CFA Institute Research Challenge Hosted by CFA Society Indonesia

Universitas Prasetiya Mulya

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Universitas Prasetiya Mulya PT Perusahaan Gas Negara Tbk. This report is published for educational purposes only by Infrastructure, Utilities, Transportation, and Energy Sectors students competing in CFA Institute Research Challenge 2018 Indonesia Stock Exchange

Date : February 15th, 2019 Current Price : IDR 2,460 Recommendation : BUY

Ticker : PGAS IJ (Bloomberg) Upside Potential : 20.73% Target Price : IDR 2,970

MARKET PROFILE Time for the Giant to Break-Free 52-Wk Price Range (IDR) 1,505 – 2,860 Backed by a favourable gas distribution industry outlook, PGAS is well positioned as a market leader to Avg. Trading Volume 90,396,068 achieve growth and further market penetration. We believe PGAS can overcome insecurity of supply and Shares Outstanding (Bn) 24.24 high capital expenditure, through capital expenditure efficiency and securing gas supply through Free Float 43,04% Pertamina’s gas holding. After considering the investment risks and future growth prospects, we arrived Market Cap. (Tn) IDR 59.63 at a BUY recommendation on PGAS with a 12-month target price of IDR2,970/share, reflecting a 20.73% P/E (ttm) 16.35x upside potential from its IDR2,460 closing price on 15/02/2019 based on our sum of the parts valuation P/BV 1.21x model. Our recommendation lays on the following key catalysts: USD/IDR 14,160 Strong Upcoming Demand from Gas Infrastructure Projects Government have set a target on gas power plant installation of 47.7 GW by 2030 vs current 13.98 GW Share Price Information (IDR) (growing 9.2% CAGR) (IRENA, 2017). The growing capacity will lead to a growing gas demand. However, inadequate pipeline network is currently a setback as it only provides 20-30% of the needed PGAS JCI infrastructure (Ministry of SOE, 2018). Therefore, government is expected to ramp up this figure up to 7000 80-100% by 2030F. Since this government-led plan will involve high expertise to be executed, the 6000 government will turn its favours on PGAS as the government’s leader in the gas sub-holding to deliver this product. On the other hand, PGAS will gain benefits from this, as the government will give incentives 5000 for construction in new market area in the form of 20 years monopoly rights (resulting in maximized

IDR/Share 4000 margins as there will be no margin sharing between distributors) and IRR at 12% in that new market area (Company Presentation, 2019). 3000 Secured Supply from Gas Holding to Fulfil Enormous Potential Demand To fulfil the high potential demand, gas supply comes into the equation. The establishment of the 2000 government’s oil and gas holding will align Pertamina’s gas supply chain, securing more supply for PGAS. 1000600 The oil and gas holding means that Pertamina will turn in PGAS’ favour more as the leader in the gas sub- holding, in terms of transporting and distributing its gas. We expect more secured supply for PGAS to be 400 realized soon. To start with, PGAS will benefit from Pertamina’s 6 gas fields with a total potential of 200 281 mmscfd which are expected to fully commercialize by 2021 (Ministry of SOE, 2018). We see this holding initiative as a mutualism between Pertamina and PGAS. Pertamina can have more ease at 0 bringing more blocks to the commercialization process due to assurance of distribution through PGAS,

Volume (Million) Volume while PGAS can benefit from the opportunity in transporting the potential supply.

June-17 June-18 June-16 PGAS-Pertagas Pipeline Integration to Boost Synergic Value

With a secure potential supply and huge potential demand, PGAS will need the infrastructure to match

October-16 October-17 October-18

February-16 February-17 February-18 February-19 the supply and demand’s region. Currently, gas production in Indonesia aggregately is above gas demand (7,453 mmscfd vs 7,318 mmscfd), but lack of infrastructure has created gas supply imbalances in several Source: Bloomberg regions (Ministry of EMR, 2018). This is most evident in Region II and III (Figure 8) which runs a gas supply deficit while Region IV has a gas supply surplus. The acquisition of Pertagas will solve this uneven supply Upside Potential in 2019F problem. PGAS’ and Pertagas’ pipeline will be integrated, which will connect Region II, III, and IV’s pipeline network with a 576 km pipeline costing US$213.25 mn of CAPEX. The plan, expected to finish by 3500 2020, will bring an additional revenue of US$342.85 mn by 2023F. Revenue synergy along with cost savings from CAPEX duplication avoidance and SG&A savings will bring NPV of total synergic value at 3000 2,970 20.73% US$582.14 mn. 2500 2,460 Attractive Valuation with Strong Cash Flow Generator PGAS is trading at an attractive 12.7% 2019F FCF Yield and 5.9x 2019F EV/EBITDA (-1 std of 5-yrs historical 2000 average). With a turnaround performance, we believe incremental downside risk remains limited as there will also be lower dependency on upstream oil and gas portfolio post Pertagas acquisition. 1500 Therefore, PGAS’ developed infrastructure earnings characteristic will resurface. Key Financial Highlights 2016A 2017A 2018F 2019F* 2020F 1000 Revenue Growth -4.37% 1.19% 11.88% 20.29% 7.41% Gross Margin 30.22% 26.85% 27.09% 27.29% 27.78%

EBITDA Margin 26.23% 28.12% 26.68% 27.36% 27.62%

June-16 June-17 June-18

EPS (IDR) 182.0 85.6 171.1 179.4 232.2

October-16 October-17 October-18

February-17 February-18 February-19 February-16 ROE 9.73% 4.63% 8.65% 9.18% 10.61% PGAS ROA 4.52% 2.35% 4.44% 4.44% 5.25% Current Price Interest Coverage 3.9 2.9 3.2 3.1 3.9 Target Price Debt/Equity 0.92 0.75 0.72 0.81 0.74 Source: Bloomberg Source: Company Reports, Team Estimates *Acquisition of Pertagas

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Figure 1: Revenue Breakdown BUSINESS DESCRIPTION Established in 1965 as the National Gas Company of Indonesia, PT Perusahaan Gas Negara Distribution (Persero) Tbk listed its shares in the Jakarta Stock Exchange in 2003 (Bloomberg code: PGAS IJ). PGAS 18% which moves mainly in B2B business has four distinguished business segments in the gas industry ranging Oil & gas 3% from upstream to downstream. As per 3Q18, distribution segment holds the biggest proportion to Others revenue at 79.2% (Figure 1) where the biggest customer comes from power generation sector. 79% Distribution Segment. Distribution segment’s activity is conducted by purchasing natural gas from suppliers and selling natural gas to end customers at a margin. Currently, profit margin for this business Source: Company Presentation 3Q18 segment is being regulated by Ministry of Energy and Mineral Resources. Being the backbone of

Figure 2: Distribution Segment Market Share company, which constitutes 79.2% of total revenue as per 3Q18, PGAS’ distribution segment holds the biggest market share of 76% in the gas distribution industry (Figure 2). Company serves various customer 3% segments: industrial, commercial, household, and gas-filling stations. Based on its contribution to 4% revenue, industrial customers are the biggest – constructing 97.7%, followed by commercial, household, 2% and gas-filling station which contributes 2.0%, 0.3% and 0.1% respectively. Amongst industrial 76% 16% customers, power plant sector comprises 41% of total distribution volume to industry (Figure 3). As the main business of distribution segment is gas trading, the biggest cost comes from gas purchase, which comprises ~80% of total operational costs. Company’s distribution pipeline is currently 5,170 km long with total distribution volume of 849 mmscfd per 3Q18 (Figure 4). PT PGN (Persero) Tbk Transmission/Transportation Segment. Transmission business is conducted by transporting PT Energasindo Heksa Karya shippers’ (owners) gas through high-pressure transmission pipelines to the off-taker and receive toll fee PT Bayu Buana Gemilang PT Surya Cipta Indonesia per transported gas in return, as set by the Oil and Gas Downstream Regulatory Agency (BPH Migas). Others This segment is handled by several business units: Transportasi Gas Indonesia (TGI), Kalimantan Jawa Gas (KJG), and PGAS itself. PGAS’ transmission pipelines extend as long as 2,284 km, transporting 718 mmscfd (Million Standard Cubic Feet per Day) of gas in 3Q18 (Figure 4). Unlike distribution pipeline, Source: Company Report 2017 transmission pipeline’s size is much bigger in order to contain the high pressure of gas and to be able to Figure 3: Distribution Segment Customers transport it in a far longer distance, thus making CAPEX cost to be dominant. Oil and Gas Segment. To support PGAS’ core business, the company have developed an upstream segment engaging in exploration, exploitation, and development of oil and gas. This business is managed Others by Saka Energi Indonesia (SEI) that was first established in 2011. Currently, it has 11 blocks under 41% 2.3% 14% operation with composition of production comprised of oil (26%) and gas (74%). From those oil and gas Industrial 35% 10% blocks, Saka bears significant amount of depreciation cost. The depreciation cost accounted ~57% of 97.7% Saka’s total operational cost in 2017. Besides oil and gas lifting, this segment also generates revenue from LPG and LNG lifting (Figure 5). Other Segments. Other than upstream and downstream segments, PGAS also has supporting divisions Power Plant Chemical such as telecommunications, services, construction and maintenance of pipeline networks, building Ceramic Others management, and financial lease managed by various subsidiaries. PGN LNG, one of PGAS’s subsidiary is developing non-pipeline gas infrastructure through LNG. Currently PGN LNG owns 40% stake of FSRU in Source: Company Report 2017 West Java and 100% in FSRU Lampung. Figure 4: PGAS Distribution & Transmission Segment Volume Strategies. PGAS has been focusing on growth strategy reflecting from actions the company has taken. Growth strategy aims to enlarge the number of volumes to compensate for the regulated pricing 1,717 1,678 1,598 1,591 1,505 1,567 environment. The strategy will be achieved through infrastructure development to capture potential demand in new area. Furthermore, recent oil and gas holding formation will enlarge company’s coverage 824 865 802 803 772 849 aligning with its growth strategy. Reflecting on recent holding formation, PGAS has been adopting some strategies, those are: Value Optimization & Operational Efficiency. Value optimization will be started with supply chain 854 852 789 795 733 718 optimization. PGAS will engage Pertamina’s upstream business to secure its supply and to distribute natural gas within wider coverage area. Operational efficiency can be achieved through 2013 2014 2015 2016 2017 3Q18 reducing duplicacy of pipeline/infrastructure development between Pertagas and PGAS resulting lower Distribution Volume capex cost. Infrastructure development will improve transmission and distribution pipeline utilization Transmission Volume (MMSCFD) rate through economic of scale operation. Better supply quantity combined with improved pipeline Source: Company Presentation 3Q18 coverage will increase company’s capability to fulfil more demand to existing and new customers. Holding company formation will also enable company to attain larger funding or financial support to Figure 5: SAKA Revenue Breakdown develop its downstream business along with better investment capability. 473 Strengthening Core Business & Expanding Market Share. Through Pertagas acquisition, company intends to focus more on its distribution segment while Pertagas will handle transmission 298 314 308 264 segment more. Pertagas acquisition will increase PGAS’s market share by 10% length-wise, reaching 198 95% of nation’s pipeline infrastructure compared to pre-acquisition of 85%. Company is also highly 65 156 120 89 exposed to government’s long-term infrastructure roadmap thus giving the company an opportunity to 204 tap to underserved markets such as East Indonesia or outside Sumatra-Java Islands. In a longer term the 126 133 166 123 company will also diversify its portfolio on LNG products and infrastructure. Currently, company is also 2014 2015 2016 2017 1H18 exploring its distribution business on household gas through cooperation with government.

Crude oil Natural gas (MnUS$) LPG LNG Shareholder Structure. PT Pertamina (Persero) holds 56.96% ownership of the company while the remaining 43.04% is owned by the public with ownership below 5% each (Figure 6). Total shares issued Source: SAKA Energi Report & Presentation 2018 up to 2018 is 24,24 billion shares including one series A Dwiwarna that entitles a special voting right

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Figure 6: Shareholder Structure owned by the government. Previously there was transfer of ownership from Indonesian government as controlling shareholder to PT Pertamina (Persero) align with government’s vision to form a holding 57% company for oil and gas sector. The transfer is legalized in April 2018 allowing Pertamina to be the parent company and create integration towards a vision amongst oil and gas enterprises. Pertamina Public CORPORATE GOVERNANCE

43% Corporate Management. PGAS’ management is comprised of highly-experienced board of commissioners and directors with widely known skills and competence relevant to the industry. Related to the nature of the company as an SOE, several members of the company’s key management have been Source: Company Report 2017 directly appointed by the government (Appendix C.8, C.9). Placement of several commissioners in the Table 1: PGAS Board of Director company from the government’s side is aimed to increase the monitoring function and helps align the company’s visions towards the government’s objectives for the natural gas industry. Board of Director The company is also channelling their focus to human resource quality as the industry only prevails to Name Title human resource with high technical skills to be able to operate the complex pipeline infrastructure. Gigih Prakoso President Director Director of Human Resources and General Affairs, Mrs. Desima Equalita is known to have deep understanding to the company’s human resources as she has been in every stage of the company from Said Reza Pahlevi Director of Finance low-mid-high management and has a tenure for almost 10 years in the company. Dilo Seno Director of Infrastructure Oil and gas holding company formation. PGAS, under government’s decree is experiencing some Widagdo & Technology degree of changes in the organization structure (Appendix A.5). Major shareholder of PGAS has moved Danny Praditya Director of Commercial from the government to PT Pertamina (Persero), making PGAS to be Pertamina’s sub-holding. PGAS will Director of HR & General be handling the midstream and downstream natural gas business while the upstream business will be Desima E. Siahaan Affairs handled by Pertamina directly. This will help the company to enhance its focus on distribution segment Source: Company Press Release 2018 and further improve synergy. In line with the holding company formation, the company has acquired PT Pertamina Gas, one of Table 2: PGAS Board of Commissioner Pertamina’s subsidiaries working on midstream and downstream business of natural gas. With that strategy, the company placed Mr. Gigih Prakoso and Mr. Said Reza Pahlevi as President Director and Board of Commissioner Name Title Director of Finance, both has previously served as Director of Investment Planning and Risk Management IGN Wiratmaja of Pertamina, and Director of Administration and Finance of PT Pertamina Patra Niaga respectively. President Commissioner Puja Placement of two Pertamina’s top management in PGAS has clearly translated the company’s strategy to align PGAS vision to the parent company, Pertamina. Mohamad Ikhsan Comissioner Social responsibility. PGN implemented a holistic approach to the society by practicing ISO Paiman Raharjo Independent Comissioner 2600: 2010 which enables them to contribute in seven core subjects: organizational governance, human rights, labour practices, environment, fair operating practices, consumer issues, and community Kiswodarmawan Independent Comissioner involvement and development. This is evident with the company’s contribution towards the success of Hambra Commissioner the Nawacita program to realize economic independence by driving strategic sectors in the domestic Source: Company Press Release 2018 economy. One of them is the Village Development Program which aims to build community independence around the PGN Offtake Station. As of 2017, the company received 2 awards for the Figure 7: Natural Gas Industry Customer perseverance of corporate social responsibility act.

24% INDUSTRY OVERVIEW & COMPETITIVE POSITIONING Indonesian gas transportation and distribution industry is known as a quasi-monopoly market. This is 18% mainly due to its capital intensive nature, tight permit approvals, and relations needed to secure supply. The several players in this industry serves 3 main segments: industry (40%), electricity (24%), and 40% fertilizer (18%) (Figure 7). In these segments, there are shifts towards a higher gas usage, driven by gas’ 5% clean emission, competitive price, and reliable source of power at peak hours. 14% Natural Gas Industry: Ample Room for Growth

Industry Countries Indonesia Malaysia Thailand Philippines Vietnam Power sector GDP/capita (USD) 3,847 9,945 6,594 2,989 2,343 Petrochemical Natural gas consumption (m3/capita) 204 1,296 1,678 31 161 Oil lifting Gas in energy mix 22% 50% 59% 22% 22% Others Power plant capacity (GW) 62 34 44.6 20.1 59.4 Total gas pipelines length (km) 11,702 6,439 5,900 576 955 Source: Ministry of Energy and Mineral Resources 2018 Gas Reserves (TSCF) 142.72 134.45 6.80 4.91 10.11 Source: Countries’ Energy Handbook 2018, Ministry of Energy and Minerals, OPEC Annual Statistic Bulletin 2018, US Figure 8: Indonesia Gas Network Region Energy Information Administration, Statistical Review of World Energy

Indonesia is ranked 1st in terms of gas reserves among other ASEAN emerging countries. This shows that Indonesia still has much room and opportunity for natural gas industry to develop further. Also, Indonesia has a rather low natural gas consumption per capita of 204 m3 compared to other countries and only accounts for 22% of the energy mix by 3Q18 while Thailand is at 59% and Malaysia is at 43%. Those data translate that higher natural gas consumption in Indonesia is still within reach for improvement and will boost the industry’s performance even further. However, domestic natural gas hasn’t been utilized properly due to the lack of infrastructure development. For Indonesia to reach the same level of gas consumption, it will require the development of infrastructure to supply the high

Source: Ministry of Energy and Mineral Resources potential demand – as Indonesia currently only cover 20-30% of the needed infrastructure (Ministry of 2018 SOE, 2018).

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Figure 9: Natural Gas Supply and Demand per Government’s Support in Securing Gas Supply Region 2019F A total gas reserve of 142.72 TSCF puts Indonesia in a secure position in terms of gas supply. This reserve, 3250 3088 able to fulfil 54 years of current total annual consumption, is expected to be utilized even more efficiently as upstream regulations are being streamlined. However, Indonesia is expected to run a gas supply deficit 2152 by 2025 due to lack of encouragement from gas lifters because of uncertain regulations. To enlighten the 1600 1690 1596 situation, Ministry of Energy and Mineral Resources is gradually simplifying its notorious oil and gas regulations which is previously considered as unfavourable for investors. One such incentive is the rise 914 700 of baseline company-take of profits from 30% to 48% for upstream gas companies. The ministry of EMR 423 240 120 53 is also constantly simplifying regulations, most recently in 12/02/2019, where 10 oil and gas regulations are condensed into only 7. With these steps, we believe upstream lifting environment to welcome more Region 1 Region 2 Region 3 Region 4 Region 5 Region 6 investors and thus securing more domestic supply. Demand Supply (MMSCFD) Indonesian Gas Network Region Given the nature of being an archipelagic country, it is indeed harder to build adequate gas infrastructure Source: Ministry of Energy and Mineral Resources that could cover the whole country. Inadequate gas infrastructure has caused uneven gas supply despite 2018 of abundant natural gas reserves. Most players in the gas distribution industry has their own pipeline Figure 10: Natural Gas Potential Demand built near the supply of natural gas blocks. This aims to simplify the distribution process with no additional transportation costs but discourages companies to build pipelines far away from gas supply. 8255 8400 As a result, Indonesia is lacking gas infrastructure, especially in regions where gas supply is absent. Based 8000 7896 on the available gas distribution network, the Ministry of Energy and Mineral Resources divides the Indonesian archipelago into 6 regions: (I) Aceh and North Sumatra, (II) Central Sumatra, South Sumatra, 7600 7600 Riau Islands, Natuna and West Java, (III) Central Java, (IV) East Java, (V) Kalimantan and Bali, (VI) Sulawesi, Nusa Tenggara, Maluku, and Papua (Figure 8). Overall, Region II and Region III are facing gas shortages 7200 7318 (2019F: Aggregate supply: 3,141 mmscfd vs. aggregate demand: 3,370 mmscfd), while other regions are 6800 left with more supply but no adequate infrastructure to distribute them (2019F: Aggregate supply: 2018F 2019F 2020F 2021F 2022F 2023F 5,085 mmscfd vs aggregate demand: 4,230 mmscfd) (Figure 9).

