## Uganda: Extractive Industry Fiscal Regimes — Mission technical notes (July 6–17 2015) ## Source details **Canonical URL:** [Uganda: Extractive Industry Fiscal Regimes — Mission technical notes (July 6–17 2015)](https://www.imf.org/-/media/files/publications/cr/2017/cr17368.pdf) ## Other formats - [Markdown version](/-/media/files/publications/cr/2017/cr17368.pdf.md) - [Structured JSON version](/-/media/files/publications/cr/2017/cr17368.pdf.json) --- ### Preface: mission purpose, engagement, and scope - Mission purpose: - Technical notes concluding the second mission under the IMF Topical Trust Fund on Managing Natural Resource Wealth (MNRW) — Module 1 on extractive industry (EI) fiscal regimes. - Implements recommendations from “Uganda: Fiscal Regimes for Extractive Industries: Next Phase,” FAD (June 2015). - Mission visited Kampala and Entebbe during July 6-17 2015. - Mission led by Philip Daniel (FAD External Expert) with Diego Mesa Puyo (FAD), Emil M. Sunley (FAD External Expert) and Lee Burns (LEG Expert). - Stakeholders consulted: - Frequent meetings with the Technical Group on Petroleum (MFPED, MEMD, URA); named government officials and meetings with Tullow Uganda, Total E & P Uganda, CNOOC Uganda, PwC, Royal Norwegian Embassy, and World Bank office in Kampala. - Temporal scope: - Final report reflects legislation and circumstances prevailing during the mission of July 2015; notes changes up to end-October 2015 where relevant. - Report organization (four notes): - Note I: New licensing round and model PSA — bid variables, draft model PSA comments, FARI simulations, cost recovery financing rules. - Note II: Midstream infrastructure — crude pricing, pipeline tariff as guide to refinery crude price, pipeline configurations, refined product pricing and taxation. - Note III: Mining fiscal issues — Draft Mining Policy commentary, export rules/subsidies for processing, royalty regime gaps. - Note IV: General taxation issues — 2015 ITA and VAT amendments, VAT on imported services, DTA policy and model DTA guidelines. ### I. A New Model Production Sharing Agreement (PSA) — licensing, bid design, and model PSA assessment - Licensing round status and timing: - By mid-2015 prequalification reached; some 16 companies prequalified. - Qualified applicants required to purchase further data; government set January 15, 2016 as bid deadline. - Six blocks offered; two open to licensing at different stratigraphic levels. - Bid variables and evaluation: - Work program/expenditure may be bid item, fixture, or mix; UPD may prescribe a minimum work program. - Financial proposals should be restricted to at most two variables for transparency. - Typical financial bid variables: a Signature Bonus; an additive percentage points increase to the higher (tier 2) state share currently set at 75 percent. - If both bonus and production share are biddable, evaluation methods are outlined (Box 1 Methods of Bid Evaluation). - Dutch Auction mechanism illustrated with nominated bonus $10 million and example bids resulting in a winning signature bonus of $22 million. - Comments on the draft Model PSA (July 1, 2015): - Draft is advanced and contains strong new features such as the R-Factor production sharing system; aligns with modern standards. - Consistency with PEDPA 2013: include PEDPA definitions where PSA lacks them; PSA cannot override PEDPA. - Definitions and control: recommend referencing issued equity shares carrying voting rights when defining Control (two-fifths threshold). - State participation: model defines “commercial involvement” too broadly; issued model sets maximum carried state participation at 20 percent. - Liability: joint and several liability appropriate for contractual obligations but not for income tax liability; recommend several liability for tax purposes in Article 14. - Reporting and discovery: include subsurface water discovery among reportable natural resources; issued model now refers to “natural resources”. - Decommissioning costs: recommend separate classification and compliance reporting; PEDPA treatment applies. - Accounting and audit: Chart of Accounts advisory only; government audit/inspection rights must extend to midstream facilities that affect upstream price — issued model extends rights. ### Royalty, cost