. Conduct technical inspection and physical inventory of completed projects. g. Conduct regular monitoring and evaluation of the Project.
The abovementioned activities were undertaken by five (5) technical staff of SWEMD and three (3) technical staff from the three (3) DOE Field Offices (one technical staff per Field Office).
99. What is the legal basis?
The HEP is a continuation of the DOE’s Rural Electrification Program in support to the National Government’s goal to attain 90% household electrification level by 2017. The National Government, through Congress, has allocated in 2014 PhP 139.44 million for the energization of off-grid areas in the countryside using photovoltaic solar home systems or micro-hydro systems.
100. What are the criteria used in identifying project beneficiaries/areas under the HEP?
The general selection criteria for HEP project areas are the following:
a. The target sitio is duly certified by the concerned EC as unenergized and has no grid extension plan by the EC within the next 3 years - (40%); • Distance from the last tapping point- >5km (40%), <5km, >2km
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(30%), <2km (20%) b. Social Acceptability of PV-SHS - (20%); c. Willingness to provide Counterpart funding (initial P1000 and monthly fee, P150-P250)- (20%); and d. Accessibility of the Sitio- (20%) d.1 Four wheel drive vehicle - (20%) d.2 Boat /Jabal Jabal (15%) d.3 Hike-(10%)
101. What is the financing source of HEP projects?
The HEP projects are funded through the Locally Funded Project (LFP) allocation under DOE’s annual budget. Project proposals are submitted to Congress annually for deliberation and approval.
102. What is the implementation mechanism/institutional arrangement being adopted for HEP?
The hardware component (including costs of insurance, transshipment and installation) as well as the conduct of technical trainings of users and technicians of the HEP is provided by the DOE while the social preparation component is conducted in collaboration with Team Energy Foundation, Incorporated and/or Winrock AMORE.
The respective Electric Cooperatives (ECs) or Distribution Utilities (DUs) are tapped in the identification of sitio beneficiaries which are not included in their grid expansion program within the next 3-5 years under the National Electrification Administration’s Sitio Electrification Program (SEP) or Barangay Line Enhancement Program (BLEP). These ECs or DUs are encouraged to receive the ownership, operation and maintenance of the Project through the signing of a Deed of Donation between DOE and the concerned EC.
The “Bayanihan” tradition likewise serves as a counterpart of the household beneficiaries who would normally transport their Solar Home Systems to their respective households. The required membership/connection fee (for the revolving fund) to the Sitio Power Association (SPA) and concerned EC is P 1,000 per member household.
Once the RE Systems are completed and turned over to the household beneficiaries, the Sitio Power Association (SPA), which is composed of the household beneficiaries, will manage the sustainable operation of the
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system including the rate setting, collection and management of fees from the beneficiaries. Portion of the membership fee will be spent on regular maintenance and operating costs and a portion will also be set aside for replacement of balance of systems (battery, LED lamps, charge controller) beyond warranty period of two (2) years. Replacement of busted PV system components after the warranty period will be done by the ECs who are tasked by the DOE in their respective Memorandum of Agreement. Likewise, the SPAs and ECs are trained on technical and management aspects by the DOE and the project implementers prior to actual operation of the system.
103. What is the approval process for Expanded Rural Electrification (ER) Projects?
The DOE Secretary approves the annual target households (sitios) for energization. The DOE-Rural Electrification Administration and Management Division checks the list of target unenergized households and counterchecks which agency will implement the electrification projects, these include: a) National Electrification and Administration – for grid extension through Electric Cooperatives; b) National Power Corporation – Small Power Utilities Group (NPC- SPUG) for island electrification; c) Private Companies and Utilities – for “Adopt a Household” concept of the ER projects; d) Renewable Energy Management Bureau for HEP; and e) Electric and Power Industry Management Bureau – for Energy Regulation (E.R.) 1-94 and related activities.
The lead implementing agency then prepares and processes the documents for the energization of the target households.
Under the HEP, the first major activity is the conduct of Rapid Rural Appraisal (RRA) in the proposed households (sitios) in order to determine the economic and technical viabilities of energizing the proposed households (sitios). Once found to be technically and economically viable and using the selection criteria indicated in item 3 above, the REMB will seek the DOE Secretary’s approval of the proposed list of household beneficiaries. Upon approval by the DOE Secretary of the proposed project, the DOE Bids and Awards Committee would facilitate the procurement of the required Solar Photovoltaic Systems or Micro-hydro Systems. Page 59 of 207
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104. Since its inception in 1999 how many Barangays have been implemented under the previous Barangay Electrification Program?
For the period 1999-2009, there are 802 barangays energized under the BEP. Following is the annual breakdown of barangays energized under the BEP:
Accomplishment of the Barangay Electrification Project as of December 31, 2010
Energized Estimated Total Year RE Technology Used Barangays per year Capacity (kW) PV McHP 1999 1 0.30 - 0.30 2000 60 44.15 150.60 194.75 2001 127 129.40 8.40 137.80 2002 85 80.64 26.00 106.64 2003 105 121.20 80.00 201.20 2004 92 106.90 48.00 154.90 2005 65 71.39 51.00 122.39 2006 77 91.20 2.90 94.10 2007 90 136.75 - 136.75 2008 3 0.90 11.00 11.90 2009 96 131.80 127.00 258.80 Total 802 914.63 504.90 1,419.53
105. What are the causes of delays/slippages?
a. Delay of fund releases from DBM (Funds for the year are usually released by the 2nd quarter and beyond); and b. Inability of concerned LGU or household beneficiaries to timely provide their committed counterpart funds.
106. What were the corrective measures implemented by DOE- REMB?
In CY2005, the DOE simplified the process of BEP implementation by conducting the centralized bidding of equipment and installation of the same at the identified BEP sites, instead of the usual fund transfer to beneficiary-LGUs or ECs. In this way, LGU counterparts and commitments no longer hindered the project implementation. Furthermore, the DOE fund allocations were directly paid to the winning bidder through progress billing. The said arrangement was supported by RE suppliers as this would also simplify project coordination. Page 60 of 207
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107. Since its inception in 1999 how much funds have already been allocated for the BEP?
Total Energized Estimated Total Allotment % Utilization Percentage RE Technology Year Obligations Barangays per Total Releases (Php) per year Completion Capacity (Php) year (kW) PV McHP 1999 45,314,000.00 45,250,872.50 99.86 1 0.30 0.30 - 2000 81,659,000.00 81,658,999.00 100.00 60 194.75 44.15 150.60 2001 109,538,250.00 109,537,811.55 100.00 127 137.80 129.40 8.40 2002 139,430,000.00 138,926,642.81 99.64 85 106.64 80.64 26.00 2003 80,049,000.00 80,041,007.20 99.99 105 201.20 121.20 80.00 2004 80,017,000.00 78,482,824.29 98.08 9296.39% 154.90 106.90 48.00 2005 76,672,000.00 71,301,824.50 93.00 65 122.39 71.39 51.00 2006 76,672,000.00 75,654,682.82 98.67 77 94.10 91.20 2.90 2007 76,672,000.00 72,138,662.51 94.09 90 136.75 136.75 - 2008 82,322,000.00 82,320,361.72 100.00 3 11.90 0.90 11.00 2009 98,786,000.00 96,080,737.28 97.26 97 258.80 131.80 127.00 Total 947,131,250.00 802 1,419.53 914.63 504.90
Note: Project Funds for the year can be utilized in the succeeding year. The number of Households energized in a given year denotes an actual installation and commissioning of project. In most cases, the rest of the targeted Households for the year are in different phases of project implementation i.e. RRA, Proposal preparation, on‐going etc. in which case, these are treated as project slippage since they are not actually implemented and commissioned on the same year. Nonetheless, allotment releases have already been obligated for said “slippage project”.
108. How much funds are proposed/allocated for HEP project and how many households are targeted for energization from 2010 to 2016?
AVERAGE COST ENERGIZED/TARGE PROPOSED/APPROVED YEAR PER HOUSEHOLD T HOUSEHOLDS BUDGET (PhP) (PhP)
2011 3,450 63,016,608.00 18,265.68
2012 7,500 171,313,623.00 22,841.82
2013 5,400 126,767,120.00 23,475.39
2014 5,400 139,443,832.00 25,822.93
2015 5,400 153,388,215.00 28,405.23
2016 5,400 168,727,037.00 31,245.75 Total 32,550 Overall Average Cost per Household 25,009.47
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109. How many households under the HEP were energized from 2011 to 2015?
Accomplishment of HEP as of June 2015:
ENERGIZED COMMUNAL TOTAL CAPACITY CAPACITY PV CAPACITY YEAR HOUSEHOLDS SOLAR HOME CAPACITY (KW) (KW) STREETLIGHTS (KW) PER YEAR SYSTEM (KW) 2011 2,750 82.5 6 0.45 40 3 85.95 2012 - - - - - 2013 6,276 188.28 85 6.375 151 11.325 205.98 2014 6,978 209.34 55 4.125 1,026* 76.95 290.415 2015 6,919 187.57 61 4.575 121 9.075 201.22 2016 ------TOTAL 22,923 668 207 16 1,338 100 784
Note: *Includes 932 PV streetlights under PV Streetlighting Project in Typhoon Yolanda Devastated Areas.
110. What is an Affiliated Renewable Energy Center (AREC)?
State universities and colleges (SUCs) or private academic institutions (PAIs), which the Department of Energy (DOE) has entered into a Memoranda of Agreement (MOAs) to assist in the administration and management of the latter’s National Renewable Energy Program (NREP), specifically the Policy and Program Support Component. It serves as extension arm of the Renewable Energy Management Bureau (REMB) in the promotion, development and implementation of Area-Based Renewable Energy Plan and Program. It is formerly known as the Affiliated Non-Conventional Energy Center (ANEC) and eventually elevated to AREC pursuant to Renewable Energy Act of 2008.
111. What is the legal basis?
The Republic Act (RA) No. 9513 otherwise known as the “Renewable Energy Act of 2008”, declares that it is the policy of the State to encourage the accelerate the exploration, development and increase the utilization of renewable energy resources such as, but not limited to, biomass, solar, wind, hydropower, geothermal, and ocean energy resources, and including hybrid systems. Pursuant to Item e, Section 31, Rule 10 of the Implementing Rules and Regulations of RA 9513 as embodied in the Department Circular No. DO2009-05-008 mandates the continued strengthening of the Affiliated Renewable Energy Centers (ARECs) nationwide.
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112. What is the source of Project Funds?
The AREC Project Funds is sourced based on the General Appropriations Act (GAA) aspart of the DOE’s Annual Budget (Fund 101). The budget proposal is submitted annually to DBM and Congress for deliberation and approval.
The annual project funds are distributed to ARECs based primarily in the number of HEP and BEP areas/projects being monitored and evaluated.
113. What are the criteria in the establishment of AREC?
a. The institution should be a college or university with knowledge on energy sector; b. It should have strong technical capabilities that can handle the technical component of RE systems and technologies; c. It has considerable experiences and good services in extension work; d. The institution should be willing to participate and provide counterpart funds or in kind; e. It should have existing manpower with competence and expertise in relevant fields; f. The institution should be strategically located and accessible to rural people and other RE clienteles; and g. There should be no existing AREC in the proposed coverage area.
114. What are the major activities of the AREC?
Operation of the Center is focused on the following areas: a. Implements, monitors and evaluates Household Electrification Program (HEP); b. Monitors and evaluates Barangay Electrification Program (BEP); and c. Assists in the implementation of Bottom-up Budgeting (BUB) Process.
Other activities include: a. Provides technical and extension services to RE users/clienteles; b. Conducts of RE resources inventory; c. Assists in the development of regional/provincial RE energy database; and d. Assists the DOE in the conduct of RE related activities.
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115. What is the implementation arrangement of AREC Project?
Partnership between the Department and concerned SUC/PAI is formalized through Memorandum of Agreement (MOA). The Agreement sets the targets/objectives that the Center should accomplished at the end of each year. The DOE provides corresponding yearly financial assistance with counterpart from the Center either in cash or in-kind using the latter’s approved activities as basis.
The AREC submits quarterly technical and financial reports for the DOE to monitor the progress of the Project. Meanwhile, the Agreement is renewed annually based on submission and compliance of Center’s Terminal Report for the activities undertaken and Financial Report as liquidation of its cash advance.
AREC is required to have a qualified Extension Head having educational background and extensive experience on community organization; and at least one (1) technical staff should be Certified Solar PV Technician by the Department.
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116. What are the State Universities and Colleges / Private Academic Institutions involved in the implementation of AREC project?
NO NAME OF AREC ADDRESS PROJECT LEADER CONTACT DETAILS A Luzon 1 Isabela State University 3309, Echague, Isabela Ramon D. Velasco, Ph.D. [email protected] (078) 305-9120 2 Benguet State University 2601 La Trinidad, Benguet Engr. Edgar M. Molintas [email protected] (074) 422 - 4380 3 Kalinga-Apayao State College 3800 Tabuk, Kalinga Amado P. Imper, Ph.D. - 4 Central Luzon State University 3119 Science City of Victorino T. Taylan, Ph.D. [email protected] Munoz, Nueva Ecija (044) 456-5592 5 Pampanga State Agricultural Magalang, Pampanga Honorio M. Soriano, Jr. [email protected] University (045) 343-4950 6 Cavite State University 4122 Indang, Cavite Engr. Jaime Q. Dilidili [email protected] (046) 415-0973 Fax 7 Western Philippines University 5302 Aborlan, Palawan Engr. Bernardo S. Ocampo [email protected] (048) 433-2733 8 Central Bicol State University of 4418 Pili, Camarines Sur Jose L. Pardalis, Ph.D. Agriculture [email protected] (054) 477-3320 local 126 9 Bicol University 4503 Legaspi City, Albay Jerry S. Bigornia, Ph.D. [email protected] (052) 820-6103 B Visayas 1 Central Philippine University 5000 Lopez Jaena St., Engr. Jeriel G. Militar [email protected] (033) 320-3004 2 Cebu Technological University 6000 M.J. Cuenco Ave., Cecilio S. Baga, Ph.D. (032) 412-0970 3 Silliman University 6200 Dumaguete City, Nichol R. Elman, Ph.D. [email protected] (035) 422-7207 4 University of Eastern Philippines 6400 Catarman, Northern Engr. Lidany F. Cornillez [email protected] (055) 251-8611 5 Visayas State University 6521 Visca, Baybay, Leyte Roberto C. Guarte, Ph.D. [email protected] (053) 563-7117 C Mindanao 1 Xavier University Corrales Avenue, 9000 Engr. Alejandro S. Villamor [email protected] (088) 858-8962 2 Central Mindanao University 8710 Musuan, Bukidnon Engr. Arman T. Gascon [email protected] (088) 356-1912 3 University of Southeastern F. Iñigo St., Obrero, Davao Engr. Renato G. Arancon [email protected] (082) 221-1636 4 Sultan Kudarat State University 9800 Access, E.J. Montilla, Rolando F. Hechanova, Ph.D. [email protected] (064) 200-4259 5 University of Southern Mindanao Kabacan, North Cotabato Francisco Gil, N. Garcia, Ph.D. [email protected] (064) 248-2138 6 Mahardika Institute of Technology Ilmoh Street, Bongao, Tawi-Engr. Sambas I. Hassan [email protected]
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COMPETITIVE SELECTION PROCESS
117. What is Competitive Selection Process (CSP)?
CSP is a process wherein a distribution utility (DU) or a group of distribution utilities (DUs) undertake a transparent and competitive bidding of their power supply contracts in a least-cost manner.
118. What is the DOE’s policy on CSP?
On 11 June 2015, the DOE issued Department Circular No.DC2015-06- 0008 “Mandating All Distribution Utilities to Undergo Competitive Selection Process (CSP) in Securing Power Supply Agreement (PSA),” which requires all DUs (grid and off-grid) to procure their PSAs through CSP conducted by a Third Party.
119. What are the salient features of DOE Department Circular No.2015-06-0008?
The said DOE DC also mandates the following:
a. Aggregation of DUs’ un-contracted demand requirement; b. Annual conduct of CSP; c. Uniform PSA Template on the terms and conditions to be issued by the ERC and DOE; d. Joint DOE and ERC issuance of implementing guidelines (IG) on the aggregation of un-contracted demand requirements of DUs and the process for recognition or accreditation of the Third Party, within 120 days of the effectivity of the said DC (or 27 October 2015); and e. In coordination with the DOE, ERC to issue supplemental guidelines on the design and execution of the CSP; and f. Non-applicability to PSAs with tariff rates already approved and/or have been applied for approval by the ERC before the effectivity of the said DC.
120. What are the ERC issuances relating to CSP?
The ERC subsequently issued the following resolutions on CSP:
a. Joint DOE and ERC Resolution No. 1, Series of 2015, “A Resolution Enjoining All Distribution Utilities to Conduct Competitive Selection Process (CSP) in the Procurement of Supply for Their Captive Market”
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This resolution highlights that the DOE and ERC recognize that the CSP engenders transparency and enhances security of supply in the procurement of power supply by the DUs for their captive electricity end-users in the long-term.
Also, said Joint Resolution stipulates that ERC shall issue the regulation to implement the CSP. It was signed on 20 October 2015 and published in The Philippine Star and Philippine Daily Inquirer on 7 November 2015.
b. ERC Resolution No. 13, Series of 2015, “A Resolution Enjoining All Distribution Utilities to Conduct Competitive Selection Process (CSP) in the Procurement of Their Supply to the Captive Market”
1) This resolution prescribes that a DU may adopt any form of CSP in awarding the PSA to a generation company pending ERC’s issuance of the CSP IG. The Terms of Reference (TOR) to be used by the DUs in the conduct of CSP shall have the following minimum terms and conditions:
a) Required/Contracted Capacity and/or Energy Volumes; b) Generation sources (i.e. Hydro, Coal, Natural Gas, Diesel and others); c) Method of procurement for fuel, if applicable; d) Cooperation/Contract Period; e) Tariff structure unbundled to capacity fees, variable and fixed operating and maintenance (O&M) fee, fuel fee and others, including the derivation of each component, base fee adjustment formula, if any; f) Form of payment (pesos or foreign currency denominated); g) Penalties (if applicable); h) If applicable, details regarding any transmission projects or Grid connection projects necessary to complement the proposed generation capacity, including identification of the parties that will develop and/or own such facilities, any costs related to such projects and specification of the parties responsible for recovery of any cost related to such projects; and i) Other key parameters.
2) It also allows conduct of Direct Negotiation only after at least two (2) failed CSPs. The following cases are considered as failed CSP:
a. The DU did not receive any proposal; b. Only one supplier submit proposal; and c. Competitive Proposal from prospective suppliers failed to meet the TOR requirements as determined by the DUs Bids and Awards Committee (BAC).
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3) It was signed on 20 October 2015 and published in the Philippine Daily Inquirer on 6 November 2015.
c. ERC Resolution No. 1, Series of 2016, “A Resolution Clarifying the Effectivity of ERC Resolution No.13, Series of 2015”
1) This resolution restated the effectivity of ERC Resolution No.13, series of 205 (ERC CSP Resolution) to 30 April2016.
2) It also reiterated compliance to the following provisions of Section 2 of the ERC CSP Resolution: DUs shall adopt the Terms of Reference prescribed in Section 2. of ERC Resolution No.13, series of 2015; and There should be at least two (2) qualified bids for the CSP to be considered as successful.
3) It also prescribes the following provisions for PSAs that have automatic renewal or extension of terms: PSAs approved by ERC or filed with ERC before the effectivity of Resolution No.1, may have one (1) automatic renewal or extension for a period not exceeding one (1) year from the end of their respective terms; and There will be no automatic renewal clause or extension of PSAs upon effectivity of ERC Resolution No.1, series of 2016.
4) It was signed on 15 March 2016 and published in the Daily Tribune on 23 March 2016.
121. What is the status of the CSP Implementing Guidelines (IG)?
The Joint DOE & ERC Technical Working Group on CSP (CSP-TWG) was created to formulate the CSP-IG. Said group had several meetings to discuss and prepare the CSP IG. The draft IG prepared by the ERC CSP- TWG, in coordination with the DOE CSP-TWG will be revised to be aligned with the proposed Senate Bill No.1308 introduced by Senator Sherwin Gatchalian.
122. How is CSP implemented in off-grid areas?
On 24 January 2004, DOE issued Department Circular (DC) No. DC2004- 01-001 which prescribes the rules and procedures for Private Sector Participation (PSP) in existing NPC-SPUG areas pursuant to Rule 13 of the Implementing Rules and Regulations of the Electric Power Industry
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Reform Act of 2001 (EPIRA-IRR). This circular requires the conduct of a competitive selection process (CSP) in selecting one or more New Power Provider (NPP) that will take over the generation function of NPC-SPUG.
123. What are the salient features of DOE Department Circular 2004-01-001?
The said DOE DC also mandates the following:
a. Declaring all existing NPC-SPUG areas open for private sector participation b. Directing NPC-SPUG to privatize its power generation facilities and associated power delivery systems c. A Competitive Selection Process (CSP) that is required in selecting an NPP should ensure the following: 1) lowest long-term cost of power and services; 2) environmental compatibility with the local area; and 3) most advantageous implementation schedule.
d. Distribution Utilities (DUs) operating in NPC-SPUG areas shall have the following options in undertaking a CSP: 1) Request DOE to secure a Transaction Advisor or engage the services of a Transaction Advisor, at its own cost, to assist in selecting the appropriate NPP 2) Allow NPC-SPUG to assign its existing PSA to an NPP through a competitive process; or 3) Manage the competitive selection process by itself
e. Allow NPPs to lease or purchase existing NPC-SPUG generating assets as an option for the take-over of the generation function of NPC- SPUG.
124. What is the ERC issuance/s on CSP for off-grid areas?
Complementing DOE DC2004-01-001, the Energy Regulatory Commission (ERC) issued ERC Resolution No. 11 Series of 2005 to adopt the guidelines for the setting and approval of electricity generation rates and subsidies for missionary areas. This was later amended by ERC Resolution No. 21 Series of 2011 to provide the mechanism by which the Renewable Energy (RE) Developers for Missionary Electrification may avail of their cash incentive from the Universal Charge for Missionary Electrification as provided under the Renewable Act of 2008.
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The said resolutions specifically outline the procedure for the following:
a. Notice of CSP Launch; b. Award of PSA to NPP; c. Filing and Approval of the Power Supply Agreement (PSA) and the NPP’s True Cost Generation Rate (TCGR); d. Recovery of the NPP’s TCGR; e. Disbursement of the RE Cash Incentive; f. UC-ME Administration and Filing Requirements and Procedures
125. What is the status of the PSP program in off-grid areas?
As of December 2015, there are already ten (10) Small Island and Isolated Grids (SIIGs) which are being supplied by NPPS from which seven (7) have already attained the full privatization of their generation services (areas wherein NPC-SPUG has already ceased to operate).
126. WHAT ARE NEW DEVELOPMENTS IN ENHANCING AND UPDATING CSP POLICIES?
a. Senate Bill No. 1308 “An Act Institutionalizing Reforms in the Procurement by Distribution Utilities of Supply for the Captive Market”
This Senate Bill intends to institutionalize the CSP to enhance competition and transparency. Under this Bill, at least 70% of the uncontracted demand of DUs in grid and off-grid shall be subjected to an auction to be conducted through a
Third Party, which is the Philippine Electricity Market Company (PEMC), resulting to a Power Supply Contract with cooperation period of not more than five (5) years. The CSP period shall not exceed 60 days from the “advertisement of the invitation to bid until verification of ERC”.
The Third Party Auctioneer shall be regulated by the ERC and shall be entitled to a just and reasonable costs for services rendered.
On the other hand, the ERC, in coordination with DOE and NEA, shall prepare the CSP rules, which shall include but not limited to the following: i. Rules governing the Third Party Auctioneer (i.e. detailed scope of work, bonds and guarantees, costs and return recovery mechanisms, monitoring and evaluation framework, prohibited acts, and fines and penalties); ii. Rules for registration for all CSP participants with the Third Party Auctioneer; Page 70 of 207
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iii. Rules for registration of demand aggregators; iv. Rules for certification of wholesale aggregators; v. Detailed procedure and timeline for CSP; vi. Rules for determination of the reserve price for a CSP; vii. Standardized contents of an Invitation to Bid; viii. Standardized general conditions of a Power Supply Contract (PSC); ix. Guidance in the preparation of the particular conditions of a PSC; x. Procedure and requirements for reconsideration and complaints in accordance with the Bill’s Section 13 (Qualification) and Section 18 (Negligence and Abuse of the Third Party Auctioneer); xi. Procedure and requirements for negotiated PSCs by DUs in accordance with Section 17 (Exemptions from CSP); and xii. Other such rules, procedures, and requirements that will ensure the effective implementation of the Bill.
The Senate Committee on Energy has already conducted two (2) Technical Meetings on this bill.
b. House Bill No. 5617 “An Act Institutionalizing Reforms in the Procurement by Distribution Utilities of Supply for the Captive Market”
Similar to SB1308, the said legislative proposal from the House of Representatives aims to subject all the uncontracted demand of the captive market by the DUs into a CSP. Said House proposal sets the framework for the conduct of CSP including the establishment of Third Party Auctioneer. Being similar to the Senate Bill, it is expected that both houses of the Congress will later come up with a unified or harmonized legislation for CSP for immediate promulgation.
c. Policy Studies under European Union – Access to Sustainable Energy Programme (EU-ASEP)
In support to DOE’s missionary electrification program, EU-ASEP is conducting a study to review the CSP experience in off-grid area and to recommend solutions to policy and implementation gaps related to supply procurement in off-grid areas.
As a status, the study has drafted a new DOE Circular on CSP for Off-grid Areas based on initial consultations made with the concerned DUs in off-grid areas. At a step forward, the Circular shall be revised to incorporate salient features of the above proposed legislations on CSP, as applicable.
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POWER DEVELOPMENT PLAN
127. Why is there a need to prepare the Power Development Plan after the passage of EPIRA?
The DOE is mandated under Chapter II, Section 37 of EPIRA to prepare and update annually the Power Development Plan (PDP). The PDP 2016- 2040 provides the long-term outlook on the demand and supply requirements in three major Grids, namely: Luzon, Visayas and Mindanao. The PDP also presents the holistic power sector roadmaps for the short-, medium- and long-term planning horizons.
These roadmaps:
Draw their foundation on the DOE’s mandate to ensure the delivery of sustainable, stable, secure, sufficient, and accessible energy; Accord themselves with the DOE vision towards a globally- competitive energy industry that powers up Filipino communities through clean, efficient, robust and sustainable energy systems that will create wealth, propel industries and transform the lives of men and women and the generations to come; Encompass programs and policies for the generation, transmission, distribution and supply subsectors as well as market development and institutional support mechanisms; and Align their plans with the national vision contained in the Ambisyon 2040 that the Philippines shall be a prosperous, predominantly middle-class society where no one is poor; hence, a “Matatag, Maginhawa at Panatag na Buhay” (strongly rooted, comfortable, and secure life).
128. What is the difference of the PDP before and after EPIRA?
Prior to EPIRA, the PDP being formulated by the National Power Corporation (NPC) serves as an Investment Plan of the government for the power sector. The government is responsible to source out funds or is expected to provide guarantee to make sure that the needed capacities will come on line as programmed.
After EPIRA, the PDP provides an integrated road map to key stakeholders and investors regarding future demand and supply requirements specific for each of the three Grids (Luzon, Visayas and Mindanao). It also includes the power sector roadmaps for the short,
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medium, and long-term planning horizons encompassing the generation, transmission, distribution and supply subsectors as well as market development and institutional support mechanisms.
129. What is Peak demand, Co-incident peak demand and Non- coincident demand?
Peak demand is the highest demand (MW) at one point in time in a year. The demand recorded by the System Operator is termed as “system peak.” In the case of distribution utilities which do not have metering device to accurately record the peak demand, they use the average demand computed from the sales and load factor.
Coincident peak demand is a point in time that the system comprising of several grids attain the highest level at the same time. That particular demand may not be the peak for individual grids considered.
Non-coincident peak demand is the aggregate of the peak demand of the grids, which may or may not be at the same time in a year. As expected, the non-coincident peak demand is higher than coincident peak. This is exemplified in the Visayas grid wherein there are several sub-grids. The aggregate peak demand of Leyte-Samar, Bohol, Cebu, Negros and Panay will not be the same as the Visayas system peak, unless the peak demands for the five sub-grids occur at the same time.