(MMSCFD) Gas Infrastructure Masterplan, a Key to Develop Industry One of the government’s long-term goal regarding the distribution industry is to construct gas Source: Ministry of Energy and Mineral Resources infrastructure based on a roadmap to be achieved by 2030 (Appendix C.3). It aims to maximize domestic 2018 gas utilization by connecting gas infrastructure throughout all regions in Indonesia and to increase

Figure 11: Natural Gas Demand in Java and distribution coverage to suppliers and customers, as well as to capture new potential demand. Potential Outside Java demand will reach 8,255 mmscfd in 2023F based on EMR Ministry (2018) forecast on each region’s demand (Figure 10). The plan will include the construction of West Java-East Java pipeline by 2020 to 4900 4390 address regional supply imbalance problems. The two regions will be connected by pipeline with a length of 567-667 km with 850 mmscfd capacity. Those pipelines will be completed by 2020 and start operating 4300 4070 4105 3804 at full capacity by 2021. Once the pipeline starts to operate, it will capture new demand for natural gas that has been highly anticipated by local consumers in Sumatera-Java area (Region II-IV), demand will be 3700 3865 3791 3530 as high as 4,070 mmscfd in 2019F compared to other regions of 3,530 mmscfd (Figure 11). While these 3100 3515 plans will take some time to realize, other forms of gas distribution will still take place.

2500 New Market Potentials in the Household Segment 2018F 2019F 2020F 2021F 2022F 2023F Households in Indonesia currently procure their gas supply through LPG tubes that are delivered to each Demand outside Java household through non-pipeline distribution networks. With the ongoing construction of city gas (MMSCFD) Demand in Java pipelines, households can now acquire gas at a price of IDR 4,500-IDR 6,500/m3, compared to the 12 kg LPG tubes sold at Rp155,000, or IDR 23,919/m3. The absence of gas pipeline infrastructure connecting

Source: Ministry of Energy and Mineral Resources households to gas supply is a new potential market for the Indonesian natural gas industry. Even though 2018 the average household consumes much less gas (0.005 MMSCF/year) than industries (157.24 MMSCF/year), the potential number of customers to be reached is enormous. There are 69.5 million Figure 12: Indonesian Energy Mix household in Indonesia, and only 192,489 being PGAS’ current household consumers. City gas projects 4% 5% 5% 6% 6% still offer a good deal as it will help the industry to connect with thousands of new consumers and gain 7% 7% 7% 6% 6% new potential revenue that is promising and sustainable.

51% 58% 62% 60% 61% Higher Demand from Core Customers Await Apart from the potential from household sector, higher demand from power generation and 12% petrochemical is expected to take place in 2019F afterwards. MEMR has proposed higher electricity 6% 4% 4% 2% demand as designed in RUPTL 2018-2027 with sustainable gas proportion in the energy mix of 23% in 25% 23% 21% 23% 24% 2019F (Figure 12). Gas demand from electricity is expected to increase up to 1,581 mmscfd by 2023F. 2016 2017 2018 2019 2020 Fertilizer sector will also increase their production capacity according to government’s vision to revitalize the industry. Gas as its raw material, will experience an increase along with the increase in production. Gas Oil Combined with tax holiday policy for petrochemical industry, it is expected that natural gas demand as Coal Hydro raw material for fertilizer will soar up to 1,470 mmscfd applying the best scenario in 2023 (Figure 13). Geothermal Regulations to Secure Bargaining Power to Consumer Source: PLN Statistics, PLN RUPTL 2018-2027 There are times where players in the gas transportation business were not able to pass through gas

acquisition cost increase to major customers. However, under EMR Ministerial Regulation No. 58/2017, price to end consumers are set at a formula of gas buying price, infrastructure costs, and a 7% margin. While this regulation may limit margins, players within this sector is assured to be able to pass through the gas acquisition cost to customers. This situation will protect margins which will not fall below the

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Figure 13: Natural Gas Demand from Core regulated margin spread. Having the regulation set into place gives gas transportation players an extra Customers bargaining chip to determine price to consumers.

1800 1560 1581 COMPETITIVE POSITIONING PGAS is currently the market leader in the Indonesian gas distribution industry. High barriers to entry 1500 1368 such as its capital intensive nature, tight permit approvals, and the relations required to secure supply, 1470 1470 has deterred new entrants to enter and survive, leaving PGAS alone to be dominant in the industry. 1200 Combined with Pertagas acquisition and oil and gas holding formation, PGAS’ position as a market leader 1125 will be enhanced through several ways: 900 Potential New Demand from Parent Company

600 PGAS has just moved under the wing of Pertamina, Indonesia’s oil and gas holding company. It will bring 2018F 2019F 2020F 2021F 2022F 2023F integration between upstream and downstream, creating higher effectiveness and efficiencies in natural Power Generation gas management. Moreover, PGAS will also be able to capture potential deals inside Pertamina group. (MMSCFD) Currently Pertamina is engaging many diverse projects, for instance Refinery Development Master Plan Fertilizer (RDMP) to reduce Indonesia’s dependency to oil import. RDMP projects consist of five oil refineries project: Cilacap, Balikpapan, Balongan, Tuban, and Bontang. Those oil refineries are expected to Source: PLN RUPTL 2018-2027, Ministry of Energy and Mineral Resources generate additional gas demand of 765 mmscfd for oil lifting (Figure 14). Other projects such as LPG terminal or pipeline construction projects, will surely benefit PGAS compared to other players in industry. Figure 14: Potential Demand from Oil Lifting Gas Holding to Secure Supply Contracts Bontang 125 Oil and gas holding formation will allow Pertamina to directly provide its natural gas supply into PGAS’ Tuban 125 supply chain. According to Indonesian Ministry of SOE’s plan, all Pertamina’s gas contracts will be given to PGAS along with its supply infrastructure (transmission and distribution pipeline). Currently Balongan 80 Pertamina produces gas 1,785 mmscfd domestically and another potential additional gas supply with 6 Balikpapan 229 blocks commencing with total amount 281 mmscfd up to 2021F (Figure 15). Pertamina’s natural gas Cilacap 206 production is expected to increase due to viability from additional exploration and extraction using PGAS’ (MMSCFD) infrastructure, likewise improving PGAS’s supply. Infrastructure will increase revenue when demand soars high, mutually benefitting both sides. Source: Ministry of Energy and Mineral Resources 2018 More Developed Infrastructure to Access End Customers Improved gas infrastructure comes from PGAS-Pertagas' pipeline integration and various government Figure 15: Potential Gas Supply from Gas Holding projects regarding gas infrastructure roadmap. Currently PGAS holds 85% nation’s gas infrastructure (7,454 km). Post-acquisition of Pertagas, PGAS has 95% of nation’s infrastructure (9,677 km). Pipeline Cepu 186 integration between both companies will also excel the distribution process from supplier to customer, Puspa 40 for example SSWJ and East Java pipeline integration. Next, government also incessantly enforcing its Cikarang Tegal 15 infrastructure roadmap project. As an SOE, PGAS has an advantage and received more exposure towards Salawati 20 various government’s infrastructure projects. Nation’s long-term masterplan to support gas Bambu Besar 10 infrastructure (Appendix C.3) will increase company’s coverage to new demand and supply. Even more, company’s position as market leader with extensive pipeline will ease the bidding process over a project, Simenggaris 10 making it easier for company to grow larger. (MMSCFD)

INVESTMENT SUMMARY Source: Ministry of SOE 2018 Figure 16: PGAS’s Share Price and News Flows since February 2016 (Stock Price in IDR)

First time Figure 17: EV/EBITDA Band recorded loss in ConocoPhillips increased Appointment of new 10 quarter report its gas selling price President Director, 9.34 9 Gigih Prakoso 8.24 8

7 7.15

6 6.05

5 4.96 Government capped PGAS's ownership was PLN proposed DMO 4 gas selling price of at $6/MMBTU $1.8/MMBTU in transferred to Pertamina 3 North Sumatra Natural gas pricing PGAS acquired 51%

formula announcement ownership of Pertagas

8/2/2017 9/2/2018 9/5/2018

2/18/2016 5/18/2016 8/18/2016 12/5/2017 8/16/2017 8/15/2018 12/2/2019

11/11/2016 11/13/2017 12/11/2018

EV/EBITDA PGAS IJ Average EV/EBITDA We issue a BUY recommendation on PGAS with a 12-month target price of IDR2,970/share implying EV/EBITDA STD+1 7.66x EV/EBITDA and 1.18x EV/IC. This represents a potential 20.73% upside from its closing price of EV/EBITDA STD+2 IDR2,460/share on 15/02/2019. We derived our target price using a sum of the parts method, employing EEV/EBITDA STD-1 the following methodologies: Discounted Cash Flow to the Firm and Trading Multiples. Our EV/EBITDA STD-2 recommendation is based on these key drivers: Key Drivers Source: Bloomberg, Team Estimates Growth Opportunity in Indonesia’s Gas Market Despite its abundant gas reserve (largest in Asia), Indonesia's gas hasn’t been utilized properly due to a lack of infrastructure. This is evident with Indonesia having one of the lowest gas consumptions per capita

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compared to other emerging Asian countries. The lack of infrastructure has resulted in gas supply deficits in several regions, despite aggregate supply being above aggregate demand. This situation is due to the tight permit nature of the industry and high capital intensity resulting an underdeveloped gas pipelines. But with better connectivity and recovering industrial demand, a great potential is to be seen from PGAS.

Gas Infrastructure Development to Boost Potential Demand To fulfil the increasing electricity demand, the government have set an ambitious plan to expand Indonesian gas infrastructure up to 80%-100% of needed infrastructure to achieve energy mix target by 2030 (compared to current condition of 20%-30%). The government-backed PGAS which controls the gas-sub holding will be favoured in building and operating the humongous planned network of pipeline with a 20 years monopoly rights and higher margin at 12% IRR.

Gas Sub-Holding Formation to Secure PGAS’ Supply The gas sub-holding will bring a security of supply for PGAS. Pertamina can have more ease at commercializing blocks, and PGAS can transport the potential supply. PGAS being under Pertamina also means that Pertamina will favour PGAS more in terms of distributing its gas. One impact of the mutualism can be felt soon from Pertamina’s 6 gas fields with a total capacity of 281 mmscfd which is expected to commercialize by 2021. PGAS to Benefit from Acquisition Synergy

Acquisition of Pertagas will provide substantial synergy for PGAS. From this initiative, PGAS will

strengthen its market share of pipeline into 95% length-wise, allowing the company to grab more customers. Revenue synergy will occur from the plan to integrate both companies’ pipelines across Java, Figure 18: Distribution Volume and Margin allowing the gas surplus from Region IV to be channelled into the gas deficit Region II and III. This will Spread under Pertagas (PTG) Consolidation pump up the available supply that can be distributed by PGAS to meet the demand. Apart from revenue, cost synergies will also transpire from lower SG&A expenses, as well as capex duplication avoidance. 1,600 2.18 2.2 Following the acquisition, PGAS will obtain a synergic value of US$582.14 mn. 1,174 Value Opportunity: Strong Cash Generator Trading at Discount 1,135 1,200 1,001 With a turnaround performance and limited incremental risks, PGAS is currently trading at a 12.7% 2019 971 2.1 FCF Yield and 5.9x EV/EBITDA (-1 standard deviation based on 5 years historical average). We believe 800 that this attractive valuation and brighter outlook will not only provide an adequate margin of safety, but also create a top- notch investment opportunity. 2 2.02 400 2.01 2.01 2.01 2.00 Valuation Methodology We used sum of the parts approach, employing the following methodologies: Discounted Cash Flow to - 1.9 2018F 2019F 2020F 2021F 2022F 2023F the Firm and Trading Multiples to arrive at our 12-month target price of IDR 2,970/share, which presents an upside potential of 20.73% from 15/02/2019 closing price of IDR 2,460. Distribution Volume Margin Spread Key Risk

Source: Team Estimates Delay in Pipeline Integration The pipeline integration bound to be finished by 2020 will cover the gas shortage in Region II and III. Any Figure 19: Cash Flow delay in this pipeline integration means that these two regions will run a gas deficit for a longer time,

2.5 16% eliminating the potential revenue of US$342.85 mn. 13.5% 2.14 2.15 2.21 Change in Gas Pricing Regulation 12.8% Being a highly regulated industry, gas pricing is very dependent on new regulations, the newest being 2 1.83 13.4% 12.5% 12% EMR Ministerial Regulation No. 58/2017 which sets the price downstream gas price. While this recent 11.3% 11.8% 1.5 10.9% 10.6% regulation is also beneficial seeing that margin is guaranteed, future regulations may affect PGAS’ 8% profitability negatively. 1 Gas Demand from Power Plant Muted 4% Power Plant Sector remain as the largest customer of PGAS, contributing 41% of its total distribution 0.5 volume. With natural gas bearing one of the higher costs compared to other energy alternatives (coal and renewable energy), PLN have indicated some interest to lower gas proportion in the national energy 0 0% 2018F 2019F 2020F 2021F 2022F 2023F mix. Although it has been rejected by the Minister of Energy, this have marked an uncertainty in the natural gas market, especially for PGAS. OCF/Capex Capex/Sales FINANCIAL ANALYSIS FCF Margin Lower Margins to be Accommodated with Higher Sales Volume Source: Team Estimates Even though the upcoming government regulation (Appendix C.5, C.6) will diminish PGAS’ gas distribution margin arriving at a cheaper gas price, we believe that this factor, along with infrastructure Figure 20: Fixed Asset Turnover integration will boost natural gas demand and distribution volume. The cheaper gas price will make gas 3 more attractive, while the infrastructure will support the increase in demand. Therefore, we expect 2.01 revenue trend to be upward with 8.65% CAGR for 2018-2023 supported by higher growth in distribution and transmission volume of 16.96% CAGR and 5.61% CAGR respectively. Whereas previous trend 2 1.45 1.49 1.29 1.35 1.4 of revenue is rather stagnant at 0.02% CAGR over the past 5 years, due to a falling distribution and transmission volume at -1.03% CAGR and -1.96% CAGR respectively. This resulted in a revenue slowdown 1 as reflected by lower revenue/km of US$478,000/km in 2013 to US$322,000/km in 2017 (Figure 18). Strong cash generating abilities 0 2018F 2019F 2020F 2021F 2022F 2023F Throughout 2013 until 2017, PGAS presented positive OCF and negative FCF in 2013 to 2015 due to company’s strategy in acquiring oil and gas blocks through Saka Energi and higher CAPEX is required in the early production stage in 2014. However, as SAKA undergoes the middle production stage, PGAS has Source: Team Estimates showed a positive FCF with increasing trends. We expect this trend to continue as PGAS will most likely

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Figure 21: PGAS Debt to Equity Ratio focus on the downstream sectors in the future which generates higher FCF. In the forecasted period

1 2 (2018-2023), we project OCF/CAPEX to be significantly higher at an average of 2.04x (2018-2023) 1.86 0.81 compared to historical average of 1.33x throughout 2013- 2017 (Figure 19). 0.8 0.72 0.74 1.6 0.68 0.64 Optimization of Pipeline (Fixed Asset Turnover) 0.6 0.59 1.2 PGAS’s pipeline network grew by 8.74% CAGR in 2014-2017 to 5,169 km. But distribution volume 0.4 0.8 experienced a -3.72% CAGR in the same period. This resulted in a consistently falling utilization of pipeline from 0.22 mmscfd/km to 0.15 mmscfd/km. The falling utilization signals that existing pipelines 0.2 0.4 are not utilized effectively. The same trend is shown by the fixed asset turnover which gets lower each 0 0 consecutive year, at 1.68x on 2017. With the acquisition of Pertagas which have lower fixed asset 2018F 2019F 2020F 2021F 2022F 2023F turnover, we expect this ratio to decrease further to 1.29x in 2019F. However, we believe that the Debt to Equity forecast period will present a turnaround in trend, due to the introduction of new supply which will drive Lowest Debt Covenant utilization up, causing an increase of fixed asset turnover to 1.49x by 2023F (Figure 20).

Source: Team Estimates Understated Pipeline Value PGAS uses a double declining depreciation method with a useful life of 16-20 years on its gas pipeline. Table 3: Sum of the Parts Valuation Without Meanwhile, natural gas pipelines are typically designed to have a useful life of 50 years (Deep Drillings Acquisition Insight, 2016). This has caused the company to capitalize larger depreciation expense and lower asset Sum of the Parts valuation - without acquisition value on its book by a huge sum. Currently, its gas pipeline’s remaining life is 8.8 years. Under market Equity Value value circumstances, PGAS’ gas pipeline actual remaining life is 38.8 years, providing a fair value of US$ Company ('000 US$) 2.28 bn vs current US$1.26 bn, a discount of 43.19%. PGAS exc Saka Energi 2,787,116 Expect Higher Leverage, but Still Within Safety Nets Saka Energi 698,260 Debt (Interest Bearing)/Equity Ratio has averaged at 0.71x over the past 5 years, much higher compared Transgasindo 616,086 to regional peers’ average (gas utility companies) of 0.35x. While other peers are focusing on the Regas 405,502 Total 4,506,964 downstream sector, PGAS is increasingly leveraged to finance its offshore upstream projects. In 2019, we expect debt/equity ratio to increase further to 0.81x due to Pertagas acquisition in which transaction USD/IDR Rate 14,160 Shares Outstanding 24,240 will required PGAS to acquire US$ 713 mn of debt under a 50% debt; 50% cash payment scheme. With Target Price 2,630 its strong cash generating abilities, we expect PGAS to be able to deleverage, resulting in a drop of Recommendation HOLD Debt/Equity to 0.59x by 2023F. Compared to PGAS’ lowest debt covenant of 1.86x, its leverage ratio is Closing Price (15 Feb 2019) 2,460 still far below (Figure 21). Also, we see that PGAS can confront the level of debt, considering Altman Z Potential Upside 6.90% Score of 4.57 indicating a far from bankruptcy level (Appendix B.31). Source: Team Estimates Focusing on the Same Path; No More CAPEX Duplication The goal after the Pertagas acquisition is to integrate both companies’ pipeline network. To do that, a Table 4: Sum of the Parts Valuation With Acqst. 576 km of pipeline will be built. Based on a stable historical cost of US$343,255/km of pipeline, we project Sum of the Parts Valuation - with acquisition that the plan to link the networks will cost a CAPEX of US$213.25 mn which will be allocated over 2019- Equity Value Company 2021. However, both companies can now be focusing on building pipeline towards the same path and ('000 US$) no more capex duplication. Also, with the Pertamina sub holding formed, PGAS will more likely to focus PGN + PTG 2,787,116 on its downstream rather than its upstream exploration which historically contributed ~ 58.97% of its Saka Energi 698,260 Transgasindo 616,086 total allocated capex. We expect capex/ revenue trends to decrease over time, reflecting the company’s Regas 405,502 efficiency. From the 3 years historical average of 17.98% to 11.75% on average over the next 5 years Synergic Value 582,134 (2018F – 2023F). Total 5,089,098 Good Quality Reported Earnings. Annual audits have been conducted by PWC, expressing the USD/IDR Rate 14,160 consolidated financial reports objectively present PGAS’ financial position. We performed a Beneish M- Shares Outstanding 24,240 score analysis which consist of 8 variables for the last five year to evaluate PGAS’ earnings Target Price 2,970 quality (Appendix B.32). Based on the result of the variable, the company has a low likelihood of earnings Recommendation BUY manipulation. We arrive at an average M-Score of – -2.78 during the last five years (below –2.22). Closing Price (15 Feb 2019) 2,460 Potential Upside 20.73% VALUATION Source: Team Estimates Our valuation arrived at IDR 2,970/share, driven by our sum of the parts model. We have considered the Table 5: Distribution & Transmission’s Segment acquisition of Pertagas and assigned 0% weight on peers' analysis for our valuation in order to wholly Beta Calculation reflect PGAS synergic value post Pertagas acquisition. This method involves estimating the firm’s value

Pre- Post- and adjusting it with net debt and non-controlling interest (equity) to arrive at the equity value. Sum of the parts (SOTP) was employed due to PGAS’ multifaceted corporate structure and business Acquisition Acquisition Beta 1.42 1.16 model. This method allowed us to use appropriate methodology for each segment, based on the D/E 0.88 0.47 company’s classification. We valued each segment independently because we believe that valuing PGAS Unlevered Beta 0.86 0.86 on a consolidated basis would misrepresent the value of separate business models, drivers of financial Projected D/E 0.47 0.68 performance, and risk profile of each of the business segments. We valued PGAS’ distribution and Re-levered Beta 1.16 1.30 transmission (including Pertagas after acquisition) and Saka Energi Indonesia (upstream) with Free Cash Source: Team Estimates Flow to the Firm model (FCFF), Transgasindo and Regas (JV) using blended EV-to-EBITDA & P/E multiples.