recovery, production-sharing, and simulations (FARI modeling) - Royalty design and treatment: - Model PSA royalty scheme applies a single rate to total production once each royalty rate is triggered (non-incremental application). - Model PSA royalty schedule (Model PSA (July 2015)): - < 25,000 = 8%; 25,000 - 50,000 = 10%; 50,000 - 75,000 = 12%; 75,000 - 100,000 = 14%; 100,000 – 130,000 = 16%; > 130,000 = 18%. - Comparison: PSA EA1 (2004) used incremental DROP tranches with First 2,500 = 5%; Next 2,500 = 7.5%; Next 2,500 = 10%; > 7,500 = 12.5%. - Fixed gas royalty: model leaves rate for negotiation; many jurisdictions fix gas royalty (five percent common). - Production bonuses tied to cumulative production are redundant under R-Factor; issued model retains simpler, non-negotiable production bonuses. - Cost recovery limits and financing costs: - Cost recovery limits: PSA EA1 (2004) = 60%; Model PSA (July 2015) = 65%; Option 1 (June 2015) = 70%. - Interest/uplift treatment: - PSA EA1 uplift on development costs: 15% uplift. - Model PSA (July 2015) allows interest recoverable; debt limit not to exceed 50% of Licensee’s financing requirement. - FAD June 2015 proposed replacing interest with a one-time uplift of 15% of capital costs incurred (limited to first five years of development expenditure). - Simulation: for total development costs $500 million and a fixed 7.5 percent annual nominal interest, the 15 percent uplift is always lower than interest expense across D/E scenarios tested; under strict D/E 1:1 interest would need to be 5 percent or lower for uplift to exceed interest expense (repayment period assumed 10 years). - Production sharing and R-Factor: - R-Factor schemes (Model PSA and Option 1) provide Gov. Share: 50% for 0 < 1; formula for 1 – 3; > 3 = 75%. - PSA EA1 (2004) government share by DROP tranches: First 5,000 = 45.0%; Next 5,000 = 47.5%; Next 10,000 = 52.5%; Next 10,000 = 57.5%; Next 10,000 = 62.5%; Over 40,000 = 62.7%. - Simulated project example (FARI): - Price assumption: $80/bbl FOB Mombasa yielding a real pre-tax IRR of 29 percent for the large project example. - Corporate tax: 30% across PSAs. - State participation: PSA EA1 = 15% carried; Model PSA = 20% carried; Option 1 = 15% carried. - Minimum effective royalty calculations (Model PSA example): - Cost recovery limit 65 percent implies 35 percent of gross production is profit petroleum. - Government share of profit petroleum 50% of 35% = 17.5% of gross. - Formal royalty starts at 8%. - Cost oil = 65% of 92% = 32.2%. - Minimum share of profit oil to government = 16.1%. - Effective minimum royalty to government = 8 + 16.1 = 24.1 percent. - Comparative figures: - Option 1 (8% royalty, cost recovery 70%) results in minimum effective royalty rate of 21.8 percent. - Figure 1 (first year of production minimum effective royalty): PSA EA1 (2004) = 32.0%; R-factor Option 1 = 21.8%; Model PSA (July 2015) = 25.8%. - Progressivity and AETR: - Average Effective Tax Rate (AETR) undiscounted: regimes yield AETRs between 81 and 85 percent. - Discount rate 10 percent AETR results: - Model PSA = 93 percent. - EA1 PSA = 91 percent. - R-factor Option 1 = 89 percent. - Model PSA and Option 1 more progressive than EA1; Option 1 shows higher progressivity. ### Sensitivity analysis (Model PSA at $80/bbl) — quantified impacts - Parameters tested and ranges: - Min royalty rate: ↓ to 6% — ↑ to 10%. - Cost recovery limit: ↓ to 55% — ↑ to 75%. - Min. gov. share: ↓ to 40% — ↑ to 60%. - Max. gov. share: ↓ to 65% — ↑ to 85%. - CIT rate: ↓ to 25% — ↑ to 35%. - State participation: ↓ to 15% — ↑ to 25%. - Key quantified sensitivities: - A 10 percentage point increase in the maximum government share increases government revenue by $170 million. - A 10 percent point decrease in the maximum government share reduces revenue by $199 million. - A 10 percent point increase in the maximum government share would reduce the post-tax IRR from 13.1 to 12.4 percent. - A 10 percent point decrease in the maximum government share would increase post-tax IRR to 13.7 percent. - Changes to minimum and maximum government share of profit petroleum have the greatest effect on government revenue and post-tax IRR. ### Royalty design: DROP vs R-Factor mechanics and implications - DROP (incremental daily