130. What are the approaches being done by DOE in forecasting demand?
Following are the steps in coming up with the electricity sales and peak demand forecasts for the three main grids:
a. Data Collection
Actual baseline data (2015) on the following were collected to serve as the reference forecast scenario for the coming years:
1) Power Generation submitted by Generation Companies (GenCos) through their Monthly Operations Report (MOR); 2) Power Delivered by the National Grid Corporation of the Philippines (NGCP) to Distribution Utilities (DUs), Non-Utility Customers or directly-connected industries, Economic Zones, Government Owned Utility (GOU) and Generation Customers; 3) Electricity Sales and Consumption sourced from the MOR Page 73 of 207
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submitted by private DUs and Monthly Financial and Statistical Report (MFSR) submitted by Electric Cooperatives (ECs) thru the National Electrification Administration (NEA); and 4) Other relevant data such as station use, transmission losses, peak demand and load factor gathered by the DOE
b. Electricity Sales and Peak Demand Forecasts
The high GDP growth projection of the Development Budget Coordination Committee (DBCC) and the electricity consumption to gross regional domestic product (GRDP) of Luzon, Visayas and Mindanao based on historical trend were used and applied to the actual (2015) electricity sales to come up with the baseline electricity sales forecasts. This high GDP growth forecast is aligned with the long-term goal towards industrialization and increase in income per capita which leads to higher electricity demand.
The historical average of the actual electricity-to-GRDP elasticity was used for Luzon and Visayas while the elasticity adopted for Mindanao is pegged at 1.0 to account for the suppressed electricity demand and insufficient supply during the previous years. This elasticity level is also fixed at 1.0 in anticipation of demand side expansion in the region for the coming years brought by the commercial operation of large power generation plants starting 2015.
c. Peak Demand Forecasting
From the energy sales forecasts, the actual (2015) Station Use (SU) and Transmission Losses (TL) are added to come up with the gross generation. From this gross generation, the peak demand forecasts are derived using the load factor approach which is also based on the actual load factor for (2015).
131. When do we say that there is a power shortage?
Technically, there is a power shortage if the existing available capacity is below the following operational reserve margins:
a. Required Regulating Reserve (RR) which is equal to 4 % of the peak demand and allocated exclusively to cover inter‐ and intra‐hour variations in demand (load behaviors), variations from generation schedules and hourly forecasts for regulation of frequency and voltage level in the system;
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b. Required Contingency Reserve (CR) which is the synchronized generation capacity from Qualified Generating Units, equivalent to the largest synchronized generating unit, allocated to cover the loss or failure of a synchronized generating unit or a transmission line or the power import from a single circuit interconnection, whichever is larger (647 MW for Luzon, 150 MW for Visayas, and 150 MW for Mindanao); and
c. Required Dispatchable Reserve (DR) which is the Generating capacity, equivalent to the second largest synchronized generating unit, that is readily available for dispatch in order to replenish the Contingency Reserve Service whenever a generating unit trips or a loss of a single transmission interconnection occurs. (647 MW for Luzon, 135 MW for Visayas, and 150 MW for Mindanao)
Based on the illustration above, if the total available capacity is within the required dispatchable reserve level, the system is on normal state considering that there is sufficient reserve margin in the grid. Once there will be capacity outage which will cause the capacity below the required contingency reserve level, the system will be on Yellow Alert state. The system operation, which is the NGCP, alarms all energy stakeholders that the contingency reserve is less the required level.
When the system’s available capacity continues to fall below required regulating reserve level, the NGCP will now announce Red Alert State wherein the system has zero contingency reserve in the system and existence of generation deficiency which may lead to Manual Load
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Dropping (MLD) or rotating “Brownout” in order to balance the demand to the remaining available capacity in the grid.
132. What are the considerations in coming up with the additional capacity requirement?
For the 2016-2040 PDP, to determine the annual capacity addition per type of plant operation (baseload, mid-range and peaking), the peak demand forecast plus reserve requirement, which is set at 25 % of peak demand, was subtracted from the existing average available capacity and committed capacities. Dependable capacity was used to consider the yearly de-rating and to exclude the station use of power plants in the demand-supply simulation.
Baseload power plants that provide continuous, reliable and efficient power at low cost such as coal, existing natural gas, geothermal, biomass, and baseload hydroelectric power plants were accounted. For peaking power plants which provide power during high demand period, oil-based, wind and solar photovoltaic (PV) power plants were considered. For mid- merit power plants which are more flexible in operation than baseload and cheaper than peaking plants, new natural gas-fired power plants were included in the simulation.
To ensure secure, reliable and sufficient supply of electricity, a 70 % baseload was set as a minimum requirement for capacity addition for the future years.
133. What are the total committed and indicative capacities for Luzon, Visayas, and Mindanao?
Committed power projects are those private sector initiated projects that secured financial closing in their project leading them to a firm commercial operation schedule and EPC program. On the other hand, indicative projects are those projects that are still undergoing pre-development stage process such as securing permits, clearances and certificates.
Based on DOE’s List of Committed and Indicative Power Projects as of June 2017, the total committed and indicative capacities, coming for all existing plant technologies in the country, for the three grids are shown on the following tables:
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COMMITTED 2017 2018 2019 2020- 2025 TOTAL PER GRID LUZON 785 653 1,400 1,304 4,142 VISAYAS 94 244 30 40 408 MINDANAO 588 570 131 0 1,289 TOTAL PER 1,467 1,467 1,561 1,344 5,839 YEAR
2017 2018 2019 2020-2025 TBD TOTAL INDICATIVE LUZON 273 916 2,834 3,894 8.196 16,113 VISAYAS 175 329 237 1,976 787 3,504 MINDANAO 0 553 342 950 697 1,289 TOTAL PER YEAR 448 1,798 3,413 6,820 9,680 22,159 Source: DOE’s Private Sector-Initiated Power Projects as of December 2016
The total capacities for both committed and indicative projects are based on the plant’s scheduled commercial operation.
134. What is baseload, mid-range and peaking plants?
Baseload Plants are those generating facilities which can generate dependable power to consistently meet demand. These plants produce continuous, reliable and efficient power at low cost and run at all times throughout the year except in the cases of repairs or scheduled maintenance. Baseload power plants have capacity factors at 67% and above which are typically coal, geothermal and biomass (subject to availability of feedstock as fuel) power plants.
Intermediate/Mid-Merit Plants are facilities that fill in the gap between base load and peaking plants. Compared to peaking plants, intermediate/mid-merit plants are more efficient in terms of operation because it can run for a longer period of time. Mid-merit plants incur higher construction cost but lower operational cost compared to peaking plants. Mid-merit plants, such as natural gas, have capacity factors ranging from 23% to 67%.
Peaking Plants are generating facilities that provide power during peak system demand periods. Peaking plants can start up and respond quickly to changes in electrical demand. These plants are very expensive to operate (for oil-based power plant due to usage of diesel/bunker oil as fuel). Peaking plants, such as solar, wind, hydro and oil-based power plants, have capacity factors below 23%.
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POWER GENERATION
135. What are the major sources of power in the country?
PHILIPPINES FUEL TYPE Capacity (MW) Percent Share (%) Installed Dependable Installed Dependable Coal 7,569 7,230 35.0 37.0 Oil Based 3,584 2,816 16.6 14.4 Natural Gas 3,431 3,291 15.9 16.8 Renewable Energy(RE) 7,038 6,199 32.5 31.7 Geothermal 1,906 1,752 8.8 9.0 Hydro 3,637 3,241 16.8 16.6 Wind 427 383 2.0 2.0 Biomass 224 160 1.0 0.8 Solar 843 663 3.9 3.4 TOTAL 21,621 19,536 100.0 100.0 Source: DOE List of Existing Power Plants as of December 2016
As of 30 June 2017 the countries installed capacity stood at 21,423 MW. Coal fired power plants accounted the highest at 35% or 7,569 MW installed capacity. Oil-based power plants and natural gas plants closely followed at 16.96% (3,584 MW) and 15.9 % (3,431 MW), respectively.
Renewable Energy (RE) -based sources had a total installed capacity of 7,047 MW this 2017 or about 32.6 percent share of the country. Conventional RE technology such as Hydroelectric power plants have about 16.8 percent (3,637 MW), Geothermal plants have about 8.9 percent share (1,916 MW) and Biomass type has 1.0 percent (224 MW) share in the total installed capacity mix. On the other hand, variable renewable energy (VRE) sources have developed immensely in 2017 wherein solar capacity grew to 843 MW or 3.9 percent share in capacity mix while wind capacity maintain its share at 427 MW installed capacity or 2.0 percent.
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136. How much electricity is produced by fossil fuel and Renewable Energy?
2016 Generation PHILIPPINES by Plant Type GWh % Share Coal 43,303 47.7 Oil-based 5,661 6.2 Natural Gas 19,854 21.9 Renewable Energy (RE) 21,979 24.2 Geothermal 11,070 12.2 Hydro 8,111 8.9 Biomass 726 0.8 Solar 1,097 1.2 Wind 975 1.1 Total Generation (GWh) 90,798 100.0
PHILIPPINES GENERATION FOR 2016 Plant Type Total Generation (GWh) % Share Fossil Fuel 68,818 75.8% Renewable 21,979 24.2% Energy (RE) Total Generation 90,798 100% Source: DOE Power Statistics 2016
Fossil fueled power plants (coal, oil-based and natural gas) accounted for almost ¾ of the generation share or 32,345 GWh in the country for the first half of 2017, while generation from Renewable Energy was at 12,303 GWh or 27.6 percent of the total generation.
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137. How much electricity is produced using local fuel against imported fuel? Or the country’s self-sufficiency level for power generation?
PHILIPPINES 2016 Generation PLANT TYPE GWh %Share Coal 43,303 47.7 Oil-Based 5,661 6.2 Natural Gas 19,854 21.9 Renewable Energy (RE) 21,979 24.2 Total Generation 90,798 100.0
PLANT TYPE GWh % Share Generation from
Local Fuel Local Coal 4,489 4.9 Natural Gas 19,854 21.9 Renewable Energy (RE) 21,979 24.2 Self-Sufficiency (%) 46,322 51.0 Source: DOE Power Statistics 2016
Self-sufficiency level or electricity produced in the first half of 2017 using local fuel posted at 53.4 percent or 23,855 GWh. Of the local fuel, generation from Renewable Energy contributed the highest share at 27.6 percent or 12,303 GWh followed by Natural Gas at 21.0 percent or 9,354 GWh and local coal at 4.9 percent or 2,198 GWh.
138. What sector consumed most of the electricity?
1st Half 2017 Electricity Sales & Consumption by Sector, Philippines
Philippines 2016 Consumption (GWh) % Share Residential 13,675 34.5
Commercial 11,144 28.1
Industrial 10,500 26.5
Others 971 2.5
Total Sales 36,290 91.6
Own-Use 58 0.2
System Loss 3,250 8.2
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For the first half of 2017, electricity sales to the residential sector, composed of households, consumed 34.5 percent or 13,675 GWh while industrial sector, composed of energy-intensive industries such as manufacturing establishments and factories, accounted for 26.5 percent or 10,500 GWh of total electricity sales. Commercial sector, composed of private establishments such as malls and private offices, stood at 28.1 percent or 11,144 GWh. Lastly “others” such as public buildings, street lights, irrigation posted at 2.5 percent or 971 GWh. .
139. How much is the increase in electricity demand in 2015 from 2014 and 2016 from 2015?
Comparison of 2016 and First Half 2017 Peak Demand from Luzon, Visayas and Mindanao Peak Demand (MW) Deviation/ Difference st GRID Half 2016 MW % 2017 LUZON 10,054 9,726 328 3.4 VISAYAS 1,933 1,893 140 2.1 MINDANAO 1,696 1,653 43 2.6 TOTAL (Non- coincidental) 13,683 13,272 391 3.3 Source: DOE Power Statistics NGCP Daily Operation Report (DOR)
The system peak demand for the grids increased significantly as shown in the above table. For the first half of 2017, the peak demand for the Luzon Grid was recorded at 10,054 MW which occurred on 9 May 2017. This was 3.4 % or 328 MW higher than the recorded demand of 9,726 MW which happened in the same month last year. This was attributed to the high electricity consumption due to high temperature and increased utilization of air conditioning and other cooling equipment of the residential and commercial sector especially during summer period.
System peak demand continued to increase for the first half of 2017 in the Visayas with 2.1% growth rate. Its highest recorded coincident peak demand occurred on 19 May 2017 at 1,933 MW.
In Mindanao, the recorded highest demand, including embedded loads, was at 1,696 MW which occurred on 18 April 2017. This was higher by 2.6% from 1,653 MW in 2016. Mindanao’s peak demand usually occurs during the latter part of the year where hydro capacity is high.
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Comparison of 2015 and 2016 Peak Demand from Luzon, Visayas and Mindanao
Peak Demand (MW) Deviation/Difference GRID 2016 2015 MW % LUZON 9,726 8,928 798 8.9 VISAYAS 1,893 1,768 124 7.0 MINDANAO 1,653 1,517 136 9.0 TOTAL (Non- 13,271 12,213 1,058 8.7 coincidental) Source: DOE Power Statistics NGCP Daily Operation Report (DOR)
Luzon reached new all-time high system peak demand at 9,726 MW which occurred on 03 May 2016 at 2:00 PM with corresponding 11,137 MW of available capacity. This is 8.9% higher than the 2015 peak demand at 8,928 MW. About 800 MW increase of demand was due to the El Nino phenomenon which hit the country starting second half 2015 up to June 2016, including summer season where electricity consumption is expected to rise up proportionately with the temperature.
Same with Luzon, Visayas reached their Highest System Demand at 1,892 MW on 5 May 2016, 1:28 PM with corresponding 2,242 MW of Available Capacity. This is 7.0% higher than the 2015 peak demand at 1,768 MW.
Highest System Demand in Mindanao at 1,653 MW occurred on 01 December 2016, 5:51 PM with corresponding 1,931 MW Available Capacity. This is 9.0% higher than the 2015 peak demand at 1,517 MW.
TRANSMISSION
140. What is the National Transmission Corporation (TRANSCO)?
TransCo is the government-owned and controlled corporation created pursuant to Republic Act 9136 to acquire all the transmission assets of the National Power Corporation. TransCo is the owner of the transmission network.
141. What is the National Grid Corporation of the Philippines (NGCP)?
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Act of 2001" (EPIRA). Under Republic Act No. 9511 (R.A. 9511) or “An Act Granting the National Grid Corporation of the Philippines A Franchise to Engage in the Business of Conveying or Transmitting Electricity Through High Voltage Backbone System of Interconnected Transmission Lines, Substations and Related Facilities, and For Other
Purposes”, it has the responsibility to operate, manage and maintain the nationwide
Grid of the Republic of the Philippines, for a term of fifty (50) years. The NGCP is both the Transmission Network Provider and the System Operator.
142. What is Transmission Development Plan (TDP)?
The TDP refers to a plan for managing the transmission system through efficient planning for expansion, upgrading, rehabilitation, repair and maintenance, to be submitted to the DOE.
143. Who prepares the TDP?
TRANSCO or its Buyer or Concessionaire (NGCP) shall be responsible for the preparation of the TDP, in consultation with the Electric Power Industry participants.
144. What is DOE’s responsibility on the TDP?
In view of the Electric Power Industry Reform Act of 2001 (EPIRA), the DOE is mandated to approve the TDP. The DOE, following its approval of the TDP prepared by the TRANSCO or its Buyer or Concessionaire, shall integrate the TDP with the Power Development Program (PDP) and the Philippine Energy Plan (PEP). The DOE is also responsible for providing, among others, the System Peak Demand Forecast and the List of Generation Capacity Addition to NGCP, which are the two major inputs in the TDP.
145. How is the TDP prepared?
Section GP5.2.7, Chapter 5 (Grid Planning) of the Philippine Grid Code (PGC) prescribes the following procedures in the preparation of the TDP:
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a. The Transmission Network Provider shall collate and process the planning data submitted by the Users into a cohesive forecast and use this in preparing the data for the TDP. b. The development of the TDP shall aim at the identification of the least economic cost development of the Grid to supply the forecasted Demand, with due attention being paid to:
1) Directives issued by the DOE in relation with the implementation of the Energy Policy; 2) Compliance with the Performance Standards established in the Performance Standards for Transmission (PST) of the PGC; 3) Compliance with the Grid Operating Criteria; 4) Ensuring safety, reliability, security, and stability of the Grid; 5) Allow appropriate integration into the Grid of new generation projects;
c. In developing the TDP, the Transmission Network Provider shall consult with the other participants of the electric power industry such as the System Operator, Generation Companies, Distribution Utilities, Market Operator, Users, and other concerned entities in order to gather inputs and concerns to enhance the Grid planning process.
d. In evaluating alternatives for Grid development, special attention shall be paid toprojects aimed to: 1) Reducing the requirements of out-of-merit Dispatched units; 2) Reducing existing and/or potential Congestion problems that appear in the Grid, either in Normal State or as a result of an Outage Contingency, which may result in increased risk of Outages or raise the cost of service or the electricity prices; 3) Reduction of losses in the Grid; and 4) Reduction of the costs for the development of the Distribution System. In all these cases, an economic analysis should be performed, aimed to select the technically feasible alternatives with the least cost.
146. What are the major sections of the TDP?
The major sections of the TDP are the following:
a. Major Network Development - focuses on the proposed network expansion and upgrades which are generally based on the system simulation studies conducted by NGCP;
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b. Operation and Maintenance - covers the plans to maintain, operate, expand and improve the high voltage backbone transmission system and facilities. It contains the Capital Expenditure (CAPEX) program of O&M which primarily aims to increase the reliability of the grid and address the aging problems of transmission facilities; c. Metering Services – contains the Proposed expansion, upgrade, rehabilitation and replacement programs of NGCP for Transmission Revenue Metering Facilities; and d. System Operations – contains the proposed upgrading, restoration, repair and/or maintenance projects for telecommunication systems and infrastructures, protection, SCADA and other supervision-related applications and equipment necessary for the effective management of the grid, system’s reliability and generation dispatching including, but not limited to, market operations and arrangement for ancillary services.
147. What are the Major Drivers for Transmission Project Development?
The following are the major transmission project drivers:
a. Load Growth – this pertains to ensuring transmission facility adequacy and given top most priority are projects to address the projected overloading which will occur even during normal condition or no outage condition. b. Generation Entry – this pertains to accommodation of new power plant connections to the grid and bulk generation capacity additions would usually drive new transmission backbone development. c. Power Quality – this involves the installation of equipment that will aid in operating the grid within the grid code prescribed voltage limit. d. System Reliability – this pertains to projects that will provide N-1 contingency and projects that will upgrade aging facilities or replace defective equipment. e. Island Interconnection - this refers to new interconnection facilities to link isolated island grid. These are special projects which include the Visayas-Mindanao Interconnection Project and Batangas-Mindoro Interconnection Project.
148. What is the status of the Visayas-Mindanao Interconnection Project (VMIP)?
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already finished, with the results favoring a more feasible connection through the western route, Mindanao to Cebu route. NGCP already filed an application for the approval of the implementation of the VMIP to the ERC, with prayer for Provisional Authority, and was received by ERC on 27 April 2017. The ERC conducted three (3) hearings for the said application to determine compliance with jurisdictional requirements, conduct NGCP’s Expository presentation, conduct Pre-trial Conference, and for the presentation of evidence. The estimated time of completion of the project is on December 2020, subject to ERC approval.
149. What is the Status of the proposed Batangas-Mindoro Interconnection Project (BMIP)?
This project involves the interconnection of Mindoro to the Luzon Grid via NGCP’s Batangas 230 kV substation. Based on the 2014-2015 TDP, target date of completion is March 2021. On 01 August 2011, NGCP filed the said project with the Energy Regulatory Commission, which was docketed as ERC Case No.2011-108 RC.
DISTRIBUTION
150. What is a Distribution Development Plan?
The Distribution Development Plan (DDP) is a five-year plan prepared annually by all distribution utilities (DUs) for managing their distribution systems and ensuring continuous, reliable and affordable electricity service to its customers through identification of infrastructure requirements and timely procurement of power supply agreements.
151. What is the legal basis of the DDP?
Chapter II, Section 23 of the EPIRA and Section 7, Rule 4(p) of the EPIRA-Implementing Rules and Regulations mandates all DUs to prepare and submit annually their five-year DDP to the DOE every 15th of March of every year. In the case of electric cooperatives (ECs), their DDPs shall be submitted through the National Electrification Administration (NEA) for review and consolidation.
152. What are the DOE issuances on DDP?
On DOE issued DOE Department Circular No.DC2004-02-002 “Prescribing the Guidelines for the Formulation of a Five-Year Distribution Development Plan Pursuant to Section 2 of Department of Energy Circular No.DC2003-12-011, entitled “Enjoining All Distribution Utilities to Supply Adequate, Affordable, Quality and Reliable Electricity”
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153. What are the contents of the DDP?
The DDP has the following major contents:
a. Historical Data (Coincident Peak Demand, System Loss, Energy Purchased, Energy Sales, Number of Customers) b. Barangay and Sitio Electrification Program c. Household Electrification Program d. Demand and Energy Requirements (Grid and Off-grid; Annual, Monthly & Hourly) e. Supply Plan (Contracted, For PSA Approval, Under Negotiation) f. Infrastructure/Capital Expenditure Requirements and corresponding financial costs g. One Page DDP Summary
154. What is the DOE’s responsibility on the DDP under the EPIRA?
Pursuant to Section 37(c) of the EPIRA, the DOE is mandated to integrate the DDP of DUs in the Power Development Plan (PDP) and in the Philippine Energy Plan (PEP). With this mandate, the DOE prepares annually a consolidated national DDP from the NEA’s submission of the National Electric Cooperatives Distribution Development Plan (NECDDP) and DDP submissions of private investor-owned utilities (PIOUs) and other DUs.
155. What is NEA’s responsibility on the DDP under the EPIRA?
Section 7, Rule 4(p) also requires the NEA to review the annual DDP submissions of the ECs and consolidate the same into the NECDDP for submission to DOE not later than 15th March of every year.
156. What is the importance of the DDP in the PDP?
The consolidated growth rate of electricity sales forecasts of DUs (PIOUs and ECs) derived from the submitted 2016-2025 Distribution Development Plans were used and applied to the actual electricity sales of the reference year (2016) to come up with the electricity sales forecast for Luzon, Visayas and Mindanao from 2017-2025. From this baseline forecast, electricity sales from non-utility, government-owned utilities, economic zones and un-served energy sourced from the NGCP were added to come up with the total electricity sales forecast. This is to synchronize the consolidated DUs’ data with that of the actual energy which have been transmitted to the high voltage lines of NGCP.
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157. What is a distribution utility?
A distribution utility is an entity that has an exclusive franchise to operate a distribution system.
158. What is a distribution system?
A distribution system refers to the system of wires and associated facilities belonging to a franchised distribution utility extending between the delivery points on the transmission or sub-transmission system or generator connection and the point of connection to the premises of the end-user.
159. What are the types of distribution utilities?
Distribution utilities are categorized as follows: (a) Electric Cooperatives (ECs); (b) Private Investor-Owned Utilities (PIOUS); (c) Local Government Unit-Owned Utilities (LGUOUs); and (d) Multi-Purpose Cooperatives (MPCs).
To date, there are 150 DUs in the country, of which 121 are ECs, 22 PIOUs, 5 LGUOUs, and 2 MPCs.
DUs No. Remarks
Luzon Visayas Mindanao Total
ECs 56 31 34 121 PIOUs 12 6 4 22 LGUOUs 4 0 1 5 The 5-year franchise of PAMES approved/granted by NEC on 8 March 2006 has already expired. MPCs 0 2 0 2 Total 72 39 39 150
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MISSIONARY ELECTRIFICATION DEVELOPMENT PLAN (MEDP)
160. What is missionary electrification?
It refers to the provision of basic electricity service in Unviable Areas with the ultimate aim of bringing the operations in these areas to viability levels, including the provision of power generation and associated power delivery systems in areas that are not connected to the transmission system. (ERC Resolution No. 21, Series of 2011)
161. What are off-grid systems/areas?
These refer to the electrical systems not connected to the interconnected transmission lines, distribution lines, substations and related facilities for the purpose of conveyance of bulk power on the grid of the Philippines. (Section 4 (jj) of RA 9513 or Renewable Energy Act of 2008).
162. What Is A Missionary Area?
This refers to an area which cannot be served in the foreseeable future in a financially feasible way by the extension of TransCo’s transmission grid. (2016 MEDP).
163. What is an unviable area?
It refers to a geographical area within the Franchise Area of a Distribution Utility where immediate extension of distribution line is not feasible. (Rule 4 of EPIRA-IRR)
164. Who performs missionary electrification function?
Missionary electrification functions are performed by National Power Corporation (NPC) through the Small Power Utilities Group (SPUG), Private Sector Participation (PSP) and Distribution Utilities(DUs).
165. What is Missionary Electrification Development Plan (MEDP)?
MEDP is a government’s plan formulated by the Department of Energy that will implement policies and programs to sustain the provision of adequate, reliable, and efficient supply of electricity in missionary or off-grid areas and to
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enable communities in those areas receive the benefit of electrification (2009 MEDP).
166. Where do missionary electrification funds come from?
As mandated in Section 70 of RA 9136 of EPIRA of 2001, missionary electrification function shall be funded through the revenues from sales in missionary areas and from the universal charge to be collected from all electricity end-users as determined by the ERC.
167. What is Missionary Electrification Universal Charge (UC- ME)?
It shall refer to the Missionary Electrification component of the Universal Charge, expressed in Peso per Kilowatt-hour, determined, fixed and approved by ERC and applied to all electricity end-users as provided for in Section 34 of the EPIRA.
168. Why is Private Sector Participation (PSP) encouraged in off-grid/unviable areas?
This is given in Section 3(b) of Rule 13 of Implementing Rules and Regulations of EPIRA that the National Power Corporation-Small Power Utilities Group (NPC-SPUG) shall periodically assess the requirements and prospects for bringing its functions to commercial viability on an area- by-area basis at the earliest possible time, including a program to encourage private sector participation.
Also, PSP is expected to improve generation efficiency, provide much- needed capital and offer significant cost and reliability benefits to the end- consumer; consequently, it will be required to meet future demand growth.
EPIRA REFORM
169. What is Retail Competition and Open Access (RCOA)?
Retail Competition refers to the provision of electricity to a Contestable Market by Suppliers through Open Access.
Open Access refers to the system of allowing "any qualified person the use of transmission and/or distribution system, and associated facilities subject to the payment of transmission and/or
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distribution retail wheeling rates duly approved by ERC.
This means that End-users classified as Contestable, defined through a demand threshold, initially those with an average demand of 1 MW and above for the preceding 12-month period, will be able to choose their Supplier of electricity which will be conveyed through the distribution wires of a Distribution Utility subject to the payment of wheeling rates. Accordingly, the timeline for Contestability is set as follows:
26 JUNE 2013
Initial Commercial Operation for 1 MW Option for CCs to remain with DUs
26 February 2017
Full Contestability for 1 MW and up Voluntary Contestability for 750kW and up
26 June 2017
Full Contestability for 750kW and up Retail Aggregation
26 JUNE 2018
Optional for 501 kW to below 750 kW subject to ERC determination Continuing evaluation by ERC
170. What are the main reasons behind RCOA?
The rationale for the RCOA is to enable customers to choose their electricity provider based on the quality of the services and the price that the customers prefer. This concept is often referred to as Customer Choice, such that when a customer is not satisfied with the services of its existing Supplier commonly known as Retail Electricity Supplier (RES), it may at any time switch to another RES so that its preferred kind of service will be met.
With the implementation of RCOA, the expected growth for electricity demand will be met through the additional investments brought by many energy suppliers competing to attract customers by providing the best services at the lowest cost.
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RCOA may also bring innovation to the electric power industry as RESs plan for different marketing strategies as customers’ preferences differ and become more sophisticated. The innovation may include offering services that consists of using clean energy sources, energy efficiency technologies, tendering advice for energy management, other value- added services or incentives, or simply offering the best rates.
171. When was the initial commercial operation of RCOA?
RCOA started commercial operations on 26 June 2013, two (2) years after the ERC declaration of compliance with the pre-requisites provided for under Section 31 of the EPIRA.
172. What is the status of commercial operation of RCOA to date?
As of January 2017, out of 1,065 prospective RCOA participants, the Central Registration Body (CRB) registered a total of 633 participants while 328 applicants for registration are in process. From the 275 registered participants in June 2013, the number of participants significantly increased by 358 in January 2017 wherein 323 are Contestable Customers.
Status of RCOA Commercial Operations, January 2017
Total June January Participants % Change Applicant Registered 2013 2017 and Applicant Retail Electricity 15 22 47% 0 22 Supplier Local Retail Electricity 3 12 300% 0 12 Supplier Retail Metering 18 29 61% 1 30 Service Provider Contestable Customer 239 562 135% 325 869 Supplier of Last Resort 0 8 100% 2 10
Total 275 633 130% 328 961 Note: Table includes only those who have already registered with the CRB.
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173. Who are the ERC Registered Retail Electricity Suppliers (RES)?