Table 6: Distribution & Transmission’s Segment Distribution Segment Cost of Equity Calculation  Revenue. Projected revenue was calculated by multiplying total volume and average selling price from Pre- Post- each segment (detail below). This segment’s revenue is expected to grow 8.47% CAGR 2018F/2023F. Acquisition Acquisition  Volume. (Distribution) Sales volume was forecasted based on available gas supply and demand in USD Indonesia 10 Yr 4.05% 4.05% each region. The lower between the two will be used as the distribution volume. From 2021 Government Bond onwards, we used the demand value for all of the regions, in regard to the interconnection of Equity Risk 7.62% 7.62% Premium regions after 2020 which introduces new supply to gas deficit regions. Beta 1.16 1.30 (Transmission) Volume is expected to grow along with gas demand from each region and the Cost of Equity 12.89% 13.94% development of new transmission pipelines. This includes the Gresik-PKG pipeline in Eastern Java Source: Team Estimates with a capacity of 100 mmscfd which starts commissioning at the end of 2017, a new pipeline in

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Table 7: Distribution and Transmission’s Southern Sumatera transmitting 126 mmscfd for ConocoPhillips is expected to be completed by Segment Cost of Debt Calculation the end of 2018, and Semarang-Gresik pipeline that will start transmitting 100 mmscfd by 2020. Pre- Post- Thus we arrive at a projection of 6.96% and 30.93% CAGR (due to consolidation of Pertagas) from Acquisition Acquisition 2018 to 2023 of distribution volume and transmission volume respectively. Cost of Debt 5.05% 6.67%  Price. (Distribution) To set the selling price, we considered gas pricing formula (Apendix C.9) set by After-Tax Cost of Debt 3.79% 5.00% the EMR Ministerial Regulation No. 58/2017 which consists of cost of gas, infrastructure Source: Team Estimates management cost, and trading margin (7% cash cost) for industrial customers. This gas pricing Table 8: Distribution and Transmission’s formula will be effectively implied in July 2019. We also consider gas price forecast, which is Segment WACC Calculation implied in our cash cost, to administer the selling price used. Pre- Post- (Transmission) Selling Price is forecasted based on average toll fees charged in each region Acquisition Acquisition (Northern Sumatera, Southern Sumatera, Western Java, Eastern Java, and Kalimantan). We expect Cost of Equity 12.89% 13.94% toll fees to be sustained as toll fees are stable for the last 3 years in the nature of it being highly Weight of Equity 68% 59% affected by regulations specific for each region. After-Tax 3.79% 5.00% Cost of Debt  Cost. Cost is mostly derived from the purchase of gas. We made a projection of purchase of gas price Weight of Debt 32% 41% following the movement of global natural gas price as its benchmark. Infrastructure management cost WACC 9.98% 10.31% is calculated by the cost of services divided by volume, in which we take several items into account: Source: Team Estimates depreciation expense, general and administrative expenses, repair and maintenance cost, tax and levy, and other operational expenses. Operational cost is expected to increase by 7.80% CAGR 2018- 2023. Table 9: Upstream Segment Beta Calculation  Capital Expenditures. Oil & Gas peers Beta Debt/MCap In the forecast period, CAPEX will be driven to meet the volume growth and Guanghui Energy 1.01 0.11 maintenance of assets. We forecast CAPEX with some adjustments after the acquisition takes place in Medco Energi 1.71 2.79 which PGAS’ downstream segment will require additional CAPEX to integrate its pipelines Internasional with Pertagas’, which is estimated to be US$213.25 mn over the course of 5 years (2018-2023). Oil and Natural Gas Corp 1.04 0.36 Following the acquisition, there will be CAPEX savings from CAPEX duplication avoidance. CAPEX is Bharat Petroleum Corp 1.43 0.39 forecasted with normalized CAPEX to sales ratio ranging between 7.72% to 9.14% for the next 5 years. Median 1.24 0.37 Source: Team Estimates Oil and Gas Sales Segment (Upstream)  Revenue. Revenue from Saka is calculated by considering the lifting volume and selling price from each Table 10: Upstream Segment WACC Calculation Cost of Equity – CAPM 13.46% commodity. Revenue from oil and gas sales is expected to grow 6.94% CAGR from 2018F/2023F. Market Risk Premium 7.62%  Volume. The growth of volume is forecasted for each block that the company owns, factoring in Risk Free Rate 4.05% the capacity utilization level and production stages (and permits). Currently, most of SAKA Energi’s Beta 1.24 blocks are at an early production stage and 2 blocks (East Kalimantan and Sanga-Sanga) have Cost of Debt 4.01% reached its expiration year. We also estimated Sidayu (under Pangkah) block to commence its Target D/E 0.37 operation in the end of 2019 which will contribute 15.7% in oil lifting volume and 28.2% in gas WACC 10.89% lifting volume. Hence, from the 2018-2023 period, oil lifting volume and gas lifting volume are Source: Team Estimates expected to grow by 4.98% CAGR and 8.72% respectively. Table 11: Joint Venture Valuation Assumption  Price. Selling price is set based on the assumptions of commodity forecasts (Appendix B.26) for Peers Valuation each type of commodity sold, namely LNG, LPG, Oil, and Natural Gas. Multiples Computation  Cost. We estimate cash cost by converting gas and oil to the same units (mmboe). This cost will Increase EV/EBITDA 8.4 (decrease) in line in a ratio of 55% with the movement of commodity forecast as contractors will P/E 17.2 increase its service cost during commodity price hike and decrease its service cost when commodity Transgasindo (TGI) Enterprise Value 1,026,000 price fall. Operational cost (including depreciation) is expected to increase by 3.26% CAGR 2018-2023. Net Debt (145,955)  Capital Expenditures. CAPEX is required to continue Saka Energi’s exploration and operational activities. Value from EV/EBITDA (50%) 585,978 In the forecast period, we adjusted based on the blocks’ production stage and its revenues. CAPEX is Value from P/E (50%) 443,062 expected to grow by 3.37% CAGR for the next 5 years with CAPEX/sales ratio between 0.26-0.30. Equity Value 1,029,039 Ownerships 59.87% Joint Ventures (Midstream Segment) – Trading Multiples Attributable Equity Value 616,086 While accounting classification excludes profit from joint ventures from EBIT, we still acknowledge 2 of Regas PGAS’ JVs contribution to PGAS valuation as it cannot be left out. This is due to their large contribution Enterprise Value 744,281 for the company’s earnings (18.2%) and the nature of operations which are comparable to PGAS’ core Net Debt (146,681) business. We derived the target price based on the average gas infrastructure industry’s EV/EBITDA of Value from EV/EBITDA (50%) 445,481 Value from P/E (50%) 568,273 8.42x and P/E of 17.3x. In computing the valuation, we equally weight both variables (50%;50%). It was Equity Value 1,013,754 selected since (1) It is a proper metric for gas distribution company in measuring operating performance, Ownership 40% by adjusting peers’ tax rate (due to lack of comparison in Indonesia) and depreciation method accounting Attributable Equity Value 405,502 adjustment (2) the Joint Ventures attribute PGAS based on its earnings, thus earnings performance will Source: Team Estimates affect PGAS’ bottom line. Thereafter, we multiply it by PGAS’ ownership (%) to reflect its value for PGAS.

Figure 22: Synergic Value Up To 2023F Synergic Value We foresee PGAS-PTG synergy would take place in the form of additional operating income (Business 2,787 1,425 1,425 582 3,369 alignment & optimization and business expansion in gas sub holding) and cost savings. By acquiring Pertagas, PGAS can capture potential deals inside Pertamina group, align Pertagas’ and PGAS’ infrastructure to reach gas supply site and boost sales volume. Also, both companies can avoid pipeline construction duplication and therefore being more efficient on capital expenditure. We then compare the equity value of PGAS with and without the synergy. From this analysis, we conclude that there is a

synergic value of US$582 million, which contributes to an upside potential from target price of Pertagas

only) IDR2,630/share without acquisition into IDR2,970/share with acquisition.

TotalValue PGAS (parent

(USD Mn) SynergicValue Weighted Average Cost of Capital (WACC) AcquisitionCost Downstream Segment. The cost of equity is calculated through the Capital Asset Pricing Model adjusted Source: Team Estimates to the country risk premium. As for the risk-free rate, we used the 10Y Indonesia Government Dollar-

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Figure 23: Revenue Contribution Pre- Denominated Bond Yield of 4.05%. The dollar-denominated bond yield is selected instead of Rupiah- Acquisition vs Post-Acquisition denominated government bonds to fully match PGAS’ USD earnings and nature of business. We calculated beta from 5Y monthly stock price regressed against JCI (Jakarta Composite Index), resulting in 18.07% a Beta of 1.16. We then unlevered the beta using PGAS’ current capital structure, and re-levered it using Pre- 0.26% its expected capital structure post-acquisition, resulting in a re-levered Beta of 1.30. The expected market Acquisition 2.46% risk premium is 7.62% (Damodaran) which leads us to a 13.94% cost of equity. As for the cost of debt, the after-tax cost of debt of 5.01% is based on relevant interest-bearing liabilities. After inputting the 79.21% proper weight based on the targeted capital structure, the WACC is 10.31%. Upstream Segment. We calculate Beta using pure play method derived from median peers’ adjusted beta. 2.29% After deriving the cost of equity (CAPM) and cost of debt, we calculate WACC (Table 10) using appropriate 11.18% weight from peers’ capital structure (debt/market value of equity). WACC for Saka valuation is 10.89%. Post- 12.72% Acquisition Terminal Growth Rate Downstream segment. Growth rate is calculated based on the sustainable growth rate derived from PGAS’ retention ratio of 58.6% and the average ROE of gas utility companies from countries in which its industry Downstream Segment 73.80% has matured namely, Taiwan, Japan, and United States of America (Appendix B.23). Therefore, we Upstream Segment arrived at a terminal growth rate of 3.79% for PGAS downstream segment. Midstream Segment Upstream segment. Due to limitation of the company’s gas reserve and contract expiration. We assume Others terminal growth to be 0% as management will also start to reduce its focus on the upstream segment.

Source: Team Estimates Relative Valuation: Peers Analysis We analysed trailing price relative to comparable firms (Asia-emerging with underdeveloped pipeline). Market Cap EV/EBITDA (x) EV/IC (x) FCF Yield (%) Figure 24: Monte Carlo Simulation Gas Utilities Comps Ticker (Mn US$) 2018F 2019F 2018F 2019F 2018F 2019F Petronas Gas PTG MK 8,734 11.1 10.3 2.5 2.4 2.6 2.7 PTT PCL PTT TB 4,448 5.2 5.1 1.1 1.1 13.7 13.9 Gujarat Gas Ltd GUJGA IN 1,442 15.2 13.2 3.5 3.3 0.4 3.2 Gail Limited GAIL IN 10,532 9.5 8.9 2.0 2.0 5.0 5.2 China Tian Lun Gas 1600 HK 1,171 10.2 9.5 1.5 1.5 3.4 3.7 Kunlun Energy 135 HK 10,006 6.1 6.0 1.1 1.0 0.9 5.2 Perusahaan Gas Negara PGAS IJ 4,211 6.8 5.9 1.1 1.1 10.1 12.7 Average 9.1 8.4 1.8 1.8 5.2 6.7 Source: Bloomberg, Team Estimates

We identified the most appropriate regional peers of gas utility companies. In analysing multiples Source: Team Estimates valuation, we used EV/EBITDA and EV/IC as it is deemed to be the most appropriate multiple to compare

PGAS to its peers. We used this multiple (EV/EBITDA) mainly due to lack of comparable peers in the Figure 25: Monte Carlo Statistics nation. Looking for industry peers in other countries results in diverse tax rates, therefore using a Statistics Forecast Values multiple which excludes tax is needed. Also known as a capital-intensive business, the industry is filled Trials 1,000,000 with complex financial leverage and substantial depreciation expenses. Hence, we also took into Mean 2,974 consideration (EV/IC) to derive on how investors’ willingness to pay on capital invested in the gas Median 2,937 infrastructure company. With this adjustment, we can reflect the company’s actual performance Mode --- exclusive of non-cash charges. We do not consider other peers in the same industry from Indonesia Standard Deviation 533 (namely, RAJA IJ) due to its small size making it irrelevant to be compared with PGAS. Given that since Variance 283,906 Skewness 0.4184 2013, PGAS has been exposed for its upstream entities, therefore implying a discount compared to its Kurtosis 3.31 peers due to its volatile characteristic. We believe that PGAS will be less exposed to its upstream Coeff. Of Variability 0.1792 performance post Pertagas acquisition (Figure 23), thus PGAS’ infrastructure earnings characteristics will Minimum 1,136 resurface and result in less volatility. Moreover, its free cash flow yield is higher compared to its peers, Maximum 7,179 much higher than most of Indonesia’s government and private bonds yield, affirming our bullish outlook. Range Width 6,043 Mean Std. Error 1 RISKS TO TARGET PRICE Source: Team Analysis To support our analysis, we conduct an analysis on possible unexpected outcome by inputting variables that could distress our target price and halter our BUY recommendation. By using three independent Figure 26: Blue-Grey Sky Scenario approaches: Monte Carlo simulation, a sensitivity analysis to closely study the impact of the discount rate and terminal growth rates (Table 12), and a blue-grey sky scenario (Figure 26). Monte Carlo Simulation. We performed Monte Carlo simulation to understand the sensitivity of our model towards the 12-month target price. We tested 7 variables: (1) distribution volume (2) margin spread (3) interest rate (4) distribution and transmission expense (5) G&A expense (6) other expense (7) other income. After running 1,000,000 simulations, we observed a 60.57% BUY probability, 36.59% HOLD, and 2.85% probability to SELL. From the result, we concluded that the most sensitive variable in our model is gas distribution margin spread. Table 12: WACC & Terminal Growth Sensitivity WACC 9.07% 9.38% 9.69% 10.00% 10.31% 10.62% 10.93% 11.24% 11.54% 3.34% 3,513 3,300 3,109 2,935 2,777 2,632 2,499 2,376 2,263 3.45% 3,584 3,364 3,166 2,987 2,823 2,674 2,537 2,411 2,295 3.56% 3,659 3,430 3,225 3,040 2,871 2,718 2,577 2,448 2,328 3.68% 3,736 3,499 3,287 3,095 2,921 2,763 2,618 2,485 2,363 Source: Team Estimates 3.79% 3,817 3,571 3,351 3,152 2,973 2,810 2,661 2,524 2,398

3.90% 3,902 3,646 3,417 3,212 3,026 2,858 2,704 2,564 2,435 4.02% 3,990 3,724 3,486 3,273 3,082 2,908 2,749 2,605 2,472

Growth Terminal 4.13% 4,083 3,805 3,558 3,337 3,139 2,959 2,796 2,647 2,511 4.24% 4,179 3,890 3,633 3,404 3,198 3,013 2,844 2,691 2,550 SELL: 0 (0%); HOLD: 33 (40.74%); BUY: 48 (59.26%)

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Figure 27: Tornado Sensitivity Analysis Blue-Grey Sky Scenario. Based on our insights, we believe that PGAS – Pertagas integration will solve infrastructure problem, thus increase gas supply reach. We consider it’s essential that we perform 2,497 2,747 2,997 3,247 3,497 (IDR) sensitivity analysis on this primary variable of model based on Indonesia natural gas balance scenario (I Margin Spread – Grey Sky, II – Base, III – Blue Sky). Longer than estimated integration will cause available gas supply to Distribution Volume deteriorate by 10%, resulting recommendation to HOLD. Given PGAS’ is currently under direct control of Distribution & Transmission… Pertamina and high urgency to build domestic gas infrastructure, we see this event to be unlikely.

Other Income INVESTMENT RISKS GA Expense

Other Expense Regulatory Risk; Downstream Gas Price Amendment (RR1) In a highly regulated industry, PGAS selling price is very dependent on government regulations. In 2017, Interest Rate the government has issue EMR Ministerial Regulation No. 58/2017 which sets the formula for downstream gas pricing and margin. While the government is keen on lowering gas price for end Source: Team Estimates customers, there is concern on future regulation that might pressure PGAS distribution margin further. Figure 28: Electricity Cost Comparison Also, the 11% IRR for infrastructure management cost based on recent regulation remained uncertain 1,879 whether it is based on book or acquisition value. To accommodate this uncertainty, we conduct a 1,455 sensitivity analysis on each margin changes of $0.1/MMBTU will affect 6.81% on our target price. 807 Regulatory Risk; National Energy Policy (RR2) Regarding energy, government can approve or reject any proposed energy mix by PLN. Although current government stance is in favour of cleaner forms of energy such as natural gas, the situation is not Natural Gas Coal Oil (Diesel) guaranteed to be that way forever. If concerns regarding costs of energy becomes major, there is a risk (IDR/KWH) that we’ll see a low proportion of gas in the energy mix, as there are other sources of energy which can be used at lower costs. But we believe this scenario is unlikely, as gas remains the most reliable choice Source: PLN Statistics 2017 of energy during peak hours. Its clean properties help government to be environmentally friendly.