rates of production) characteristics: - Government share determined by production tranches; effective government share is a weighted average across tranches and does not reach the highest tranche at moderate production rates. - Example at 50,000 bpd: effective government share = 57.25 percent (below highest tier 67.5 percent). - R-Factor characteristics: - Government share determined by R-factor reflecting project profitability; once R-factor threshold reached, higher government share applies and can reach 75 percent for R-factor > 3. - R-Factor responds to profitability; DROP does not. - Implication: - New model PSA (R-Factor) is more progressive and more sensitive to profitability; can raise government share during high-profit periods but may impose higher burden on marginal projects. ### Midstream infrastructure, pipeline commercial models, and pricing interactions - Pipeline commercial models: - Model 1: pipeline owners bear no throughput risk, earn minimum return; compatible with ownership mirroring upstream; pipeline provides transportation only. - Model 2: freestanding pipeline company negotiating tariffs and contracts with shippers; owners take initial risk obtaining throughput contracts; may engage in spot trading in mature form. - Likely evolution: start Model 1 and evolve toward Model 2. - Capacity, tariffs, and cost of capital: - Tariff modeled as annual reservation charge; annuity over 21 years repaying capital with specified return. - Operating costs split ~25 percent fixed and 75 percent variable. - FAD (June 2015) used a post-tax real return of 7.5 percent (approx pre-tax real 10 percent and nominal pretax 12.5 percent); industry rates database equivalent nominal pre-tax figure 9.3 percent. - Capacity sizing trade-off: initial plateau capacity sizing affects ability to accept third-party crude later. - Crude pricing into refinery: - Upstream crude into refinery assumed sold at export parity (netback from arm’s length seaport price to inlet flange). - Refinery crude price will be negotiated, guided by pipeline tariff; monthly provisional pricing with later adjustment possible. - Refinery may pay higher upstream price if it needs supply and export through pipeline is attractive to producers. ### Refinery assumptions, profitability, and tax/regulatory options - Refinery assumptions (FAD, June 2015): - Initial capacity 30,000 bpd, increasing to 60,000 bpd after ~seven years. - Uganda current consumption ~28,000 bpd; expected to exceed 30,000 bpd when refinery on stream. - 159 liters in one barrel assumption; official midpoint monthly USD:UGX exchange rate used. - Example domestic import prices (Mombasa to Kampala route assumptions): - Petrol: UGX 2,300 per liter (excluding excise). - Diesel: UGX 2,000 per liter (excluding excise). - Profitability drivers: - Crack spread (cost of crude delivered minus domestic product prices) expected to make refinery highly profitable on assumptions used. - Design trade-off: refinery configured for Uganda crude high wax content; small refinery size increases per-barrel costs versus large refineries. - Tax/regulatory options: - Excess (windfall) profit tax preferred to capture super-normal returns while preserving incentives. - Regulating rate of return and adjusting crude price less preferred. - Petroleum products to be subject to excise duty and VAT; consideration to repeal VAT exemption and adjust excise closer to refinery commencement. - Avoid fuel consumption subsidies; they tend to benefit richer segments. ### Mining fiscal issues — beneficiation, royalties, gap analysis, and recommendations - Draft Mining Policy (July 9, 2015): - Draft Green Paper requires further work: describe problem, analyze options and impacts, justify proposals; presupposes reassignment of government functions. - Policies to promote domestic processing: - Instruments include export prohibitions, export taxes, differential royalties, reduced corporate tax rates. - Caution: these measures can be costly in lost revenue, exports, FDI; Zambia experience (10 percent export tax) led to stockpiling and suspension; Madagascar example of differential tax led to windfall for Ambatovy. - Prefer direct tax incentives strictly linked to processing investment, or direct government support (spending/infrastructure) rather