As of January 2017, there are 26 RES already licensed by the ERC. However, 22 have so far registered with the CRB:
a. Premier Energy Resources Corporation b. TeaM (Philippines) Energy Corporation c. Trans-Asia Oil & Energy Development Corporation d. Masinloc Power Partners Company Limited e. Kratos RES, Inc. f. Aboitiz Energy Solutions, Inc. g. Advent Energy, Inc. h. Prism Energy, Inc. i. San Miguel Electric Corporation j. SN Aboitiz Power-RES, Inc. k. DirectPower Services, Inc. l. First Gen Energy Solutions, Inc. m. Ecozone Power Management, Inc. n. Global Energy Supply Corporation o. GNPower Ltd. Co. p. Waterfront Mactan Casino Hotel, Inc. q. Millenium Power RES, Inc. r. FDC Retail Electricity Sales Corporation s. AC Energy Holdings, Inc. t. Manta Energy, Inc. u. SMC Consolidated Power Corporation v. Corenergy, Inc. w. KEPCO SPC Power Corporation x. Citicore Energy Solutions, Inc. y. Vantage Energy Solutions and Management, Inc. z. Mazzaraty Energy Corporation
174. Who are the ERC Registered Local Retail Electricity Suppliers?
As of January 2017, there are 24 ERC-authorized Local Suppliers. Out of the 24, only 12 have already registered transactions in the CRB:
a. Angeles Electricity Corporation (AEC) b. Manila Electric Company (MERALCO) c. Dagupan Electric Corporation (DECORP)
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d. Visayan Electric Company (VECO) e. Subic Enerzone Corporation (SEZ) f. Bohol Light Company, Inc. (BLCI) g. Tarlac Electric, Inc. (TEI) h. San Fernando Electric Light & Power Co. (SFELAPCO) i. Ilocos Norte Electric Cooperative, Inc. (INEC) j. Nueva Ecija I Electric Cooperative, Inc. (NEECO I) k. Cebu I Electric Cooperative, Inc. (CEBECO I) l. Cebu III Electric Cooperative, Inc. (CEBECO III) m. Batelec II Electric Cooperative, Inc. (BATELEC II) n. Benguet Electric Cooperative, Inc. (BENECO) o. Cebu II Electric Cooperative, Inc. (CEBECO II) p. Pampanga II Electric Cooperative, Inc. (PELCO II) q. Tarlac II Electric Cooperative, Inc. (TARELCO II) r. Camarines Sur II Electric Cooperative, Inc. (CASURECO II) s. Leyte II Electric Cooperative, Inc. (LEYECO II) t. Central Negros Electric Cooperative, Inc. (CENECO) u. Batangas I Electric Cooperative, Inc. (BATELEC I) v. Quezon I Electric Cooperative, Inc. (QUEZELCO I) w. Nueva Ecija II Electric Cooperative, Inc. (NEECO II) x. Cabanatuan Electric Corporation (CELCOR)
175. Was the EPIRA a result of an outcry for a cheaper electricity rate?
Partly, the EPIRA was envisioned to achieve a more reasonable cost of electricity for the consumers. More importantly, the power sector reforms were implemented to achieve transparency in the operations and the pricing system to reflect the "true" cost of electricity, and at the same time improve the delivery of power supply to end-users. Further, the reforms were envisioned to encourage private sector investments in the electric power industry and sustain the growing electricity demand. The reforms were pushed in the hope that the same benefits would be gained as that of economies which went on ahead of the reforms such as United Kingdom.
176. What is the Electric Power Industry Reform Act of 2001 (R.A. 9136)?
RA 9136 is a law passed on 08 June 2001, which provides the framework for the restructuring of the Philippine electric power industry and the total electrification of the country.
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Among other benefits, RA 9136 is envisioned to make electricity rates more transparent, achieve higher efficiency in the operations of utilities and related agencies thereby improving the delivery of power supply to end-users. As an end-goal, the EPIRA aims to give electricity End-users a CHOICE of supply of electric power.
Under the EPIRA regime, the electric power industry will be unbundled into four sectors namely: generation, transmission, distribution and supply. Transmission and distribution will remain a natural monopoly while the generation and supply sectors will be competitive and open in order to attract private sector investments and help achieve the primary goal of EPIRA of ensuring supply security, availability and reliability. Alongside the establishment of the wholesale electricity spot market, the privatization or sale of NPC's generating power plants and IPP contracts is expected to trigger competition on the generation side. On the government side, this privatization will relieve the burden of ensuring continuous financing for the construction, operation and maintenance of hugely capital-intensive power generating plants to the private sector.
177. With RA 9136 in place, what reforms were instituted in the power industry?
Two (2) major reforms are embodied in RA 9136, namely, (a) the restructuring of the electricity supply industry and (b) the privatization of the National Power Corporation (NPC).
The restructuring of the electricity industry calls for the separation of the different components of the power sector namely: generation, transmission, distribution and supply. On the other hand, the privatization of the National Power Corporation (NPC) involves the sale of the state-owned power firm's generation and transmission assets (e.g., power plants and transmission facilities) to private investors.
These two (2) reforms are aimed at encouraging greater competition and at attracting more private-sector investments in the power industry. A more competitive power industry will in turn result in lower power rates and a more efficient delivery of electricity supply to end-users.
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178. With restructuring, will the power industry be fully deregulated?
No. The deregulation applies only to competitive segments such as generation and supply. This means that the prices imposed by generators and suppliers will not require the approval of the Energy Regulatory Commission (ERC) but will be based on their agreement with their customers. However, these entities will remain subject to compliance with operational and business standards set forth by relevant government agencies, such as the ERC and the DOE. Specifically, the generators and suppliers will remain subject to the anti-competitive practices guidelines as promulgated by the ERC. On the part of the DOE, the generators and suppliers, as members of the WESM, shall comply with the WESM Rules and its Market Manuals.
On the other hand, the rates being imposed for transmission and distribution services will be subject to approval and regulated by the ERC.
179. How can government ensure that consumers will be protected from undue and frequent increases in power rates?
RA 9136 has created the ERC as an independent, quasi-judicial regulatory body tasked to promote competition in the power sector, encourage market development and ensure customer protection and choice.
The ERC was provided with rate-setting functions to ensure that the rates being imposed to consumers are transparent and reasonable. The ERC has promulgated the applicable guidelines for the approval of the total electricity rates being imposed by Distribution Utilities to end-users. The ERC’s process of approval requires the conduct of public hearings in the localities where the rates will be imposed. In this regard, the end-users may participate in the said hearings and may submit its comments to the rate review/approval being conducted. This is in line with the rights and obligations of an end-user pursuant to the Magna Carta for Electricity Consumers.
The ERC likewise ensures that the electric power industry participants adhere to the competition policies/parameters promulgated and adopted pursuant to the EPIRA.
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180. Are there any safeguards in the law to prevent certain business groups or blocs from dominating the restructured power industry?
There are safeguards provided under the EPIRA to wit:
a. Cross-ownership prohibition for the transmission owner/service provider to engage in generation of energy. b. Limitation on the control or ownership by a group of companies: 1) Not more than 30% of the total installed capacity in a grid and 2) Not more than 25% of the installed capacity in the national grid. c. Contracting limitation between a DU and affiliate generation company of not more than 50% of the DU’s demand. d. Divestment for companies that are not publicly listed.
181. What are the safety nets for the avoidance of "sweetheart" deals?
Under Section 45b of EPIRA, a DU cannot buy more than 50% of its demand from an affiliate generation company. To countercheck, one can compare if a contract of an affiliate is above or at par the market prices. Thus, this is one way of checking sweetheart deals. ERC issued a guideline wherein the procurement of supply by a DU is required to go on an open competitive bidding process on the procurement of all of their power supplies. This means that a certain DU cannot just go straight and negotiate with a particular generation company for a power supply agreement. They have to go through an open competitive bidding or a Competitive Selection Process (CSP) for its supply of electricity. This bidding requirement provides a transparent procurement process to ensure that the supply contract that will be negotiated by the DU will be the least cost supply.
182. What guides the sale schedule of the NPC generating plants?
The main objective is to bring assets to the market in a timely manner under a plan that maximizes proceeds within PSALM’S procedures and limitations for fair and transparent auctions. The key considerations are:
a) Interest from strategic financial investors.
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b) Time required by bidders for due diligence and to prepare binding bids. c) Availability of supply contracts (TSCs/BSCs) for certain plants. d) Funding requirement of bidders and capacity of loan market. e) Legal pre-conditions (creditors consent) and outstanding plant specific issues (e.g. steam supply agreements). f) Fair and transparent process. g) Compliance with creditor’s conditions set in applicable MOUs and Omnibus Amendment Agreements (OAAs).
183. What is the status of the privatization of NPC generation assets in Luzon and Visayas?
PSALM has privatized a total of 28 power plants of different fuel resource in Luzon and Visayas with a total capacity of 4,364 MW or equivalent to 87% of the total generating capacity of NPC in Luzon and Visayas.
Status of Privatized Generation Assets as of 31 December 2016
Rated Capacity Winning Bid Power Plant Location Winning Bidder Turnover Date Price (US$M) (in MW)
Luzon 3,890.53 Korea Water Angat Norzagaray, Resources Hydroelectric 218.00 440.88 31-Oct-14 Bulacan Corporation (K- Power Plant Water) Bacon-Manito Bacon, Sorsogon Bac-Man Geothermal Power 150.00 28.25 3-Sep-10 & Manito, Albay Geothermal, Inc. Plants
Limay Combined Panasia Energy 620.00 Limay, Bataan 13.50 18-Jan-10 Cycle Power Plant Holdings, Inc.
Batangas (Calaca) Sem Calaca Coal-Fired 600.00 Calaca, Batangas Power 361.71 3-Dec-09 Thermal Corporation Palinpinon- Valencia, Negros Tongonan Green Core 305.00 Oriental & 220.00 23-Oct-09 Geothermal Power Geothermal, Inc. Kananga, Leyte Plants Ambuklao-Binga Bokod & Itogon, SN Aboitiz Hydroelectric 175.00 325.00 10-Jul-08 Benguet Power Hydro Inc. Power Complex
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Rated Winning Bid Power Plant Location Winning Bidder Turnover Date Capacity Price (US$M)
Masinloc Coal- Masinloc, Masinloc Power Fired Thermal 600.00 930.00 17-Apr-08 Zambales Partners Co., Ltd. Power Plant Magat SN Aboitiz Hydroelectric 360.00 Ramon, Isabela Power-Magat, 530.00 25-Apr-07 Power Plant Inc. Pantabangan- First Gen Hydro Masiway Pantabangan, 112.00 Power 129.00 17-Nov-06 Hydroelectric Nueva Ecija Corporation Power Plants Cawayan Sorsogon II Guinlajon, Hydroelectric 0.40 Electric 0.41 30-Jun-05 Sorsogon Power Plant Cooperative, Inc. Amlan Amlan Hydroelectric Amlan, Negros Hydroelectric 0.80 Power 0.23 24-Jun-09 Oriental Power Plant Corporation (AHPC) Tiwi-MakBan Tiwi, Albay & AP Renewables, Geothermal Power 747.53 446.89 25-May-09 Laguna/ Batangas Inc. Plants Barit Buhi, Camarines People's Energy Hydroelectric 1.80 0.48 24-Jan-05 Sur Services, Inc. Power Plant
Visayas 473.8
Power Barge 101 Bo. Obrero, Iloilo Trans-Asia Oil and Energy 9696 City 9.31 8-Jul-15 Power Barge 102 Development Power Barge 103 Zambales Corporation Naga Land-Based Colon, Naga, SPC Power Gas Turbine 55 1.01 29-Jan-10 Cebu Corporation Power Plant Naga Power Plant Colon, Naga, SPC Power 153.1 30.71 25-Sep-14 Complex Cebu Corporation Panay 1 & 3- SPC Island Dingle, Iloilo & Bohol Diesel 168.5 Power 5.86 25-Mar-09 Tagbilaran, Bohol Power Plants Corporation Loboc Sta. Clara Power Hydroelectric 1.2 Loboc, Bohol 1.42 30-Jun-05 Corporation Power Plant Mindanao 237.1 Agusan FG Bukidnon Manolo Fortich, Hydroelectric 1.6 Power 1.53 29-Mar-05 Bukidnon Power Plant Corporation Talomo 3.5 Mintal HEDCOR, Inc. 1.37 19-Jan-05
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Rated Winning Bid Power Plant Location Winning Bidder Turnover Date Capacity Price (US$M)
Hydroelectric &Catalunan Power Plant Pequeño, Davao City Therma Mobile Power Barge 117 100 Agusan del Norte 16.00 1-Mar-10 Inc. Compostela Therma Marine Power Barge 118 100 14.00 6-Feb-10 Valley Inc. SPC Island Power Barge 104 32 Ilang, Davao City Power 4.69 30-Jun-16 Corporation Total Capacity Privatized 4,601.43 Total Luzon/Visayas Privatized Capacity 4,364.30
Total Capacity for Privatization Luzon/Visayas 5,014.3 0 Priva level Luzon/Visayas 87% Total Capacity for Privatization Philippines 6,233.50
184. What is the schedule for privatization?
The table on the next page shows PSALM’s remaining assets for privatization and its indicative privatization schedule as approved by the PSALM Board. The privatization of these assets shall continue depending on an approved timetable by the PSALM Board and the direction that will be set by the DOE or by appropriate authorities. More so, schedule for the privatization of generation assets may change depending on the confluence of factors such as investor’s interest and plant-specific concerns.
Indicative Privatization Schedule for Gencos as of 30 November 2016
Asset Type/ Rated Capacity (MW) Bid Date Turnover Date Plant Name
Owned Generating Plants
Malaya Thermal 650.00 1st Semester 2017 Agus 1 & 2 Hydro 260.00 Agus 4 & 5 Hydro 213.10 1st Semester 2018 Agus 6 & 7 Hydro 254.00 Pulangui Hydro 255.00 Decommissioned Plants Sucat Thermal 850.00 1st Semester 2017 Bataan Thermal 175.00 Sale/disposal is subject to resolution of court cases involving the Bataan Gas Turbines 120.00 asset Note :Indicative Privatization Schedule for the Appointment of IPPAs as of 30 Nov. 2016
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Contracted Turnover Grid Plant Name Capacity Bid Date Date (MW)
Casecnan Multi-Purpose 140.00 2018 Hydro Luzon Benguet Mini Hydro 30.75 IPP contract to expire in 2018 Grid Caliraya-Botocan- 728.00 2018 Kalayaan Hydro Sub-total Luzon 898.75 Visayas Unified Leyte - Bulk 160.00* 2017 Grid Energy
Security Strip 40.00 Sub-total Visayas 200.00 Mindanao Coal-Fired 200.00 2018 Sub-total Mindanao 250.00 GRAND TOTAL 1,298.75
185. What is the status of the transfer of the contracted energy outputs of NPC-IPPS to IPP administrators?
PSALM had privatized IPP contracts to include the contracted capacities for Sual and Pagbilao coal-fired thermal power plants, San Roque, Bakun, Ilijan Natural Gas Combined Cycle Power Plant, and Unified Leyte GPP- Strips of Energy. This is equivalent to 77.46% of the total NPC contracted energy output in Luzon and Visayas thereby marking the completion of the five (5) preconditions for the implementation of the RCOA.
Status of Privatization of NPC-IPP Contracts as of December 2016
Contracted Capacity Plant Winning Bidder Remarks (MW)
Luzon 3,668.75
Pagbilao Coal-Fired Power Turned over on 01 700.00 Therma Luzon, Inc. Plant October 2009
Sual Coal-Fired Power San Miguel Energy Turned over on 06 1,000.00 Plant Corporation November 2009
Benguet Mini-Hydroelectric IPP contract will expire in 30.75 - Power Plant January 2018
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Contracted Capacity Plant Winning Bidder Remarks (MW)
Turned over on 26 Bakun Mini-Hydro 70.00 Amlan Power Holdings Corp. February 2010
San Roque Multipurpose Turned over on 26 345.00 Strategic Power Devt. Corp. Hydro January 2010 Ilijan Combined Cycle Turned over on 26 June 1,200.00 South Premier Power Corp. Power Plant 2010 Subic Diesel Power Plant 108.00 - Turned over to SBMA Turned over to Province Bauang Diesel Power Plant 215.00 - of La Union Privatized as part of the Tiwi-Makban power Makban Binary - AP Renewables Inc. plant/turned over in May 2009 Visayas 407.10 Turned over on 25 Naga Power Plant 153.10 SPC Power Corporation September 2014 Naga Land Based Gas Turned over in January 54.00 SPC Power Corporation Turbine 2010 FDC Utilities, Inc. (FDCUI) Unified Leyte Geothermal Energy Inc. (ULGEI) Trans-Asia Oil and Energy Development Corporation Unified Leyte GPP - Strips Turned over on 26 200.00 of Energy Aboitiz Energy Solutions, Inc. December 2014 Vivant Energy Corporation Good Friends Hydro Resources Corporation Waterfront Mactan Casino Hotel Inc. Total Luzon/Visayas 4,075.85 Turned Over to 3,845.10 IPPAs/SGC/OGA/LGUs IPPA PRIVATIZATION LEVEL (LUZON/VISAYAS) 77.46%
* UL bulk capacity is based on the average daily declared capability of about 400 MW by EDC less the 200 MW sum of strips and 40 MW security capacity
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186. Why was privatization started only in 2004 when the EPIRA was enacted in 2001?
The implementing rules and regulations came out only on 27 February 2002, almost a year after the EPIRA. It took six (6) months to prepare and finalize the privatization plan which was approved in December 2002. Consultations were also made with the JCPC. The investment climate then did not augur well for the power sector because energy companies around the world were experiencing financial difficulties. The assets also had to be prepared for the sale: bidding procedures, transaction documents, inventory of assets, due diligence for the buyer and the seller, bidding package submission to COA, etc. The initial privatization strategy was to secure creditor consent prior to any Genco sale and thus the privatization of Transco was prioritized over that of the generating assets.
187. When was TransCo bidded out?
After three (3) unsuccessful bids, PSALM achieved a successful bidding for the 25-year Concession of the National Transmission Corporation (Transco) on 12 December 2007 with the Consortium of Monte Oro Grid Resources Corporation, Calaca High Power Corp. and State Grid Corp. of China, collectively, the "Monte Oro Consortium,” as the highest bidder. The Monte Oro Consortium offered US$3.950 billion for the Concession contract, besting the Consortium of San Miguel Energy Corp., Dutch firm TPG Aurora BV and Malaysia's TNB Prai Sdn bid of US$3.905 billion. The Concession Period of twenty-five (25) years starts on the commencement date to be agreed upon by the Parties after the following conditions precedent have been both satisfied: (1) Congress has granted a franchise to the Winning Bidder to carry out the concession; (2) PSALM has secured the consent of financial institutions and lenders of the National Power Corp. pertaining to (i) transfer of transmission assets and all other properties to TransCo as mandated by Section 8 of the EPIRA; and (ii) the privatization of TransCo by way of Concession.
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Privatization of TRANSCO
MILESTONE ACTIVITY DATE
National Grid Corporation of the Philippines (NGCP) won the bid for Transco concession for a price of 12 December 2007 US$3.95 billion
Concession Agreement Signed 28 February 2008
Franchise Approval of the NGCP 01 December 2008
Commencement of TransCo Concession (NGCP) 15 January 2009 Source: TransCo
188. What is the status of TransCo’s privatization?
The Republic Act No. 9511 or “An Act Granting the National Grid Corp. of the Philippines (NGCP) a Franchise to Engage in the Business of Conveying or Transmitting Electricity through High Voltage Back-Bone System of Interconnected Transmission Lines, Substations and Related Facilities, and for Other Purposes” was signed into law by President Gloria Macapagal Arroyo on 01 December 2008. It mandated the transfer of the franchise of the government-owned power grid operator, TransCo, to NGCP and allowed the private concessionaire to commence its operation, maintenance and expansion of the electric transmission grid for 50 years, in accordance with the Concession Agreement.
On 14 January 2009, the Power Sector Assets and Liabilities Management Corporation (PSALM) formally turned over the 25-year concession of the National Transmission Corporation (TransCo) to the National Grid Corporation of the Philippines (NGCP). The NGCP remitted US$987.5 million to PSALM as its upfront payment for the operation of the transmission system and in compliance with the provisions of the sale transaction. The amount comprises 25% of the US$3.95-billion purchase price to acquire the concession contract.
189. What is the status of the sale of TransCo sub-transmission assets?
The sale of TransCo’s STAs involves 123 sale contracts and 107 interested distribution utilities (DUs), most of which are electric cooperatives (ECs). The STAs include some 5,900 ckt-km of mostly 69 kV transmission lines and 1,600 MVA of substation capacity.
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As of 31 January 2016, TransCo has signed 113 sale contracts with 92 DUs/ECs/consortia amounting to PhP6 billion. These sales cover an aggregate length of 3,804 ckt-kms of sub-transmission lines and 34,048 sub-transmission structures and 830 MVA of substation capacity. Of the 113 sale contracts, 70 contracts with total sale price of PhP4.24billion have been approved, approved with modification, and disapproved. Included in the said contracts are eight (8) contracts amounting to PhP261.4 million disapproved as of September 30, 2016 posted at the ERC website. The rest of the sale contracts are for filing with the ERC for evaluation and approval.
STA Sale per Region as of 31 December 2016
No. of Sale Region Amount CKM per region Contracts
North Luzon 34 1,673,152,549.20 1,189.04 South Luzon 17 1,155,312,490.46 469.04 Visayas 29 1,211,689,831.22 683.26 Mindanao 33 1,916,546,545.94 1,462.66 Total 113 5,956,701,416.82 3,803.99 Source: TRANSCO
190. How can the government ensure that the proceeds from the sale of NPC assets will be optimized?
A set of criteria in the grouping of NPC assets will be considered. These criteria include financial viability, efficiency of operations, and management and operational synergy. Furthermore, all assets of NPC shall be sold in an open and transparent manner through public bidding.
From the beginning balance in 2000 of PhP830.7 billion, PSALM’s financial obligations amounted to a total of PhP1.2 trillion in 2003, which included PhP483.4 billion debts and PhP757.2 billion BOT lease obligations. The increase was brought about by the following: New capacities were commissioned after 2001 (Bakun, Ilijan Natural Gas, San Roque Multi Purpose and Kalayaan 3 and 4); Further Peso devaluation by 8% from 2001 level (PhP55.57=1US$); and New debts were incurred since Internal Cash Generated was able to fund only 10% of maturing obligations.
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From 2000 to 3rd quarter 2016, the graph below shows the movement of financial obligations of PSALM:
Total Debt and IPP Obligations As of 3rd Quarter 2016
3000
2500 1093.3 1026.4 1240.6 1011.5 2000 951.5 830.7 863 813.9 773.5 763.5 1500 701.2 696.5 662.1 646.8 582.2 550.8 1000 542.5 500
0 3rd Q 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Total Obligations 830.7 863 1026.4 1240.6 1093.3 1011.5 951.5 773.5 813.9 763.5 701.2 696.5 662.1 646.8 582.2 550.8 542.5 Debts 319.1 327.6 396 483.4 368.6 374.4 376.5 320.4 326 322 307 348.1 364.7 357.1 324 305.4 311.8 BOT Lease 511.6 535.4 630.4 757.2 724.7 637.1 575 453.1 487.9 441.5 394.2 348.4 297.4 289.7 258.2 245.4 230.7 BOT Lease Debts Total Obligations 191. What is the current status of the power sector’s financial obligation to date?
Through the efforts of PSALM in continuously implementing its liability management program and strategies, PSALM’s financial obligations was reduced to PhP542.5 billion (or US$11.2 billion) or a decrease of PhP698.5 billion from the level of PhP1.2 trillion.
Financial Obligations as of 3rd Quarter 2016 PhP Equivalent US$ Equivalent (in Billions) (in Billions) Debts 311.77 6.46
IPP Lease 230.73 4.78 Obligations
Total 542.50 11.24 Note: Figures based on 3rd quarter 2016 Statement of Financial Position
192. In terms of currency denomination, what composes the power sector loans?
In terms of currency, more than half (51.91%) of PSALM’s debt is denominated in dollars, amounting to PhP161.8 billion. Peso- denominated debt accounts for 38.64%, equivalent to PhP120.5 billion. The remaining debt is in Japanese Yen (9.45%), amounting to PhP29.5 billion. As of October 2016, the currency mix or percentage of Page 106 of 207
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PSALM/NPC debts to outstanding PSALM/NPC debts broken down into US Dollar, Japanese Yen, and Peso are as follows:
Debt Profile by Currency as of 3rd Quarter 2016 Amount in USD Amount in PhP equivalent (in % of Total Currency equivalent Millions) (in Millions) US$ 161,844.0 3,353.8 51.91% PHP 120,474.4 2,496.5 38.64% JPY 29,454.7 610.4 9.45% Total 311,773.1 6,460.7 100.00% Exchange Rates Used: BSP Guiding Rate dated 30 September 2016 USD : PhP 1.00 = 48.2570 JPY : PhP 1.00 = 0.4777 EUR : PhP 1.00 = 54.1685 KRW: PhP 1.00 = 0.0438 Source: PSALM
193. What is the present status of electricity rates?
Effective rates for the MERALCO franchise areas for the month of November 2016 is PhP5.6835 for Industrial Customers, PhP7.2923/kWh for Commercial Customers and PhP8.6816 for Residential Customers. Available data for ECs as of September 2016 for Residential Customers suggest PhP8.9118 for residential, PhP7.6335/kWh for commercial and Luzon with PhP6.4237/kWh for Industrial Customers.
194. What are the government’s initiatives to shield the marginalized from the high cost of electricity?
To achieve the objectives of this policy, the following were implemented: Unbundled the electric power industry functions into generation, transmission, distribution and supply sectors, including the rates to reflect the true cost of providing each service.
a. Removed cross subsidies within a grid, between grids and/or classes of customers. b. Condoned the loans of ECs used for electrification purposes amounting to PhP 18.1 billion. This resulted to reduction in ECs rates in the range of PhP0.0578/kWh to PhP1.3507/kWh. As of November 2016, the national government, through PSALM, has paid a total of PhP16.269 billion worth of financial obligations (PhP16.192 billion to NEA and PhP 77 million to LGUs and other government agencies). c. Implemented lifeline rate for the marginalized residential customers.
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d. Provided mandated rate reduction (MRR) from NPC’s generation rate equivalent to 30 centavos/kWh reduction for residential customers across the country.
195. What is the status of Universal Charges?
As of 30 November 2016, remittances of collecting entities (CEs) to PSALM amounted to PhP108.174 billion, while interest earnings from deposits and placements of UC funds amounted to PhP0.149 billion while UC fund disbursement amounted to PhP107.646 billion.
Meanwhile, PhP38.816 billion was transferred from the UC-Stranded Contract Cost (UC-SCC) Special Trust Fund (STF) account to PSALM’s UC-SCC Special Fund Account (SFA) in accordance with the PSALM Board-approved Guidelines and Procedures on Disbursement and Utilization of UC-SCC of NPC.
ERC Approved UC Rates as of 30 June 2016 Type PhP/kWh
UC-ME 0.1561 UC-EC 0.0025 UC-SCC 0.1938 Total 0.3524 Source: PSALM
As of 30 November 2016, balance of PhP677 million left in the UC Fund is shown in the Table below (with the summary of inflows & outflows of the UC Fund):
UC Remittances, Interests and Disbursements as of 30 November 2016 (in Billion PhP)
PARTICULARS REMITTANCES INTERESTS DISBURSEMENTS BALANCE
Special Trust Fund – 61.136 0.044 61.137 0.043 ME –NPC SPUG ME-Renewable
Energy Developer 0.161 Cash Incentive 0.311 0.001 0.151 (REDCI) Environmental 0.424 1.819 0.096 1.491 Charge Stranded Contract 0.049 44.908 0.008 44.867 Cost – SCC TOTAL 0.677 108.174 0.149 107.646
Source: PSALM
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196. What is the status of the condonation of loans of all electric cooperatives?
Loan Condonation as of 30 November 2016 Total Actual Payments Balance Assumptions Amount % Amount % NEA 17.978 16.1921/ 90.07 1.785 9.93 LGU/OGA 0.096 0.0772/ 79.85 0.019 20.15 TOTAL 18.074 16.269 90.01 1.8053/ 9.99 / Inclusive of PhP0.369 billion pertaining to NEA’s double collection from ECs amounting to PhP2.215 billion for the period 2001-2003 2/ Net of discount from the Provincial Government of Palawan amounting to PhP3,725,000.97 3/ Balance covers the remaining amount to be paid to NEA and LGU/OGA, subject to submission of complete documents/requirements and compliance with the terms and conditions provided under Section 5 of EO 119
197. What are the challenges for the continuing implementation of power sector reforms?
There remain challenges in the sector reforms before its ultimate objective will be met to wit:
a. Need to put in place a dynamic and comprehensive competition policy/guidelines to mitigate possible exercise of market power by few firms who now acquired NPC generating assets and control of contracted capacities b. Need to further encourage private sector investment to boost up capacity requirements and avert possible shortage of supply c. Need to strengthen power supply security and reliability standards as well as enforcement thereof to promote efficiency d. Paradigm shift for distribution utilities particularly the electric cooperatives e.g., continuing reliance on government’s intervention and support e. Need to harmonize power sector reforms with the Renewable Energy Act f. Need to harmonize regulations with the government policies.