Figure 29: Downstream Gas Price Amendment Operational Risks; Delay in Pertagas Integration (OR1) Stress Test Toward Target Price One factor for uneven supply problem is absence of pipeline between regions. A longer than estimated pipeline integration will hamper potential supply from East Java and delay the increase in gas distribution volume. If the network integration is put off past within our forecasted period, we project a potential opportunity loss of US$342.85 mn in revenue due to the inability in fulfilling demand for the delayed period. As a result, we arrive at a target price of IDR 2,630/share and shift our recommendation to HOLD. Operational Risks; Pipeline leakage (OR2) As a gas distributor, PGAS charged its natural gas at a premium price. However, the company must be Source: Team Estimates responsible and bear losses if the natural gas failed to be delivered properly since its customers’ Figure 30: Delay in Pertagas Integration Stress operational activities would be hampered. These losses will depend on the size of its customer. The most Test Toward Target Price recent being an incident at Jakarta which was caused by an LRT project. Operational Risks; Losing Supply Contracts (OR3) Although contracts are likely to be renewed, losing supply contracts would create a concern for PGAS in delivering its gas to end customers in the future. Should PGAS lose such (or some) contracts, PGAS will not be able to deliver its gas despite adequate infrastructure and solid gas demand. We believe with the new gas holding, PGAS will have more secured supply contract from Pertamina.

Source: Team Estimates Market Risks; Slowdown in Indonesia Industrial Growth (MR1) Industrial output has been a determinant factor for gas demand as ~97% of PGAS’ customer is derived Figure 31: Risk Matrix from the industrial sector. Thus, a negative growth would translate into a lower gas demand volume.

Based on historical 5 years distribution volume and GDP growth, we found that the two variables have a correlation of 0.92. While this highly positive correlation opens an opportunity when industrial growth is high, a slowdown in the industrial growth can pose a problem to PGAS’ gas distribution volume. Market Risks; Interest Rate Hike (MR2) In acquiring Pertagas, PGAS used a 50% cash and 50% debt payment mechanism in which its promissory notes will expire in 6 months (approximately June 2019). Therefore, an increase in interest during the period will increase its cost of debt. However, we see this risk as unlikely as the Fed remains dovish in raising its interest rate, and the current condition where the Indonesia 7 Days Repo Rate already at its peak. Each 1% increase in interest rate will cause earnings to fall by ~5.46%. Market Risks; Oil and Gas Price Fluctuations (MR3) Saka contributed 29% of PGAS consolidated EBITDA in 2019F (down from 2018F 40%). Therefore, weaker oil and gas price from estimated will bring a direct negative impact for Saka selling price, pressuring its Source: Team Estimates margin. Also, should Brent Oil Price fall below $59 (1-year average), Saka will record a US$30 million in impairment loss. While this does not enter our earnings projections, an impairment could result in a loss

Table 13: Mitigating Risks Strategy of confidence from investors, as PGAS are assuming the effects of oil price fluctuations.

Risks Mitigating Factors Downstream Gas Price Amendment Offset the risk in margin spread with a strategy to boost distribution volume (e.g. Pipeline Integration) Regulatory Risk National Energy Policy Grab customers in other industrial segments Delay in Pertagas Integration Integrate pipeline network in several areas Operational Risk Pipeline Leakage Set operating procedures, maintenance, and repairs to ensure pipeline installation quality Losing Supply Contracts Secure supply contracts through Pertamina holding Slowdown in Indonesia Industrial Growth Have consumers in other segments and constantly develop other household segments Market Risk Interest Rate Hike Acquire fixed rate debt with a proportion of 95% fixed and 5% floating Oil and Gas Price Fluctuations Focusing on midstream and downstream segment Source: Team Estimates

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APPENDICES SECTION A: BUSINESS OVERVIEW

A.1: PGAS’s Business Process Midstream Downstream Upstream

Gathering Gas Natural Gas Transmission  Exploration Pipeline Pipelines Processing  Exploitation Distribution of natural gas to end-customers:  Development of oil  Industrial and gas  Commercial

 Household  Gas-filling stations Storage Natural Gas Transmission Pipeline

Source: Company Reports, Team Analysis

A.2: PGAS Transmission Business Segment PGN TGI KJG Length (km) 1041 1006 201 Off-taker PLN, BBG CPI, Gas Supply P.LTD, PGN, PLN PLLN Wampu-Belawan; Grissik – Duri; Kepodang – Tambak Lorok Pipelines SSWJ Phase I; SSWJ Phase II Grissik – Batam - Singapore (Kalimantan Jawa I) Volume (MMSCFD) 8 645 76 2017 Revenue (MN US$) 2.5 151.62 55.46 Length Pipeline Operator Shippers Off-taker Toll Fee (US$/MMSCFD) (km) Wampu Belawan PGN 37 PLN PLN 0.400 SSWJ Phase I PGN 378 PGN PGN – West Java Distribution 1.550 PGN – West Java Distribution; SSWJ Phase II PGN 626 PGN ; PLN 1.470 PLN – Muara Tawar ConocoPhillips; PGN; PLN; Grissik – Duri TGI 536 Pertamina; GEI; PT Energasindo Chevron; PLN; PGN 0.466 Heksa Karya ConocoPhillips; PetroChina; PGN; Gas Supply Pvt Ltd; PGN; PLN Grissik – Batam – TGI 470 PLN Batam; PT Inti Daya Latu Prima; Batam; Tanjung Ucang power 0.740 Singapore PDPDE South Sumatra plant Kepodang – KJG 201 PLN PLN Tambak Lorok 2.326 Tambak Lorok Source: Company Reports 2018

A.3: PGAS Subsidiaries and Affiliates Company Name Entity Ownership Line of Business PT Saka Energi Indonesia (SEI) Subsidiary PGN 99.997%; PGASSOL 0.003% Upstream oil & gas PT PGN LNG Indonesia (PGN LNG) Subsidiary PGN 99.999%; GEI 0.000% LNG PT Gagas Energi Indonesia (GEI) Subsidiary PGN 99.88%; PGASSOL 0.12% Downstream PGN 99.91%; Yayasan Kesejahteraan Pegawai dan PT PGAS Solutions (PGASSOL) Subsidiary Engineering Pensiunan Gas Negara (YKPP Gas) 0.09% PT PGAS Telekomunikasi Nusantara Subsidiary PGN 99.93%; YKPP Gas 0.07% Telecommunication PT Permata Graha Nusantara (PERMATA) Subsidiary PGN 99.989%; PGASSOL 0.011% Property management Joint Floating storage and PT Nusantara Regas PGN 40%; Pertamina 60% Venture regasification terminal Joint PT Transportasi Gas Indonesia (TGI) PGN 59.87%; Transasia Pipeline 40%; YKPP Gas 0.13% Gas transportation Venture PT Kalimantan Jawa Gas (KJG) Affiliation Permata 80%; PT Bakrie & Brothers 20% Gas transportation PT Permata Karya Jasa (PERKASA) Affiliation Permata 75%; YKPP Gas 25% Oil and gas supporting services PT Solusi Energi Nusantara (SENA) Affiliation PGASSOL 99.9%; Permata 0.1% Engineering PT Widar Mandripa Nusantara (WIDAR) Affiliation GEI 99.996%; Perkasa 0.004% Power plant and trade PT Andiracitra Grahawira 68.43%; PT Banten Global Joint Services, transportation, trade PT Namtem Gas Synergi Synergi 14.14%; PT Banten Global Development 8.57%; Venture and mining Izma Agyano Bursman 8.71%; Perseroan 0.14% Source: Company Reports 2018

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A.4: PGAS’s Source of gas

Source: Company Presentation 2018

A.5: Pertagas Acquisition Transaction Structure

57% 49%

51%

99% 70% 65% 66% 90%

PTGN PKG PDG PSG PAG Source: Company Presentation 2018

A.6: Gas Infrastructure Plan Post-Acquisition

Source: Company Presentation 2018

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A.7: SAKA’s asset summary Assets Ownership Reserves (MMBOE) Type(s) of Resources Year Acquired Contract expiration Fasken (US) 36% 15.2 Gas 2014 2050 Pangkah 100% 28.5 Gas, LPG, and Crude Oil 2013 2026 Bangkanai 30% 10.9 Gas 2013 2033 West Bangkanai 30% N/A Gas 2015 2043 Muara Bakau 11.70% 9.9 LNG 2015 2032 Sanga- Sanga 37.80% 12 Gas, LPG, LNG, and Crude Oil 2016 2018 Wokam 100% N/A Gas 2016 2040 SES 8.90% 1.6 Gas 2014 2018 Ketapang 20% 5.8 Gas, Crude Oil 2013 2028 South Sesulu 100% 33.5 Gas Development 2014 2039 Muriah 20% 4.7 Gas 2014 2026 Source: SAKA Energi Reports 2018

A.8: SWOT Analysis SWOT ANALYSIS Strengths Weaknesses

 Market leader with vast spread gas infrastructure, constructing 85% of nation’s gas infrastructure  Dependency to suppliers’ natural gas  Backed with government support as nation’s gas distributor company  Fragmented geographical presence complicate  Security of supply and long-term contract customers infrastructure development  Integrated upstream-downstream business model and value chain of natural gas  Exposure to commodity price fluctuations  Strong reputation and highly experienced

Opportunities Threat  Tight government’s regulation  Abundant resources of natural gas  More competitive energy alternatives and other  Growing preference towards clean environment substitute product  Lack of gas distribution and infrastructure provide more room for company to grow  Weaker Indonesian economic growth and  Horizontal acquisition of Pertagas will strengthen company’s position domestic industrial growth  Potential in developing new products to non-conventional gas sources  High capital requirement to develop  Construction of non-pipe gas infrastructure utilizing LNG and FSRU infrastructure Source: Team Analysis

SECTION B: FINANCIAL MODELLING AND ANALYSIS

B.1: Consolidated Income Statement ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 2,934,779 2,969,590 3,322,312 3,996,356 4,292,347 4,552,004 4,751,822 4,932,488 Cost of Revenues (2,047,839) (2,172,360) (2,422,274) (2,905,595) (3,099,858) (3,254,300) (3,386,906) (3,510,489) Gross Profit 886,940 797,230 900,038 1,090,761 1,192,489 1,297,704 1,364,916 1,421,999 Distribution and Transmission Expense (220,402) (237,150) (237,941) (235,004) (233,379) (240,368) (245,468) (250,468) SG&A Expense (234,003) (202,507) (204,913) (251,857) (257,402) (270,129) (280,163) (287,921) Other income (loss) 11,707 19,441 10,199 9,642 9,842 10,423 10,969 11,454 Operating Income 444,242 377,015 467,383 613,541 711,550 797,630 850,255 895,065 Finance expense (132,405) (147,175) (169,338) (220,198) (220,396) (217,951) (218,465) (217,028) Finance Income 17,838 17,313 23,245 21,888 38,097 43,113 50,203 59,609 Share of Profit from Joint Ventures 57,713 38,461 68,618 94,533 108,872 120,818 125,752 129,254 Other non-operational profit (loss) (2,404) (10,064) 0 16,893 18,128 19,411 19,963 20,548 Profit before tax 384,985 275,549 389,908 526,658 656,250 763,021 827,708 887,447 Income tax expense (76,401) (127,766) (97,477) (131,664) (164,063) (190,755) (206,927) (221,862) Profit for the period 308,584 147,783 292,431 394,993 492,188 572,266 620,781 665,586 Non-controlling interest 4,260 4,638 6,349 95,063 103,929 111,593 113,024 113,173 Profit Attributable to Parent Entity 304,324 143,145 286,082 299,930 388,259 460,672 507,758 552,413 Source: Team Estimates

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B.2: Income Statement per Segment: Distribution and Transmission Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 2,620,664 2,496,734 2,770,605 3,488,010 3,641,757 3,845,119 4,013,446 4,160,761 Cost of Revenues (1,745,135) (1,728,572) (1,993,096) (2,505,191) (2,632,818) (2,777,318) (2,897,702) (3,007,362) Gross Profit 875,529 768,162 777,508 982,819 1,008,939 1,067,800 1,115,744 1,153,399 Distribution and Transmission Expense (220,402) (237,150) (237,941) (235,004) (233,379) (240,368) (245,468) (250,468) SG&A Expense (223,186) (191,736) (195,579) (242,913) (246,611) (258,413) (267,511) (274,311) Other income (loss) 11,707 (23,819) 10,199 9,642 9,842 10,423 10,969 11,454 Operating Income 443,648 315,458 354,187 514,544 538,791 579,442 613,734 640,075 Finance expense (89,598) (76,529) (91,348) (172,843) (172,984) (170,483) (170,939) (169,446) Finance Income 10,465 10,101 10,260 5,975 13,528 15,591 19,348 24,067 Share of Profit from Joint Ventures 59,442 45,638 57,692 86,599 92,444 103,838 107,992 111,594 Other non-operational profit (loss) (7,348) 28,025 0 16,893 18,128 19,411 19,963 20,548 Profit before tax 416,610 322,692 330,790 451,169 489,906 547,799 590,097 626,837 Income tax expense (84,676) (81,226) (82,698) (112,792) (122,477) (136,950) (147,524) (156,709) Profit for the period 331,934 241,466 248,093 338,377 367,430 410,849 442,573 470,128 Non-Controlling Interest (4,260) (4,638) (6,349) (95,063) (103,929) (111,593) (113,024) (113,173) Profit Attributable to Parent Entity 327,674 236,828 241,744 243,314 263,500 299,256 329,550 356,955 Source: Team Estimates

B.3: Income Statement per Segment: Upstream Segment

('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenues 314,115 472,856 551,707 508,346 650,589 706,886 738,376 771,727 Cost of Revenues (302,704) (443,788) (429,177) (400,404) (467,040) (476,982) (489,204) (503,127) Gross Profit 11,411 29,068 122,530 107,942 183,550 229,903 249,172 268,600 General and administrative expense (10,817) (10,771) (9,334) (8,944) (10,791) (11,716) (12,651) (13,610) Finance cost (42,807) (70,646) (77,989) (78,046) (78,102) (78,159) (78,215) (78,272) Finance income 7,373 7,212 12,985 15,913 24,569 27,523 30,856 35,542 Shares of net loss in joint venture (1,729) (7,177) 10,925 7,934 16,428 16,980 17,759 17,660 Other (expense)/income 4,944 5,171 0 0 0 0 0 0 Profit before tax (31,625) (47,143) 59,117 44,798 135,654 184,532 206,921 229,920 Income tax expense 8,275 (46,540) (14,779) (11,200) (33,913) (46,133) (51,730) (57,480) Profit for the period (23,350) (93,683) 44,338 33,599 101,740 138,399 155,190 172,440 Source: Team Estimates

B.4: Income Statement per Segment: Transgasindo / Transportasi Gas Indonesia (TGI) ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 158,719 151,625 152,062 165,584 177,070 178,764 189,022 194,166 Depreciation and Amortization (60,723) (60,845) (58,000) (50,546) (49,974) (48,184) (44,927) (45,359) Finance income 154 169 148 207 218 239 267 271 Finance cost 0 (2,641) (2,649) (2,884) (3,084) (3,114) (3,292) (3,382) Profit before tax 59,410 58,671 58,292 68,614 72,940 72,065 76,498 78,999 Income tax expense (15,386) (15,124) (14,573) (17,153) (18,235) (18,016) (19,124) (19,750) Profit for the period 44,024 43,547 43,719 51,460 54,705 54,049 57,373 59,250 Consolidated to PGAS 26,357 26,072 26,174 30,809 32,752 32,359 34,349 35,473 Source: Team Estimates

B.5: Income Statement per Segment: Regas / PT Nusantara Regas

('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 573,253 568,664 720,346 744,644 814,933 874,196 892,779 919,312 Depreciation and Amortization (1,448) (1,948) (2,142) (2,363) (2,506) (2,729) (2,767) (2,860) Finance income 1,489 2,982 2,948 2,940 3,257 3,474 3,739 4,146 Finance cost (583) (436) (1,028) (956) (942) (909) (836) (775) Profit before income tax 73,577 64,981 87,371 88,004 97,873 104,408 107,179 110,490 Income tax expense (18,550) (16,067) (21,843) (22,001) (24,468) (26,102) (26,795) (27,623) Profit for the period 55,027 48,914 65,528 66,003 73,405 78,306 80,384 82,868 Consolidated to PGAS 22,011 19,566 26,211 26,401 29,362 31,322 32,154 33,147 Source: Team Estimates

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B.6: Consolidated Statement of Financial Position ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Current Assets Cash and equivalent 1,304,043 1,056,081 516,435 929,484 1,058,240 1,259,311 1,520,046 1,765,639 Short term investment 40,589 56,032 65,699 61,208 58,004 61,937 68,197 70,641 Trade receivables 321,165 339,661 360,222 533,290 576,893 613,153 634,653 654,836 Other receivables 234,041 189,639 229,381 225,081 277,876 305,856 326,669 349,182 Inventories 65,294 60,820 75,919 82,366 108,613 120,634 127,336 132,546 Prepaid taxes 34,264 24,433 24,297 153,195 173,990 186,047 189,855 191,323 Advances 125,278 81,382 94,468 98,419 117,535 125,035 130,151 136,216 Total Current Assets 2,124,674 1,808,048 1,366,420 2,083,042 2,371,151 2,671,972 2,996,907 3,300,384 Non-Current Assets Trade Receivables 454,260 437,055 501,233 469,335 543,987 581,429 604,964 628,347 Advances, non-current portion 60,508 41,907 99,431 97,756 94,498 89,960 96,743 107,255 Investment in shares of stock 427,439 386,402 409,697 529,794 557,858 591,976 618,067 651,504 Fixed Assets, net of acc. depr. 1,828,631 1,706,414 1,653,493 3,098,798 3,171,266 3,241,876 3,282,570 3,319,848 Oil and gas properties 1,708,665 1,594,912 1,489,997 1,397,736 1,351,575 1,330,458 1,322,146 1,303,669 Exploration and evaluation of assets 52,594 76,780 98,158 120,819 134,416 145,293 153,125 172,704 Goodwill and other intangible assets 4,627 4,236 740,471 740,471 740,471 740,471 740,471 740,471 Deferred expense, net 77,051 63,272 79,146 75,167 86,595 92,655 96,949 101,048 Others 91,708 169,656 146,831 283,649 314,770 338,042 349,992 362,562 Total Non-Current Assets 4,705,483 4,480,634 5,218,458 6,813,524 6,995,435 7,152,159 7,265,026 7,387,407 Total Assets 6,830,157 6,288,682 6,584,878 8,896,567 9,366,587 9,824,131 10,261,933 10,687,792 Current Liabilities Trade Payables 111,760 95,182 131,250 232,049 268,759 300,184 313,130 334,358 Other payables 107,409 94,495 98,615 169,174 196,621 206,632 221,762 232,150 Accrued liabilities 231,197 192,011 197,017 321,656 392,619 419,236 440,630 458,240 Taxes payable 42,691 31,657 33,480 38,440 42,827 47,193 50,955 54,528 Short term portion of long term bank loans 270,987 22,857 22,919 58,327 56,191 47,006 50,033 52,572 Other current liabilities 51,327 30,459 30,711 66,301 70,613 73,994 76,673 78,960 Total Current Liabilities 815,371 466,661 513,992 885,946 1,027,630 1,094,246 1,153,182 1,210,809 Non-Current Liabilities Long term bank loans 1,296,315 413,733 464,764 1,457,327 1,390,619 1,402,455 1,397,969 1,376,351 Deferred revenue net 84,646 123,528 122,389 141,176 190,871 203,284 222,172 231,156 Post-employment benefits 94,371 107,989 109,513 113,624 114,958 120,435 124,629 127,982 Bonds payables 1,335,343 1,955,926 1,959,251 1,962,582 1,965,918 1,969,260 1,972,608 1,975,961 Other Non-Current Liabilities 32,080 32,278 33,338 35,051 35,546 36,115 36,615 37,039 Total Non-Current Liabilities 2,842,755 2,633,454 2,689,255 3,709,760 3,697,911 3,731,550 3,753,992 3,748,489 Total Liabilities 3,658,126 3,100,115 3,203,247 4,595,706 4,725,541 4,825,796 4,907,174 4,959,298 Equity Share capital 344,019 344,019 344,019 344,019 344,019 344,019 344,019 344,019 Other paid in capital 284,339 284,339 284,339 284,339 284,339 284,339 284,339 284,339 Retained earnings 2,564,574 2,571,000 2,769,259 2,960,532 3,242,580 3,538,172 3,834,439 4,148,623 Other component of equity (27,936) (29,568) (30,022) (29,659) (29,750) (29,810) (29,739) (29,766) Non- controlling interest 7,035 18,777 14,036 741,629 799,857 861,615 921,701 981,279 Total equity attributable to owners of the company 3,164,996 3,169,790 3,367,595 3,559,231 3,841,189 4,136,720 4,433,058 4,747,214 Total Equity 3,172,031 3,188,567 3,381,631 4,300,861 4,641,046 4,998,335 5,354,759 5,728,494 Total Liabilities and Equity 6,830,157 6,288,682 6,584,878 8,896,567 9,366,587 9,824,131 10,261,933 10,687,792 Source: Team Estimates