than export restrictions or broad tax subsidies. - Explicit recommendations: - Refrain from export prohibitions and export taxes on unprocessed minerals. - If subsidy desired, use direct government spending or an initial tax allowance tied to investment in processing facilities. - Royalty base, rates, and administration gaps: - Recommend defining royalty base as gross sales value (sales value before selling, transport, insurance costs). - For smelted/refined products, gross sales value = net smelter return. - Specific royalty rate examples under Mining Regulations: - 5 percent for precious metals, - 10 percent for precious stones, - 5 percent for base metals and ores, - specific rates for listed minerals (e.g., phosphate rock UGX 10,000 per ton). - UGX 10,000 per ton for phosphate rock ≈ 2.5 percent of benchmark US$115 per ton price for phosphate rock 32-33 percent P2O5 FOB Morocco. - Recommend using Advance Pricing Agreements (APAs) to reduce related-party pricing disputes. - Administration: strong case for shifting royalty administration to URA to apply Tax Procedures Act rules and enable risk-based audits; amendments to Tax Procedure Act and Mining Act required to effect shift. - Revenue sharing and local allocations: - Current allocation: central government 80 percent; district council 10 percent; urban/sub county council 7 percent; owners/lawful occupiers 3 percent. - Recommend studying allocation practices, prompt payments to local governments, and guidance where customary communal title complicates owner allocations. - Explicit mining recommendations (from source): - Define royalty base as gross sales value. - Allow government to enter APAs for related-party sales. - Amend Mining Act for specific rates on construction minerals and review specific rates annually or biennially. - Require mineral companies to self-assess royalty with monthly or quarterly payments. - Shift royalty administration to URA. - Study and consider amending allocation of royalty revenue to local governments and owners. ### General taxation for extractive industries — VAT, imported services, ITA Part IXA, and technical corrections - VAT and deemed paid regime: - VAT Amendment Act 2015 implements deemed paid VAT for taxable supplies by a contractor to a licensee for use solely and exclusively in mining or petroleum operations; “licensee” and “contractor” defined. - Implementation requires a Practice Note under s 44 of the Tax Procedures Code Act to guide “solely and exclusively” tests. - Outstanding FAD recommendations: exempt imports by a contractor for direct and exclusive use in operations; requires EAC Customs Management Act amendment at EAC level. - VAT Amendment Act 2015 reintroduced input tax credit for reverse charged VAT on imported services for licensees/contractors, but uncertainties remain on definition of “imported services.” - VAT on imported services (B2B and B2C principles and gaps): - Reverse charge rationale: apply to registered persons to capture VAT on services that do not cross the border; two situations distinguished (registered person using services solely for taxable supplies vs partly for exempt supplies). - Current law: s 4(c) imposes VAT on “supply of imported services (other than an exempt service) by any person”; s 5(c) makes recipient liable (reverse charge). - Prior to amendment, reverse charged VAT had no input credit; amendment allows contractor/licensee input tax credit. - Gaps and recommendations: - Reverse charge rule should apply only to registered persons; amend regulation 13 accordingly. - Include a definition of “imported services” in s 1 of the VAT Act. - Require non-resident registered persons without a place of business in Uganda to appoint an agent for VAT obligations. - Income tax Part IXA and petroleum expenditure definitions: - Laws to amend ITA and VAT Act effective July 1, 2015 reverted to pre-2010 regime: chargeable income of a licensee based on normal ITA rules modified by Part IXA. - Enacted definitions of “petroleum exploration expenditure” and “petroleum development expenditure” differ from mission recommendations and from mining equivalents; MEMD advice influenced scope. - Key issues and recommendations: - Cost of acquiring a petroleum exploration right or an interest likely