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ADDITIONAL DATA
1. Milestones on TransCo Privatization
Privatization of TRANSCO MILESTONE ACTIVITY DATE National Grid Corporation of the Philippines (NGCP) won the bid for Transco concession 12 December 2007 for a price of US$3.95 billion Concession Agreement Signed 28 February 2008 Franchise Approval of the NGCP 01 December 2008 Commencement of TransCo Concession 15 January 2009 (NGCP) Source: TRANSCO
2. Status of Sub-Transmission Assets Privatization - STA Sale Per Region as of 31 December 2016
No. of Sale Region Amount CKM per region Contracts North Luzon 34 1,673,152,549.20 1,189.04 South Luzon 17 1,155,312,490.46 469.04 Visayas 29 1,211,689,831.22 683.26 Mindanao 33 1,916,546,545.94 1,462.66 Total 113 5,956,701,416.82 3,803.99 Source: TRANSCO
Status of the Sale of TRANSCO Sub-Transmission Assets as of 31 December 2016 (Total Sale Contract)
Total Sale Sale Total Sale to Total Sale Sale Total Sale to ECs Region Contracts to PDUs Contract to ECs (Amount) (Amount PDUs (Amount in PhP) in PhP) North Luzon 34 1,673,152,549.20 23 1,251,339,111.00 11 421,813,438.20 South 17 1,155,312,490.46 8 204,095,886.59 9 951,216,603.87 Luzon Visayas 29 1,211,689,831.22 19 752,875,198.72 10 458,814,632.50 Mindanao 33 1,916,546,545.94 26 1,818,609,326.08 7 97,937,219.86 Total 113 5,956,701,416.82 76 4,026,919,522.39 37 1,929,781,894.43 Source: TRANSCO
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3. Status of the Sale of TRANSCO Sub-Transmission Assets as of 31 December 2016
ERC APPROVED/DISAPPROVED SALE CONTRACTS
No. of Approved/ Amount (PhP) ERC Amount (PhP) Region Disapproved Approved ERC Disapproved Sale Contracts
North Luzon 18/3 1,022,107,701.65 126,597,401.22 South Luzon 10 754,593,900.31 Visayas 17/3 913,222,512.28 70,977,453.43 Mindanao 17/2 1,288,825,970.12 63,899,778.94 Total 62/8 3,978,750,084.36 261,474,633.59 Source: TRANSCO
4. Status of the Sale of TRANSCO Sub-Transmission Assets as of 31 December 2016 - FOR ERC APPROVAL
Region Sale Contracts Amount in Millions (PhP)
North Luzon 3 82.16 South Luzon 5 368.12 Visayas 5 167.69
Mindanao 11 471.66 Total 24 1,089.64 Source: TRANSCO
5. Status of the Sale of TRANSCO Sub-Transmission Assets as of 31 December 2016 - FOR ERC FILING
Sale Contracts With Amount in Millions Region Issues (PhP) North Luzon 1 98.65 South Luzon 0 - Visayas 1 6.59 Mindanao 2 7.40 Total 4 112.64 Source: TRANSCO
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6. Status of the Sale of TRANSCO Sub-Transmission Assets as of 31 December 2016 - FOR DIVESTMENT
Region Sale Contracts Amount (PhP) North Luzon 3 74,540,867.00 South Luzon 4 314,628,650.00 Visayas - - Mindanao 3 188,049,497.00 Total 10 577,219,014.00 Source: TRANSCO
7. Indicative Schedule of Privatization for Generating Assets as of 31 November 2016
Rated Capacity Asset Type/ Bid Date Turnover Date (MW) Plant Name Owned Generating Plants
Malaya Thermal 650.00 1st Semester 2017 1st Semester 2017 Agus 1 & 2 Hydro 260.00 Agus 4 & 5 Hydro 213.10 1st Semester 2018 Agus 6 & 7 Hydro 254.00 Pulangui Hydro 255.00 Decommissioned Plants Sucat Thermal 850.00 1st Semester 2017 1st Semester 2017 Bataan Thermal 175.00 Sale/disposal is subject to resolution of Bataan Gas Turbines 120.00 court cases involving the asset Source: PSALM
8. Indicative Privatization Schedule for the Appointment of IPPAs - as of 31 November 2016 Contracted Grid Plant Name Capacity Bid Date Turnover Date (MW)
Casecnan Multi-Purpose 140.00 2018 Hydro Luzon Grid Benguet Mini Hydro 30.75 IPP contract to expire in 2018 Caliraya-Botocan- 728.00 2018 Kalayaan Hydro Sub-total Luzon 898.75 Unified Leyte - Bulk 160.00 Visayas Grid Energy 2017 Security Strip 40.00 Sub-total Visayas 200.00 Mindanao Coal-Fired 200.00 2018 Sub-total Mindanao 250.00 GRAND TOTAL 1,298.75
Source: PSALM
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9. Privatization Proceeds as of 3rd Quarter 2016, (in US$ Billion)
Privatization Assets Generated Collected Balance Generating Assets 3.605 3.605 0.000 Decommissioned Plants 0.007 0.007 0.000 Transmission Asset (TransCo) 6.100 3.963 2.137 Appointment of IPPAs 10.245 3.229 7.016 TOTAL 19.957 10.804 9.153 Source: PSALM
10. Privatization Proceeds Utilization as of 3rd Quarter 2016
Utilization In US$ Billion
Debt Prepayment 1.298
Regular Debt Service 5.742
Lease Obligations 2.570
Others 0.102
TRANSCO Opex 0.001
TOTAL 9.713
USD:PhP = 48.257 (BSP Guiding Rate dated 30 September 2016) Source: PSALM
11. PSALM LIABILITY MANAGEMENT
Total Debt and IPP Obligations As of 3rd Quarter 2016
3000 BOT Lease Debts Total Obligations 2500 1093.3 1026.41240.6 1011.5 2000 951.5 830.7 863 813.9 773.5 763.5 1500 701.2 696.5 662.1 646.8 582.2 550.8 1000 542.5 500
0 3rd 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Q 2016 Total Obligations 830. 863 1026 1241 1093 1012 951. 773. 813. 763. 701. 696. 662. 646. 582. 550. 542. Debts 319. 327. 396 483. 368. 374. 376. 320. 326 322 307 348. 364. 357. 324 305. 311. BOT Lease 511. 535. 630. 757. 724. 637. 575 453. 487. 441. 394. 348. 297. 289. 258. 245. 230.
Source: PSALM
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12. Financial Obligations as of 3rd Quarter 2016
PhP Equivalent USD Equivalent (in Billions) (in Billions) Debts 311.77 6.46 IPP Lease Obligations 230.73 4.78 Total 542.50 11.24 Source: PSALM
13. Debt Profile By Currency as of 3rd Quarter 2016 Amount in Amount in Percent of Total Currency PhP Equivalent US$ Equivalent
(in Millions) (in Millions) JPY 29,454.7 610.4 9.45% PHP 120,474.4 2,496.5 38.64% US$ 161,844.0 3,353.8 51.91% Total 311,773.1 6,460.7 100.00% Exchange Rates Used: BSP Guiding Rate dated 30 September 2016 USD : PhP 1.00 = 48.2570 JPY : PhP 1.00 = 0.4777 EUR : PhP 1.00 = 54.1685 KRW : PhP 1.00 = 0.0438 Source:PSALM
14. Status of Loan Condonation as of 31 November 2016
Total Actual Payments Balance Assumptions Amount % Amount % NEA 17.978 16.1921/ 90.07 1.785 9.93 LGU/OGA 0.096 0.0772/ 79.85 0.019 20.15 TOTAL 18.074 16.269 90.01 1.8053/ 9.99 1/ Inclusive of PhP0.369 billion pertaining to NEA’s double collection from ECs amounting to PhP2.215 billion for the period 2001-2003 2/ Net of discount from the Provincial Government of Palawan amounting to PhP3,725,000.97 3/ Balance covers the remaining amount to be paid to NEA and LGU/OGA, subject to submission of complete documents/requirements and compliance with the terms and conditions provided under Section 5 of EO 119 Source: PSALM
WESM
198. What is the Wholesale Electricity Spot Market (WESM)?
The Wholesale Electricity Spot Market (WESM) is a venue for trading electricity as a commodity. It serves as a clearing house to reflect the
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economic value of electricity for a particular period, as indicated by the "spot price". This market differs from other markets because electricity cannot be stored in large quantities and it is not possible to trace which generator produced the electricity consumed by a particular customer. For such reasons, the wholesale electricity market uses the concept of a “pool” where all electricity output from generators are centrally coordinated. Generators as well as buyers of bulk electricity compete for a share of this pool, to be dispatched and scheduled to meet the electricity demand in real time.
As a wholesale market, it is open to distributors, directly connected customers, large users, and eventually, supply aggregators. As a spot market, electricity is traded on a real time basis or on the “spot”.
The WESM's role in the country's overall energy reform is to create a fair, transparent and reliable trading environment that will attract investments and encourage healthy competition leading to the ultimate objective of cheaper electricity for all consumers. The WESM specifically aims to:
Provide incentives for the cost-efficient dispatch of power through an economic merit while guaranteeing the security and reliability of the power system.
Create reliable price signals to assist participants in weighing investment options. Provide and maintain a fair and level playing field for suppliers and buyers of electricity.
199. What is the legal basis for the WESM?
The WESM was created by virtue of Section 30 of Republic Act No. 9136, otherwise known as the Electric Power Industry Reform Act (EPIRA) of 2001. It mandated the DOE to establish the WESM within one year from its effectivity, and formulate the detailed rules for the WESM, jointly with electric power industry participants.
200. What benefits can be derived from the WESM?
The establishment of the WESM will facilitate a transparent and competitive electricity market for the country. It will serve as an efficient venue for the trading of electricity to ensure that generation is balanced with the ever-changing demand for electricity.
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The WESM is designed to encourage competition in generation while at the same time providing incentives for the effective operation and development of the transmission networks, coupled with locational price signals to encourage the economically correct geographic placement of any future planned generation.
With competition as the key driving factor, efficiency gains are expected to arise in the short and long term. In the short-term, efficiency gains will result from pressures on electricity businesses to reduce costs, align prices and tariffs with costs, and use of assets more efficiently. In the longer term, as new competitors emerge in wholesale power generation, the efficiency gains are likely to be more substantial.
The spot market provides economic price signals to generators, customers, and network service providers to assist them in their alternative investment options for new generation capacities, demand side management (e.g. consumption curtailment in response to high prices), and network expansions. These price signals are also important, in terms of the signals they provide to competing energy sources.
Ultimately, the WESM aims to end the inherently inefficient monopoly system for generating and selling electricity by providing consumers with the "choice of power" and the "power of choice.”
201. What is the governance structure for the WESM?
The WESM is governed by an independent board, with a majority of the members comprised by stakeholders. As provided for in the WESM Rules, the Board consists of: one (1) Director representing the Market Operator; one (1) Director representing the National Transmission Corporation (TRANSCO) (now NGCP); four (4) Directors from the Distribution Sector; four (4) Directors from the Generation Sector, one (1) Director representing the Customer; and four (4) Independent Directors. The DOE Secretary acts as the first Chairperson. Under the Board are the different Committees, consisting of the Rules Committee, the Disputes Committee, the Market Surveillance Committee, the Technical Committee, and the PEM Auditor.
202. What are the WESM rules?
The WESM Rules establishes the basic rules, requirements and procedures that govern the operation of the Philippine electricity market. It sets the responsibilities of the Market Operator, System Operator, WESM
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Participants, and the PEM Board. They are intended to be complimentary with the Philippine Grid and Distribution Codes, all of which are meant to ensure the development of an appropriate, equitable and transparent electricity market, along with a safe, reliable, and efficient operation of the power system. On 28 June 2002, the DOE promulgated the Rules with the joint endorsement of the electric power industry participants. These rules became effective on 21 July 2002.
203. What are the key features of WESM?
There are three key features of the operation of the spot market. These are:
A process for scheduling generation and balancing supply and demand at all times; A price determination process which sets the marginal value of all electricity produced and consumed by time and location at all nodes; and A financial settlement process in which customers pay for electricity purchases and generators receive payments for electricity produced.
The spot market involves:
An hourly trading/dispatch/settlement period; Ex-ante real-time prices based on the hour ahead load forecasts and dispatch; Ex-post real-time prices based on actual metered generation/load; and Nodal settlement prices based on the ex-ante prices applied to the ex- ante (forecast/dispatched) loads, supplemented by an “imbalance” settlement for the difference between ex ante quantities and metered quantities at the ex post prices.
204. Who operates the WESM?
A new entity called the Market Operator (MO) will be constituted by the DOE to administer the operation of the WESM. The MO will operate the market and will ensure the optimal dispatch of generation by collecting offers from generators and bids from customers, and from which a “spot price” for electricity throughout the grid is set. It shall facilitate the settlement of financial accounts between trading participants, and continuously provide market information.
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205. Who can participate in the WESM?
All generating companies, distribution utilities, suppliers, bulk consumers/ end-users and other similar entities authorized by the Energy Regulatory Commission (ERC) shall be eligible to become members of the WESM subject to compliance with the membership criteria.
206. What are the membership requirements to participate in the WESM?
To become a registered WESM member, an entity must have an authorization issued under the Act by the ERC and must meet requirements for creditworthiness called “prudential requirements.” It must have a communication facility (e.g., telephone, fax machine, or internet connection) to facilitate the exchange of information between the Market Operator and the Trading Participant. Participants who do not meet the requirements for membership may be represented by an entity that meets the requirements for membership.
207. What is the advantage of being a registered member of the WESM?
Registered members of the WESM will have access to market data and can go through dispute resolution processes. They can also avail for themselves directly the wholesale price. Conversely, if they are not trading participants they are not directly responsible for meeting prudential and technical standards of the spot market. Buying from sources other than the WESM enables them to insulate themselves more from the volatility of the spot market, by engaging in more comprehensive supply arrangements that will normally be available for purchase through the spot market. In general, we could expect that direct participation in the market would expose buyers of bulk electricity to lower prices but greater risks, than buying from other sources.
208. How do generators compete in the WESM?
Generation companies assume full responsibility for how and when their plant is operated. Each generator offers their plant into the WESM using a series of price/quantity bands or tranches. These price/quantity tranches may be used however the generator wishes. Since generators can only make money when they are actually running, they must structure their offers in either case to enable them to be scheduled and dispatched.
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For generation companies with small generating units that fall below the specified threshold size of dispatchable plant, they must submit to the Market Operator a standing schedule of loading levels for each generating unit.
209. How do customers compete in the WESM?
In this case, however, there is usually much less flexibility in the physical system underlying demand to actually alter their demand. Many consumers will find it enough to bid a fixed estimate of their load for the settlement period without attaching a price (the price is assumed to move a specified large volume). Initially, demand-side bidding is optional since customers may have difficulty making meaningful bids. Without a good history of metered demand they will not have the information to participate in demand-side bidding.
210. How are dispatch schedules and spot prices determined in the WESM?
A single optimization is performed with all of the system requirements included in the linear programming model, which is called the “market dispatch optimization model.” At each dispatch event, the dispatch schedule and spot price are determined by accounting for:
Energy offers; Demand-side bids or forecast load ; Reserve offers (when applicable) ; Reserve requirements; Transmission system parameters, modeled using DC load-flow equations ; Most recently observed plant status.
The price determination process is based on and maintains consistency with the offer price/quantity preferences of Trading Participants, and provides a single market clearing price at any point in time and location in the network.
211. What is the purpose of having a look-ahead projection?
The “look-ahead” is an aid to system planning and provides the WESM participants significant up-coming events, for example, outage schedules and demand variations (such as public holidays, etc.). A market usually works better if it knows such eventualities in advance. Hydro stations that are self-committing and have a daily energy limit have a particular need to
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understand the upcoming day. The purpose is to commence the process of “discovery” of system conditions and the corresponding dispatch and prices. In addition to the weekly load ahead, a spot market requires a more accurate day-ahead pre-dispatch.
212. How is the look-ahead projection conducted?
The process for the look-ahead projection is conducted as follows:
It commences one week in advance of real-time, or, alternatively the look-ahead goes to a fixed day of the week, e.g., Sunday. Participants supply their indicative offers. Where a participant fails to submit a new offer, the previous offer “rolls-over”. The roll-overs would either apply to the most appropriate earlier day – for example, week- day, weekend day or public holiday – or the last offer made regardless of the day. In order to give participants more complete information, the MO supplies several load scenarios. These sensitivity studies enable the participants to make more reliable decisions. The information is updated daily until real-time. The corresponding dispatch/pricing scenarios are formed and disseminated on a daily basis.
213. How are bilateral contracts dispatched in the WESM?
Generation companies must submit generation offers to the Market Operator to be considered in the central scheduling and dispatch process. Since the market and dispatch are fully integrated all electricity output from generators must be sold through the WESM, regardless if covered by bilateral contracts or not. Trading participants may opt to settle quantities transacted under bilateral contracts directly with its contracting party.
214. Are we doing away with long-term contracts?
No, at its option, a DU may secure 100% of its requirements from bilateral contracts. Still, there are times when the DU may incur imbalances such as during peak periods, then it can source from the WESM.
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215. How will the WESM provide the correct market signal to prospective investors?
There may be some distortion in the short term, particularly while prices and contracting levels shift up or down from their current levels to sustainable equilibrium levels. In general though, the WESM will provide an accurate pricing to reflect the participant’s estimate of the value of energy and reserves in the short term. This has the potential of substantially increasing the efficiency of the generation sector. It will encourage owners and operators of electric power plants to be more efficient in their operations, and for the more efficient power plants to replace less efficient ones in the dispatch process.
216. How will the WESM affect electricity rates?
A competitive market does not guarantee a reduction in price but should lead, in the long term, to prices lower than they otherwise would have been. Market prices are driven by all kinds of factors, and may be quite volatile in the short and medium term. The initial direction of price movement depends upon the state of the industry before reform. If there is surplus capacity, prices should go down, but if prices have been artificially suppressed or subsidized, they will eventually increase to levels equivalent to the cost of building a new power plant. In the long run, the market should improve industry efficiencies, thereby leading to lower electricity prices.
In the short-term, there is little room yet for price reductions once the WESM becomes operational since 90 % of the capacity of power generators are still covered by bilateral contracts, where prices are fixed. However, over the longer term, the competitive market will drive out many inefficiencies, and should keep both contract and spot market prices as low as possible---but they must be high enough to sustain and encourage entry of investments in building new capacities.
217. What are the safeguards in the WESM that assure competition and level-playing field among participants?
This is handled at two levels. Within the market, competitive pressure is the major safeguard but manipulative behavior can be reported to the Market Surveillance Committee under the PEMC Board, who may impose appropriate penalties. There would also be safeguards in the Competition Rules to be promulgated by the ERC. The Philippine Competition Page 121 of 207
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Commission was also established which mandate includes protecting and ensuring efficiency of competition in the electricity market for the benefit of consumers and businesses.
On 9 June 2006, prior to the commercial operation of the Luzon WESM, the WESM Tripartite Committee, composed of the DOE, ERC and PEMC, adopted the implementation of a WESM offer price cap of PhP62,000 per megawatt-hour (MWh). The WESM offer price cap was adopted as a mitigating measure to limit or reduce possible instances of excessive increases or high market prices as well as protect consumers against unjustifiable prices.
With the significant price spike event during the SPEX Malampaya natural gas supply curtailment in November and December 2013, the WESM Tripartite Committee resolved to reduce the WESM offer price cap to an interim level of PhP32,000 per MWh effective 27 December 2013 until 30 September 2015.
Upon the recommendation also of an independent study conducted to review the effectiveness of the existing WESM Design, the DOE, ERC and PEMC commissioned a study by Power Wrangler Ltd (“PW”) to develop and review the methodology and determination of the levels of (i) the offer price cap and floor and (ii) the market price cap and floor for energy and reserves in the WESM. In line with the recommendation of PW, the DOE, ERC and PEMC issued a Joint Resolution adopting a new WESM Offer Price Cap at PhP32,000/MWh and WESM Offer Price Floor of negative PhP10,000/MWh. The said values are subject of an annual review to ensure the capability of WESM to encourage further investments in the generation sector.
As an additional mitigating measure, an interim secondary price cap of PhP6,245/MWh was implemented in May 2014 for the protection of public welfare and to thwart the replication of exorbitant and unreasonable high market prices during the SPEX Malampaya turnaround in November and December 2013. ERC imposition of a secondary cap amounting to PhP6,245/MWh upon breach of the PhP8,186/MWh seventy-two (72) hour rolling average Generator Weighted Average Price (GWAP) threshold. This interim measure was set to mitigate sustained high prices in the WESM.
The implementation of the said secondary price cap was extended by the ERC, until its imposition of permanent price cap on 15 December 2014 which took effect last 09 January 2015. The permanent price cap was
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adopted as follows:
A Cumulative Price Threshold (CPT) amounting to PhP1,512,028.00 equivalent to the Generator Weighted Average Prices (GWAP) over a rolling 7-day period or one hundred sixty eight (168)-hour trading interval, which is equivalent to an average spot price of PhP9,000/MWh over the period A breach of the CPT for the said period triggers an imposition of a price cap amounting to PhP6,245/MWh. He market clearing price for the immediate trading interval following the breach will be pegged at the value of the price cap and shall be imposed until after the succeeding GWAP rolling average is already below the CPT For intervals where the market clearing price is below the CPT during the period when the price cap is imposed, the market clearing price will be applied for settlement purposes. During the intervals when the price cap is in effect, oil-based plants will be entitled to recover additional compensation equivalent to the remainder of the total cost of fuel and variable O&M costs, subject to submission of sufficient proof for evaluation and confirmation of PEMC.
The key purpose of setting the price cap and floor are: (1) Technical - In the event the market does not clear at any price because of supply scarcity and load is shed as a consequence, setting the price administratively to some capped value is useful; and (2) Structural - As a constraint on the exercise of market power; and price caps are about preventing the abuse of market power.
218. How are ancillary services costs determined?
As provided in the Act, the “user fees for ancillary services” that will be charged by the TRANSCO for the provision of ancillary services shall be fixed by the ERC after due notice and public hearing. Under normal circumstances they are paid for on a combination of a capacity fee (representing the capacity the Generator is contracted to keep available for provision of the service) and costs (the costs the Generator incurs when the service is called for).
TRANSCO shall arrange for the provision of adequate ancillary services by competitive bidding process. Where applicable, certain categories of ancillary services may be traded through the WESM wherein the costs of reserve are determined through an optimization process.
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219. What are Financial Transmission Rights (FTRS)?
FTRs provide the generator with a means of reducing the impact of any nodal price differences across the trading region through means of a difference contract secured with network service provider or transmission facility owner. These FTRs, for an agreed level of capacity, reimburse the generator for any disadvantage due to the price in its region being at variance from the market selling price. FTRs will normally not provide a 100% hedge to all generators against regional price variations such that the portion of transmission which is a natural bottleneck will provide incentives for either the location of new generation close to the point of load (relieving the transmission) or to encourage investment in reinforcement of the transmission network.
220. What is the difference between FTRS and wheeling charges?
Strictly, the issue is a comparison between nodal price differences and wheeling charges. If they have been properly integrated, the nodal price differences will cover short term cost of line losses and congestion rentals and the wheeling charges will cover the fixed costs of building and maintaining the network and the overheads of the Transco.
221. What has been done in preparation for the commencement of WESM operation?
Incorporation of the PEMC
As provided in Section 30 of the EPIRA, the DOE formulated the creation of the Philippine Electricity Market Corporation (PEMC). The PEMC shall undertake the preparatory work and initial operation of the WESM. It shall establish, maintain, operate and govern an efficient, competitive, transparent and reliable market for the wholesale and purchase of electricity and ancillary services in the Philippines in accordance with applicable laws, rules and regulations. The Articles of Incorporation and By-laws of the PEMC were finalized in collaboration with the WESM Technical Working Group. PEMC is a duly incorporated non-stock non-profit corporation registered with the Securities and Exchange Commission (SEC) on 18 November 2003.
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• Creation of the PEMC Board and Appointment of Corporate Officers
On 18 December 2003, the DOE constituted the PEMC Board and appointed the Board Directors in accordance with the By-laws of PEMC and the WESM Rules. Designated as Board directors were the following: Dr. Alan T. Ortiz of TRANSCO for the Transmission Sector; Mr. Mario R. Pangilinan for the Market Operator; Mr. Ernesto B. Pantangco of PIPPA, Mr.Froilan A. Tampinco of PSALM, Mr. Pio J. Benavidez of NPC and Mr. Edgardo A. Bautista of Mirant Philippines represented the Generation Sector; Mr. Jesus P. Francisco of Meralco, Mr. Ramon C. Abaya of PEPOA, and Mr. Wilfred L. Billena of Iloilo 1 Electric Cooperative represented the distribution sector; selected as Independent Directors include Atty. Vigor D. Mendoza II of Philippine Ecozones Association, Mr. Meleusipo E. Fonollera of Institute of Integrated Electrical Engineers of the Philippines, Mr. Elvico B. Gumban of Semiconductor and Electronics Industries Philippines; and Mr. Lasse A. Holopainen, former Assistant Secretary of the DOE.
From the members of the Board, appointed as Corporate Officers include Mr. Lasse A. Holopainen as President of PEMC, Atty. Celina Rillas Encarnacion as Corporate Secretary, and Ms. Elizabeth Lumasac as Treasurer.
Inauguration of the WESM Site
The Corporate Offices of WESM/PEMC was inaugurated on 5 December 2003, located in the heart of Ortigas Center. This office site is the market operation control center and shall house the market management system necessary to operate the WESM.
Development of WESM Price Determination Methodology
The proposed WESM Price Determination Methodology (PDM) was submitted to ERC for approval on 28 June 2003. The PDM was developed in collaboration with the WESM-TWG. Several presentations to various industry participants were conducted to explain how the PDM works. A public hearing on PDM has been conducted by the ERC on 12 February 2004 to solicit views and comments from different sectors of society, stakeholders and prospective market participants.
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222. What benefits can be derived from the WESM?
The establishment of the WESM will facilitate a transparent and competitive electricity market for the country. It will serve as an efficient venue for the trading of electricity to ensure that generation is balanced with the ever-changing demand for electricity.
The WESM is designed to encourage competition in generation while at the same time providing incentives for the effective operation and development of the transmission networks, coupled with locational price signals to encourage the economically correct geographic placement of any future planned generation.
With competition as the key driving factor, efficiency gains are expected to arise in the short and long term. In the short-term, efficiency gains will result from pressures on electricity businesses to reduce costs, align prices and tariffs with costs, and use of assets more efficiently. In the longer term, as new competitors emerge in wholesale power generation, the efficiency gains are likely to be more substantial.
The spot market provides economic price signals to generators, customers, and network service providers to assist them in their alternative investment options for new generation capacities, demand side management (e.g., consumption curtailment in response to high prices), and network expansions. These price signals are also important, in terms of the signals they provide to competing energy sources.
Ultimately, the WESM aims to end the inherently inefficient monopoly system for generating and selling electricity by providing consumers with the "choice of power" and the "power of choice.”
The WESM is governed and managed by the Philippine Electricity Market Corporation. The basic features of the WESM are as follows:
Gross Pool
All energy transactions (whether contracted or not) are scheduled through the market. Energy transactions include the demand and supply of electricity. This allows all the power produced, supplied and used to be accounted for.
Net Settlement
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Only spot market quantities are settled in the market, i.e., bilateral contract quantities between generators and distribution utilities or customers transacted in the pool are settled outside of the market.
Locational Marginal Price
Marginal price is computed at each market trading node (as defined in the WESM Market Network Model (MNM)) or transmission system location reflective of the transmission system loss and/or congestion (if there are any).
Reserve Co-optimization
Energy and Reserve offers are scheduled at the same time.
Demand Bids
Customers that can qualify to have their loads to be scheduled through the market can opt to submit demand bids for their scheduled loads
Mandatory Market Existing distributors are mandated by law to procure at least 10% of its electricity from the WESM for the first five years from its establishment.
Entities directly connected to the transmission system are not allowed to inject or withdraw without registering in the WESM.
The trading process maybe summarized in five steps as follows:
Step One: Trading participants submit online hourly energy offers (price and quantity).
Step Two: The Market Operator matches offers of generators with demand bids of customers, prioritizing the lowest offers (generators) and highest bids (customers).
Step Three: The Market Operator submits the dispatch schedule to the System Operator for central dispatch and informs the trade participants of the price and schedule.