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B.7: Statement of Financial Position Segment: Distribution and Transmission Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Current Assets Cash and equivalent 1,141,394 772,548 233,123 527,816 608,276 754,859 938,970 1,107,891 Short term investment 40,589 56,032 65,699 61,208 58,004 61,937 68,197 70,641 Trade receivables 261,213 253,431 269,930 442,317 463,045 491,189 505,071 520,292 Other receivables 67,245 52,913 69,856 78,093 89,759 101,460 113,168 126,038 Inventories 9,299 8,216 9,258 18,005 21,585 22,095 22,676 24,157 Prepaid taxes 2,223 3,046 3,512 133,225 144,621 154,576 156,156 155,980 Advances 59,958 35,348 40,757 48,930 54,198 56,217 58,268 61,086 Total Current Assets 1,581,921 1,181,534 692,135 1,309,594 1,439,488 1,642,333 1,862,506 2,066,085 Non-Current Assets Trade Receivables 222,642 209,108 235,274 224,279 230,361 240,665 249,019 256,326 Advances, non-current portion 60,508 41,907 99,431 97,756 94,498 89,960 96,743 107,255 Investment in shares of stock 382,370 376,009 396,592 513,514 535,008 562,333 581,321 604,162 Fixed Assets, net of acc. depre. 1,828,631 1,706,414 1,653,493 3,098,798 3,171,266 3,241,876 3,282,570 3,319,848 Goodwill and other intangible assets 4,627 4,236 740,471 740,471 740,471 740,471 740,471 740,471 Deferred expense, net 49,331 29,953 40,271 39,347 40,752 42,845 44,921 46,670 Loan to subsidiaries 838,350 838,350 838,350 838,350 838,350 838,350 838,350 838,350 Others 30,477 108,932 75,981 218,367 231,221 247,264 255,170 263,457 Total Non-Current Assets 3,416,936 3,314,909 4,079,863 5,770,883 5,881,927 6,003,763 6,088,564 6,176,537 Total Assets 4,998,857 4,496,443 4,771,998 7,080,477 7,321,415 7,646,096 7,951,070 8,242,622 Current Liabilities Trade Payables 80,352 64,004 92,344 194,943 217,972 242,915 252,391 271,312 Other payables 69,173 70,315 75,115 146,596 163,416 171,052 183,663 192,191 Accrued liabilities 92,598 57,466 66,260 196,029 207,859 221,254 228,633 235,894 Taxes payable 18,199 23,249 23,670 29,400 31,258 34,624 37,826 40,806 Short term portion of long term bank loans 170,987 22,857 22,919 58,327 56,191 47,006 50,033 52,572 Other current liabilities 49,499 28,122 28,686 64,360 68,271 71,452 73,928 76,007 Total Current Liabilities 480,808 266,013 308,994 689,657 744,969 788,303 826,473 868,781 Non-Current Liabilities Long term bank loans 801,502 389,050 464,764 1,457,327 1,390,619 1,402,455 1,397,969 1,376,351 Deferred revenue, net 546 2,533 4,801 28,201 24,718 25,241 31,525 31,202 Post-employment benefits obligation 89,085 103,811 105,892 110,155 110,773 115,891 119,722 122,703 Bonds payables 1,335,343 1,337,012 1,339,285 1,341,562 1,343,842 1,346,127 1,348,415 1,350,708 Other Non-Current Liabilities 11,606 7,659 8,719 10,432 10,927 11,496 11,996 12,420 Total Non-Current Liabilities 2,238,082 1,840,065 1,923,461 2,947,677 2,880,878 2,901,210 2,909,627 2,893,384 Total Liabilities 2,718,890 2,106,078 2,232,455 3,637,334 3,625,847 3,689,513 3,736,100 3,762,165 Equity Share capital 344,019 344,019 344,019 344,019 344,019 344,019 344,019 344,019 Other paid in capital 284,339 284,339 284,339 284,339 284,339 284,339 284,339 284,339 Retained earnings 1,674,348 1,774,453 1,928,374 2,104,384 2,298,586 2,497,852 2,696,161 2,902,081 Other component of equity -29,758 -31,208 -31,208 -31,208 -31,208 -31,208 -31,208 -31,208 Total equity attributable to owners of the company 2,272,948 2,371,603 2,525,524 2,701,534 2,895,736 3,095,002 3,293,311 3,499,231 Non- controlling interest 7,019 18,762 14,019 741,610 799,832 861,581 921,658 981,226 Total Equity 2,279,967 2,390,365 2,539,543 3,443,143 3,695,567 3,956,583 4,214,970 4,480,457 Total Liabilities and Equity 4,998,857 4,496,443 4,771,998 7,080,477 7,321,415 7,646,096 7,951,070 8,242,622 Source: Team Estimates

B.8: Statement of Financial Position per Segment: Upstream Segment (‘000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Current Assets Cash and Cash Equivalent 162,649 283,533 283,312 401,668 449,964 504,452 581,076 657,748 Trade Receivables 31,052 59,952 86,230 90,292 90,973 113,848 121,964 129,582 Other Receivables 19,910 166,796 136,726 159,526 146,988 188,117 204,395 213,501 Inventories 36,770 55,995 52,604 66,661 64,360 87,028 98,539 104,660 Advances 16,051 37,077 31,403 36,640 33,760 43,207 46,945 49,037 Prepaid Expenses 11,958 32,041 21,387 20,785 19,969 29,369 31,471 33,699 Cash call advances 10,966 28,243 14,631 17,071 15,729 20,130 21,872 22,847 Total Current Assets 320,772 542,753 626,514 674,286 773,448 931,664 1,029,639 1,134,401 Non-Current Assets Other long term receivables 275,839 231,618 227,947 265,958 245,056 313,626 340,764 355,945 Fixed Assets 11 0 0 0 0 0 0 0 Exploration and evaluation of assets 49,947 52,594 76,780 98,158 120,819 134,416 145,293 153,125 Oil and gas properties 1,614,420 1,708,665 1,594,912 1,489,997 1,397,736 1,351,575 1,330,458 1,322,146 Investment in joint venture 0 45,069 10,393 13,106 16,279 22,851 29,643 36,746 Estimated claims for tax refund 59,637 61,231 60,724 70,850 65,282 83,548 90,778 94,822 Deferred tax assets 21,179 27,720 33,319 38,875 35,820 45,843 49,809 52,028 Total Non-current assets 2,021,033 2,126,897 2,004,075 1,976,945 1,880,992 1,951,858 1,986,746 2,014,812 Total Assets 2,341,805 2,669,650 2,630,589 2,651,230 2,654,440 2,883,522 3,016,385 3,149,213

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2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Current liabilities Trade payables 20,009 31,408 31,178 38,907 37,106 50,787 57,269 60,738 Taxes payables 3,059 24,492 8,408 9,810 9,039 11,568 12,569 13,129 Other payables 27,874 38,236 24,180 23,499 22,577 33,204 35,581 38,099 Accrued liabilities 140,224 138,599 134,545 130,757 125,626 184,760 197,982 211,997 Short term employee benefits 1,025 1,828 2,337 2,025 1,941 2,341 2,542 2,745 Short term bank loans 0 100,000 0 0 0 0 0 0 Total current liabilities 192,191 334,563 200,648 204,998 196,289 282,661 305,943 326,708 Non-current liabilities Deferred tax liabilities 81,848 84,100 120,995 117,588 112,975 166,152 178,043 190,646 Bonds Payable 0 0 618,914 619,966 621,020 622,076 623,133 624,193 Long term employee benefits 3,687 5,286 4,178 3,621 3,469 4,186 4,545 4,907 Loans to shareholders 838,350 838,350 838,350 838,350 838,350 838,350 838,350 838,350 Long term bank loans 294,892 494,813 24,683 0 0 0 0 0 Asset abandonment and site obligation 17,149 20,474 24,619 24,619 24,619 24,619 24,619 24,619 Total Non-Current Liabilities 1,235,926 1,443,023 1,631,739 1,604,144 1,600,433 1,655,383 1,668,690 1,682,715 Total Liabilities 1,428,117 1,777,586 1,832,387 1,809,142 1,796,723 1,938,043 1,974,633 2,009,424 Equity Share Capital 1,062,537 1,062,537 1,062,537 1,062,537 1,062,537 1,062,537 1,062,537 1,062,537 Retained earnings -148,967 -172,311 -265,990 - 221,652 - 206,389 - 118,542 - 22,217 75,741 Others 96 1,822 1,640 1,186 1,549 1,458 1,398 1,469 Non-controlling interest 22 16 15 18 20 26 34 43 Total Equity 913,688 892,064 798,202 842,088 857,717 945,479 1,041,752 1,139,790 Total Liabilities & Equity 2,341,805 2,669,650 2,630,589 2,651,230 2,654,440 2,883,522 3,016,385 3,149,213 Source: Team Estimates B.9: Statement of Financial Position per Segment: Transgasindo / Transportasi Gas Indonesia (TGI) (‘000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Assets Cash and equivalent 147,908 129,877 181,116 191,223 208,956 233,822 236,967 240,242 Other current assets 28,244 50,689 50,835 55,356 59,196 59,762 63,191 64,911 Other non-current assets 442,478 377,309 328,821 325,098 313,454 292,268 295,074 296,629 Total Assets 618,630 557,875 560,772 571,677 581,605 585,851 595,233 601,781 Liabilities Short term financial liabilities 93,052 13,222 13,260 14,439 15,441 15,589 16,483 16,932 Other short term liabilities 7,972 7,724 7,746 8,435 9,020 9,107 9,629 9,891 Long term financial liabilities 4,323 28,230 28,311 30,829 32,968 33,283 35,193 36,150 Other long term liabilities 43,653 38,182 38,292 41,697 44,590 45,016 47,599 48,894 Total Liabilities 149,000 87,358 87,609 95,400 102,018 102,994 108,904 111,868 Equity 469,630 470,517 473,162 476,276 479,586 482,857 486,329 489,914 Consolidated to PGAS (Investment in JV) 281,167 281,699 283,282 285,147 287,128 289,086 291,165 293,311 Source: Team Estimates

B.10: Statement of Financial Position per Segment: Regas / PT Nusantara Regas (‘000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Cash and equivalent 158,999 157,165 156,770 173,660 185,231 199,338 221,052 241,630 Other current assets 57,806 58,432 76,979 82,758 94,193 105,084 111,611 119,525 Other non-current assets 54,257 60,127 79,212 85,159 96,925 108,132 114,848 122,992 Short term financial liabilities 3,314 25,436 28,999 26,979 26,573 25,655 23,580 21,853 Other short term liabilities 3,425 1,819 2,304 2,382 2,607 2,796 2,856 2,941 Other long term liabilities 11,323 12,700 16,088 16,630 18,120 19,523 19,938 20,531 Equity 253,000 235,769 265,569 295,586 328,968 364,580 401,136 438,822 Consolidated to PGAS (Investment in JV) 101,200 94,308 106,228 118,234 131,587 145,832 160,455 175,529 Source: Team Estimates

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B.11: Consolidated Statement of Cash Flow (‘000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Operating Cash Flow Net Income 308,584 147,783 292,431 394,993 492,188 572,266 620,781 665,586 Depreciation 325,613 458,018 418,896 479,937 474,100 475,254 475,261 482,384 Change in NWC 234,916 31,916 50,749 (32,973) 15,534 23,948 8,291 2,797 Total Operating Cash Flow 399,280 573,886 660,577 907,903 950,753 1,023,572 1,087,751 1,145,172

Investing Cash Flow Capital Expenditure (348,472) (542,460) (282,437) (471,638) (514,004) (535,624) (515,474) (520,764) Change in Trade Receivables 62,944 17,205 (64,178) 31,898 (74,652) (37,442) (23,535) (23,384) Change in Goodwill (776) 391 (736,235) 0 0 0 0 0 Others (12,658) (4,531) (73,869) (251,260) (67,355) (58,911) (49,119) (60,617) Total Investing Cash Flow (298,962) (529,395) (1,156,719) (691,000) (656,011) (631,978) (588,128) (604,765)

Financing Cash Flow Addition in Long-Term Bank Loan 42,898 (882,582) 51,031 992,563 (66,709) 11,836 (4,486) (21,617) Dividend Payment (166,655) (136,720) (94,172) (162,367) (173,228) (211,583) (244,264) (264,208) Income (Payment) from/to minority interest 4,565 11,742 (4,741) (727,593) (58,228) (61,757) (60,087) (59,578) Others 187,415 715,107 4,377 93,542 132,178 70,981 69,949 50,589 Total Financing Cash Flow 68,223 (292,453) (43,505) 196,145 (165,987) (190,523) (238,888) (294,815)

Net Cash Flow 168,541 (247,962) (539,646) 413,049 128,756 201,071 260,735 245,593 Cash at the beginning of the year 1,135,502 1,304,043 1,056,081 516,435 929,484 1,058,240 1,259,311 1,520,046 Cash at the end of the year 1,304,043 1,056,081 516,435 929,484 1,058,240 1,259,311 1,520,046 1,765,639 Source: Team Estimates

B.12: Common Size of Consolidated Income Statement ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Cost of Revenues -69.78% -73.15% -72.91% -72.71% -72.22% -71.49% -71.28% -71.17% Gross Profit 30.22% 26.85% 27.09% 27.29% 27.78% 28.51% 28.72% 28.83% Distribution and Transmission Expense -7.51% -7.99% -7.16% -5.88% -5.44% -5.28% -5.17% -5.08% SG&A Expense -7.97% -6.82% -6.17% -6.30% -6.00% -5.93% -5.90% -5.84% Other income (loss) 0.40% 0.65% 0.31% 0.24% 0.23% 0.23% 0.23% 0.23% Operating Income 15.14% 12.70% 14.07% 15.35% 16.58% 17.52% 17.89% 18.15% Finance expense -4.51% -4.96% -5.10% -5.51% -5.13% -4.79% -4.60% -4.40% Finance Income 0.61% 0.58% 0.70% 0.55% 0.89% 0.95% 1.06% 1.21% Share of Profit from Joint Ventures 1.97% 1.30% 2.07% 2.37% 2.54% 2.65% 2.65% 2.62% Other non-operational profit (loss) -0.08% -0.34% 0.00% 0.42% 0.42% 0.43% 0.42% 0.42% Profit before tax 13.12% 9.28% 11.74% 13.18% 15.29% 16.76% 17.42% 17.99% Income tax expense -2.60% -4.30% -2.93% -3.29% -3.82% -4.19% -4.35% -4.50% Profit for the period 10.51% 4.98% 8.80% 9.88% 11.47% 12.57% 13.06% 13.49% Non-controlling interest 0.15% 0.16% 0.19% 2.38% 2.42% 2.45% 2.38% 2.29% Profit Attributable to Parent Entity 10.37% 4.82% 8.61% 7.51% 9.05% 10.12% 10.69% 11.20% Source: Team Estimates

B.13: Common Size of Income Statement per Segment: Distribution & Transmission Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Cost of Revenues -66.59% -69.23% -71.94% -71.82% -72.30% -72.23% -72.20% -72.28% Gross Profit 33.41% 30.77% 28.06% 28.18% 27.70% 27.77% 27.80% 27.72% Distribution and Transmission Expense -8.41% -9.50% -8.59% -6.74% -6.41% -6.25% -6.12% -6.02% SG&A Expense -8.52% -7.68% -7.06% -6.96% -6.77% -6.72% -6.67% -6.59% Other income (loss) 0.45% -0.95% 0.37% 0.28% 0.27% 0.27% 0.27% 0.28% Operating Income 16.93% 12.63% 12.78% 14.75% 14.79% 15.07% 15.29% 15.38% Finance expense -3.42% -3.07% -3.30% -4.96% -4.75% -4.43% -4.26% -4.07% Finance Income 0.40% 0.40% 0.37% 0.17% 0.37% 0.41% 0.48% 0.58% Share of Profit from Joint Ventures 2.27% 1.83% 2.08% 2.48% 2.54% 2.70% 2.69% 2.68% Other non-operational profit (loss) -0.28% 1.12% 0.00% 0.48% 0.50% 0.50% 0.50% 0.49% Profit before tax 15.90% 12.92% 11.94% 12.93% 13.45% 14.25% 14.70% 15.07% Income tax expense -3.23% -3.25% -2.98% -3.23% -3.36% -3.56% -3.68% -3.77% Profit for the period 12.67% 9.67% 8.95% 9.70% 10.09% 10.68% 11.03% 11.30% Non-Controlling Interest -0.16% -0.19% -0.23% -2.73% -2.85% -2.90% -2.82% -2.72% Profit Attributable to Parent Entity 12.50% 9.49% 8.73% 6.98% 7.24% 7.78% 8.21% 8.58% Source: Team Estimates

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B.14: Common Size of Income Statement per Segment: Upstream Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenues 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Cost of Revenues -96.37% -93.85% -77.79% -78.77% -71.79% -67.48% -66.25% -65.19% Gross Profit 3.63% 6.15% 22.21% 21.23% 28.21% 32.52% 33.75% 34.81% General and administrative expense -3.44% -2.28% -1.69% -1.76% -1.66% -1.66% -1.71% -1.76% Finance cost -13.63% -14.94% -14.14% -15.35% -12.00% -11.06% -10.59% -10.14% Finance income 2.35% 1.53% 2.35% 3.13% 3.78% 3.89% 4.18% 4.61% Shares of net loss in joint venture -0.55% -1.52% 1.98% 1.56% 2.53% 2.40% 2.41% 2.29% Other (expense)/income 1.57% 1.09% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% Profit before tax -10.07% -9.97% 10.72% 8.81% 20.85% 26.10% 28.02% 29.79% Income tax expense 2.63% -9.84% -2.68% -2.20% -5.21% -6.53% -7.01% -7.45% Profit for the period -7.43% -19.81% 8.04% 6.61% 15.64% 19.58% 21.02% 22.34% Source: Team Estimates