not petroleum exploration expenditure; treated as intangible asset and deducted under s 31 over useful life. - Cost of acquiring petroleum exploration information may not be authorized expenditure under MEMD advice; scope could be clarified in a Practice Note. - Cost of acquiring depreciable assets for exploration likely petroleum exploration expenditure and expensed under s 89GB; clarify via Practice Note. - Petroleum development expenditure currently treated such that depreciable assets are straight-line depreciated over lesser of expected life or six years under s 89GC(2) — this was not intended; amend or clarify so normal depreciation rules apply. - Revert to original proposed definitions of petroleum exploration/development expenditure or amend development expenditure to cover only capital expenditure; prepare Practice Note. - Delete definition of “gross income of a licensee” (inserted s 89A(1)) and prepare Practice Note on gross income determination. - Ring-fencing, farm-outs, farm-in/farm-out taxation: - Ring fencing under s 89GA references “contract area” consistent with PEDPA definitions; ensure model PSA definitions align with ITA and PEDPA. - Terminal losses: no provision for transferring terminal losses; MOFPED confirmed policy of terminal losses; deductions allowed for rehabilitation/decommissioning funds mitigate impact. - Farm-outs: s 89GD(2)(a) taxes value of work commitments undertaken by farmee; FAD recommended excluding these values to encourage exploration; recommend amending s 89GD(2)(a). - Non-resident contractor tax and withholding: - S 89GG imposes non-resident contractor tax at 10 percent of gross service fee paid by a licensee; originally intended to apply only where contractor has no branch in Uganda; parliamentary amendment removed branch carve-out so s 89GG applies irrespective of branch presence. - Recommendation: make non-resident contractor tax non-final and creditable for service fees paid to a Ugandan branch of a non-resident contractor; clarify priority of s 89GG over ss 83 and 85 in Practice Note. - Technical corrections to Part IXA (specific numbered items listed in source) — recommended deletions, cross-reference fixes, and definition corrections (12 distinct technical corrections enumerated). - Source rules and transitional provisions: - Recommend modernizing s 79 source rules (including indirect transfers of immovable property); transitional regulations under s 164(2)(a) of ITA to be prepared in consultation with licensees. ### Double Tax Agreements (DTAs), transfer pricing, and treaty policy - DTA policy and revenue risk: - DTAs allocate taxing rights and can reduce source country revenue; Uganda has nine DTAs in force; EAC tax treaty ratified by only Rwanda and Kenya. - Government should develop a DTA policy with guidelines for partner choice, negotiation baseline, model DTA development, and DTA impact statements quantifying revenue loss. - Prefer UN Model DTA as basis (greater source country protection), with selective OECD elements. - Prohibit negotiations with countries posing revenue risk; consider alternatives to DTAs (exchange of information, TIEA, Multinational Convention). - DTA impact statement contents: - Reasons for partner choice, assessment of DTA’s effects on trade and investment, other benefits, and quantification of potential revenue loss. - Model DTA recommendations (specific items relevant to resources sector): - Include substantial equipment and services PE inclusions; ensure exploration is explicitly covered in PE definitions. - Align construction PE time limits with domestic branch definition (recommend 90 days rather than current one month in draft DTA). - Prefer pre-2010 OECD separate entity approach for profit attribution; retain Article 7(2) and (3) in draft model DTA. - Adopt 10 percent withholding rate for interest and royalties in model DTA (alignment with most recent DTAs). - Ensure equipment lease payments treated as royalties in DTAs to reflect domestic law characterization. - For capital gains on indirect transfers, adopt OECD Article 13(4) with modifications to cover non-corporate entities and align immovable property definition with domestic law. - Include a Limitation on Benefits (LOB) Article to prevent treaty shopping; prefer simpler LOB