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Step Four: Electricity is dispatched to the buyer, for distribution to the end-users.
Step Five: Electricity used is measured and settled using the locational marginal prices and schedule.
223. What is Independent Market Operator (IMO)?
“Independent Market Operator” or “IMO” refers to a person who is financially and technically capable, with proven experience and expertise of not less than two (2) years as a leading independent market operator of similar or larger size electricity markets endorsed jointly by the DOE and Electric Power Industry Participants to assume the functions, assets and liabilities from the Autonomous Group Market Operator (AGMO), pursuant to Section 30 of the EPIRA.
224. What is the legal basis for the establishment of the IMO?
Following are the legal bases for the establishment of the IMO:
EPIRA Section 2(j) - To establish a strong and purely independent regulatory body and system to ensure consumer protection and enhance the competitive operation of the electricity market:
EPIRA Section 30 - Not later than one (1) year after the implementation of the wholesale electricity spot market, an independent entity shall be formed and the functions, assets and liabilities of the market operator shall be transferred to such entity with the joint endorsement of the DOE and the electric power industry participants. Thereafter, the administrative supervision of the TRANSCO over such entity shall cease.
EPIRA IRR Rule 9 Sec. 6 (a)xxx Not later than one (1) year after the implementation of the WESM, an independent entity, the IMO, shall be formed and the functions, assets and liabilities of the AGMO shall be transferred to such entity with the joint endorsement of the DOE and the Electric Power Industry Participants: Provided, That the IMO shall be financially and technically capable, with proven experience and expertise of not less than two (2) years as a leading independent market operator of similar or larger size electricity market.
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225. What are the requirements for the IMO?
The EPIRA and its IRR require the IMO to be an independent entity which is financially and technically capable, with proven experience and expertise of not less than two (2) years as a leading independent market operator of similar or larger size electricity market.
226. Does the PEMC qualify to be the IMO?
Yes. Based on the results of study conducted under the ADB, PEMC qualifies to be the IMO due to the following reasons:
PEMC has operated the WESM for over five years as the AGMO. The review of the financial condition of PEMC and its likelihood of operating as an Independent Market Operator reveals financial capability. The Company’s auditors are the world class accounting firm of Ernst and Young and have given the Company a clean opinion.
Review of the personnel, applicable technical specifications, and services and assurance practices of PEMC reveals technical capability and expertise in operating an electricity market.
We considered the proviso requiring the IMO to be a “leading independent market operator of similar or larger size electricity market”. The JCPC refers to the term ‘independent’ in reference to the electricity market system as the means to ensuring consumer protection and to enhance the competitive operation of the electricity market. The JCPC considered (refer January 17 2002 meeting) that the move from the AGMO to the IMO was similar to the Transco provision in Section 21 of EPIRA, except in that provision it refers to the requirement for proven “domestic and/or international” experience and expertise as a leading transmission system operator. The AGMO IMO transition was treated differently to the Transco transition and did not refer to “domestic” expertise and experience because, as Senator Osmeña states, “[I]n this country we do not have such an animal yet”.
It is now over five years that the WESM has been operational and AGMO has operated it. The AGMO governing body is stakeholdered and is not independent. The AGMO market operator is not stakeholdered and is independent as an operations group. The reference in Section 6(a) of Rule 9 of IRR that the IMO has experience and expertise as a leading ‘independent’ market operator was merely an acceptance that no market operator with expertise and experience existed in the Philippines. Now
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that situation has changed and PEMC does have that experience and expertise. The members of the IMO Board, although not identified yet, will have significant experience in not only markets but other disciplines also. In addition, the Market Committee structure will exist to provide substantial input to it.
227. What is the governance structure for the WESM?
The WESM is governed by a Board, with majority of the members comprised by stakeholders. As provided for in the WESM Rules, the Board consists of:
one (1) Director representing the Market Operator ; one (1) Director representing the National Transmission Corporation (TRANSCO) (now NGCP) ; four (4) Directors from the Distribution Sector (2 private and 2 ECs); four (4) Directors from the Generation Sector; one (1) Director representing the Customer; four (4) Independent Directors (includes the Market Operator); and The DOE Secretary acts as the first Chairperson.
Under the Board are the different Committees, consisting of the Rules Committee, the Disputes Committee, the Market Surveillance Committee, the Technical Committee, and the PEM Auditor.
BENEFITS TO HOST COMMUNITIES PURSUANT TO ENERGY REGULATIONS 1-94, AS AMENDED FREQUENTLY ASKED QUESTIONS
228. Legal and operational bases
a. Section 5 (i) of R. A. No. 7638, also known as “Department of Energy Act of 1992” which took effect in December of 1992 and its corresponding E.R. No. 1-94, issued by DOE on 27 June 1994; b. Section 66 of R. A. 9136, also known as “Electric Power Industry Reform Act of 2001” which stated that all obligations of generation companies and energy resource developers as defined in Section 5(i) of RA 7638 including its implementing rules and regulations shall continue; and
c. Part A, Rule 29 of EPIRA-IRR, which took effect on March 22, 2002.
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229. What is Energy Regulations (ER) 1-94?
ER 1-94and its attendant rules and guidelines are DOE’s compliance with Section 5(i) of RA No. 7638, otherwise known as the “Department of Energy Act of 1992.” This specific provision mandates the DOE to devise ways and means of giving direct benefits to the province, city, or municipality, especially the community and people affected, and equitable preferential benefit to the region that hosts the energy resource and/or the energy-generating facility. [Provided, however, that the other provinces, cities, municipalities, or regions shall not be deprived of their energy requirements.
To further strengthen the provision of financial benefits to host communities under ER 1-94, as amended, the legislators reiterated under Section 66 of the EPIRA that all obligations of the generation companies and energy resource developers as defined in Section 5(i) of RA 7638 including pertinent issuances shall continue.
230. What are the policy objectives of ER 1-94?
The objectives embodied in Section 5(i) of RA 7632 (ER 1-94) are:
a. To recognize and recompense the contributions made by the pertinent community and people affected; b. To lessen conflict of rights; and c. To promote harmony and cooperation among host local government units, community and people affected, the energy resource developers or power producers, and the appropriate agencies of the National Government.
231. What is the scope of ER 1-94?
The generating facilities and/or energy resource development facilities covered are as follows:
a. Spin-off facilities of NPC or their transferees, including generation facilities transferred to PSALM and subsequently privatized; b. Agus and Pulangui complexes; c. Facilities owned and operated by NPC-SPUG; d. Facilities under BOT arrangement and other variants with government agencies (NPC, NIA, SPUG, PNOC-EDC) and distribution utilities (IPPs of DUs); e. Facilities owned or operated by a DU;
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f. Self-generation facilities; g. Facilities operating in Economic Zones; and h. Integrated energy resource development and generation facilities such as hydro, geothermal, and coal.
Note: Prior to EPIRA, there are some exemptions e.g., power plants with less than 10 MW capacities. With EPIRA, all generating facilities regardless of their capacities are now “covered” by the provision of one centavo per kilowatt-hour financial benefits.
232. Who are the direct beneficiaries under ER 1-94?
The direct beneficiaries mentioned under this program are the community and people affected who were relocated as a result of the development of energy resource/s and installation of generating facilities. Also, those local government units hosting a generating facility are considered as beneficiary under the program.
233. When do LGUs or regions considered as ‘host” under ER 1-94?
a. For generation facilities, host LGU or host region is that where the generating facility is physically located. In case of power barges, the host LGU or region is that where the power barge is moored.
b. For energy resources, the host LGU is that where the producing positive coal and geothermal reserves are located as delineated by geo-chemical, geo-physical, and exploration surveys. For hydro, it is where the hydro reservoir is located and for petroleum and natural gas it is that where the producing petroleum/natural gas reservoir is located.
234. What is the nature of benefits under ER 1-94?
The benefits shall be derived from the ER 1-94 which defines the obligation of the generation company and/or energy resource developer to set aside one centavo per kilowatt-hour (P0.01/kWh) of the total electricity sales as financial benefit of the host communities of such generation facility. It shall be allocated into three (3) separate funds, namely:
a. Electrification Fund (EF); b. Development and Livelihood Fund (DLF); and
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c. Reforestation, Watershed Management, Health, and Environment Enhancement Fund (RWMHEEF)
Note: Generating facilities and/or energy resource developers are not required anymore to provide non-monetary benefits such as priority dispatch, trainings, labor, etc. directly to their host communities. Everything is done through ER 1-94, as amended (except for priority dispatch).
235. How is the P0.01 per kWh financial benefits distributed or allocated to EF, DLF and RWMHEEF?
The P 0.01 per kWh financial benefit is allocated as follows:
a. For a Generation Facility and/or energy resource located in a non- highly urbanized city:
i. ½ of P0.01per kWh or P0.005 per kWh goes to EF and is applied in the following radiating order: designated resettlement area/s; host barangay/s; host municipality/ies or city/ies; host province/s; host region/s; and other areas as may be prioritized/determined by DOE
ii. ¼ of P 0.01 per kWh or P0.0025 per kWh goes to DLF and is applied in the following manner: designated resettlement area/s - 5% host barangay/s - 20% host municipality/ies or city/ies - 35% host province/s - 30% host region/s - 10%
Note: In the absence of a designated resettlement area/s, funds allocated for the resettlement shall form part of the host barangay/s.
iii. ¼ of P0.01 per kWh or P0.0025 per kWh goes to RWMHEEF and is allocated as follows: designated resettlement area/s - 5% host barangay/s - 20% host municipality/ies or city/ies - 35% host province/s - 30% host region/s - 10%
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Note: In the absence of a designated resettlement area/s, funds allocated for the resettlement shall form part of the host barangay/s.
b. For a Generation Facility and/or energy resource located in a highly urbanized city:
iv. ¾ of P0.01 per kWh or P0.0075 per kWh goes into EF and is applied in the following order: designated resettlement area/s; host barangay/s; host city/ies or city/ies; province/s nearest to the host city/ies; region/s of the host city/ies; host communities of other facilities with insufficient electrification fund; areas traversed by transmission lines and substations or similar facilities; and other areas as may be prioritized/determined by DOE.
v. 1/8 of P0.01 per kWh or P0.00125 per kWh goes to DLF and is allocated as follows: designated resettlement area/s - 10% host barangay/s - 30% host city/ies - 60%
Note: In the absence of a designated resettlement area/s, funds allocated for the resettlement shall form part of the host barangay/s.
vi. 1/8 of P0.01 per kWh or P0.00125 per kWh goes to RWMHEEF and will be allocated as follows: designated resettlement area/s - 10% host barangay/s - 30% host city/ies - 60%
Note: In the absence of a designated resettlement area/s, funds allocated for the resettlement shall form part of the host barangay/s.
236. How can the host LGUs/Region avail of the benefits under DLF and RWMHEEF?
The implementation and provision of financial benefits is project-based, meaning, the project proponent through the assistance of the Community Relations Officer/s (ComRel/s) of the concerned generation company. The endorsement shall constitute the submission of their initial
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evaluation over the LGUs project proposal, a detailed project proposal and the accorded supporting documents to DOE as described in a separate brochure on ER 1-94.
a. The preferred projects under ER 1-94, as amended, are as follows:
Development Projects: Livelihood Projects: Street-lighting Food Production/Processing Farm to Market Road Ice Plant Multi-Purpose Pavement Livestock & Poultry Farm Produce Collection & Production Buying Station Handicraft Production Rice/Corn Milling Aquaculture Communal Irrigation System Vegetable Seed Farm Fish Ports Small Scale Services Public Market, School Building, Livelihood Projects Day Care Centers, etc.
Environment Enhancement Reforestation and Watershed Projects: Management Projects:
Fire Truck Improvement of forest cover Waste Management Equipment, engineering measures i.e. Garbage Truck, Dump Truck, Community-based forestry Bulldozer, Backhoe/Loader Management Construction/Installation of Agro-forestry Waste Treatment Facility Conservation of Mangroves Sanitary Landfill Development Seedling nursery Development of Waste Recovery Warehouse Construction of Concrete Sanitary Waste Collection Facility
Health Related Projects:
Water supply system Municipal Hospital Medical Equipment/facilities Medicinal Plant Gardens
Note:Please note that these are just preferred. The key element in any project proposal submitted to DOE for funding under ER 1-94, as amended is sustainability and greater benefits to the greater number of people. Also, funding for the above- Page 135 of 207
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listed projects shall include costing of materials, labor, and equipment, exclusive of payment for salaries, wages, honoraria, allowances, administrative expenses, transportation, travel expenses, and all other expenses that maybe incurred in the processing proposals, release of projects funds, and implementation of said projects. (DC2000-03-003)
a. The DOE will review and process the project proposal within 13 working days upon receipt of complete supporting documents.
b. A Memorandum of Agreement (MOA) shall be entered into by and among the DOE, Generation Company and/or energy resource developer and the concerned LGU to effect funds commitment and project implementation.
Note: If the MOA is routed among the different signatories, the whole process would take. 30 days to complete. To shorten the process, the DOE, to the extent possible, arranges one-day sit down MOA signing c. DOE will release the funds within fifteen (15) days upon submission of complete supporting documents pursuant to the provisions in the MOA e.g., result of competitive public bidding, etc.
d. All work programs/project proposals shall be implemented within one (1) year upon receipt of funds.
237. How can the ‘Host Community” avail of EF under the program? Is the process of availment is the same as under the DLF and RWMHEEF?
a. The management and supervision of implementing rural electrification programs funded through ER 1-94, as amended, is directly undertaken by the DOE taking into account all pertinent information on the remaining un-energized areas in the country. b. There are many ways in which implementation of electrification projects are facilitated: (i) through the Distribution Utility concerned; (ii) through the community or local government unit; (iii) through legislators; and (iv) through referrals and endorsements from various Government agencies. c. The DOE preferred that the generation company and/or energy resource developer should coordinate with the concerned Distribution Utility in the programming of electrification projects including the prioritization for the year. The annual electrification programs shall be directly forwarded to DOE for review and evaluation.
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d. DOE shall complete the review and approval of annual work programs/project proposals within thirteen (13) working days upon receipt of complete supporting documents. Thereafter, a MOA shall be entered into by and among the DOE, concerned distribution utility/project implementer to effect funds commitment and project implementation. The process of obtaining signatures on the MOA takes thirty (30) days. The project funds are released by DOE directly to the distribution utility.
Note: Please note that if the MOA is routed among the different signatories, the whole process would take 30 days so that the DOE is, to the extent possible, arranges one-day sit down MOA signing.
238. What happens to the interest earnings from the three (3) trust funds?
As provided under Section 4 (b), Rule 29 (A) of the EPIRA-IRR, interest earnings from EF, DLF and RWMHEEF shall be set aside by DOE into one account to be utilized for the electrification projects of the communities in the following order of priority:
a. Direct host barangay/s and host municipality/ies or city/ies with insufficient accrued EF b. Areas traversed by transmission lines, substations or similar facilities c. Areas not directly connected to the Grid or national transmission system which include isolated or remote communities d. Other areas as may be prioritized/determined by DOE
239. What agency establishes, administers, and monitors the EF, DLF, and RWMHEEF?
The DOE shall establish trust accounts specific for EF, DLF, and RWMHEEF in the name of DOE and the generation facilities or generation company and or/energy resource developer. To do this, the generation company and/or energy resource developer shall submit to DOE the following:
a. Report that contains: actual generation, station use, system loss and electricity sales in kWh; b. Accrued benefits due to the host LGU and host region; c. Details of benefits and/or financial assistance advanced to the host LGU and host region; and d. Such other information the DOE may deem necessary for review and
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audit. The DOE shall also review and audit the source of funds, particularly on the total electricity sales of the Generation Facility to determine the financial benefits due to the host LGU and host regions.
240. What is the common cause/s of delays in the approval/implementation of projects?
a. For Electrification Projects i. ROW (Right-of-Way) Problems; ii. Price escalation; and iii. The distribution utility has various electrification projects to implement or manage; and
iv. Un-liquidated project fund of a distribution utility for previously approved project/s.
b. For Non-Electrification Projects v. Non-observance with E.R. No. 1-94 requirements; vi. Submission of proposals with Incomplete documents; vii. Un-liquidated project fund released for previously approved project/s; viii. Protest from members of the community where the proposed location/site of the project will be implemented; and ix. Change of local executives
241. Can generation companies and/or energy resource developers advance financial assistance to the concerned host community?
Yes, the generation company and/or energy resource developer may extend advance financial assistance during the pre-operation stage or before the start of the commercial operations of the power project for the purpose of securing favorable endorsement from the community and people affected. Said advanced financial assistance shall be credited against the future accruals at an amortization rate of 20% of the total financial benefits (prior to allocation/distribution to the EF, DLF, and RWMHEEF) as defined in the rules and guidelines. Further, the project/s to be implemented shall be approved by the DOE.
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242. How can the generation companies and/or energy resource developers be engaged in the ER 1-94 Program of DOE? The generation company and/or energy resource shall be engaged under the ER 1-94 through the forging of Memorandum of Agreement on the Establishment Trust Account between DOE and the former. Said instrument will firm up the commitment of the generation company and/or energy resource in their obligation under the program.
Also, the MOA is one of the listed requirements of ERC for their issuance of Certificate of Compliance and Authority to Operate to the generation company and/or energy resource prior to its commercial operations.
QUALIFIED THIRD PARTY
243. What is a Qualified Third Party (QTP)?
It refers to an alternative electric service provider authorized to serve remote and unviable areas "waived" by the Distribution Utilities (DUs) pursuant to Section 59 of the EPIRA and Rule 14 of the EPIRA- Implementing Rules and Regulations (IRR).
244. What are remote and unviable areas?
Pertains to a geographical area within the franchise area of a DU where immediate extension of distribution line is not feasible (Rule 4 of the EPIRA-IRR).
245. What are “waived” areas?
Areas within the franchise area of a DU which the concerned DU has allowed parties other than itself or its adjoining DUs to provide electricity services. The list of Waived Areas upon passing the criteria set by NEA shall be declared by the DOE as open for QTP participation.
246. What is the legal basis for QTPs?
As mandated under Section 59 of the EPIRA and Rule 14 of EPIRA-IRR, all areas that have been declared remote and unviable by DOE shall be open for participation by entities to be known as QTPs. To operationalize the participation and investment by the QTPs, the DOE issued the following rules and guidelines:
Department Circular (DC) No. 2004-02-002 – Issued on 20 February 2004, "Prescribing Guidelines for the Formulation of Five- Page 139 of 207
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Year Distribution Plan (DDP)" which requires all DUs to, among others, identify and submit to DOE the list of barangays within their respective franchise areas that are deemed remote, unviable and cannot be provided with electric service within the next three (3) years. Department Circular No. 2004-06-006 - Issued on 18 June 2004, prescribed the qualification criteria for QTPs covering financial, technical criteria, among others. Department Circular No. 2005-12-011 - Issued on 12 December 2005, prescribed the guidelines for participation of QTPs for provision of electric service in remote and unviable areas, pursuant to Sections 59 and 70 of EPIRA and its IRR. Resolution No. 22 Series of 2006 - Issued by the Energy Regulatory Commission (ERC) on 3 May 2006, which prescribed the rules for the authorization and regulation of the operations of entities endorsed by the DOE as QTP pursuant to Section 59 and 70 of the EPIRA and its IRR.
247. What is DOE’s policy on QTP participation?
As part of their universal service obligations, the franchised DUs must always endeavor to serve its franchise areas including remote and unviable areas. A DU may allow adjacent DU whose franchise is nearer to the said remote and unviable area to serve it. Any of them may file petition to the ERC for a preferential tariff for the electricity service in the unviable area as prescribed by Rule 7 of the EPIRA- IRR. If the DU or the adjacent DU could not serve the said areas due to financial and operational deficiencies, only then will the DU allow any alternative service providers or QTPs to operate in the areas given a specific period of time. If no QTP is willing to serve, NPC-SPUG will serve the areas as "the last resort."
Participation of QTPs shall be open to any party provided that the QTP has demonstrated technical and financial capability to serve the area, willing to comply with the technical and financial and other requirements through competitive or transparent manner and it is not "the DU" that waived the area.
248. What are the eligibility criteria for QTP participation?
QTP participation is open to any capable party, including but not limited to private firms, local government units, cooperatives, non-government organizations, generation companies or their subsidiaries or subsidiaries of DUs.
All QTPs shall adopt least-cost and most efficient technology options in serving unviable areas. In determining the QTP, preference shall be given to Persons or entities that can offer the least-cost technologies utilizing renewable energy resources.
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DOE Circular No. 2004-06-006 issued on 18 June 2004 defines the general requirements to pre-qualify interested party/ies as QTP. These are as follows:
a. Financially and technically capable, and of good standing in the business community.
b. Registered with Securities and Exchange Commission (SEC), meets the criteria set forth under this Circular.
c. Organizations may include, without limitation, private firms, LGUs, Cooperatives, NGOs, generation companies or its subsidiaries or subsidiaries of DUs.
d. Technical Criteria. To be accredited as QTP, an interested Person must demonstrate that it has the technical skills and capacity to operate a power generation facility and/or an electric power distribution system for public supply.
e. Financial Criteria. An interested person must demonstrate that it has the financial capacity to finance a power generation facility and electric power distribution system of the size likely to be required for the operations.
f. Local Enterprises and Renewable Technologies. Consistent with government policies in relation to the development of local enterprises and renewable technologies, DOE will encourage local enterprises and organizations with expertise in renewable technologies to operate as QTPs.
Following the above criteria for qualification, the DOE-EPIMB is responsible to evaluate the capacity of every applicant based on the documents officially submitted. DOE Circular No. 2005-12-011 and the ERC Resolution 22 series of 2006 also provide other criteria for the actual authorization of the QTP to serve the unviable areas.
249. Are there limitations on pre-qualification (accreditation) of QTPs?
Based on DC 2004-06-006, the DOE may restrict the type or size of system that a QTP will be allowed to construct and operate. Such restrictions may include, without limitation, (i) restrictions on the size of system, (ii) restrictions on the location of the system, and (iii) restrictions on the generating technology to be used.
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250. How can an entity become a QTP? What is the proposed QTP process?
DOE Circular No. 2005-12-011 and ERC Resolution 22 series of 2006 jointly prescribe the complete process for the selection and authorization of a pre-qualified entity as QTP to serve the unviable areas.
a) The first step is for the DU to identify the remaining unelectrified barangays within its franchised area and segregate into two sub- programs i.e., those areas that it will implement by itself and those that it considers as unviable areas for participation of QTPs. This information will be included in the concerned DU's Distribution Utility Development Plan (DDP).
b) Since the DU's DDP particularly ECs will pass through and endorsed by NEA to DOE, the proposed unviable or waived areas will be tested against NEA's criteria for waiving. If NEA affirmed the area as "waivable," such will be submitted and reported to DOE for proper declaration. In case, the area fails to meet NEA's waiving criteria, then NEA will inform the DU concerned and direct said area to be part of its own electrification program.
c) Based on DOE's list of waived areas, any potential and interested QTP/s may manifest their intention to DOE to serve the particular area by submitting to DOE an Expression of Interest (EOI). The DOE will do the pre-qualification process, subject to meeting the prescribed rules and guidelines including offers made by the potential QTP/s. Under DOE Circular DC 2005-12-011, DOE shall conduct a Selection Process to determine the most suitable QTP based on the offers made by pre- qualified QTP/s in a particular service area. Such QTP will be endorsed to ERC for permitting and authorization including tariff approvals. Please note that the QTP/s shall be entering into agreements with: i. NPC-SPUG for the QTP Service Contract and Subsidy Agreements; and ii. Concerned DU for the Waiver Agreement.
d) The illustration is the QTP Process from Identification to Selection.
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251. What will happen to the existing informal service providers (ISPs) currently operating in the unviable areas of the DUs?
It has been known to both DOE and ERC that there exist ISPs in the remote unelectrified barangays, including the Privately-Owned Power Supplies (POPS) and community-based facilities that use diesel generators and micro-hydro systems.
ERC has given these informal entities at most one (1) year, to be reckoned from the effectivity of ERC's Resolution No. 22 series of 2006, formally submit their intention to continue their service as Qualified Third Party (QTP) subject to the usual pre-qualification and other QTP requirements, including endorsement by the DOE.
252. What are the rights and obligations of QTPs?
Consistent with DOE Circular No. 2005-12-011, the QTPs shall have the following responsibilities: a. Meet the qualification criteria set by the DOE in the Request for Proposal (RFP). b. Secure from ERC relevant permits and licenses, including authority to charge its rates, in order to commence providing services in its respective area/s. c. Comply with all the provisions, including the financial, technical, and environmental and other performance standard of the QTP
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Service Contract entered into with NPC-SPUG. d. Submit periodic reports to ERC on its financial and technical performance pursuant to Rule 14 of the EPIRA-IRR. e. Operate and maintain its facilities to provide services in the QTP Service Area in an efficient and sustainable manner. f. Submit periodic reports to DOE on the status of its electrification program and the completed number of connections. g. As applicable and with prior authority from ERC, charge and collect UC from all end-users within the QTP Service Area and remit the same to the DU or the National Transmission Corporation, as the case may be, in accordance with law.
253. What will be the role of ERC, DOE and DUs in the QTP implementation and operations?
a. Responsibilities of DOE.
In addition to setting the qualification criteria for determining QTPs, the DOE shall have the following responsibilities: i. Monitor rate of electrification for each QTP Service Area. ii. Conduct the QTP selection process, in coordination with the Technical Working Group formed pursuant to Section 12 herein, in accordance with this Circular and the RFP. iii. Determine and incorporate in the MEDP the QTP projects and corresponding UC-ME requirements, if any, in payment of the Missionary Electrification Subsidy. iv. Form a Technical Working Group composed of representatives from DOE, NPC-SPUG, NEA, and PSALM to conduct, among others, the evaluation of proposals and recommend thereafter the candidate QTP to serve the Unviable Areas. v. Inform the ERC in writing of any significant variations between the executed QTP Service Contract and related agreements and the ERC pre-approved Model QTP Service Contract and related agreements. vi. Assist NPC-SPUG in the preparation of the latter's proposal to ERC for approval a uniform Subsidized Approved Retail Rate for the purpose of determining the corresponding amount of Missionary Electrification Subsidy that each QTP shall be entitled to receive from NPC-SPUG. vii. To encourage investments and private sector participation in Unviable Area/s, coordinate with the ERC on the appropriate rate setting methodology that will provide for the QTPs full cost recovery of the investments incurred or to be incurred including the cost to cover their operation in the QTP Service Areas. viii. Consistent with Section 1(d) of Rule 13 of the EPIRA- IRR, include in the preparation of MEDP all the electrification projects to be undertaken by the QTPs in Page 144 of 207
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Unviable Areas for possible subsidy allocation to be funded through UC-ME. ix. The DOE, in consultation with the Technical Working Group, shall adopt a transition mechanism to govern existing waived areas and community-based organizations and provide for the inclusion of the same in the QTP program. For this purpose: 1. Areas that are currently served by the DUs but are deemed unviable on account of huge operating costs may be offered by the concerned DUs for inclusion in the list of Unviable Areas or to be clustered with the Unviable Areas for inclusion under the QTP Program. 2. Subject to any guidelines that the ERC may issue, private sector-driven or community-based electrification projects which do not require subsidy from the UC-ME may proceed with the service provided that the proponents/operators shall notify the DOE within three (3) months from the Effective Date of this Circular.
b. Responsibilities of ERC.
i. The ERC, on the other hand, shall set guidelines for the issuance of Authority to Operate (ATO) and other necessary operating permits to QTPs that serve a remote or unserved and Unviable Area within the DUs Franchise Area. The ERC shall likewise set the rules in computing rates that allow full cost recovery of the Generation Facilities and delivery systems built to serve remote or unserved and Unviable Areas. These include the Subsidized Approved Retail Rate (SARR) and Full Cost Recovery Rate (FCRR).
ii. Consistent with the approved SARR and the FCRR, the ERC will also determine and approve the provision of subsidy to be collected from the Universal Charge for Missionary Electrification (UC-ME).
c. Responsibilities of NEA.
i. Establish the criteria for verification of areas submitted or nominated by the DUs as remote and unviable areas for clearance by the DOE, in accordance with Section 3(b) of this Circular. ii. Evaluate and verify the areas submitted by DUs as remote and unviable and submit its recommendations to the DOE in accordance with Section 3 of this Circular. iii. Assist the DOE in monitoring of the rate of electrification by the QTP of the different QTP Service Areas.