B.15: Common Size of Income Statement per Segment: Transgasindo (TGI) ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Depreciation and Amortization -38.26% -40.13% -38.14% -30.53% -28.22% -26.95% -23.77% -23.36% Finance income 0.10% 0.11% 0.10% 0.12% 0.12% 0.13% 0.14% 0.14% Finance cost 0.00% -1.74% -1.74% -1.74% -1.74% -1.74% -1.74% -1.74% Profit before tax 37.43% 38.69% 38.33% 41.44% 41.19% 40.31% 40.47% 40.69% Income tax expense -9.69% -9.97% -9.58% -10.36% -10.30% -10.08% -10.12% -10.17% Profit for the period 27.74% 28.72% 28.75% 31.08% 30.89% 30.23% 30.35% 30.51% Consolidated to PGAS 16.61% 17.19% 17.21% 18.61% 18.50% 18.10% 18.17% 18.27% Source: Team Estimates

B.16: Common Size of Income Statement per Segment: Nusantara Regas ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Depreciation and Amortization -0.25% -0.34% -0.30% -0.32% -0.31% -0.31% -0.31% -0.31% Finance income 0.26% 0.52% 0.41% 0.39% 0.40% 0.40% 0.42% 0.45% Finance cost -0.10% -0.08% -0.14% -0.13% -0.12% -0.10% -0.09% -0.08% Profit before income tax 12.83% 11.43% 12.13% 11.82% 12.01% 11.94% 12.01% 12.02% Income tax expense -3.24% -2.83% -3.03% -2.95% -3.00% -2.99% -3.00% -3.00% Profit for the period 9.60% 8.60% 9.10% 8.86% 9.01% 8.96% 9.00% 9.01% Consolidated to PGAS 3.84% 3.44% 3.64% 3.55% 3.60% 3.58% 3.60% 3.61% Source: Team Estimates

B.17: Common Size of Consolidated Statement of Financial Position ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Current Assets Cash and equivalent 19.09% 16.79% 7.84% 10.45% 11.30% 12.82% 14.81% 16.52% Short term investment 0.59% 0.89% 1.00% 0.69% 0.62% 0.63% 0.66% 0.66% Trade receivables 4.70% 5.40% 5.47% 5.99% 6.16% 6.24% 6.18% 6.13% Other receivables 3.43% 3.02% 3.48% 2.53% 2.97% 3.11% 3.18% 3.27% Inventories 0.96% 0.97% 1.15% 0.93% 1.16% 1.23% 1.24% 1.24% Prepaid taxes 0.50% 0.39% 0.37% 1.72% 1.86% 1.89% 1.85% 1.79% Advances 1.83% 1.29% 1.43% 1.11% 1.25% 1.27% 1.27% 1.27% Total Current Assets 31.11% 28.75% 20.75% 23.41% 25.31% 27.20% 29.20% 30.88% Non-Current Assets Trade Receivables 6.65% 6.95% 7.61% 5.28% 5.81% 5.92% 5.90% 5.88% Advances, non-current portion 0.89% 0.67% 1.51% 1.10% 1.01% 0.92% 0.94% 1.00% Investment in shares of stock 6.26% 6.14% 6.22% 5.96% 5.96% 6.03% 6.02% 6.10% Fixed Assets, net of acc. depr. 26.77% 27.13% 25.11% 34.83% 33.86% 33.00% 31.99% 31.06% Oil and gas properties 25.02% 25.36% 22.63% 15.71% 14.43% 13.54% 12.88% 12.20% Exploration and evaluation of assets 0.77% 1.22% 1.49% 1.36% 1.44% 1.48% 1.49% 1.62% Goodwill and other intangible assets 0.07% 0.07% 11.25% 8.32% 7.91% 7.54% 7.22% 6.93% Deferred expense, net of current portion 1.13% 1.01% 1.20% 0.84% 0.92% 0.94% 0.94% 0.95% Others 1.34% 2.70% 2.23% 3.19% 3.36% 3.44% 3.41% 3.39% Total Non-Current Assets 68.89% 71.25% 79.25% 76.59% 74.69% 72.80% 70.80% 69.12% Total Assets 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Current Liabilities Trade Payables 1.64% 1.51% 1.99% 2.61% 2.87% 3.06% 3.05% 3.13% Other payables 1.57% 1.50% 1.50% 1.90% 2.10% 2.10% 2.16% 2.17% Accrued liabilities 3.38% 3.05% 2.99% 3.62% 4.19% 4.27% 4.29% 4.29% Taxes payable 0.63% 0.50% 0.51% 0.43% 0.46% 0.48% 0.50% 0.51% Short term portion of long term bank loans 3.97% 0.36% 0.35% 0.66% 0.60% 0.48% 0.49% 0.49% Other current liabilities 0.75% 0.48% 0.47% 0.75% 0.75% 0.75% 0.75% 0.74% Total Current Liabilities 11.94% 7.42% 7.81% 9.96% 10.97% 11.14% 11.24% 11.33%

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2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Non-Current Liabilities Long term bank loans 18.98% 6.58% 7.06% 16.38% 14.85% 14.28% 13.62% 12.88% Deferred revenue net of current portion 1.24% 1.96% 1.86% 1.59% 2.04% 2.07% 2.17% 2.16% Post-employment benefits obligation 1.38% 1.72% 1.66% 1.28% 1.23% 1.23% 1.21% 1.20% Bonds payables 19.55% 31.10% 29.75% 22.06% 20.99% 20.05% 19.22% 18.49% Other Non-Current Liabilities 0.47% 0.51% 0.51% 0.39% 0.38% 0.37% 0.36% 0.35% Total Non-Current Liabilities 41.62% 41.88% 40.84% 41.70% 39.48% 37.98% 36.58% 35.07% Total Liabilities 53.56% 49.30% 48.65% 51.66% 50.45% 49.12% 47.82% 46.40% Equity Share capital 5.04% 5.47% 5.22% 3.87% 3.67% 3.50% 3.35% 3.22% Other paid in capital 4.16% 4.52% 4.32% 3.20% 3.04% 2.89% 2.77% 2.66% Treasury Stock 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% Retained earnings 37.55% 40.88% 42.05% 33.28% 34.62% 36.02% 37.37% 38.82% Other component of equity -0.41% -0.47% -0.46% -0.33% -0.32% -0.30% -0.29% -0.28% Non- controlling interest 0.10% 0.30% 0.21% 8.34% 8.54% 8.77% 8.98% 9.18% Total equity attributable to owners of the company 46.34% 50.40% 51.14% 40.01% 41.01% 42.11% 43.20% 44.42% Total Equity 46.44% 50.70% 51.35% 48.34% 49.55% 50.88% 52.18% 53.60% Total Liabilities and Equity 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Source: Team Estimates

B.18: Common Size of Statement of Financial Position per Segment: Distribution & Transmission Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Current Assets Cash and equivalent 22.83% 17.18% 4.89% 7.45% 8.31% 9.87% 11.81% 13.44% Short term investment 0.81% 1.25% 1.38% 0.86% 0.79% 0.81% 0.86% 0.86% Trade receivables 5.23% 5.64% 5.66% 6.25% 6.32% 6.42% 6.35% 6.31% Other receivables 1.35% 1.18% 1.46% 1.10% 1.23% 1.33% 1.42% 1.53% Inventories 0.19% 0.18% 0.19% 0.25% 0.29% 0.29% 0.29% 0.29% Prepaid taxes 0.04% 0.07% 0.07% 1.88% 1.98% 2.02% 1.96% 1.89% Advances 1.20% 0.79% 0.85% 0.69% 0.74% 0.74% 0.73% 0.74% Total Current Assets 31.65% 26.28% 14.50% 18.50% 19.66% 21.48% 23.42% 25.07% Non-Current Assets Trade Receivables 4.45% 4.65% 4.93% 3.17% 3.15% 3.15% 3.13% 3.11% Advances, non-current portion 1.21% 0.93% 2.08% 1.38% 1.29% 1.18% 1.22% 1.30% Investment in shares of stock 7.65% 8.36% 8.31% 7.25% 7.31% 7.35% 7.31% 7.33% Fixed Assets, net of acc depre 36.58% 37.95% 34.65% 43.77% 43.31% 42.40% 41.28% 40.28% Goodwill and other intangible assets 0.09% 0.09% 15.52% 10.46% 10.11% 9.68% 9.31% 8.98% Deferred expense, net of current portion 0.99% 0.67% 0.84% 0.56% 0.56% 0.56% 0.56% 0.57% Loan to subsidiaries 16.77% 18.64% 17.57% 11.84% 11.45% 10.96% 10.54% 10.17% Others 0.61% 2.42% 1.59% 3.08% 3.16% 3.23% 3.21% 3.20% Total Non-Current Assets 68.35% 73.72% 85.50% 81.50% 80.34% 78.52% 76.58% 74.93% Total Assets 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Current Liabilities Trade Payables 1.61% 1.42% 1.94% 2.75% 2.98% 3.18% 3.17% 3.29% Other payables 1.38% 1.56% 1.57% 2.07% 2.23% 2.24% 2.31% 2.33% Accrued liabilities 1.85% 1.28% 1.39% 2.77% 2.84% 2.89% 2.88% 2.86% Taxes payable 0.36% 0.52% 0.50% 0.42% 0.43% 0.45% 0.48% 0.50% Short term portion of long term bank loans 3.42% 0.51% 0.48% 0.82% 0.77% 0.61% 0.63% 0.64% Other current liabilities 0.99% 0.63% 0.60% 0.91% 0.93% 0.93% 0.93% 0.92% Total Current Liabilities 9.62% 5.92% 6.48% 9.74% 10.18% 10.31% 10.39% 10.54% Non-Current Liabilities Long term bank loans 16.03% 8.65% 9.74% 20.58% 18.99% 18.34% 17.58% 16.70% Deferred revenue net of current portion 0.01% 0.06% 0.10% 0.40% 0.34% 0.33% 0.40% 0.38% Post-employment benefits obligation 1.78% 2.31% 2.22% 1.56% 1.51% 1.52% 1.51% 1.49% Bonds payables 26.71% 29.73% 28.07% 18.95% 18.35% 17.61% 16.96% 16.39% Other Non-Current Liabilities 0.23% 0.17% 0.18% 0.15% 0.15% 0.15% 0.15% 0.15% Total Non-Current Liabilities 44.77% 40.92% 40.31% 41.63% 39.35% 37.94% 36.59% 35.10% Total Liabilities 54.39% 46.84% 46.78% 51.37% 49.52% 48.25% 46.99% 45.64% Equity Share capital 6.88% 7.65% 7.21% 4.86% 4.70% 4.50% 4.33% 4.17% Other paid in capital 5.69% 6.32% 5.96% 4.02% 3.88% 3.72% 3.58% 3.45% Treasury Stock 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% Retained earnings 33.49% 39.46% 40.41% 29.72% 31.40% 32.67% 33.91% 35.21% Other component of equity -0.60% -0.69% -0.65% -0.44% -0.43% -0.41% -0.39% -0.38% Total equity attributable to owners of the company 45.47% 52.74% 52.92% 38.15% 39.55% 40.48% 41.42% 42.45% Non- controlling interest 0.14% 0.42% 0.29% 10.47% 10.92% 11.27% 11.59% 11.90% Total Equity 45.61% 53.16% 53.22% 48.63% 50.48% 51.75% 53.01% 54.36% Total Liabilities and Equity 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Source: Team Estimates

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B.19: Common Size of Statement of Financial Position per Segment: Upstream Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Current Assets Cash and Cash Equivalent 6.95% 10.62% 10.77% 15.15% 16.95% 17.49% 19.26% 20.89% Trade Receivables 1.33% 2.25% 3.28% 3.41% 3.43% 3.95% 4.04% 4.11% Other Receivables 0.85% 6.25% 5.20% 6.02% 5.54% 6.52% 6.78% 6.78% Inventories 1.57% 2.10% 2.00% 2.51% 2.42% 3.02% 3.27% 3.32% Advances 0.69% 1.39% 1.19% 1.38% 1.27% 1.50% 1.56% 1.56% Prepaid Expenses 0.51% 1.20% 0.81% 0.78% 0.75% 1.02% 1.04% 1.07% Cash call advances 0.47% 1.06% 0.56% 0.64% 0.59% 0.70% 0.73% 0.73% Total Current Assets 13.70% 20.33% 23.82% 25.43% 29.14% 32.31% 34.13% 36.02% Non-Current Assets Other long term receivables 11.78% 8.68% 8.67% 10.03% 9.23% 10.88% 11.30% 11.30% Fixed Assets 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% Exploration and evaluation of assets 2.13% 1.97% 2.92% 3.70% 4.55% 4.66% 4.82% 4.86% Oil and gas properties 68.94% 64.00% 60.63% 56.20% 52.66% 46.87% 44.11% 41.98% Investment in joint venture 0.00% 1.69% 0.40% 0.49% 0.61% 0.79% 0.98% 1.17% Estimated claims for tax refund 2.55% 2.29% 2.31% 2.67% 2.46% 2.90% 3.01% 3.01% Deferred tax assets 0.90% 1.04% 1.27% 1.47% 1.35% 1.59% 1.65% 1.65% Total Non-current assets 86.30% 79.67% 76.18% 74.57% 70.86% 67.69% 65.87% 63.98% Total Assets 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Current liabilities Trade payables 0.85% 1.18% 1.19% 1.47% 1.40% 1.76% 1.90% 1.93% Taxes payables 0.13% 0.92% 0.32% 0.37% 0.34% 0.40% 0.42% 0.42% Other payables 1.19% 1.43% 0.92% 0.89% 0.85% 1.15% 1.18% 1.21% Accrued liabilities 5.99% 5.19% 5.11% 4.93% 4.73% 6.41% 6.56% 6.73% Short term employee benefits 0.04% 0.07% 0.09% 0.08% 0.07% 0.08% 0.08% 0.09% Short term bank loans 0.00% 3.75% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% Total current liabilities 8.21% 12.53% 7.63% 7.73% 7.39% 9.80% 10.14% 10.37% Non-current liabilities Deferred tax liabilities 3.50% 3.15% 4.60% 4.44% 4.26% 5.76% 5.90% 6.05% Bonds Payable 0.00% 0.00% 23.53% 23.38% 23.40% 21.57% 20.66% 19.82% Long term employee benefits 0.16% 0.20% 0.16% 0.14% 0.13% 0.15% 0.15% 0.16% Loans to shareholders 35.80% 31.40% 31.87% 31.62% 31.58% 29.07% 27.79% 26.62% Long term bank loans 12.59% 18.53% 0.94% 0.00% 0.00% 0.00% 0.00% 0.00% Asset abandonment and site obligation 0.73% 0.77% 0.94% 0.93% 0.93% 0.85% 0.82% 0.78% Total Non-Current Liabilities 52.78% 54.05% 62.03% 60.51% 60.29% 57.41% 55.32% 53.43% Total Liabilities 60.98% 66.58% 69.66% 68.24% 67.69% 67.21% 65.46% 63.81% Equity Share Capital 45.37% 39.80% 40.39% 40.08% 40.03% 36.85% 35.23% 33.74% Retained earnings -6.36% -6.45% -10.11% -8.36% -7.78% -4.11% -0.74% 2.41% Others 0.00% 0.07% 0.06% 0.04% 0.06% 0.05% 0.05% 0.05% Non-controlling interest 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% Total Equity 39.02% 33.42% 30.34% 31.76% 32.31% 32.79% 34.54% 36.19% Total Liabilities & Equity 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Source: Team Estimates

B.20: Key Financial Ratio Key Financial Ratios 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Growth Ratios Revenue Growth -4.37% 1.19% 11.88% 20.29% 7.41% 6.05% 4.39% 3.80% Gross Profit Growth -18.08% -10.11% 12.90% 21.19% 9.33% 8.82% 5.18% 4.18% EBITDA Growth -30.12% 8.47% 6.14% 23.38% 8.43% 7.36% 4.13% 3.92% EBIT Growth -42.64% -15.13% 23.97% 31.27% 15.97% 12.10% 6.60% 5.27% Net Profit Growth -39.50% -52.11% 97.88% 35.07% 24.61% 16.27% 8.48% 7.22% Liquidity Ratios Current Ratio 2.61 3.87 2.66 2.35 2.31 2.44 2.60 2.73 Quick Ratio 2.53 3.74 2.51 2.26 2.20 2.33 2.49 2.62 Cash Ratio 1.60 2.26 1.00 1.05 1.03 1.15 1.32 1.46 Efficiency Ratio Total Asset Turnover 0.43 0.47 0.50 0.45 0.46 0.46 0.46 0.46 Fixed Asset Turnover 1.60 1.74 2.01 1.29 1.35 1.40 1.45 1.49 Inventory Turnover 31.36 35.72 31.91 35.28 28.54 26.98 26.60 26.48 Payable Turnover 18.32 22.82 18.46 12.52 11.53 10.84 10.82 10.50 Receivable Turnover 3.78 3.82 3.86 3.99 3.83 3.81 3.83 3.84 Profitability Ratios Gross Profit Margin 30.22% 26.85% 27.09% 27.29% 27.78% 28.51% 28.72% 28.83% EBITDA Margin 26.23% 28.12% 26.68% 27.36% 27.62% 27.96% 27.89% 27.93% EBIT Margin 15.14% 12.70% 14.07% 15.35% 16.58% 17.52% 17.89% 18.15% Net Profit Margin 10.51% 4.98% 8.80% 9.88% 11.47% 12.57% 13.06% 13.49%

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Key Financial Ratios 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Solvency Ratios Debt to Total Assets Ratio 0.42 0.38 0.37 0.39 0.36 0.35 0.33 0.32 Debt to Equity Ratio 0.92 0.75 0.72 0.81 0.74 0.68 0.64 0.59 Interest Coverage Ratio 3.88 2.90 3.20 3.09 3.90 4.56 5.05 5.69 Cash Flow Ratios CFO/Capex 1.16 1.13 1.83 2.14 1.93 1.94 2.15 2.21 CFO/Sales 0.14 0.19 0.20 0.23 0.22 0.22 0.23 0.23 Du Pont Ratios ROE 9.73% 4.63% 8.65% 9.18% 10.61% 11.45% 11.59% 11.62% ROA 4.52% 2.35% 4.44% 4.44% 5.25% 5.83% 6.05% 6.23% Assets/Equity 2.15 1.97 1.95 2.07 2.02 1.97 1.92 1.87 NI/Sales 10.51% 4.98% 8.80% 9.88% 11.47% 12.57% 13.06% 13.49% Sales/Assets 0.43 0.47 0.50 0.45 0.46 0.46 0.46 0.46 Source: Team Estimates

B.21: Valuation: PGAS + PTG

Free Cash Flow to the Firm 2019F 2020F 2021F 2022F 2023F Terminal Value EBIT (1-Tax) $385,908 $404,093 $434,582 $460,300 $480,056 Depreciation $251,680 $260,239 $269,569 $276,559 $283,941 EV 6,440,260 Change in NWC -$57,896 -$5,878 $12,928 -$2,109 -$7,650 Debt $2,857,216 Capex $312,982 $332,707 $340,179 $317,253 $321,219 Cash $527,816 FCFF $382,503 $337,503 $351,044 $421,715 $450,428 $7,173,000 (-) Minority Interest $741,610 PV of FCFF $382,503 $305,966 $288,504 $314,198 $304,232 $4,844,857 Value of Equity 3,369,250

SAKA ENERGI Free Cash Flow to the Firm 2019F 2020F 2021F 2022F 2023F Terminal Value EBIT (1-Tax) $74,248 $129,569 $163,641 $177,391 $191,242 Depreciation $228,257 $213,861 $205,685 $198,702 $198,443 Change in NWC - 10,485 23,548 20,205 7,373 7,907 EV $1,755,962 Capex $158,656 $181,296 $195,446 $198,221 $199,545 Debt $1,459,370 FCFF $154,334 $138,585 $153,675 $170,498 $182,233 $1,672,815 Cash $401,668 PV of FCFF $154,334 $124,971 $124,965 $125,026 $120,503 $1,106,163 Value of Equity $698,260

Source: Team Estimates

B.22: Joint Venture Valuation: Multiple Assumption Gas Utilities Comps Ticker Market Cap (Mn US$) EV/EBITDA (x) P/E(x) Petronas Gas PTG MK 8,734 10.3 20.2 PTT PCL PTT TB 4,448 5.1 9.4 Gujarat Gas Ltd GUJGA IN 1,442 13.2 31.5 Gail Limited GAIL IN 10,532 8.9 21.4 China Tian Lun Gas 1600 HK 1,171 9.5 12.7 Kunlun Energy 135 HK 10,006 6.0 11.4 Perusahaan Gas Negara PGAS IJ 4,211 5.9 14.0 Average 8.4 17.2 Source: Bloomberg, Team Estimates

TRANSGASINDO / TRANSPORTASI GAS INDONESIA (TGI) REGAS / NUSANTARA REGAS EV/EBITDA (x) P/E(x) EV/EBITDA (x) P/E (x) EBITDA 121,837 Earnings 51,460 EBITDA 88,383 Earnings 66,003 Enterprise Value 1,026,000 Equity Value 886,124 Enterprise Value 744,281 Equity Value 1,136,546 Net Debt (145,955) Ownerships 59.87% Net Debt (146,681) Ownerships 40% Equity Value 1,171,955 Equity Value 890,963 Ownerships 59.87% Ownerships 40% Attributable Equity Value 701,650 Attributable Equity Value 530,522 Attributable Equity Value 356,385 Attributable Equity Value 454,618 Weight 50% Weight 50% Weight 50% Weight 50% Implied Equity Value 616,086 Implied Equity Value 405,502 Source: Team Estimates

Enterprise value for Transgasindo and Regas derived by applying same weights on P/E and EV/EBITDA based on regional peers average. Although Regas focuses on LNG storage and regasification, we see that multiplier of gas pipeline utilization company can be applied for Regas as listed peers above have LNG management in their portfolio. Hence, the implied multiples is applicable given the similar characteristic of its business.