based on s 88(5) of ITA with exception for substantial economic activity. - Transfer pricing and branch attribution: - Transfer Pricing Regulations apply separate entity approach for branch attribution; recommend amending regulation 4 so separate entity approach need not apply when the other country uses single entity approach to avoid mismatches. - Consolidated DTA recommendations: - Develop DTA policy; prepare model DTA based on UN Model DTA; prepare DTA impact statements; include LOB Article; amend Transfer Pricing Regulations per above. _Italic: IMF staff report for the mission in Uganda on Extractive Industry fiscal regimes (Module 1), July 6-17 2015, concluding technical notes and commentary on the draft Model PSA (July 1, 2015)._ ### Preface ................................................................................................................ ### Preface ### Mission purpose and context - Technical notes concluding the second mission under the project in Uganda on extractive industry (EI) fiscal regimes (Module 1) under the IMF Topical Trust Fund on Managing Natural Resource Wealth (MNRW). - The report implements recommendations from the first mission report: “Uganda: Fiscal Regimes for Extractive Industries: Next Phase,” FAD (June 2015). - The mission visited Kampala and Entebbe during the period July 6-17 2015. - The mission led by Philip Daniel (FAD External Expert) with Diego Mesa Puyo (FAD), Emil M. Sunley (FAD External Expert) and Lee Burns (LEG Expert). ### Engagement and stakeholders consulted - Frequent meetings with the Technical Group on Petroleum (officials from MFPED, MEMD, and URA). - Government officials engaged included: - MFPED: Mr. Lawrence Kiiza (Director of Economic Affairs), Mr. Moses Kaggwa (Commissioner for Tax Policy), Mr. Francis Twinamatsiko (Head of Oil and Gas Taxation Division). - MEMD: Mr. Kabagambe-Kaliisa (Permanent Secretary); Petroleum Exploration and Production Department: Mr. Ernest Rubondo (Petroleum Commissioner and Acting Director), Mr. Robert Kasande (Assistant Commissioner and Head of the Refinery Project); Geology and Mines Department: Mr. Joseph Okedi (Principal Inspector of Mines). - URA: Ms. Doris Akol (Commissioner General), Ms. Patience Tumusiime Rubagumya (Commissioner, Legal Services and Board Affairs), Messrs. Silajji Kanyesige, Mayanja Walakira, and Cyprian Chillanyang (Assistant Commissioners); Mr. John Mayanja (Commissioner LTO). - Meetings with industry and international partners: Tullow Uganda, Total E & P Uganda, CNOOC Uganda, PwC, Mr. Kyrre Holm (First Secretary, Royal Norwegian Embassy), Mr. Nganou Jean-Pascal (Senior Economist, World Bank office in Kampala). - Administrative/logistical support acknowledged from IMF Office and MFPED staff: Ms. Caroline Ntumwa, Ms. Winifred Bisamaza, Ms. Vanessa Ihunde, Ms. Stella Nabakooza. ### Temporal scope - The final report reflects legislation and circumstances prevailing during the mission of July 2015. - Where relevant, the report notes changes of substance that occurred up to the end of October 2015. --- ### Introduction and Executive Summary ### Scope of the report - Covers key issues in implementing existing fiscal regimes for upstream petroleum and mining, midstream segment of the Uganda Oil project, and the design of new regimes. - Organized as four notes: - Note I: New licensing round and new model Production Sharing Agreement (PSA) — bid variables, bid evaluation methods, detailed comments on draft model PSA (July 2015), simulations of fiscal terms, and alternatives for cost recovery rules for financing costs. - Note II: Midstream infrastructure — crude oil pricing (export pipeline and domestic refinery), pipeline tariff as a guide to refinery crude price, two main commercial pipeline configurations, pricing and taxation of refined products. - Note III: Mining fiscal issues — commentary on Draft Mining Policy of 2015, export rules and subsidies for domestic processing with regional examples, gaps and uncertainties in mining royalty regime and solutions. - Note IV: General taxation issues — issues relating to 2015 amending legislation to the Income Tax Act (ITA) and VAT Act and suggested technical amendments, VAT on imported services and recommendations, and guidelines to develop a Double Tax