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d. Responsibilities of NPC-SPUG.
i. Ensure that the QTP shall serve its respective QTP Service Area by providing adequate and reliable electric service and performing in accordance with the standards set in the QTP Service Contract. ii. Review, finalize and execute the QTP Service Contract and subsidy Disbursement Agreement with the selected QTP, in accordance with this Circular and ERC Guidelines on QTP. iii. Apply with the ERC for the approval of the SARR and the missionary Electrification Subsidy. iv. Submit periodic reports to ERC on QTP performance relative to its compliance with the terms of QTP Service Contract and ERC guidelines. v. Submit periodic reports to ERC and PSALM on the disbursement and utilization of the UC-ME. vi. Unless otherwise provided in the MEDP or an alternative arrangement with the affected DU, act as the service provider of last resort in case the QTP fails to fulfill its obligations to serve the areas awarded to the QTP.
e. Responsibilities of the DU.
i. Extend assistance to the QTP serving a QTP Service Area within its franchise; such assistance to include but not be limited to securing the necessary rights of way, site acquisition, and coordination with concerned local agencies. ii. Finalize and execute a Waiver Contract with the QTP with respect to the Unviable Area/s within its franchise.
254. Will these QTPs also receive subsidy from the government?
Yes. Under ERC's Resolution 22 series of 2006, the Missionary Electrification subsidy to be provided to a QTP is defined as a fund duly approved by the ERC to cover the difference between the Full Cost Recovery Rate (FCRR) and the Socially Approved Retail Rate (SARR), to be sourced from Universal Charge for Missionary Electrification (UCME).
255. What is the status of QTP implementation?
a. The DOE has issued the Department Circular 2004-06-006 "Prescribing the Qualification Criteria for the Qualified Third Party Pursuant to Sec. 59 of the Electric Power Industry Reform Act of 2001, and its Implementing Rules and Regulations" on 18 June 2004. b. The DOE also issued Department Circular 2005-12-011 "Prescribing the Guidelines for Participation of QTPs for provision of Electric Service in Remote and Unviable Areas, Pursuant to Sections 59 and 79 of the Electric Industry Power Reform Act of 2001 and Its Implementing Rules
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and Regulations" on 12 December 2005. c. As a complimentary guideline to the DOE Circular DC-2005-12-011, the ERC has promulgated the Resolution 22 series of 2006 entitled "A Resolution Promulgating the Rules for the Regulation of Qualified Third Parties Performing Missionary Electrification in Areas Declared Unviable by the Department of Energy." e. DOE is currently amending the DOE Circulars on QTPs to streamline the QTP approval/qualification process and harmonize with the Renewable Energy Act and its related issuances.
f. Table 1 presents the current status of the QTP Projects:
QTP Projects (as of August 2017) PROJECT LOCATION TECHNOLOGY TARGET HHs PROPONENT STATUS
Operational, Rio Tuba, Bataraza, 1.05 MW Diesel Authority to Operate 1744 PSPI Palawan ‐ Biomass (ATO) issued by ERC , 2010 Operational, Malapascua, Daan‐ 750 kW Diesel 771 PSPI Permanent ATO Bantayan, Cebu issued by ERC, 2016
Hybrid : 1.4 MW Authority to Operate Sabang, Puerto Princesa Solar + 1.2 MW 683 SREC (ATO) issued by ERC City, Palawan Diesel + 2.3 05 October 2016 MWh Battery
Candawaga & Culasian, Awaiting ERC’s 268 kW Diesel 998 PSPI Rizal, Palawan Issuance of ATO
Balut Island, Saranggani, Awaiting ERC’s 690 kW Diesel 3570 PSPI Davao Occidental Issuance of ATO
Liminangcong, Taytay, Provisional ATO 108 kW Diesel 709 PSPI Palawan issued by ERC, 2016 For submission of Semirara Island, Caluya, ‐ ‐ SEUI final technical and Antique financial proposal Lahuy Island, Haponan Island in Municipality of Caramoan and Quinasalag Ongoing processing ‐ ‐ ‐ Island in the Municipality of application of Garchitorena, Camarines Sur Saranggani Island, Davao For reposting of ‐ ‐ ‐ Occidental public notice
Calayan and Camiguin For reposting of ‐ ‐ ‐ Islands, Calayan, Cagayan public notice
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PROJECT LOCATION TECHNOLOGY TARGET HHs PROPONENT STATUS Barangay Panobolon, Nueva Valencia; Barangay Guiwanon, Nueva Valencia; For verification by ‐ ‐ ‐ and Barangay NEA; For posting Inampulugan, Sibunag, Guimaras Barangay Palma Gil, Barangay Sto. Niño, For verification by Barangay Dagohoy in the ‐ ‐ ‐ NEA; For posting Municipality of Talaingod, Davao del Norte Barangay Aleva, Barangay Decabaitot, For verification by Barangay Binalabag, ‐ ‐ ‐ NEA; For posting Municipality of Linapacan, Palawan
NATIONWIDE INTENSIFICATION OF HOUSEHOLD ELECTRIFICATION (NIHE) 2015-2017 (GRANT ASSISTANCE FUNDS)
256. What are the legal and operational bases?
a. Section 2(a) of Republic Act No. 9136, otherwise known as the “Electric Power Industry Reform Act of 2001” or “EPIRA” states that it is the policy of the State to ensure and accelerate the total electrification of the country;
b. Section 23 of EPIRA which requires all Distribution Utilities (DUs) to provide universal service within their franchise, over a reasonable time from the requirement thereof, including Unviable Areas, in a manner that shall sustain economic viability of the DU;
c. The General Appropriations Act of 2015 has approved the budget and implementation of DOE’s NIHE Project for Fiscal Year 2015 with Special Allotment Release Order No. SARO-BMB-A-15- 0003315 dated March 19, 2015;
d. The General Appropriations Act of 2016 has approved the budget and implementation of DOE’s NIHE Project for Fiscal year 2016 with Special Allotment Release Order No. SARO-BMB-E-16- 0006349 dated 17 March 2016; and
e. The General Appropriations Act of 2017 has approved the budget and implementation of DOE’s NIHE Project for Fiscal year 2017 with Special Allotment Release Order No. SARO-BMB-E-17- 0003605 dated 16 March 2017.
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257. What is Nationwide Intensification of Household Electrification (NIHE) program?
It is a locally funded project for 2015-20181in support to the Government’s thrust of total electrification by providing grant assistance fund in order to increase access to electricity services by eligible unelectrified households (UHHs) in partnership with DUs and Local Government Units (LGUs).
The Program involves the formulation and implementation of specific measures to fast-track the connections of the remaining unelectrified households the franchise areas of the DUs and ECs which includes the streamlining of housewiring connections requirements by LGUs and DUs.
258. What is the policy objective of NIHE?
To attain total household electrification by 2022 by encouraging all DUs to develop and implement specific measures to fast-track the connections of the remaining unelectrified households in both electrified (load centers and urban/slum areas) and unelectrified areas of their franchised areas. .
259. Who are the co-operating agencies involve in the implementation of NIHE?
• National Electrification Administration (NEA) • Local Government Units (LGU) • All 143 Distribution Utilities (DUs) • Other Government Agencies including DSWD and DILG
1Requested extension for FY2018
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260. What are the expected work and financial outputs?
Php (in Year Main Physical Outputs/Targets Fund Status Millions) 2015 114.420 30,512 HHs served (new HHs connections) Approved; w/ SARO released by DBM 2016 646.875 170,500 HHs served (new HHs connections Approved; w/ SARO and reconnected HHs affected by released by DBM calamities) 2017 686.250 183,000 HHs served (new HHs connections Approved; w/ SARO and reconnected HHs affected by released by DBM calamities) 8.000 2,000 PV rechargeable lamps for HHs affected by typhoon/calamities 2018 613.000 120,000 HHs served (new HHs connections DBM Recommended and reconnected HHs affected by Budget calamities)
261. Who are the direct beneficiaries under NIHE?
The direct beneficiaries mentioned under this program are the unserved households and those households affected by typhoon/calamities. Criteria for new HH connections:
Target households should be technically defined by DU as unserved households (UHHs) within its franchise area. UHHsare situated on areas where the distribution facilities which are physically and technically available for service connection. Target UHHs should be situated within the allowable distance requirement of DU for service drop connection. UHHs should still be compliant to the DU and LGU requirements for new service connection (e.g. Proof of Ownership, LGU permits, etc.) Household’s dwelling units should reflect their financial incapability to apply for service connection. UHHs deemed as poor: 4P’s by DSWD or Proof of Indigence by LGUs.
262. What is the nature of grant subsidy under NIHE?
The grant subsidy shall be in the total amount of Php3,750.00/HH and shall include minimum housewiring to provide basic electric service. The sample costing may be Php2,500.00 for housewiring materials and labor (as used in NEA’s Sitio Electrification Project), Php750.00 for kilo-watt
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hour meter and Php500.00 for additional service drop wires. The Distribution Utility may opt to propose different breakdown as long as DU could provide basic electric service with maximum subsidy of Php3,750/HH andmaximum labor component of Php600/HH while the rest should be used for material component of the project.
263. What is NIHE’s implementation scheme?
I. Program and Development Stage
a. Submission of Project Proposal should include:
a.1 Accomplished Project Proposal Template a.2 Duly signed Distribution Utility Board Resolution containing the following documents: i. Attach list of HHs with accomplished Service Application forms or its equivalent forms; ii. Certification that attached list of HHs has duly accomplished said forms and HHs has qualified to the criteria set by the Department of Energy for the qualified beneficiaries of NIHE projects. iii. DU’s instruction if the proposed NIHE project shall be implemented by Contract iv.Authorization for concern Officials to enter and sign all contract/agreements concerning the NIHE Project
a.3 .Sangguniang Bayan Resolutions duly signed by LGU Officials (if applicable) i. List of Qualified Beneficiaries for NIHE program ii. LGU counterpart (breakdown of waived fees for the project) a.4 DSWD Certification as 4P’s a.5 Proposed Work Program on timeline of the implementation of NIHE Projects a.6.Summary and breakdown of the Proposed Total Project Cost of the NIHE project referring to DOE, DU and LGU counterparts (If there is) a.7.Proposed Bill of materials of the project and specific material component for the DOE allocated Php3,750.00
b. Proposal Review for Approval
i. Completeness of requirements;
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ii. Confirmation of local stakeholders’ support (local visit if necessary); iii. Eligibility of proponent (e.g. no liquidation arrears); iv. Acceptability of target and work program; v. Release of Letter of Approval;
c. .MOA Signing between DOE and DU
MOA allocates final number of approved HH beneficiaries and fund ceiling of PhP3,750/HH;
II. Implementation Stage
a. Pre-Procurement
As stated in the MOA, DU must: i. Submit Bank Certification of Checking Account exclusive for NIHE (Suggested Account Name: BANELCO- NIHE FUND); ii. Conduct of Bidding/s based on Approved Fund iii. Submit the pertinent Bid Result documents to DOE as supporting documents for the Release/transfer of funds a. Procurement and Installation ( House wiring and Connection)
i. DOE to issue NIHE Sticker/Markers with control number to proponent for installation; ii. Stickers attached to kilowatt-hour meter; iii. At least five (5) photos of the works done by the contractor during installation; iv. Sample photos of the houses served and the actual house-wiring and connections provided to the beneficiary;
III. Project Close-out (Inspection and Audit)
a. DU to submit their Project Completion Report and Acceptance b. DOE to conduct Technical and Financial Audit through DOE-REAMD and DOE- Internal Audit Staff, respectively.
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264. What is the flowchart of implementation procedure for the project?
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265. How many new players are there in the Philippines at present?
As of December 2016, a total of 265 new players are engaged in various downstream oil industry activities resulting to total investments of Php52.73Billion.
266. Market shares of oil players (YTDDecember2016)
Petron 30.7% Chevron 6.8% Shell 20.3% Others 34.2% Direct Imports 8.0%
267. LPGMarket Share (YTD December 2016)
Petron 36.34% Shell 0.24% Liquigaz 23.34% Pryce Gas 12.74% Petronas 4.84% South Pacific 6.56% Isla Gas 12.66% Others 3.28%
268. How many active gasoline stations are there in the Philippines at present?
A total of 6,264 active service new gas stations were presently in operation since the oil downstream was deregulated (1998).
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269. What do we pay for a liter of gasoline?
DEREGULATED March-17 1/ GASOLINE Industry Importer Refiner
How much pay for Product Cost (MOPS & Frt) 19.53 20.50 19.15 Duty 0.00 0.00 0.00 Excise Tax 4.35 4.35 4.35 VAT 5.00 5.00 5.00 2/ Oil Company Take 16.40 15.43 16.78 Dealers/haulers 1.40 1.40 1.40 Pump Price 46.68 46.68 46.68 1/ Assumption: Refiners import only crude 2/ Refining cost included
270. What do we pay for a liter of diesel?
DEREGULATED
March-17 1/ DIESEL Industry Importer Refiner
How much pay for Product Cost (MOPS & Frt) 20.02 21.08 19.16 Duty 0.00 0.00 0.00 Excise Tax 0.00 0.00 0.00 VAT 3.32 3.32 3.32
Oil Company Take 6.33 5.27 7.18 2/ Dealers/haulers 1.29 1.29 1.29 Pump Price 30.95 30.95 30.95 1/ Assumption: Refiners import only crude 2/ Refining cost included
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271. What do we pay for a liter of kerosene?
DEREGULATED March-17 KEROSENE Industry Importer Refiner 1/
How much pay for Product Cost (MOPS & Frt) 19.37 20.64 18.83 Duty 0.00 0.00 0.00 Excise Tax 0.000.000.00 VAT 3.943.943.94 Oil Company Take 12.16 10.89 12.71 2/ Dealers/haulers 1.29 1.29 1.29 Pump Price 36.76 36.76 36.76 1/ Assumption: Refiners import only crude 2/ Refining cost included
272. What is downstream oil deregulation? How does it affect the current pricing of petroleum products?
. Republic Act No. 8479 which was signed in February 1998 defined the regulatory framework for the downstream oil industry.
. The framework is based primarily on the guiding principle of a truly competitive market under a regime of fair prices, adequate supply of environmentally clean and high quality petroleum products.
273. What are the features of RA 8479?
The Oil Deregulation Law is an institutional and legislative reform that has:
. Provisions for fair trade . Programs to encourage entry of new industry participants by providing incentives to new players (except for refineries where existing players are also entitled) . Promote retail competition with support through the Gasoline Station Lending and Financial Assistance Program. . Anti-trust safeguards . Defined DOE’s role in the deregulated environment . a. INCENTIVES OF RA 8479
. Income Tax Holiday . Additional deduction for labor expense
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. Minimum tax and duty of 3% and VAT on imported capital equipment . Tax credit on domestic capital equipment . Exemption from contractor’s tax . Unrestricted use of consigned equipment
. Exemption from the real property tax on production equipment or machineries . Exemption from taxes and duties on imported spare parts . b. PRICING FEATURES (DEREGULATED VS. REGULATED)
Pricing Features
REGULATED DEREGULATED Who Sets ERB Market Cost Assured Investment Risk Recovery Price Basis Actual Import Cost Dubai/MOPS/Market OPSF P15B deficit - P20.6B No Subsidy RORB 12% max. allow. 6.5% 3% to (-) least level Tax Specific Tax Specific Tax for gasoline and jet fuel only 12% VAT Duty 20%/10% 0% (thru EO 890, 04Jul10) Adjustment Bi-monthly and Monthly Generally monthly (same time for industry) lately weekly/anytime
274. What are the prevailing petroleum product prices?Did the Philippines rush into deregulation without proper/enough transition?
. Chapter V of RA 8479 explicitly provides for the transition phase from fully-regulated to deregulated downstream oil industry.
. Among others, the law allows for an Automatic Oil Pricing Mechanism to enable the domestic price of petroleum products to approximate and promptly reflect the price of oil in the international market.
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275. What are the benefits of deregulation to the average consumers/commuters?
The entry of competition resulted to:
. vibrant downstream oil industry providing efficient service and competitive price . better quality in terms of product and facilities . improved service at the gasoline stations . shift to a new image of service stations providing amenities within the facility’s premises: o convenience stores o Restrooms o ATTM counters . tends to drive down prices in areas where there are numerous service stations
c. COMPARATIVE PUMP PRICES
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276. In the wake of rising oil prices, is the government considering re-establishing a subsidy mechanism, similar to the OPSF implemented during the 1980s?
The re-establishment of OPSF is not viewed as sound fiscal measure due to following reasons:
In the event of incessant uptick in oil prices in the international market There would be less contributions and more withdrawal from the funds
Budget deficits Would require huge infusion from the National Government
277. What are the mitigating measures of the government to cushion the impact of rising oil prices?
Diesel Discount Scheme
The DOE initiated a support mechanism for the public transport sector. In the later part of 2003, pursuant to the President’s call to support the transport sector, the DOE enjoined the cooperation of the oil companies in providing the public transport sector with outright discounts on diesel pump prices to help them cope with the increases in local oil prices. Initially, 73 stations in Metro Manila, representing 12 oil companies, participated in the scheme and agreed to offer discounts to jeepney drivers ranging from 20-50 centavos per liter. The number of participating stations grew over the years as it went nationwide, with the discount ranging from P0.50 - P1.00/li. The highest number was recorded when oil prices were at peak levels in the first quarter of 2009, with 1,103 participating stations all over the country. The number has lessened in the succeeding year, reaching only 818 participating stations nationwide by the end of 3rd quarter 2010 because of price wars in Metro Manila and environs where “discounts” apply to all motorists. By end-2011, the number reached 608 all over the country, then increasing to 779 stations by the 1st quarter of 2012. The increase continued to-date, with 1,106 by 2016.
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“Pantawid Pasada” Program
Established under Executive Order (EO) 32 in 01 April 2011, the Public Transport Assistance Program (PTAP) or “Pantawid Pasada” program aims to provide relief to the public transport sector to cushion the impact of high fuel prices on the riding public. As provided by the EO, the PTAP partially subsidized the average consumption of identified public transport groups.
PTAP’s initial funding requirement was P450 million to be sourced from the DOE Special Account in the General Fund (Fund 151)– Malampaya Collections. A total amount of P300 million per SARO No. A-11-00-842 dated 20 April 2011 was released by the DBM to DOE for the Public Utility Jeepney (PUJ) driver beneficiaries, while the remaining amount of P150 million was released to the Department of Interior and Local Government (DILG) for the tricycle driver beneficiaries.
The distribution of the Pantawid Pasada Cards (PPC) commenced on 02 May 2011 among legitimate public utility jeepneys and tricycle drivers/operators initially in the National Capital Region. Each PPC was loaded with PhP1,050 and reloaded for another P1,200 cash value, (for jeepneys) for the purchase of diesel from participating gasoline stations.
The program was implemented in collaboration with the other government agencies, i.e. DBM, DOF, DND, DILG and DOTC- LTO-LTFRB.
As of December 2011, the total number of beneficiaries of the Pantawid Pasada Program throughout the country, comprising of public utility jeepneys (PUJ) with valid franchises, reached almost one hundred (100) thousand nationwide.
The program ceased last May 2013
Promotion of commercial utilization of alternative transport fuels DOE is promoting the commercial utilization of indigenous alternative transport fuels, e.g., compressed natural gas (CNG) and biofuels (CME/Ethanol-blended petroleum) to reduce dependence on imported fossil fuels.
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Energy Independence
Implementation of various programs such as energy diversification, demand management and energy conservation
Enhanced the energy efficiency and conservation efforts, starting with the government/public sector
Encouraged private sector to take an active role in the implementation of the government’s ENERCON campaign
Revitalized oil and gas exploration and development
Government veered away from oil-fired power plants
Regular and on-the spot inspection
Intensified inspection of gasoline stations to ensure that products sold to consumers are of the right quantity and quality.
Strategic and focused inspections are also being undertaken for LPG establishments and liquid fuels’ retail stations.
278. In the midst of escalating oil prices, is the country assured of enough supply? Do we have contingencies should there be shortage in supply (e.g., rationing, coupons, etc.)?
A. Oil Contingency Plan (RA 7638/RA8479)
B. Minimum Inventory Requirement (RA 7638/RA 8479)
C. Energy Efficiency and Conservation
. EC Way of Life (Motorists, Household, Industries) . Energy Audits – Energy Awards (Private Sector – Industries, Government Offices)
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279. How can the government assure the public that the oil companies are not taking advantage of the high-price situation at the expense of the consuming public?
DOE Assessment of Reasonableness
Monitoring As mandated, the DOE monitors prices of both the raw material crude oil and the refined petroleum products in the international market and provides daily summaries to both print and broadcast media, as well as to concerned government agencies.
Domestic prices, both at the wholesale and retail levels, are also monitored.
Supply (importation/production), demand (sales/exports) and the inventory of the oil companies are also being monitored.
DOE’s basis of the prices are the last ERB-issued pump prices in 1998.
There is no single formula prescribed by Law to compute prices
Based on the DOE’s evaluation, adjustments in the local pump prices are reflective of the movement in the world market.
The DOE-DOJ Task Force
The Oil Deregulation Law mandated the organization of the DOE- DOJ Task Force to ensure a truly competitive market, fair prices, adequate and continuous supply of environmentally clean and high quality petroleum products as well as to ensure fair competition and to prevent cartels and monopolies.
Should there be a need to investigate and act upon any report of an unreasonable rise in the prices of petroleum products, the DOE & DOJ convenes the DOE-DOJ Task Force as provided for under Sec. 14 of RA 8479
Enhancement of DOE-DOJ Task Force
The Task Force was enhanced with a much improved Memorandum of Agreement (MOA) signed between DOE and DOJ. The DOE-DOJ Task Force Rules and Procedure was amended with the signing of Resolution No. 2008-01 “Amending Resolution No. 98-01” last 14 July 2008 between both parties.
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Further, the DOE-DOJ Memorandum of Agreement of 1998 was amended, and the revised MOA creating the new composition of the TF was signed on 14 July 2008, as shown in the following table:
DOE DOJ Undersecretary – Co-Chair Undersecretary – Co-Chair Dir, OIMB Asst. Chief State Counsel Dir, Legal Services Two (2) State Counsels Chief, OICMD Two (2) State Prosecutors Chief, RMMSCD One (1) Asst. Prosecuting Attorney
Independent Reviews on the Deregulation of Oil Industry and Pricing
The DOE spearheaded the creation of review committee / study on the implementation of the Oil Deregulation Law, with closer focus on oil pricing:
a. Independent Review Committee (IRC) in 2005 To review and assess whether the Oil Deregulation Law has been effective and whether it has attained its goals under the prevailing economic circumstances and conditions in the country.
b. DOE-SGV-UA&P Study on Oil Prices in 2008 To conduct an independent study to determine the reasonableness of oil prices in the country.
c. Independent Oil Price Review Committee (IOPRC) in 2012 To determine if there is (a) Accumulation of excessive profits; and (b) Unfair pricing
2005 IRC - Findings/Recommendations:
After the review, the IRC generally recommended that there should not be a change in the policy of the State to deregulate the oil industry due to the following:
Oil product price increases were mainly caused by the peso devaluation and the increase in the world price of Dubai crude and refined petroleum products; not deregulation. Subsidizing oil prices (something like the OPSF) does not work in an era of rising crude prices because it would entail government resources that it cannot afford. Page 163 of 207
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Frequent price increases resulted from government suasion in spreading major price increases over a longer period. When products are interchangeable, when market share is the “name of the game,” and competition is in full swing, we should not be surprised, but rather expect, that oil companies’ prices will seem to rise and fall at the same time. This does not mean that cartels exist. Deregulation has increased competition in the industry. Without competition, prices may even be higher than they already were.
2008 DOE-SGV-UA&P Study - Findings/Recommendations:
Oil prices do not seem to have been unreasonably high. If oil prices are high presently, the causes are beyond our control. Since the country has very little oil production of its own, it must import all the oil it uses. Thus we are subject to the vagaries of international oil prices. In crafting effective laws and policies in response to the high energy prices, a better understanding of how oil, and energy in general, impacts the economy is necessary. o How are energy price shocks transmitted through the economy? o What forms of energy and what quantities are consumed by the various stakeholders in society, especially the poor? o The Energy Summit last January 2008 has produced a slew of proposals that require further study to determine their likely impact and effectiveness.
2012 IOPRC - Findings/Recommendations:
Oil deregulation works; competition results in lower oil product prices
The IOPRC finds that the Oil Deregulation Law's goal of increased competition, and thus fair price (lower price than in an oligopoly), is being achieved. Deregulation has resulted in increased responsiveness of local pump prices (represented by Metro Manila prices) to world oil prices (as represented by MOPS). There is nothing extraordinary about the movements of local pump prices in the country. Generally pump price responses to changes in world oil prices have been symmetrical. Based on the gravity model, distance is an important factor in
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explaining regional pump price differences, at least for gasoline. Transport and handling costs play an important role in this, and the overall efficiency of the logistics sector is vital here. The government should, therefore, foster this efficiency by investing in the necessary infrastructure. The oil companies’ profits are reasonable. This conclusion is based on the results of its analysis of the ROE and IRR of oil companies and relating the same to the comparative ratio in other industries and risk- free government securities. Oil deregulation resulted in a lower average ROE of three major oil companies.
280. Why did Caltex, after more than 85years of Operation in the Philippines, pull out its Refining Operation? Does It indicate dampened investor interests in the country’s Downstream Oil Industry?
• Conversion of its San Pascual, Batangas refinery into a storage terminal in 2003 was a business decision. It was merely converting its refinery into a world-class terminal to become a regional supply and distribution network.
281. Aren’t oil refining companies required to go public under RA8479? Why are Shell and Caltex not yet listed even after more than 17 years of oil deregulation?
(PLEASE CHECK THIS. WHAT IS MEANT BY THIS YEAR WHEN SHELL IS ALREADY PUBLICLY LISTED) This year, Shell is going public to comply with the requirement of the country’s Oil Deregulation Law. The oil firm’s IPO was delayed for more than a decade amid unfavorable market condition, low oil prices and regulatory issues in the previous years.
PSPC IPO Update
On 13 June 2016, PSPC Chairman and President Mr. Edgar Chua notified DOE on the approval made by the PSPC Board of Directors on the initial public offering. This was subsequently ratified by the PSPC stockholders and amendments of the Articles of Incorporation. On the same day, the company also started to comply with the initial requirements of the Securities and Exchange Commission (SEC) and the Philippine Stock Exchange (PSE). Page 165 of 207
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As of 2 September 2016, PSPC is already in the process of complying with disclosure reports required by the SEC and PSE. Pilipinas Shell Petroleum Corporation (PSPC) successfully completed its initial public offering (IPO), which culminated in the listings of its shares on the Philippine Stock Exchange (PSE) on November 3, 2016. PSPC is now publicly traded on the PSE.
Caltex is no longer eligible to conduct IPO with the conversion of its refinery to an import terminal in 2003.
282. What is the DOE’s opinion on the bills amending/ repealing oil deregulation law?
The DOE welcomes opinions of all concerned groups on the issue of oil deregulation law. However, the DOE as an executive agency is not in a position to undertake the scrapping or amending of the existing legislation governing the downstream oil sector.
Understandably, there are still areas for improvement in the Law. The foregoing independent reviews provided recommendations based on the views and opinions of all affected sectors on the implementation of the said Law. These can provide some bases for the proposals to amend the Law.
283. On Liquid Fuels and Liquified Petroleum Gas, What is the total number of LPG refilling plants nationwide?
There are 263 (as of CY 2016) active refilling plants in the country.
284. What is DC no. 2000-06-010?
Department Circular No. 2000-06-010 or the "Revised Schedule of Penalties" in the LPG Industry is a set of penalties imposed on players engaged in the business of LPG who violated Rules and Regulations governing the LPG Industry.
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285. What are the offenses and corresponding penalties in the DC 2000-06-010? Refiller Distributor/ Outlet
Violations Marketer
(in Thousand Pesos)
No tare weight 3 2 1 No appropriate LPG seal 3 2 1
No trade name/unbranded
No serial no./no 4 3 1 distinguishing color, no embossed/ identifying mark/dist. Color
Underfilled 4 3 1 Tampering, altering, modifying cyl., changing valves, 5 3 1.5 repainting, relabeling
Unauthorized decanting/refilling 5 5 5
No price display board Reprimand
No weighing scale 5 3 Reprimand Hoarding 10 Refuse inspection 10 Refuse fine Closure
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286. Have there been instances when LPG players were penalized?
Number of Cases Endorsed to Legal Division
Reporting No. of No. of No. of Closed and Amt. of Fines Year Cases Cases Pending Terminated Collected Filed to Acted Cases OLC Upon
CY 2004 640 36 29 42 P 157,000 CY 2005 882 374 30 132 P 208,000 CY 2006 615 1,461 21 509 P 883,500 CY 2007 92 121 12 44 P 133,000 CY 2008 514 259 56 86 P 111,500 CY 2009 412 530 94 78 P 981,000 CY 2010 398 318 80 52 P 446,000 CY 2011 490 343 147 38 P 213,500 CY 2012 544 179 365 29 P 148,500 CY 2013 558 332 226 19 P 42,000 CY 2014 415 15 400 0 0 CY 2015 1034 152 882 0 0 CY2016 983 448 537 57 P22,605,500
287. What is EO 655?
Executive Order No. 655 is an order "Creating the Presidential Task Force on the Security of Energy Facilities and Enforcement of Energy Laws and Standards"
288. How many LPG establishments were inspected in 2015? What are the violations seen in the cylinders?
Out of 1,258 LPG establishments inspected, 964 establishments or 77% were found with violations ranging from LPG cylinders with defective/no/unauthorized seals, underfilled, no serial numbers, with defective/no tare weight markings, No SCC, among others.