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B.23: Terminal Growth Rate Assumption Company Ticker Country ROE (%) Kinder Morgan KMI US United States 5.66% Enbridge ENB US United States 8.70% Boardwalk Pipeline BWP US United States 5.01% Great Taipei Gas Corp 9908 TT Taiwan 6.79% Shin Shin Natural Gas 9918 TT Taiwan 8.73% Keiyo Gas Co Ltd 9539 JP Japan 6.24% Toho Gas Co Ltd 9533 JP Japan 5.69% Hokkaido Gas Co Ltd 9534 JP Japan 4.92% Average 6.47% PGAS retention ratio 58.6% Sustainable Growth Rate 3.79% Source: Bloomberg, Team Estimates

B.24: Distribution & Transmission Volume Assumption

Distribution Volume Transmission Volume (MMSCFD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F (MMSCFD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F PGAS 803 772 837 845 851 882 922 965 PGAS 795 733 742 813 878 906 959 989 SBU I 583 542 605 604 637 649 677 693 PTG 1,409 1,375 1,432 1,504 1,609 1,701 1,778 1,867 SBU II 130 133 138 144 112 129 138 161 Total 2,204 2,108 2,174 2,317 2,487 2,607 2,737 2,56 SBU III 91 97 95 97 101 104 108 111 PTG 137 123 134 165 169 181 187 196 Source: Team Estimates Total 940 895 971 1,010 1,020 1,063 1,109 1,161

B.25: Gas Price and Cost PGAS (USD/MMBTU) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Cash Cost $ 5.30 $ 5.77 $ 5.95 $5.88 $6.11 $6.17 $6.18 $6.11 ASP 8.55 8.54 8.36 8.14 8.35 8.43 8.45 8.38 Margin Spread 3.25 2.77 2.41 2.27 2.24 2.26 2.27 2.27

Pertagas (PTG) (USD/MMBTU) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Cash Cost $4.73 $4.67 $5.14 $5.09 $5.29 $5.34 $5.35 $5.29 ASP $5.37 $5.37 $5.90 $5.81 $6.02 $6.08 $6.09 $6.03 Margin Spread $0.64 $0.70 $0.77 $0.72 $0.73 $0.74 $0.74 $0.73 Source: Team Estimates

B.26: Upstream Segment Assumption 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Natural Gas Volume (MMSCF) 40,433 50,679 22,878 45,422 46,497 55,241 61,120 65,280 ASP ($/MMSCF) 3.87 3.92 4.02 3.98 4.14 4.18 4.09 4.05 Crude Oil Volume (MMBOE) 3.15 3.30 2.63 2.01 2.72 2.94 3.15 3.35 ASP ($/BBL) 41.94 50.14 70.96 67.80 70.58 71.19 70.94 69.90 LNG Volume (MMBTU) 3,066 11,729 20,456 21,170 25,185 26,280 27,375 28,835 ASP ($/MMBTU) 2.61 7.14 8.30 8.22 8.55 8.63 8.46 8.38 LPG Volume (MT) 50,519 54,803 25,460 25,853 27,404 28,774 30,357 31,875 ASP ($/MT) 0.34 0.46 0.50 0.51 0.51 0.53 0.53 0.52 Source: Bloomberg, Team Estimates

B.27: Blue-Grey Sky Scenario Assumption: Blue Sky Growth Forecast 2016 2017 2018F 2019F 2020F 2021F 2022F 2023F Distribution Volume 803 772 849 1,064 1,091 1,147 1,224 1,326 Growth 0% -3.90% 10.00% 25.30% 2.60% 5.12% 6.76% 8.30% Transmission Volume 795 733 753 1,382 1,506 1,579 1,698 1,781 Growth 0.76% -7.80% 2.70% 81.30% 10.40% 4.80% 7.60% 4.90% Base Case Growth Forecast 2016 2017 2018F 2019F 2020F 2021F 2022F 2023F Distribution Volume 803 772 837 1,010 1,020 1,063 1,109 1,161 Growth 0% -3.86% 8.42% 20.67% 0.95% 4.24% 4.35% 4.65% Transmission Volume 795 733 742 1,333 1,424 1,491 1,577 1,636 Growth 0.76% -7.80% 1.23% 79.65% 6.83% 4.71% 5.77% 3.74%

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Grey Sky Growth Forecast 2016 2017 2018F 2019F 2020F 2021F 2022F 2023F Distribution Volume 803 772 820 941 946 971 1018 1,006 Growth 0% -3.86% 6.22% 14.76% 0.57% 3.92% 3.52% -1.21% Transmission Volume 795 733 727 1,246 1,249 1,302 1,354 1,386 Growth 0.76% -7.80% -0.82% 71.39% 0.24% 4.24% 3.99% 2.36%

The Blue-Grey Sky Scenario is conducted based on the potential supply and demand of gas from Indonesia Gas Balance Book 2018 prepared by Ministry of Energy and Mineral Resources, with assumptions as follow:

Govt. Fertilizer & Petro. Electricity Retail Non-Retail Grey Sky (Scenario 1) 5% Stable 1.1% - - Base Case (Scenario 2) 5% Stable 5.5% 5.5% According to production capacity 5.5% + 35 GW According to production capacity & potential Blue Sky (Scenario 3) 5.5% Higher 5.5% project demand Source: Ministry of Energy and Mineral Resources, Team Estimates

B.28: Blue-Grey Sky Scenario Valuation Summary Valuation Summary - Sum of the Parts Scenarios (in '000 US$, otherwise stated) Blue Sky Base Grey Sky Segment Attributable Equity value Downstream 3,969,350 3,363,944 2,904,825 Upstream 799,503 698,260 580,576 TGI (JV) - 59.87% ownership 692,384 616,086 547,120 Regas (JV) - 40% ownership 430,982 405,502 376,153 Equity Value 5,892,219 5,083,792 4,408,674 Implied EV/EBITDA (x) 7.96 7.66 7.26 Current Share Price (IDR/share) 2,460 2,460 2,460 12 Month Target Price 3,440 2,970 2,580 Upside(Downside) 39.83% 20.75% 4.88% Source: Team Estimates

B.29: Blue Sky Scenario Financial Model

Downstream Segment (‘000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 2,620,664 2,496,734 2,770,605 3,601,905 3,813,140 4,022,217 4,231,840 4,651,221 Cost of Revenues (1,745,135) (1,785,207) (1,993,190) (2,613,024) (2,787,463) (2,934,931) (3,085,948) (3,400,385) Gross Profit 875,529 711,528 777,415 988,880 1,025,677 1,087,287 1,145,892 1,250,836 Distribution and Transmission Expense (220,402) (237,150) (238,683) (233,986) (236,828) (245,687) (254,009) (270,881) SG&A Expense (223,186) (191,736) (195,657) (249,357) (256,116) (268,274) (280,336) (300,812) Other income (loss) 48,908 12,410 10,199 9,692 9,937 10,530 11,127 12,453 Operating Income 480,850 295,052 353,273 515,229 542,670 583,856 622,674 691,596 Finance expense (89,598) (76,529) (91,348) (172,830) (172,962) (170,455) (170,909) (169,321) Finance Income 10,465 10,101 10,260 6,189 14,367 15,998 20,286 25,742 Share of Profit from Joint Ventures 59,442 45,638 58,156 95,612 104,980 118,937 127,191 133,967 Other non-operational profit (loss) (3,157) (9,478) 0 19,026 21,248 22,514 23,624 24,662 Profit before tax 458,003 264,783 330,340 463,225 510,303 570,851 622,867 706,645 Income tax expense (84,676) (81,226) (82,585) (115,806) (127,576) (142,713) (155,717) (176,661) Profit for the period 373,326 183,557 247,755 347,419 382,728 428,138 467,150 529,984 Minority Interest (4,260) (4,638) (6,340) (97,636) (108,293) (116,326) (119,334) (127,614) Profit Attributable to Parent Entity 369,066 178,919 241,415 249,783 274,435 311,812 347,817 402,370 Source: Team Estimates

Upstream Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenues 314,115 472,856 554,614 515,535 666,844 724,142 763,566 804,900 Cost of Revenues (302,704) (443,788) (429,177) (400,404) (469,228) (479,736) (492,507) (506,906) Gross Profit 11,411 29,068 125,437 115,131 197,616 244,406 271,059 297,994 General and administrative expense (10,817) (10,771) (9,334) (9,023) (10,886) (11,819) (12,763) (13,730) Finance cost (42,807) (70,646) (77,989) (78,046) (78,102) (78,159) (78,215) (78,272) Finance income 7,373 7,212 12,985 14,757 23,284 24,163 26,699 30,737 Shares of net loss in joint venture (1,729) (7,177) 10,925 8,004 16,750 17,302 18,266 18,318 Other (expense)/income 4,944 5,171 0 0 0 0 0 0 Profit before tax (31,625) (47,143) 62,024 50,822 148,661 195,894 225,047 255,046 Income tax expense 8,275 (46,540) (15,506) (12,706) (37,165) (48,973) (56,262) (63,762) Profit for the period (23,350) (93,683) 46,518 38,117 111,496 146,920 168,785 191,285 Source: Team Estimates

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Transgasindo (TGI) ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 158,719 151,625 153,271 175,251 193,970 200,797 220,987 227,000 Depreciation and Amortization (60,723) (60,845) (58,000) (50,959) (48,835) (49,096) (47,343) (50,368) Finance income 154 169 148 204 230 239 259 247 Finance cost 0 (2,641) (2,670) (3,053) (3,379) (3,497) (3,849) (3,954) Profit before tax 59,410 58,671 61,573 80,330 93,800 98,044 112,226 114,158 Income tax expense (15,386) (15,124) (15,393) (20,082) (23,450) (24,511) (28,057) (28,539) Profit for the period 44,024 43,547 46,180 60,247 70,350 73,533 84,170 85,618 Consolidated to PGAS 26,357 26,072 27,648 36,070 42,119 44,024 50,392 51,260 Source: Team Estimates

Nusantara Regas ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 573,253 568,664 726,610 827,383 906,083 980,485 1,033,902 1,087,024 Depreciation and Amortization (1,448) (1,948) (2,161) (2,625) (2,790) (3,063) (3,208) (3,384) Finance income 1,489 2,982 2,948 3,013 3,238 3,536 3,874 4,304 Finance cost (583) (436) (1,037) (1,062) (1,047) (1,020) (968) (916) Profit before income tax 73,577 64,981 88,131 97,869 108,675 117,124 124,084 130,592 Income tax expense (18,550) (16,067) (22,033) (24,467) (27,169) (29,281) (31,021) (32,648) Profit for the period 55,027 48,914 66,098 73,402 81,507 87,843 93,063 97,944 Consolidated to PGAS 22,011 19,566 26,439 29,361 32,603 35,137 37,225 39,178 Source: Team Estimates

B.30: Grey Sky Scenario Financial Model

Downstream Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 2,620,664 2,496,734 2,770,605 3,293,689 3,428,426 3,707,126 3,788,754 3,613,455 Cost of Revenues (1,745,135) (1,728,572) (1,993,096) (2,351,373) (2,463,563) (2,668,016) (2,722,641) (2,589,533) Gross Profit 875,529 768,162 777,508 942,316 964,863 1,039,110 1,066,114 1,023,922 Distribution and Transmission Expense (220,402) (237,150) (237,941) (228,820) (226,393) (235,950) (237,544) (229,094) SG&A Expense (223,186) (191,736) (195,579) (232,940) (235,767) (251,073) (255,970) (247,538) Other income (loss) 11,707 (23,819) 10,199 9,107 9,259 10,075 10,330 9,696 Operating Income 443,648 315,458 354,187 489,663 511,962 562,162 582,931 556,986 Finance expense (89,598) (76,529) (91,348) (172,908) (173,122) (170,670) (171,211) (169,933) Finance Income 10,465 10,101 10,260 5,943 13,913 15,994 19,798 24,769 Share of Profit from Joint Ventures 59,442 45,638 55,602 77,433 81,338 90,409 92,540 95,863 Other non-operational profit (loss) (7,348) 28,025 0 16,032 17,195 18,402 18,919 19,609 Profit before tax 416,610 322,692 328,700 416,162 451,286 516,297 542,977 527,295 Income tax expense (84,676) (81,226) (82,175) (104,041) (112,822) (129,074) (135,744) (131,824) Profit for the period 331,934 241,466 246,525 312,122 338,465 387,223 407,233 395,471 Minority Interest (4,260) (4,638) (6,308) (87,716) (95,769) (105,209) (104,028) (95,225) Profit Attributable to Parent Entity 327,674 236,828 240,216 224,406 242,696 282,013 303,205 300,246 Source: Team Estimates

Upstream Segment ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenues 314,115 472,856 551,707 497,263 602,349 664,932 699,104 732,163 Cost of Revenues (302,704) (443,788) (429,177) (400,418) (457,372) (466,490) (477,575) (491,567) Gross Profit 11,411 29,068 122,530 96,845 144,977 198,442 221,528 240,596 General and administrative expense (10,817) (10,771) (9,334) (8,749) (10,555) (11,461) (12,375) (13,313) Finance cost (42,807) (70,646) (77,989) (78,046) (78,102) (78,159) (78,215) (78,272) Finance income 7,373 7,212 12,985 15,913 25,067 28,538 30,932 34,421 Shares of net loss in joint venture (1,729) (7,177) 10,925 7,761 15,213 15,976 16,819 16,760 Other (expense)/income 4,944 5,171 0 0 0 0 0 0 Profit before tax (31,625) (47,143) 59,117 33,724 96,598 153,338 178,689 200,191 Income tax expense 8,275 (46,540) (14,779) (8,431) (24,150) (38,334) (44,672) (50,048) Profit for the period (23,350) (93,683) 44,338 25,293 72,449 115,003 134,017 150,144 Source: Team Estimates

Transgasindo (TGI) ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 158,719 151,625 148,563 152,136 155,294 154,161 154,428 158,630 Depreciation and Amortization (60,723) (60,845) (58,000) (49,354) (51,349) (52,029) (48,530) (47,040) Finance income 154 169 148 215 204 203 232 246 Finance cost 0 (2,641) (2,588) (2,650) (2,705) (2,685) (2,690) (2,763) Profit before tax 59,410 58,671 56,526 58,382 59,343 59,034 59,074 60,713 Income tax expense (15,386) (15,124) (14,131) (14,595) (14,836) (14,758) (14,768) (15,178) Profit for the period 44,024 43,547 42,394 43,786 44,508 44,275 44,305 45,535 Consolidated to PGAS 26,357 26,072 25,382 26,215 26,647 26,508 26,526 27,262 Source: Team Estimates

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Nusantara Regas ('000 USD) 2016A 2017A 2018F 2019F 2020F 2021F 2022F 2023F Revenue 573,253 568,664 692,159 687,407 737,994 776,755 778,042 793,462 Depreciation and Amortization (1,448) (1,948) (2,058) (2,184) (2,270) (2,427) (2,412) (2,470) Finance income 1,489 2,982 2,948 2,998 3,368 3,605 3,887 4,295 Finance cost (583) (436) (988) (883) (853) (808) (728) (669) Profit before income tax 73,577 64,981 83,951 81,249 88,743 92,872 93,567 95,555 Income tax expense (18,550) (16,067) (20,988) (20,312) (22,186) (23,218) (23,392) (23,889) Profit for the period 55,027 48,914 62,963 60,937 66,557 69,654 70,175 71,666 Consolidated to PGAS 22,011 19,566 25,185 24,375 26,623 27,862 28,070 28,666 Source: Team Estimates

B. 31: Altman Z Score Altman Z Score indicates a company’s financial health and also the likelihood of a business to go bankrupt. With the specified formula based on modified non-manufacturing emerging markets, the indicator show a score. In which below 1.1 means highly distress, 1.1 until 2.6 indicates grey zone, above 2.6 means the company is in the safe zone. The formula is 6.56X1 + 3.26 X2 + 6.72 X3 + 1.05 X4 Result: Considering the finansial information for the period 2013- 2017, PGAS has low probability on filing a bankruptcy.

Input Variables 2013 2014 2015 2016 2017 Current Asset 1,695,813 1,734,992 1,722,531 2,124,674 1,808,048 Total Assets 4,139,804 5,689,567 6,480,754 6,830,157 6,288,682 Current Liability 805,312 669,151 667,320 815,371 466,661 Total Liabilities 1,531,394 2,814,097 3,472,218 3,658,126 3,100,115 EBIT 917,243 834,171 774,470 444,242 377,015 Retained Earnings 2,033,134 2,298,429 2,428,351 2,564,574 2,571,000 Book Value of Equity 2,608,410 2,875,470 3,022,922 3,172,031 3,188,567 Derived Variables X1.Net Working Capital/Total Assets 0.22 0.19 0.16 0.19 0.21 X2. Retained Earnings/Total Assets 0.49 0.40 0.37 0.38 0.41 X3. Earnings Before Interest and Taxes/Total Assets 0.22 0.15 0.12 0.07 0.06 X4. Book Value of Equity/ Total Liabilities 1.70 1.02 0.87 0.87 1.03 Output Altman Z Score 6.29 4.60 4.01 3.83 4.21 Source: Team Estimates

B.32: M-Score Analysis We use Beneish M-Score to verify PGAS’ earnings quality in their financial results, in regards of earnings manipulation detection. The method contemplates different variables which identify any earnings manipulation or financial distortions sustained by the firm. If an M-Score lower than -2.22, the firm is not likely to be a manipulator of earnings. However, an M-Score greater than -2.22 indicates it is likely that the firm is.

The formula for 8 variable model is: Mscore= -4.84 + (0.92*DSRI) + (0.528*GMI) + (0.404*AQI) + (0.892*SGI) + (0.115*DEPI) - (0.172*SGAI) - (0.327*LVGI) + (4.679*Accrual to TA) Result: PGAS have a very low likelihood in manipulating its earnings results.

Input Variables 2012 2013 2014 2015 2016 2017 Net Sales 2,580,234 3,001,516 3,408,590 3,068,791 2,934,779 2,969,590 Cost of Goods Sold (COGS) 1,107,843 1,583,522 1,943,782 2,105,680 2,047,839 2,172,360 Net Receivables 258,652 279,956 324,971 286,595 321,165 339,661 Current Assets (CA) 1,983,818 1,780,528 1,861,815 1,722,531 2,124,674 1,808,048 Property Plant and Equipment 1,693,707 1,837,231 2,485,091 1,770,763 1,828,631 1,706,414 Depreciation 189,405 185,636 176,976 294,928 372,611 451,582 Total Assets (TA) 3,908,162 4,139,804 5,689,567 6,480,754 6,830,157 6,288,682 SGA Expenses 204,390 216,617 223,926 190,418 234,003 202,507 Net Income 914,499 804,451 722,754 402,758 304,324 143,145 Cash Flow from Operations (CFO) 1,166,418 828,875 896,663 528,440 655,546 577,904 Current Liabilities 472,749 805,312 669,151 667,320 815,371 466,661 Long term Debt 840,006 611,976 1,805,295 2,587,174 2,631,658 2,369,659 Working Capital - Cash - Depreciation (245,794) (529,588) (200,341) (455,746) (367,351) (166,276) Variables to Calculate M-Score 2013 2014 2015 2016 2017 DSRI = Day's Sales Receivable Index 0.93 1.02 0.98 1.17 1.05 GMI = Gross Margin Index 0.83 0.91 0.73 0.96 0.89 AQI = Asset Quality Index 1.08 1.35 0.71 1.03 0.93 SGI = Sales Growth Index 1.16 1.14 0.90 0.96 1.01 DEPI = Depreciation Index 0.98 0.95 1.67 1.26 1.21 SGAI = SGA Expenses Index 1.06 1.03 0.85 1.23 0.87 LVGI = Leverage Index 1.02 1.27 1.15 1.00 0.89 Total Accruals/Total Assets -0.128 -0.035 -0.070 -0.054 -0.026 M Score - 8 variable model -3.07 -2.51 -3.12 -2.63 -2.56 Source: Company Data & Team Analysis

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B.33: In-Depth Peer Analysis Petronas Gas PTT Perusahaan Gas Negara (PGAS) SOE, Involved in SOE with gas transmission and gas processing, transmission, utiliti SOE, Owner of gas transmission and distribution as its core business. Also Company es, and regassification transportation pipelines with total has LNG FSRUs, owning 40% stake in overview with pipeline capacity capacity of ~7,180 mmscfd . FSRU West Java and 100% stake in FSRU of ~3000 mmscfd. Lampung. LNG Regasification ca 1020 mmscfd 700 mmscfd 410 mmscfd pacity Gas Selling price are subject to Implied Gas Processing tariff average cash cost + Gas Selling Price = Gas Cost Price + 7% margin of US$0.5/mmbtu and Pricing Regulation margin of 1.75% and pipeline tariff +11% IRR under 60% pipeline utilization + transmission tarif of (include permitted return) gas infrastructure cost US$0.3/mmbtu of US$0.6/mmbtu Major Ownership Petronas 60.7% Thailand Finance Ministry 51.1% Pertamina 57% Power Plant (58%), Power Plant (40%), Petrochemicals Power Plant (57%), Gas Malaysia Customers NGV(6%),Petrochemicals (21%), Other industr(14%), Other industrial segment (44%), Others Berhad (15%), Industrial (28%) ial segment (15%) non industrial (2%) Pipeline Lengths ~2,500 km ~4,000 km 9,677 km Market Share ~86.5% in gas distribution Sole Operator ~76% in gas distribution Gross Profit Margin 44.6% 15% 27% Source: Company Reports, PTT and Petronas Gas Reports

We assess Peers Analysis in which business is most similar to PGAS (SOE and monopoly characteristic in the highly regulated industry. Based on the data, we conclude that PGAS has still much room to grow with more loosen margin regulations and more expansive market compared to PTT (thus PTT have lower valuation compared to PGAS). Indonesia’s low energy mix in gas and low connectivity bring growth opportunity for PGAS.

SECTION C: INDUSTRY, GOVERNMENT REGULATION & PLAN, CORPORATE GOVERNANCE

C.1: Porter’s Five Forces

Buyers' bargaining power 5 4 3 2 Level of competition Suppliers' bargaining power 1 0

Threat of substitute Threat of new entrants

Source: Team Estimates Bargaining power from buyers – Low-to-Moderate (2/5). Major consumers come from industrial sectors consisting of power sector (24%), petrochemical (18%), industry (40%), and oil lifting (5%). Those buyers have high dependency towards natural gas as their fuel or raw material, thus resulting in a low bargaining power compared to the number of suppliers available in the market. However, depending on the size of each order that is usually legalized through signed contract, power from buyers can be quite significant towards industry, e.g power plant. The ability for power plant to substitute natural gas with other fuel options also resulting them in a moderate bargaining power. In terms of price-setting power, government has a power to determine gas price based on the regulated formula – making gas price fixed. Fixed gas price may limit margin; but it will also limit buyers’ power to negotiate price. Bargaining power from supplier – Moderate-to-High (4/5). Suppliers’ have a moderate bargaining power due to its mutualistic relation between player and suppliers. Player (distribution company) need a supply to adequately distribute gas and fulfill market demand. In other way around, supplier also need distribution company to distribute their gas and prevent gas oversupply. In some region, supplier has a higher bargaining power due to lack of resources. While in the other region experience oversupply will weaken suppliers’ power, thus resulting a moderate-to-high suppliers’ bargaining power. Threat of new entrants – Low (1/5). High barriers to enter the industry come in three forms; (1) Significant amount of capital injection is needed. To be able to grab a piece of share in the industry, one needs an extensive gas infrastructure such as pipelines and other facilities. Average CAPEX in the industry is $361,700/km of pipelines, limiting the number of potential new players just from the initial capital needed. (2) Harsh regulatory environment along with tight permits approval regarding land acquisition often complicate the company to develop gas infrastructure. (3) Connection to suppliers are needed for supply clarity while promising customers are compulsory to secure demand line. Small and illicit players may available in the industry but will not be able to compete with existing player in terms of resources (suppliers, infrastructure and contracts with customers).Furthermore, government is reinforcing the regulation to eliminate multilevel traders in industry thus increasing barrier to entry for small players. Threat of substitute – Moderate (3/5). Gas can only be distributed throughout the nation through pipelines. While it’s prominent that there are other options such as gas tubes for household usage, CNG truck, LNG ships and few other options. Gas pipe is still the only choice to distribute natural gas for industrial and power plant needs. However, demand for natural gas is considerably sensitive towards other energy alternative such as oil in power generation sector. Both oil and natural gas have the capability to generate constant electricity power at peaker time unlike coal. Compared to oil, natural gas’ price is more competitive and generate lower emission - making it more preferable. Gas composition is always higher than oil, in which in 3Q18 gas comprised 22.3% while oil was only 6.2%. Level of competition – Low (1/5). The industry has a weak competition due to its quasi-monopolistic nature of PGAS who owns the majority of gas infrastructure. As PGAS controls 76% of the nation’s gas distribution. The second biggest company in the industry is Pertagas, who owns approximately 10% of the national pipeline length. Holding this acquisition to be completed, accumulated pipeline length will reach up to 9,677 kilometers or equal as

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95% national pipeline infrastructure. PGAS being a subsidiary of Pertamina will also strengthen its power in the market in terms of security of supply in which PGAS is granted a direct access to Pertamina gas production; strengthen its position in terms of higher demand from parent company or even government as government is encouraging nation’s oil and gas sector through this holding company; and PGAS is also highly-exposed to government’s infrastructure projects to connect all gas infrastructure to Indonesia. Those factors are highly attributable in enhancing PGAS position in the market likewise summarizing its stand point and competitiveness in the quasi-monopoly market.

C.2: Natural Gas Balance: Scenario 1

Net Position (MMSCFD) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Region 1 105 223 212 191 235 242 226 196 157 108 Region 2 -64 188 244 96 -167 -149 -144 -310 -541 199 Region 3 -39 -68 -68 -73 -72 -75 -75 -80 -130 -132 Region 4 -6 274 288 223 204 109 -7 -73 -138 -183 Region 5 332 482 555 904 976 1261 1726 1542 1425 1316 Region 6 110 93 149 653 632 393 328 210 288 736 Aggregate 437 1193 1381 1995 1808 1780 2055 1485 1060 2044

Scenario 2 Net Position (MMSCFD) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Region 1 66 183 102 96 181 187 156 131 102 -3 Region 2 -244 -162 -156 -254 -622 -899 -744 -1,110 -1,341 -661 Region 3 -18 -68 -93 -88 -86 -90 -90 -90 -140 -139 Region 4 0 214 313 283 232 -176 18 -83 -148 -196 Region 5 311 462 545 904 935 1,161 1,696 1,512 1,375 1,250 Region 6 20 -4 0 231 123 -107 -162 -270 -222 -488 Aggregate 135 626 712 1,173 763 75 875 90 -375 -236 Scenario 3 Net Position (MMSCFD) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Region 1 50 163 87 76 165 170 136 111 87 -19 Region 2 -463 -412 -456 -504 -888 -1,160 -1,044 -1,510 -1,791 -1,120 Region 3 -20 -68 -98 -88 -89 -92 -300 -300 -350 -349 Region 4 -124 4 183 133 55 -431 -312 -443 -523 -584 Region 5 311 462 545 804 845 1,069 1,586 1,302 1,125 1,053 Region 6 20 -4 0 231 123 -107 -162 -270 -222 -488 Aggregate -226 146 262 653 211 -551 -95 -1,110 -1,675 -1,506 Source: Country’s Energy Handbook 2018, Ministry of Energy and Mineral Resources

C.3: Government’s Natural Gas Transmission and Distribution Infrastructure Masterplan Current Gas Infrastructure (2018) Expected Gas Infrastructure Masterplan (2030)

Source: Ministry of State-Owned Enterprise

The picture above explains the current condition of Indonesia’s gas infrastructure per 2018. The existing infrastructure covers only 20-30% of nation’s need/demand for natural gas. Thus making it harder for natural gas industry to fulfill the growing demand and required energy-mix in an area beyond its infrastructure coverage. To solve this problem, government has reinforced the plan to construct and develop gas infrastructure up to 80-100% by 2030.

C.4: Energy Mix 12% 11% 8% 12% 6% 4% 4% 2% 1% 24% 15% 22% 22% 22% 21% 22% 21% 21% 23% 21% 23% 24% 24% 24% 25% 25% 6% 6% 6% 23% 5% 6% 6% 6% 12% 11% 10% 21% 4% 5% 7% 6% 6% 6% 6% 7% 5% 4% 4% 6% 4% 7% 6% 10% 10% 9% 5% 6% 8% 7% 7% 7% 65% 65% 65% 65% 53% 56% 58% 62% 60% 61% 54% 57% 59% 44% 51% 52% 51%

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Coal Hydro Geothermal Gas Oil Source: PLN Statistics, RUPTL 2018-2027

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C.5: Indonesia Historical & Upcoming Gas Pricing Policy Issue Date Policy Description Gas price (for gas originating from Indonesia’s new gas fields) is set according to the purchase power of October Third Economic Policy Fertilizer Industry, which is US$7/MMBTU. The price of gas for other industries (such as petrochemical, 2015 Package ceramics, etc) will be reduced in accordance with the ability of the ability of their respective industries. Lower gas prices will come into effect from 1 January 2016. February Ministerial Decree of Gas price is determined by considering gas field (upstream) economics, domestic and international gas price as 2016 EDSM No.6/2016 well as added value of domestic gas usage. Presidential Decree 7 domestic industries will be allowed to pay a lower gas price. Stipulates lower gas prices by a maximum of May 2016 No.40/2016 US$2/MMBTU if gas prices are higher than US$6/MMBTU. Decree of ESDM Provide supporting regulations for Presidential Decree no.40/2016. It governs gas pricing scheme of 7 specified June 2016 No.16/2016 strategic industries. November Ministerial ESDM Government set maximum gas price of $6/MMBTU for 3 specified sectors (steel, fertilizer, and petrochemical) 2016 Decree No.40/2016 for direct gas distribution staring January 2017. February Minister ESDM Decree Government will fix maximum gas price in North Sumatra and surrounding areas below US$9/MMBTU by 2017 No.434 K/12/MEM capping distribution cost below US$1.8/MMBTU. ESDM Regulation Power plants can buy natural gas at a maximum price of 14.5% of ICP (Indonesia Crude Price) in US$/MMBTU, July 2017 No.45/2017 or US$7/MMBTU from domestic suppliers. Minister ESDM Decree Allowing ConocoPhillips to increase the selling price of its gas by volume of 27-50 BBTUD from US$2.6/MMBTU July 2017 No.5882/12/MEM.M to US$3.5/MMBTU from Gresik block corridor. Pricing formula for natural gas, i.e gas selling price = gas cost price + gas infrastructure management fee + December ESDM Regulation trading fee. The gas infrastructure management fee considers a maximum IRR of 11% or 12% applied to the 2017 No.58/2017 pipeline business depending on investment in the area. The trading fee is set at a maximum 7% of the gas cost price. Effective from July 2019. Source: Company Reports, EDSM, Jakarta Post

C.6: Gas Pricing Formula Ministry of Energy and Mineral Resources (MEMR) Regulation (PERMEN ESDM) No.58/2017 Weighted Average for End Use Price = Cost of Gas + Infrastructure Management Cost + Trading Cost Implementation Infrastructure Management Cost Infrastructure Management Formula Trading Cost  Toll fee stipulated by regulatory body = Cost of Service/Volume  Industry and electricity provider  Maximum 7% of  Gas distribution setup by: IRR 11%, Cost of service are: gas price stipulated by MEMR cost of gas 60% utilization/gas allocation and  Asset value  Prevail for 5 years and open to be  The maximum project economics  Operational and maintenance evaluated per annum percentage should  Liquefaction  General and administrative  18 months grace period from date be share B2B in  Compression  Gas losses of signatory extended supply  Regasification  Insurance (Dec 27, 2017) chain  LNG/CNG storage and transpotation  Fee, Tax and levy Source: Company Presentation 2018

C.7: Major Upcoming Pipeline Project in Short-Term Projects Value Commercialization Date Gresik-Semarang Transmission Pipeline US$221 mn July 2019 Grissik Gas Pipeline US$118 mn February 2019 Duri-Dumai Gas Pipeline US$62 mn February 2019 Gresik Semarang-Pipeline US$179 mn July2019 Regasification Pertagas US$340 mn July 2019 Total US$920 mn Source: SKK Migas

C.8: Changes in Company’s Board Composition Commissioners As of Dec 31, 2017 As of 9M18 Directors As of Dec 31, 2017 As of 9M18 President commissioners Fajar Sampurno IGN Wiratmaja Puja President director Jobi Triananda Gigih Prakoso Commissioners Hendrika Sinaga Hambra Finance Nusantara Suyono Said Reza Pahlevi Infrastructure & Commissioners Mohamad Ikhsan Mohamad Ikhsan Dilo Seno Widagdo Dilo Seno Widagdo technology Strategy & business Commissioners IGN Wiratmaja Puja - Nusantara Suyono - development Independent commissioners Paiman Raharjo Paiman Raharjo Commercial Danny Praditya Danny Praditya Independent commissioners Kiswodarmawan Kiswodarmawan HC & general service Desima Equalita Desima Equalita Source: Company Report, Team Assessment

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C.9: PGAS Newly Appointed Key Management Overview Board of Title Career History in PGAS Description Commissioners IGN Wiratmaja President  President He is promoted as President Commissioner of PGAS in 2018 GMS replacing Fajar Harry Puja, 54 commissioner Commissioner, April Sampurno. Previously served as commissioner in the company for three years. He has close 2018 relation with former major shareholder of PGAS, Republic of Indonesia through his position  Commissioner, Apr as Head of Human Resource Development Agency, Ministry of Energy and Mineral 2015 – Apr 2018 Resources (MEMR). He also has experience as Director General of Oil and Gas in MEMR until  Nomination & August 2017. Highly experience in the industry of oil and gas, Mr Wiratmaja is believed to Remuneration have the ability to bring the company higher completed with his background as a graduate member, Jan 2017 – from Institut Teknologi Bandung & doctorate from University of Kentucky Apr 2018 Hambra, 50 Commissioner  Commissioner since Hambra is appointed as commissioner of the company though 2018 GMS in April. He is April 2018 replacing Mrs. Hendrika Nora Osloi Sinaga. Previously he serves as Deputy of Infrastructure Business in Ministry of State-Owned Enterprise. He was a part of Ministry of SOE, along with his background as a doctorate in Universitas Gadjah Mada. Board of Title Career History in PGAS Description Directors Gigih Prakoso President  President Director Mr. Gigih Prakoso was appointed as President Director of the company per September 2018 Director since September 2018 through Extraordinary General Meeting of Shareholder (EGMS). It is a direct order from the  Director of Strategy holder of Series A Dwiwarna that is entitled with voting right. and Business The appointment aims to strengthen the upcoming corporate action to acquire Pertagas, a Development from subsidiary of Pertamina align with Mr. Gigih previous experience as Director of Investment May 2017 - August Planning and Risk Management of Pertamina from August 2017 until September 2018. Prior 2017 to its position as one of director in Pertamina, Mr. Gigih served as PGAS’s Director of Strategy and Business Development for four months before the decree from Ministry of SOE moved him to another SOE. Appointment of Mr. Gigih reflects company’s determination in the upcoming integration Pertamina-PGAS-Pertagas as it will be the main key in determining company’s future. Said Reza Director of  Director of Finance Mr. Said Reza Pahlevi was appointed as Director of Finance along with appointment of Mr. Pahlevi Finance since April 2015 Gigih Prakoso in 2018 EGMS. His recent experience was Director of Administration and Finance in PT Pertamina Patra Niaga, a subsidiary of Pertamina managing downstream oil and gas business of the company. Supported by his competence in the industry along with experience and knowledge from the previous position will support PGAS performance further and smooth the acquisition transaction. Source: Company Reports, Team Estimates

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