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289. What is the government doing to ensure the safety of consumers, specifically the households? What is the government’s program to curb the proliferation of underfilled, unsafe and substandard LPG cylinders?
1. Conduct quantity and quality monitoring 2. Strengthen collaboration among partner agencies on enforcement (i.e., PTF-SEFEELS, DTI/DILG-BFP/LGUs) 3. Enhance consumer protection through massive information, education and communication campaigns 4. Forge partnerships with concerned private sector and consumer groups
290. What are the administrative fines/sanctions against prohibited acts in D.C. on Auto-LPG?
Prohibited Acts First Offense Second Third Offense Offense
Illegal trading P 10,000 P 10,000 Cancellation Engaging in business P 60,000 or revocation without a Standards of DOE- Compliance Certificate COC/SCC Refusal to allow P 10,000 P 10,000 inspection Underdelivering P 10,000 P 10,000 Hoarding P 10,000 P 10,000 Adulteration P 10,000 P 10,000 Note: An additional P10,000 fine shall be imposed for 2nd time violators of same prohibited act
291. How many Auto-LPG dispensing stations are there in the country?
There are a total of 140Auto-LPG dispensing stations in the country as of December 2016.
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292. What percentage is the compliance to PNS, biofuels law and clean air act of gasoline stations as of December 2015?
Number of samples of petroleum products 1,560 gathered for further laboratory tests Total number of products whose samples 1,378 or 88% passed the CAA compliance Total number of products whose samples 182 or 12% failed to meet the PNS specifications for petroleum products
293. Are there any instances that violators were apprehended under the retail rules?
Number of Cases Endorsed to Legal Division No. of No. of Closed No. of Amt. of Reporting Cases Cases and Pending Fines Year Filed to Acted Terminate Cases Collected OLC Upon d
CY 2002 115 110 5 62 P 63,000 CY 2003 158 123 35 28 52000 CY 2004 256 110 146 7 209000 CY 2005 354 122 32 23 297000 CY 2006 191 103 88 23 350000 CY 2007 250 205 45 36 590000 CY 2008 331 212 119 37 521000 CY 2009 301 97 204 15 110000 CY 2010 410 176 234 27 190000 CY 2011 165 98 67 31 40000 CY 2012 727 412 315 1 40000 CY 2013 809 136 673 2 30000 CY 2014 249 249 CY 2015 * * * * * NOTE: *Table still to be completed by Legal
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294. What is the concept of the Gasoline Station Lending and Financial Assistance Program (GSLFAP)?
The GSLFAP is designed to provide credit assistance to New Industry Participants who successfully complete the two-fold program on management and skills course (SMC)/training in the retailing of all petroleum products for the establishment, operation, improvement, management and maintenance of gasoline station including those gasoline stations engaging in LPG retail business.
295. With the implementation of Republic Act (RA) no. 9367, also known as the "Biofuels Act of 2006”, what are the sources and volumes of imported ethanol for the bioethanol program?
ETHANOL IMPORTS for the BIOETHANOL PROGRAM BY SOURCE
V O L U M E (in '000 Barrels) COUNTRY 2010 2011 2012 2013 2014 2015 2016 NETHERLANDS 17 0 0 0 0 0 0 CAMBODIA 7 0 0 96 3 0 0 SINGAPORE 151 131 136 0 21 30 0 PHILIPPINES (SUBIC) 265 406 636 478 129 0 0 INDONESIA 17 20 0 61 188 0 0 USA 78 353 44 432 1,525 1,750 1,516 VIETNAM 15 62 32 152 204 0.4 0 KOREA 249 235 19 13 16 72 12 CHINA 83 0 0 0 0 0 0 INDIA 0 0 0 0 0 0 0 AUSTRALIA 0 0 172 123 0 53 104 BRAZIL 0 1 0 332 101 0 0 THAILAND 0 169 533 266 26 0 0 PAKISTAN 0 0 0 28 0 0 0 TAIWAN 0 0 0 0 0 0 0 GUATEMALA 0 0 0 32 0 0 0 TOTAL VOLUME ('000 bbls) 883 1,376 1,572 2,013.2 2,214 1,904 1,632
296. What are the Department Circulars issued relative to the implementation of "Biofuels Act of 2006”?
DEPARTMENT CIRCULAR NO. DC2015-06-0004 Implementing the Corresponding Philippine National Standard Specifications (PNS) for the Euro 4/IV-PHFuels Complying with the Euro 4/IVEmissions Standard
DEPARTMENT CIRCULAR NO. DC2015-06-0005 Amending Department Circular No, 2011-02-0001 Entitled “Mandatory Use of Biofuel Blend”
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DEPARTMENT CIRCULAR NO. DC2015-06-0006 Providing for the Guidelines in the Conduct of Inspection Using Mobile Monitoring and Testing Laboratory
DEPARTMENT CIRCULAR NO. DC2015-06-0007 Revised Guidelines on the Utilization of locally-Produced Bioethanol in the Production of E-Gasoline
297. What is the impact of the current tax proposals to the domestic oil prices?
The impacts of the proposed re-imposition of excise taxes on oil products are summarized in the following table:
ESTIMATED IMPACT OF ADDITIONAL EXCISE TAX ON PETROLEUM PRODUCTS Prevailing Price Original Proposed New Impact on PP Products as of 14 Mar 2017 Excise Excise Pump Price P/liter % P/liter Gasoline 46.68 4.35 10.00 6.33 14% 53.01 Avturbo 43.72 3.67 10.00 7.09 16% 50.81 Kerosene 35.50 0 6.00 6.72 19% 42.22 Diesel 30.95 0 6.00 6.72 22% 37.67 Fuel oil 36.97 0 6.00 6.72 18% 43.69 LPG 33.68 0 6.00 6.72 20% 40.40
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298. What is the legal basis for the natural gas program?
TITLE DESCRIPTION Department Adm. Order No. 193 Constituting an Inter-Agency Committee on Natural Gas (22 August 1990) Development An Act Creating the Department of Energy, Rationalizing Republic Act No. 7638 the Organization and Functions of Government Agencies (9 December 1992) Related to Energy, and For Other Purposes DOE Circular No. 95-06-006 Policy Guidelines on the Overall Development and (15 June 1995) Utilization of Natural Gas in the Philippines Executive Order No. 254 Creating the Philippine Gas Project Task Force (30 June 1995) Designating the Department of Energy as the Lead Executive Order No. 66 Agency in Developing the Philippine Natural Gas (18 January 2001) Industry DOE Circular No. 2002-07-004 Rules of Practice and Procedure Before the Department (31 July 2002) of Energy Administrative Order No. 38 DOE Reorganization (23 August 2002) DOE Circular No. 2002-08-005 Interim Rules and Regulations Governing the (27 August 2002) Transmission, Distribution and Supply of Natural Gas DOE Special Order No. 2002-12- 050 Assignment of Personnel at the Natural Gas Office (3 December 2002) Executive Order No. 290 Implementing the Natural Gas Vehicle Program for (24 February 2004) Public Transport Guidelines on the Issuance of Certificate of Accreditation DOE Circular No. 2004-04-004 and Certificate of Authority to Import under the Natural (2 April 2004) Gas Vehicle Program for Public Transport (NGVPPT) Enhanced Implementation of the NGVPPT and the DOE Circular No. 2005-07-006 Development of Compressed Natural Gas (CNG) Supply (5 July 2005) and Infrastructure Adopting DC 2004-04-004 as the Implementing Rules and Regulations of EO Nos. 396 and 488 dated DOE Circular No. 2006-04-0004 December 31, 2004 and January 12, 2006, respectively, (27 April 2006) and DC 2005-07-006 dated July 5, 2005 and Amending Certain Provisions of DC 2004-04-004
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299. What are the current uses of natural gas in the country?
Power generation: The Malampaya natural gas is mainly used to generate electricity. The three power plants in Batangas currently being supplied by Malampaya provide a total of 3,213 MW of power for Luzon (Ilijan, Sta. Rita, San Lorenzo, San Gabriel and Avion).
Industrial process: The first industrial user of natural gas is the Pilipinas Shell Petroleum Corporation’s (PSPC) refinery in Batangas which started using natural gas since October 2005 as fuel for its gas turbine generators (GTG) and supplemental fuel to its furnaces within the PSPC refinery.
300. What are the proposed projects for the natural gas industry?
The proposed developments in the natural gas industry, including gas infrastructure network and facilities, hope to bring about expansion of natural gas use in other non-power demand sectors such as transport, industry and household. Natural gas poses as a clean-burning alternative fuel for transport (e.g., public utility vehicles), in various industrial processes (e.g., boiler systems, district cooling systems, water heating systems) and in household cooking.
The natural gas system infrastructure is vital to the security, economic prosperity to sustain the country’s natural gas industry. One of the challenges of using gas is the development of the gas transportation infrastructure network. Investment in transmission and distribution infrastructure network identified for Luzon, Visayas and Mindanao is important to spur expanded use of natural gas in the country. There is an ongoing study conducted by Rebel Group, Public Private Partnership (PPP) Center’s technical advisor on the conduct of Technical Feasibility study of the Batangas-Manila Pipeline project. The Joint NEDA-ICC Cabinet Committee approved the Batangas-Manila Natural Gas Pipeline Project I ('Project') for NEDA Board confirmation. Rebel is currently updating the study.
Likewise, the country’s indigenous natural gas supply versus the level of additional capacity requirement finds significant challenges ahead for the downstream natural gas industry. Existing gas field could not sufficiently provide the long-term requirements of the additional capacities unless large and timely investments are necessary to bring forth new domestic gas resources, which requires more than five years to develop. New frontier resources such as liquefied natural gas (LNG) including a pipeline Page 174 of 207
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network are of critical importance. Natural gas infrastructure projects are capital-intensive and require an anchor load to justify the economics of the infrastructure projects.
The power plant projects are the typically ideal anchor loads since power generation capacity can come on-line when the gas infrastructure is complete. However, The Philippines’ power sector continues to experience governance and market failures 15 years after the EPIRA in 2001. Currently, the Philippines has one of the highest electricity tariffs among Asian and SEA countries, but lacks a sustainable policy roadmap for the power and gas sectors which can encourage LNG infrastructure investments and importation as well as no clear policy or governance mechanisms capable to ensure Philippines gas future post Malampaya. In recognition of this, IHS Global Pte Ltd. has submitted a proposal to the South East Asia Prosperity Fund Project for the Philippines aimed at establishing a coalition of government and energy stakeholders that will work towards developing an energy policy roadmap for the future. This will support the use of liquefied natural gas (LNG) as the economic, energy-secure and low-carbon solution to the Philippines’ power needs in the immediate future.
301. What is banked gas? Is there a possibility of using banked gas to spur development in the natural gas industry?
Under the Gas Sales and Purchase Agreement (GSPA), a power generating facility has the obligation to pay for its contracted volume of natural gas at an agreed take-or-pay level whether such volume is consumed or not. However, banked gas, which has already been paid for, can be accumulated in instances wherein the generating facility does not actually consume such volume. Once the generating facility attains or exceeds its take-or-pay level for the year, it can avail of the banked gas for the remaining period in that contract year.
There are certain conditions that have to be met to be able to withdraw such banked gas, one of which is the generating facility’s attainment of its take-or-pay level for the year. Another condition is the utilization of the banked gas by the entity that has accumulated it for power generation purposes.
In September 2009, PNOC purchased 108.6 petajoules (PJ) of Ilijan’s banked gas to spur development of the Batangas to Manila pipeline project. It was looked at as the immediate source of supply to jumpstart the expanded utilization of natural gas in the industrial, commercial and
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transport sectors. In 2015, PNOC and SC 38 Consortium has jointly tendered its banked gas and the new declared volume of gas in the Malampaya reservoir equivalent to 400 MW or equivalent volume of 227.995 peta-joules to potential natural gas buyers in 2015. There was a partial awarding of contract to the bidder that meets the supplier’s criteria, the remaining volumes of said new gas and banked gas can be made available to interest buyers starting in 2016.
302. Is Natural Gas, LNG, or CNG Safe to Use?
Natural gas is an odorless and colorless mixture of hydrocarbon gases primarily of methane. It is a clean-burning and efficient fuel, which can be considered as a versatile fuel as it can be used during base load to peak demand periods and is the preferred energy source for new generating capacity. Among the fossil fuels, natural gas is the safest fuel to use. It has a limited range of flammability as it requires the correct mixture of air and fuel not lower than 5% nor greater than 15% in air and the ambient temperature must be not less than 63 C in order for it to combust. It is lighter than air such that it easily dissipates into the atmosphere.
Basically, natural gas is in gaseous state and it can be easily converted either to liquefied natural gas (LNG) or compressed natural gas (CNG) to make it more economical for long distance transport. Thus, LNG and CNG also possess the properties of natural gas.
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303. Are there differences between LPG, LNG, and CNG?
LPG LNG CNG Description By-product of Possess natural Possess natural crude oil refinery gas properties gas properties or natural gas processing Composition Propane and/or Methane Methane Butane Temperature Atmospheric -163 C Atmospheric Pressure 200 psi Atmospheric 2900 psi Flammability 2.37-9.5 5-15 5-15 range in air, (%) Ignition point, 493 630 630 (C) Density Heavier than air Lighter than air Lighter than air compared to (once re-gasified) air Uses Power As is: Power generation generation Industrial Transport fuel Industrial process process Re-gasified: (furnace (furnace operation, Power operation, boiler system) generation boiler system) Commercial Industrial Commercial (district process (district cooling cooling or (furnace or heating) heating) operation, boiler Transport fuel Transport fuel system) Household Household Commercial cooking cooking (district cooling Agricultural Agricultural or heating) (crop drying) (crop drying) Household
cooking
Agricultural (crop drying)
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Liquefied petroleum gas (LPG), which is commonly used now in the country for household cooking, is a mixture of hydrocarbon gases primarily of propane and butane. This is unlike natural gas, LNG or, CNG, which are primarily composed of methane.
LPG is commonly a by-product of the crude oil refinery process. However, it can also be a product of the natural gas refining process if the raw natural gas has high content of propane and butane.
Liquefied natural gas (LNG) is natural gas subjected to cryogenic temperature (-163 C) and atmospheric pressure which converts it to liquid form. The liquefaction process reduces the volume of natural gas by 600 times. Therefore, it is more economical to transport natural gas as LNG over long distances via LNG vessels. A unit volume of LNG becomes 600 times more once converted back to natural gas (gaseous state). LNG can be converted back to natural gas simply by vaporizing it or subjecting it to heat. The process of regasification is normally done in an LNG receiving terminal.
Compressed natural gas (CNG) is natural gas subjected to a pressure of 2900 psi (pounds per square inch) which reduces volume by 300 times. It remains in gaseous state. CNG can also be transported via CNG vessels.
Similar to LPG, LNG and CNG may also be refilled in cylinders and can be used as fuel for transport. Although, at present, LNG transport technology is limited to big trucks. It must be emphasized though that LNG, CNG, and LPG cylinders will have different specifications as they have different pressure and temperature requirements.
LPG is heavier than air, such that when released into the atmosphere it accumulates near the ground. Given the low flammability range of LPG, it is easy to ignite. LNG and CNG, if released into the atmosphere, convert to natural gas. Natural gas is lighter than air and easily dissipates into the atmosphere. LNG and CNG, as they also possess the properties of natural gas, have higher flammability range than that of LPG.
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304. What are the comparative energy prices?
Malampaya Project (in US Dollars per million Btu, $/MMBtu)
LNG Natural Gas Crude Oil Year Japan German UK USA Canada Philippines OECD (cif) (Import (Index)** (Henry (Alberta)*** (Malampaya) countries Price)* Hub)*** (cif) 2000 4.72 2.89 2.71 4.23 3.75 - 4.83 2001 4.64 3.66 3.17 4.07 3.61 5.32 4.08 2002 4.27 3.23 2.37 3.33 2.57 5.02 4.17 2003 4.77 4.06 3.33 5.63 4.83 5.41 4.89 2004 5.18 4.32 4.46 5.85 5.03 5.70 6.27 2005 6.05 5.88 7.38 8.79 7.25 6.30 8.74 2006 7.14 7.85 7.87 6.76 5.83 7.39 10.66 2007 7.73 8.03 6.01 6.95 6.17 7.32 11.95 2008 12.55 11.56 10.79 8.85 7.99 11.45 16.76 2009 9.06 8.52 4.85 3.89 3.38 8.67 10.41 2010 10.91 8.01 6.56 4.39 3.69 9.60 13.47 2011 14.73 10.61 9.03 4.01 3.47 11.63 18.56 2012 16.75 10.93 9.46 2.76 2.27 12.67 18.82 2013 16.17 10.73 10.63 3.71 2.93 12.20 18.25 2014 16.33 9.11 9.22 4.35 3.87 11.84 16.80 2015 10.31 6.61 6.53 2.60 2.01 8.74 8.77 Source: BP Statistical Review of World Energy June 2016 Source: 1984-1990 German Federal Statistical Office, 1991-2009 German Federal Office of Economics and Export Control (BAFA) ** Source: Heren Energy Ltd. (Heren NBP Index) *** Source: Energy Intelligence Group. Natural Gas Week Note: Btu – British thermal units; cif = cost + insurance + freight (average prices)
305. How much has been collected by the government from the Malampaya Project?
The amounts collected from January 2002 to March 31, 2017 were as follows:
BIR PhP 165.018 Billion DOE: LGU Share PhP 100.723 Billion NG Share 137.950 238.673
Total Government Share PhP 403.691 Billion
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306. What is the basis of the 40% contractor’s share?
The 40% CONTRACTOR’S SHARE is PURSUANT to SECTION 7.4 of SC 38 which states that “CONTRACTOR will retain an amount equal to its fee of 40% of the net proceeds from Petroleum operations.”
307. In computing income tax, why do you have to divide the 40% contractor’s share to 70%?
The CONTRACTOR’S SHARE is Net of Income Tax. We have to divide it by 70% to arrive at the correct tax base before multiplying the Tax Rate of 30%.
308. Why is the income tax of the contractor taken from the 60% government share?
PURSUANT to SECTION 6.3 of SERVICE CONTRACT NO. 38, “ THE OFFICE OF ENERGY AFFAIRS (now DOE) shall assume and pay on behalf of the CONTRACTOR and its parent company, on the first transaction in each instance where the tax is imposed, all income taxes payable to the Republic of the Philippines based on income and profits and, with respect to CONTRACTOR, on the first transaction in each instance where the tax is imposed, by the Government of the Philippines on the distribution of income and profits derived from Petroleum operations to its parent company. The OEA (now DOE) shall promptly furnish to CONTRACTOR, without fee or other consideration, the official receipts issued in the name of contractor by any duly empowered Government authority, acknowledging the payment of said taxes.”
309. How much is the 40% projected source of LGU share for 2017 to 2019?
2017 – PhP 7.040 Billion 2018 – PhP 6.472 Billion 2019 – PhP 7.201 Billion
310. How much is the projected net national government share for 2017 to 2019?
2017 – PhP 10.560 Billion 2018 – PhP 9.709 Billion 2019 – PhP 10.501Billion
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311. What was the cost recovery rate used for each year in the projection of government share?
2017 – 24.02% 2018 – 28.31% 2019 – 18.16%
312. How much was the collected government share for the period January 1 to March 31, 2017?
BIR PhP 1.786 Billion DOE: Source of LGU Share PhP 1.204 NG Share 1.806 3.010 Total Government Share PhP 4.796 Billion
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THE ALTERNATIVE FUELS PROGRAM
313. What is the significance of the alternative fuels program?
The alternative fuels program is one of the key components of Energy Independence Agenda, which outlines the roadmap for the attainment of 60% energy sufficiency level by 2010 and beyond.
The Philippine Department of Energy (DOE) is implementing a long-term alternative fuels program to help in attaining supply security and contribute to climate change mitigation through reduce dependence on imported oils and shifting to an environment-friendly alternative. The said program also aims to de-couple the price of transportation fuel from volatile oil prices. Through the said program, the DOE intends to tap the country’s available indigenous energy resources as potential transportation fuel. The goal is to develop indigenous and renewable energy fuels for long term energy security as a pillar for sustainable growth.
314. What are the benefits of using alternative fuels?
The benefits of using alternative fuels can be summarized as follows:
• Reduce our dependence on imported fuel • Contributes to energy security through fuel diversification • Generate foreign exchange savings from fuel displacement • Improve air quality • Contribute to inclusive growth
315. What programs are currently being implemented relative to alternative transport fuels development?
In the promotion of alternative fuels, the current programs are Natural Gas Vehicle Program for Public Transport (NGVPPT), Auto-LPG Program, and Electric Vehicles (EVs) Program.
316. Are there other initiatives being pursued aside from the programs mentioned above?
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vehicles, new energy storage technologies are also included in the long- term plans of the program.
THE NATURAL GAS VEHICLE PROGRAM FOR PUBLIC TRANSPORT (NGVPPT)
317. What is Natural Gas?
Natural Gas is one of the three (3) major types of fossil fuels. It is colorless, shapeless and odorless. It is a combustible mixture of hydrocarbon gases primarily of methane.
Being a gas, it is very different from coal and oil, not only in its chemical composition but also in terms of extraction, handling and use. Natural Gas was formed from the remains of plants and animals which lived on the earth millions of years ago. Over time the remains were covered by layers of sand, rock, and ice. Heat and pressure eventually changed them into methane gas that can be used as fuels.
Natural gas can be used for industrial power generation, auto-power generation, alternative transport fuel, chemical feedstock, district cooling heating systems and crop drying.
318. What are the advantages / benefits of using Natural Gas as fuel for transport?
. Natural Gas (NG) has clean burning characteristic . More quiet operation, having less vibration and less odor than the equivalent diesel engine . NGV technologies are already available in the world market (widely used in the US, Brazil, Argentina, Italy, India, Pakistan) . Safe to use. It has compiled an excellent safety record:
. Unlike LPG, NG is lighter than air and dissipates quickly into the atmosphere . NG is non-toxic and non-carcinogenic . NG has flash point that will not burn easily
319. Why is it called “pilot project”?
The NGVPPT is conceptualized as a pilot project as provided under Executive Order (EO) 290 Implementing the Natural Gas Vehicle Program for Public Transport with the primary objective of demonstrating and showcasing the initial operation of Natural Gas Vehicles for Public
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Transport in the Batangas– Manila and/or Metro Manila routes using indigenous natural gas from Malampaya. Its overall objective is to promote the use of Compressed Natural Gas(CNG) as an indigenous clean alternative fuel to diesel. The components of the pilot project are:
. Launching of 200 NGVs . Construction and operation of mother-daughter CNG refueling stations . Application of incentives and financing packages such as o Income Tax Holiday (ITH) o Zero percent rate of duty o Issuance of Certificate of Compliance with Emission Standards o Preferential franchises o Accelerated issuance of Environmental Compliance Certificate o Affordable and commercially tenable financing packages from Government Financial Institutions (GFIs) o Manpower development and capability building through training and technology transfer o Attractive CNG price . Information Education Campaign (IEC)
320. How promising is this CNG pilot project? Will it be the first step to energy self-sufficiency of the country?
The Project, if it proceeds to commercial replication, has high potential of contributing in attaining energy self-sufficiency. A number of bus companies would want to convert to CNG as it provides a solution to cleaner environment and continuously increasing prices of imported fuels. Likewise, there are private companies that expressed their intention to invest in putting up CNG supply infrastructure and related facilities. Certainly, the project is a concrete step towards attaining energy independence.
321. What is the extent of participation of the private sector in the pilot phase of the NGVPPT?
The NGVPPT pilot project is a private-sector led activity with Shell Philippines Exploration (SPEX), Philippine National Oil Company - Exploration Corporation (PNOC-EC), Pilipinas Shell Petroleum Corporation (PSPC) and DOE-accredited private bus operators, as major players.
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322. How much is the investment being undertaken for the pilot project?
The project has an estimated investment cost of US$8.1 Million a. CNG Mother: $3.5 M b. CNG Daughter: $2.1 M c. Buses: $2.5 M
323. Are there plans to expand the project’s coverage?
It is the Department’s objective to expand the coverage of the project up to the commercial phase. Once the pilot phase has been completed and the operation of CNG buses is proven to be economically viable, it will be recommended to DOTr to adopt CNG-fed buses as alternative for the diesel-fed buses under the commercial phase of the Program.
324. How is the price of CNG per liter compared to Diesel?
Under the pilot project, the price of CNG is pegged at Php 14.52 per diesel liter equivalent (DLE or Nm3) or Php 18.38 per kilogram for a seven–year period.
325. What is the extent of the users/bus driver’s training on CNG technical aspects and safety measures?
The bus operators, drivers and maintenance personnel attended various CNG technical and safety seminar sponsored by the USAID and Cummins, Philippines. Likewise, accredited bus operators conducted in- house seminars by trainers trained by PSPC. Capacity Building on Automotive Servicing and Conversion were initiated for regulators/implementers, drivers and mechanics through a Memorandum of Agreement (MOA) between DOE and TESDA signed in September 11, 2009.
326. What are the details of the CNG refilling station under the Pilot Project?
The first CNG daughter station is located along South Expressway (Northbound)in Brgy. Sto. Tomas, Biñan, Laguna (near Mamplasan exit). The daughter station was inaugurated on October 24, 2007 and launching of Libreng Sakay started on March 24, 2008 which covers routes Batangas-Cubao and Pacita-Fairview. The activity lasted for fourteen days and was very well accepted by the riding public. Commercial operation started on April 8, 2008. Page 185 of 207
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Capacity of refilling station service under the Pilot Project
The CNG refilling station can service 50 CNG buses per day.
Special equipment used for this refilling station
There are various special equipment used in CNG refilling station such as, compressor, gas nozzle, the mobile accumulator transport system (MATS) filled with cylinder tanks and break away hoses.
327. What is the Status of the NGVPPT
The Pilot Project has paved the way for the introduction of CNG as an alternative fuel for transport through demonstration and operation of CNG buses. CNG infrastructures, such as the Daughter Station, had been established at Shell Mamplasan Station located at Biñan, Laguna. Currently, the NGVPPT is not moving since February 2014 due to non- availability of CNG supply caused by technical problems at the Daughter Station and non-issuance of franchise for public conveyance since 2011. Notwithstanding the disruption in the implementation, the Pilot Project, to date, was able to displace an estimated four million (4) million liters of
diesel with a corresponding reduction in CO2 emission estimated at around 4,400 metric tons.
328. Which government agencies and private companies collaborate with the DOE in the CNG pilot project?
Some government agencies have been identified as members of the NGVPPT Executive Forum through the EO 290. The NGVPPT Executive Forum is a regular and permanent body tasked to provide effective leadership, coordination and proper direction for important aspects in the implementation of the NGVPPT. The members of the Executive Forum are:
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Agency Office/Units Involved Land Transportation Office (LTO) Department of Transportation (DOTr) Land Transportation Franchising and Regulatory Board (LTFRB) Metropolitan Manila Development Authority (MMDA) Department of Trade and Industry (DTI) Bureau of Product Standards (BPS) Bureau of Investment (BOI) Department of Finance (DOF) Bureau of Customs (BOC) Technical Education and Skills Development Authority (TESDA) Department of Science and Technology Metals Industry Research and Development (DOST) Center (MIRDC) Philippine Council for Industry, Energy and Emerging Technology Research and Development (PCIEERD) Department of the Interior and Local Bureau of Fire Protection (BFP) Government (DILG) Department of Environment and Natural Environmental Management Bureau (EMB) Resources (DENR) Shell Philippine Exploration (SPEX) Service Contract (SC)-38 Consortium Chevron-Texaco Philippine National Oil Company (PNOC) Government Financing Institutions Development Bank of the Philippines (DBP) GFIs Landbank of the Philippines (LBP)
Aside from government agencies, there are also non-government experts providing technical assistance in the project like, Mr. Alex Loinaz of Filcar Foundation and Mr. Ramon Cuison of Red Clover Corporation.
THE AUTOLPG PROGRAM
329. What is AutoLPG? AutoLPG is the use of liquefied petroleum gas (LPG) as automotive fuel. It is considered an alternative fuel since it is cleaner than conventional automotive fuels.
330. What is the role of DOE in the AutoLPG Program? Under the program, the DOE is mandated to promote the use of LPG as alternative fuel for transportation. Consequently, to attain this objective the DOE coordinate and collaborate with various government agencies to harmonize and develop rules, guidelines and standards related to the use of LPG for vehicles.
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331. Is there an Available Technology for AutoLPG in the Market?
AutoLPG technology has already been proven and available in the world market, i.e., Original Equipment Manufactured (OEM) autoLPG vehicles and converted autoLPG vehicles. Local aftermarket conversion costs ₱26,000 (inclusive of cylinder) while OEM autoLPG vehicle cost range from ₱560,000 to ₱920,000 from UK, USA, Japan and Korea. At present, there are no OEM autoLPG vehicles available in the country.
Before a vehicle can use autoLPG, there is a need to install conversion equipment or kit that will convert the engine into a multi-fueled engine.
332. What are the Benefits of Using AutoLPG? Environmental Benefits
a. AutoLPG is cleaner than conventional fuels. Compared with equivalent gasoline fuelled vehicles, LPG has less ozone-forming potential (a measure of its tendency to generate photochemical smog, which causes cancer and respiratory problems), lower greenhouse gas (GHG) emissions, and less toxic emissions.
Technological Benefits
b. Feedback on the usage/operation of autoLPG vehicles includes less maintenance, minimized pilferage, lesser engine vibration and comparable power output and torque.
Price Advantage
c. AutoLPG is priced lower than gasoline. AutoLPG retail stations currently sell autoLPG at around PhP 19.49 – 22.90 per liter (as of December 2016 – January 2017 OIMB-DOE). AutoLPG vehicle operators claim that savings is still realized at the above price) even if autoLPG vehicles travel 10-20% less the distance traveled by gasoline-fed vehicles with the same amount on fuel.
333. What is the current status on the use of LPG for vehicles in the Philippines? Currently, there are 122 LPG retail dispensing stations and 67 garage- based dispensing stations Nationwide (as of August 2016).
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334. What is the number of vehicles fuelled by LPG in the Philippines? An estimated 8,415 converted autoLPG-fed vehicles (Luzon area only) are operating in the country. (As of June 2016).
AutoLPG-fed converted taxis are also in commercial operation in Cebu City, Iloilo City, Davao City, Cagayan De Oro, among others.
335. What are the incentives to promote the use of LPG in vehicles? DBP has also included AutoLPG in the “Clean Alternative Transport Fuel Financing Program,” which provides tenable financing package for autoLPG-related activities (i.e., acquisition of AutoLPG vehicles). LTFRB also extended the franchise of autoLPG-fed converted taxis to 2-years.
336. What standards have been adopted or formulated to guide the use of AutoLPG? To ensure safety in the use of autoLPG and autoLPG technology, standards on the utilization of LPG in vehicles, cylinders and dispensing stations were promulgated in November 2006.
• There are 5 nationally- adopted and -developed standards related to Auto LPGProgram namely:
• PNS/DOE FS 3:2006– Auto-LPG Dispensing Station • PNS/UN ECE 67:2006– Uniform provisions concerning approval of specific equipment of motor vehicles using LPG in their propulsion system and approval of a vehicle fitted with specific equipment for the use of LPG in its propulsion system with regard to the installation of equipment • PNS/UN ECE 115:2006 – Uniform provisions concerning the approval of specific LPG retrofit systems to be installed in motor vehicles for the use of LPG in their propulsion system • PNS 04:2006– Road vehicles – Automotive LPG components (Containers) • PNS 05:1983– Code of Practice for the Use of LPG in Internal Combustion Engines
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THE ELECTRIC VEHICLES (EVS) PROGRAMS
337. What is an Electric Vehicle?
An electric vehicle (EV) is a type of vehicle that is driven by a battery that provides energy, an electric motor that drives the wheels and a controller that regulates the energy flow to the motor.
338. What are the benefits of driving an EV? Environmental Benefits
. Green Attribute – EVs are regarded as an environment-friendly alternative to conventional vehicles because they have no TAIL PIPE emissions.
. Less Noise and Vibration – EVs run far more quietly with minimal vibration compared to gasoline-fed counterpart, thus enhancing passenger comfort.
Economic Benefits
. Low operating and maintenance costs - Electric motors have very few moving parts and don’t need fluids such as engine oil and transmission fluid, so they require relatively little maintenance and are less likely to leak.
. Overnight Charging – EVs such as electric tricycles (E-Trikes) and electric jeepneys (E-Jeeps) using lead acid batteries charge up in 6-8 hours at night when electricity demand is low and cheap.
. For e-trikes using lithium-ion batteries, charging time is 1 to 2 hours and can use top-off charging.
. Reduced Oil Consumption – The use of EVs contributes to reduction of petroleum oil consumption. Likewise, it reduces used engine oil dumping.
. Increased Energy Efficiency
339. Are EVs available in the market?
EVs are available commercially both local and imported. The market offers a variety of EVs such as e-trikes powered with lead acid batteries which cost between PhP150,000-PhP180,000 e-trikes powered by lithium-ion batteries which cost between PhP200,000-PhP450,000 and e- Page 190 of 207
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jeeps which costs PhP600,000-PhP1,600,000. Other types of EVs in the market are the e-shuttles, e-quads, golf carts, e-bikes, e-scooters and e- buses.
340. How many potential local EV suppliers are there?
• BEMAC Electric Transportation Phils., Inc. • Philippine Utility Vehicle (PhUV), Inc. • Tojo Motors • Gerweiss Motors • Electric Vehicle Expansion Enterprises, Inc. • EV Wealth • Star8 Philippines, Inc. • Alternative Energy Trailblazers • Prozza Hirose Mfg., Inc. • Kea Industrial Inc. • Phil-Etro EV, Inc. • Ropali-Teco Corp. • PinoyAkoCorporation • Pangea Philippines, Inc.Terra Motors Philippines Corporation • Beet Philippines, Inc. • KytoPrime Green Power • Clean Transport Solutions,E-Motors • Serrotma – Alternative Modern Transport (AMT) • E-Save Transport Systems, Inc. • Master Atlantic Land Transport (MALT) Trading, Inc. • DC Electric Vehicle Corporation • Green Eco-tech • Kenwei Electric Vehicle Philippines • Eagle Motorcycles • G Car Motors Phils., Inc. • EVNOVATIONS • Mitsubishi Motors • Honda Motors • Toyota Motors • Lexus
341. Are EVs already in use locally?
According to a report of the Electric Vehicles Association of the Philippines (EVAP), there are about 8,000 electric vehicles sold and being used in major cities and provinces nationwide (Mandaluyong City, Makati City, Alabang, Quezon City, Manila, Antipolo, Cavite, Boracay, Davao City, Surigao, etc.).
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342. Is there a government initiative promoting the use of EVs in the Philippines? Yes. In April 13, 2011, the DOE through a technical assistance from the Asian Development Bank (ADB) introduced twenty (20) units of efficient e-trikes as a pilot project in the Mandaluyong City.
The pilot project showcased the potential of E-Trikes to address the current deterioration of air quality in urban areas and to increase the income of drivers.
As a result of the success in the Mandaluyong City demonstration, the DOE initiated a scale-up “E-Trike Project” or “Market Transformation through Introduction of Energy Efficient Electric Vehicles Project” which involves the deployment of 100,000 E-Trikes through a “lease-to-own” scheme to replace the same number of gas-fed internal combustion engine (ICE) tricycles specifically those two-stroke motorcycles. The Project will displace 89 million liters of gasoline fuel annually and avoid carbon
dioxide (CO2) emission of about 260,000 tons CO2 per year.
The Project will run for 5 years to be implemented in two (2) phases. The first phase is the Industry Development Phase which involves deployment of 20,000 e-trike units after which an Inter-Agency Mid-term review will be conducted to evaluate and assess the progress of the first phase. The mid-term review aims to assess if the private sector/market can stand alone or well established enough or should the government continue the second phase. The second phase is the Scale-up Phase which involves deployment of 80,000 units.
As part of the Project, the DOE in cooperation with the Philippine Information Agency (PIA) launched a Nationwide Contest for the Best E- Trike Design with a theme of “Bright Now! Do Right. Be Bright. Go E-trike!” The nature of the contest focused on the over-all appearance, functionality and achieving appropriate standards of safety for the future three wheeled vehicle of the Philippines. The winners were judged according to its Creativity/Aesthetics, Originality/Innovation, Safety & Functionality and Ergonomics.
Also, on April 15-24, 2013, the DOE conducted the “Name this E-Trike” where the E-Trike picture model was showcased in SM San Lazaro and SM Pasig which resulted to 1,272 entries. Top 10 winning entries were awarded on September 20, 2013.
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I. Benefits of the E-Trike Project
Significantly improve the quality of life of the beneficiaries Promote the use of cleaner and more efficient type of vehicles Reduce health cost and economic impact of lost productivity as a result to air pollution Stimulate the market for E-Trike related support services such as manufacturing and assembly plants, charging stations, repair and maintenance shops, motor and parts supply chains
II. Features of the e-trike
Drive train – the electric motor, batteries, controller and other components enclosed into one sealed module. Pedestrian Side Accessibility – passenger entrance and exit thru pedestrian side as safety measure. Structural Framework – sturdy body incorporated with global safety standards. Comfort – spacious passenger cabin (5 passenger seating capacity). Safety – compliance to the LTO Road Worthiness Guidelines and Inspection
III. Incentive Package of the Project
No down payment Lease-to-own arrangement for 5 years 5-Year Warranty on E-Trike unit Lithium Ion battery warranty (5 years or 80,000 km whichever comes first) Free 3-year registration with LTO and comprehensive insurance Provision of Charging Stations Free Training for drivers, Local Government Unit (LGU) officials & project implementers Standby E-Trike units in the event of case of repairs, downtime, and scheduled maintenance services
343. What is the status of the E-Trike Project (as of March 15, 2017)?
The National Economic and Development Authority (NEDA) Investment Coordination Committee directed the DOE to submit the best option in place of the current framework to address the issues surrounding the project: lack of uptake by LGUs, financing, unit cost concerns, additional costs on distribution arising from the continued delays, and possible additional costs related to wider distribution, etc. Hence, the revised Page 193 of 207
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implementation framework must provide for the expeditious and cost effective distribution of the 3,000 E-Trike units already procured.
344. Is there a DOE standard for E-Trikes?
Powered by a 3 kW electric motor with a 3 kWh lithium-ion battery E-Trike suppliers should be accredited under LTO Manufacturer/ Assembler/ Importer/ Rebuilder/ Dealer (MAIDs)
345. Is there a government policy on the use of EVs in the Philippines?
a. Bureau of Investments (BOI)
Omnibus Investments Code (Executive Order 226) Provides fiscal and non-fiscal incentives to emerging industries listed under the Investment Priorities Plan (IPP) The 2011 IPP already lists of alternative fuel vehicles including the establishment of charging stations for electric vehicles, as priority areas.
b. Land Transportation Office
Registration of Electric Vehicles
AO AHS-2008-014 “Guidelines in the Registration of Low Speed Vehicles (LSV)”
o Covers 4-wheeled electric vehicles o Exemption from smoke emission testing o Orange plate and stickers for private vehicles o Yellow plate and orange stickers for public vehicles (for hire)
Administrative Order (AO) 2006-01 “Guidelines in the Registration of Light Electric Vehicles (LEV)”
o Covers 2-wheeled and 3-wheeled electric vehicles
AO No. AVT-2014-023 dated 23 Jan. 2014
Guidelines for the Accreditation of Manufacturer/ Assembler/ Importer/ Rebuilder/ Dealer of Motor Vehicle and/or its Components Documentary Requirements:
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o Certificate of Guaranty or product-liability undertaking issued by manufacturer of importer o BOC Certificate of Payment o Certificate of Stock Reported o Sales Invoice o PNP-HPG Clearance o Duly accomplished and approved Motor Vehicle Inspection Report o Appropriate insurance certificate of cover o Valid Motorized Tricycle Operator’s Permit (MTOP), if for-hire o Tax Payer’s Identification Number (TIN) o Commercial Invoice of the vehicle from country of origin, if completely built unit (CBU).
ENERGY EFFICIENCY AND CONSERVATION
346. What is Energy Efficiency? What is Energy Conservation?
Energy Efficiency is the use of technology that requires less energy to perform the same function. Using a Light Emitting Diode (LED) light bulb that requires less energy rather than using an incandescent bulb to produce the same amount of light is an example of energy efficiency.
Energy Conservation is any behavior that results in the use of less energy. Turning the lights off when leaving the room is a way of conserving energy.
347. What is Minimum Energy Performance Standard?
It is a performance standard which prescribes a minimum level of Energy Efficiency Ratio or EER for Room Air conditioner.
348. What is an ESCO?
An ESCO, or Energy Service Company, is a business that develops, installs, and arranges financing for projects designed to improve the energy efficiency and maintenance costs for facilities over a seven to twenty year time period depending on the viability of the proposed project. ESCOs generally act as project developers for a wide range of tasks and assume the technical and performance risk associated with the project.
349. What is Green Building?
Green building (also known as green construction or sustainable building)
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refers to both a structure and the using of processes that are environmentally responsible and resource - efficient throughout a building's life-cycle: from siting to design, construction, operation, maintenance, renovation, and demolition.
350. What is the National Energy Efficiency and Conservation Program (NEECP) of the Department of Energy?
It was launched in 2004 to further strengthen and enhance the implementation of energy efficiency and conservation programs across all energy consuming sectors and make it as a way of life for every Filipinos.
351. What are the two major Information, Education and Communication Campaign Programs under the NEECP?
a. Power Conservation and Demand Side Management b. Fuel Conservation and Efficiency in Road Transport
352. What are the Administrative Orders that pertain to the 10% reduction on fuel and electricity in government buildings?
a. A.O. 103 "Directing the Continued Adoption of Austerity Measures in the Government" dated August 31, 2004 b. A.O. 110 "Directing the Institutionalization of a Government Energy Management Program (GEMP)" dated October 25, 2004 c. A.O. 126 "Strengthening Measures to Address the Extraordinary Increase in World Oil Prices, Directing the Enhanced Implementation of the Government's Energy Conservation Program" dated August 13, 2005 d. A.O. 183 “Directing the Use of Energy Efficient Lighting/Lighting Systems (EELS) In Government Facilities (Palit-Ilaw Program)” dated July 9, 2007 e. A.O. 228 “Addressing the Rising Cost of Energy” dated June 2, 2008
353. How much saving was achieved for fuel and electricity through the Government Energy Management Program (GEMP) from September 2005 to December 2016?
Savings derived from GEMP reached about ₱ 2.6 Billion.
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354. How many government agencies, including their attached agencies and instrumentalities, have been spot-checked as part of GEMP from 2005 to 2015?
There were 975 agencies spot-checked for the period 2005 to December 2016.
355. What is Low Carbon Model Town?
The APEC Low Carbon Model Towns (LCMT) project aims to combine energy-efficient buildings; transport and power systems to create communities that affordably reduce energy use and carbon emissions while creating pleasant living conditions. The LCMT project is a part of APEC's Energy Smart Communities Initiative (ESCI).
356. What is the Carbon Footprint of a product?
The total amount of greenhouse gases produced to directly and indirectly support human activities, usually expressed in equivalent tons of carbon dioxide (CO2).
357. What is www.wattmatters.gov.ph of the DOE?
A website that informs consumers of ways they can save money, by being conscious and informed of the rate at which their appliances consume electricity. It allows the user to gauge how much electricity they’re consuming, as well as how much this consumption is costing them.
358. How do you download Apps for wattmatters?
Go to www.wattmatters.org.ph website and click the “download now” button.
359. What is system loss?
System Loss is an operational cost in the power generation that is passed on to the consumers at a rate determined by the Energy Regulatory Commission (ERC) every year and collected by the power utility companies in its monthly bill to the consumers.
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360. Is there a law on anti-pilferage of electricity?
Yes. Republic Act No. 7832 titled “An Act Penalizing the PILFERAGE OF ELECTRICITY and THEFT OF ELECTRIC POWER TRANSMISSION LINES/MATERIALS, Rationalizing System Losses by Phasing Out Pilferage Losses as a Component Thereof and for other purposes.
361. What are the penalties involved in pilferage of electricity?
Republic Act No. 7832 prohibits line pilferage. The penalties for this crime are imprisonment from 6 years and 1 day up to 20 years, and/or payment of P10,000 up to P20,000. On top of this, you will have to pay for the corresponding amount of the electricity and surcharge stolen.
362. What is the Magna Carta for Residential Electricity Consumers?
It is a compilation of rights and obligations of residential customers. It is an easy reference for consumers that summarizes existing laws and rules and regulations of the Energy Regulatory Commission (ERC), the quasi- judicial body that regulates the electric industry.
363. What is an Energy Audit?
An energy audit is an investigation, a survey of WHERE, WHEN and HOW energy is used in a production plant or building facility or a single equipment, and serves to identify opportunities where energy waste could be reduced and saved to improve energy utilization efficiency.
364. What are the types of Energy Audit?
a. Plant Surveys (Walk-Through Audit) b. Preliminary Audit c. Detailed Audit
365. What are the areas considered in an Energy Audit?
a. Lighting System b. Air-conditioning c. Refrigeration System d. Electrical System e. Boilers/Furnaces/Combustion Equipment f. Compressed Air System
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g. Production Line h. Single Equipment
366. What are the electrical measuring equipment and/or devices used to measure Power, Voltage, Current and Resistance?
a. Power Analyzer b. Multimeter c. Voltmeter d. Ammeter e. Ohmmeter f. Wattmeter
367. Is it advisable to turn off the refrigerator at night since nobody is using it? Why?
No. Even though the fridge is well insulated it will warm up by some amount. Then when it's switched on again the cooling would have to work harder/or longer to bring the temperature back down again probably using the same (if not more) energy in the process.
It would be more advantageous to look at the energy usage ratings of the existing fridge and consider buying a more eco-friendly fridge.
368. Is there any truth about energy conservation and efficiency in inverter technology of airconditioners?
Yes. As compared to regular AC which runs on constant speed, the unit with inverter technology does not run at a constant speed while it cools to the desired temperature, the unit consumes less power, although it cools faster. The result is a significant increase in overall efficiency. Inverter air cons save up to 45% electricity than non- inverter air cons.
369. How does an Inverter Air-condition works?
When the inverter air conditioning is switched on, the compressor operates at a high speed in order to cool or heat the room quickly. As the room temperature approaches the set temperature, the compressor slows down, maintaining a constant temperature and saving energy.
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370. What is the prescribed thermostat setting for air- conditioned buildings?
25º C
371. Which of the two is energy efficient “electric stove” or “induction cooking”?
The efficiency of energy transfer for an induction cooker is 84%, versus 74% for a smooth-top non-induction electrical unit, for an approximate 12% saving in energy for the same amount of heat transfer.
372. Why is induction cooking energy-efficient? How does it work?
An induction cooker produces an electromagnetic field which penetrates the cooking vessel and produces heat, which is then transferred to the vessel’s contents and cooks it. A cooking vessel must be made of a ferromagnetic metal. Ferromagnetic metals are iron, nickel, cobalt and stainless steel.
373. What is energy vampire/phantom load?
Energy vampires are appliances or electronics that continue to draw a small amount of power (called standby power¬) even when they're switched off. Typical energy vampires are devices that have remote controls, or LED displays that are always illuminated.
374. Do “energy-saving devices” really save?
The DOE does not recommend the use of “Energy Saving Devices”. These purported ESD do not save energy. They may reduce the electric current, however the total energy consumed (in terms of kWh) by appliances and other energy-consuming equipment in the household are not reduced as claimed.
375. How much electricity does a cellphone charger consume?
It differs in brand. According to a study by the Lawrence Berkeley National Laboratories, the average cell phone charger uses 3.68 watts of power while it is charging, 2.24 watts of power when it is on but the cell phone is no longer charging and an average of 0.26 watts when it is plugged in but not on.
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376. Is turning on and off really recommendable for Compact Fluorescent Lamps?
No. If you are constantly turning the light on and off it will shorten the lifetime of the bulb which offsets the lifetime savings figures.
377. Is LED lighting safe?
Yes, LED lights are perfectly safe: They emit less UV radiation than any other type of light. They are very energy efficient (100lumens/W) and they are cold to the touch, so they are safe for handling and less likely to start a fire.
378. What is the meaning of power factor?
It is ratio of the electrical 'true power' that does work in the real world - the 'watts' of power that are converted to mechanical motion, heat, etc. - compared to the 'apparent power' volt-amps that the meters on the panel seem to show the load as using. Improving the PF can maximize current- carrying capacity, improve voltage to equipment, reduce power losses, and lower electric bills.
379. At what speed (km/h) is the most fuel efficient in driving a vehicle?
Cruise at around 80 kph. Tests conducted with popular cars have indicated a 25% improvement in fuel economy when speeds are reduced from 120 to 80 kph.
380. Is it better to fill up fuel in the morning and why?
Yes, because the rate of evaporation of gas is slower compared to the outside heat in the afternoon. It may not be much but in the long run this effort may prove to be economical.
381. Are there any other factors affecting the rate of evaporation of fuel?
Gasoline evaporates at different rates based on how refined the gas itself is, the ambient temperature, air pressure, wind speed and the size of the exposed area of gasoline.
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BATAAN NUCLEAR POWER PLANT (BNPP)
382. What are the Legal Bases (Executive Orders) Supporting the BNPP’s Preservation and Maintenance?
a. Pursuant to EO 55 s.1986 by the late President Cory Aquino:
i. “SECTION 1: the Philippine Nuclear Power Plant I (PNPP-I), its equipment, materials and facilities, records and uranium fuel are hereby transferred and placed under the ownership and disposition of the NG or its duly assigned agency.” and further,
ii. “SECTION 4: Until the National Government (NG) or its duly designated government agency shall have studied and ultimately determined the disposition of the Philippine Nuclear Power Plant 1 (PNPP-1), the NPC is hereby designated as a caretaker thereof, undertaking the necessary and requisite preservation and maintenance and security program therefor with the expenditures necessarily connected thereto to be shouldered by the NG for which purpose there shall likewise be an annual appropriation for such sums out of the General Fund in the National Treasury not otherwise appropriated.”
b. Pursuant to EO 265 s.1995 by former President Fidel Ramos:
i. “SECTION 4: The National Power Corporation (NPC), in coordination with the Department of Energy (DOE) for policy direction, shall continue as a caretaker of BNPP, undertaking the necessary and requisite preservation and maintenance therefor pursuant to EO 55, s. 1986, as amended with the expenditures necessarily connected thereto to be shouldered by the NG for which purpose there shall likewise be an annual appropriation of such sums out of the General Fund in the National Treasury not otherwise appropriated. The NPC is further directed to supervise and coordinate the disposition and liquidation of any unserviceable property at the BNPP and to use the funds generated therefrom to support its caretaker’s operations.”
383. What Schemes are being Applied to Preserve the BNPP?
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implementing detailed plant preservation hoping that the plant will be recommissioned.
From 1997 up to present, the preservation scheme was toned down due to budget cuts and manpower reduction. The preservation scheme being implemented is merely to keep the aesthetic features of the plant for future sale of its parts and components.
384. What Efforts have been Undertaken to Rehabilitate the BNPP?
In the last Quarter of 2007, the Philippine Government, through the DOE and Department of Science and Technology (DOST), has requested the International Atomic Energy Agency(IAEA)’s provision of support in the study of the feasibility of rehabilitating the BNPP.
A Review Mission was dispatched by the IAEA on Feb 28 to March 1, 2008. Among its major recommendations were the setting-up of the nuclear energy policy and the establishment of a dedicated core group with nuclear experience and expertise, for management of preservation and all necessary activities in BNPP.
385. What ensued after the IAEA Mission Review of 2008?
In November 2008, the NPC and Korea Electric Power Corporation (KEPCO) forged a Memorandum of Understanding for cooperation on the nuclear power projects in the Philippines for purposes, among others, of the following:
a. Exchange of data and information; b. Feasibility on the possible rehabilitation of BNPP; and, c. Cooperation on nuclear power plant rehabilitation, operation, maintenance; etc.
386. What are the Highlights of KEPCO’s Feasibility Report?
The completed KEPCO Feasibility Report was submitted last January 2010 to NPC. The highlights of the Feasibility Report are as follows:
a. All 5,966 equipment in 119 systems of BNPP were examined by the Feasibility Study team.
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b. It is recommended that 1,413 equipment need to be replaced, and 5,533 equipment and devices need to be overhauled or inspected.
c. Although the BNPP was mothballed for 26 years, the facilities of the primary system are relatively in good state. However, some equipment of the secondary system were corroded by salty air and humidity.
d. Most part of the water supply facilities will have to be rebuilt.
e. Corroded or missing system and equipment shall be replaced with new ones, and all the other facilities, systems, components, equipment, parts will have to be examined, dismantled partly or wholly and maintained properly; all piping systems shall be flushed and all systems and equipment shall be tested step by step.
f. Feasibility Study team is sure that the BNPP will be rehabilitated successfully if enough and proper maintenance, replacement, test, examination, etc, can be performed through all necessary organizations such as design, manufacturing, maintenance, commissioning, operating, fuel, etc.
g. Indicative cost of rehabilitating the BNPP is about US$1 billion.
387. What is the Effect of the most recent Nuclear Power Plant Incident in 2011 on the BNPP Rehabilitation?
Due to the Fukushima Dai-Ichi Nuclear Power Plant catastrophic incident last March 11, 2011, moratorium on all activities related to nuclear power was declared.
388. What are the Recent Undertakings by the National Government regarding BNPP?
The National Government (NG) through the Department of Finance initiates transfer of the land titles including all BNPP assets in the name of the NG. The transfer of the lots was completed in 2016.
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389. What are the Current Issues on BNPP?
The current issues on BNPP are:
a. Disposal of the Nuclear Power Village in Bagac, Bataan by the Power Sector Assets and Liabilities Management (PSALM)
The asset was transferred to the books of PSALM (because of the Electric Power Industry Reform Act, also known as EPIRA) notwithstanding the fact that this asset was not acquired thru funds of NPC but rather from obligations which were fully assumed by the NG.
NPC has opposed this disposal and made representation to the NPC/PSALM board for the retention of the asset under NPC’s management; however, the Board gave instruction for the preparation of a joint business plan for the nuclear village.
b. Purchase of Lot 23 of the BNPP land area.
This lot was not expropriated way back when BNPP was being constructed due to some legal settlements that did not materialize. The owner is now demanding NPC to pay the present cost of the lot (about 15 hectares) at PhP77.68 million and yearly rental fee of PhP4.66 million. NPC Board has given direction for the possible negotiation to purchase and NPC is now getting the fair market value of the lot.
390. Are there Proposals for the Rehabilitation/Conversion of BNPP?
Yes. Among the proposals for the Rehabilitation/Conversion of BNPP are:
a. Since 1990, at the stream of mothballing of BNPP, the government had been receiving various offers like the conversion of BNPP into NatGas and/or Coal-Fired Power Plants.
These offers however did not materialize because based on the result of the Techno-Economic Study for the Conversion which was prepared by NPC for DOE, the conversion may be technically feasible but is not economically viable; it is far better to put up a new unit rather than convert BNPP into either one of the above proposed fuel.
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b. In 2008, an offer to rehabilitate the BNPP was received by DOE and it involved private entity participation with only the plant as the government’s equity to the project.
The parties involved were corporations from Japan and local companies but the proposal did not gain consideration since the government has yet to come up with its national nuclear power policy.
c. Another proposal was received about three (3) years ago[in 2015,] which involved putting up a 600MW coal-fired thermal power plant inside the BNPP plant area.
The proposal was rejected by DOE through its letter to the former Executive Secretary Ochoa. DOE’s position on the matter was that, if it allows the putting up of the coal plant inside the BNPP, then that reduces both the possibility of rehabilitating BNPP and of putting-up of a new nuclear power plant at the side of BNPP.
All commercial nuclear plants require an Exclusion Zone which prohibits any other activity within the nuclear plant site for safety and security reasons.
391. What is NPC’s Position on BNPP as the Country’s Convenient Way to Go Nuclear?
a. The Philippines’ ASEAN neighbors are all intensely setting up its basic nuclear power infrastructure to prepare for the construction of their first unit. In the country’s situation, all it needs is the infrastructure which it was able tobe set up in 1986 prior to the mothballing of the BNPP.
b. Recommissioning of BNPP is a clear possibility because it has been done, looking at the Case of the Watts Bar 2 in Tennessee.
The Watts Bar 2, also a Westinghouse design but double the capacity of BNPP, was mothballed a year earlier than BNPP in 1985 after almost completing the plant. Owned by Tennessee Valley Authority of the USA, the plant started its recommissioning at the height of the nuclear renaissance in 2007.All works were completed in 2015 and the plant was declared for commercial operation at its full capacity of 1100MW in March 2016.
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c. All possible assistance from IAEA will come pouring in as soon as the country has issued its national position and policy on its national nuclear power program.
IAEA has been very supportive as it has been when BNPP was being constructed, and while the country was still trying to justify the nuclear options.
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