Agreements (DTA) policy and a model DTA. --- ### I. A New Model Production Sharing Agreement ### A. New Licensing Rounds and Bid Variables - Licensing round status and timeline: - By mid-2015 Uganda’s new licensing round reached the prequalification stage. - Some 16 companies successfully entered for prequalification. - Prequalified companies were sent Requests for Proposals (RFP) and the model PSA and required to purchase further data. - The government set January 15, 2016 as the deadline to receive bids from qualified applicants. - Six blocks have been offered; two of which are open to licensing at different stratigraphic (depth) levels. - Work program and expenditure as bid items or fixtures: - The required exploration work program and expenditure could be a bid item, a fixture, or a mix. - UPD may prescribe a minimum work program (quantities of seismic acquisition and numbers of wells per period). - If the work program is competitive, weighting between technical and financial bid items must be decided. - Work commitments are comparable in monetary value to a signature bonus but typically slightly lower since they are deferred; commitments beyond the first exploration period are contingent and lack a clear present value. - One possibility: require a significant minimum work commitment from prequalified companies, then decide among them according to financial proposals. - Limits on financial bid variables: - Financial proposals should be restricted to at most two variables; more variables impede evaluation and transparency. - Typical financial bid variables: - A Signature Bonus (upfront lump sum payable on signature or effective date). - A higher government share of production (an additive “x” percentage points to the higher (tier 2) state share currently set at 75 percent). - The expected yield from a higher production share is heavily discounted for probability of commercial success and time value of money; thus restricting bids to the bonus alone may be practical. - If both bonus and production share are biddable, evaluation methods are outlined (see Box 1 Methods of Bid Evaluation). - Tender process and transparency: - Competitive tender does not require open outcry auctions; a full and transparent process requires public opening and verification of bids with no subsequent negotiation. - A common approach if both technical and financial elements are bid is a “two envelope” system with an order of priority (e.g., open technical envelopes first to verify minimum standards, then open financial envelopes). - Dutch Auction mechanism for bonus bids: - Authorities can nominate a minimum signature bonus and invite bids specifying a maximum bid and counter interval. - Example provided in the text: - Nominated bonus: $10 million. - Company A: maximum $20 million, $1 million interval. - Company B: maximum $26 million, $2 million interval. - Resulting winning signature bonus example: $22 million ($2 million from Company B above Company A’s maximum). - Advantages: price discovery for the government and reassurance to bidders regarding maximum exposure; low likelihood of effective collusion with 5 or 6 bidders. ### B. Comments on the Model PSA - Overall assessment: - The draft model PSA (provided to the mission dated July 1, 2015) is at an advanced stage and contains strong new features such as the R-Factor production sharing system. - Represents an important development aligning Uganda’s petroleum agreements with modern standards. - Consistency with PEDPA 2013: - Definitions in Article 1 (1.1) should add: “Unless the context otherwise requires, any term that is not defined in this Agreement but is defined in the Petroleum (Exploration Development and Production) Act, has the meaning in that Act”. - Any model PSA definition that duplicates a PEDPA definition should be deleted unless the term is intended to have a different meaning in the PSA; a PSA definition cannot override PEDPA. - The Model PSA issued incorporates this change. --- *Italic: IMF staff report for the mission in Uganda on Extractive Industry fiscal regimes (Module 1), July 6-17 2015, concluding technical notes and commentary on the draft Model PSA (July 1, 2015).* ### 10. Reference to voting rights is needed in the definitions of Affiliated Company and ### 10. Reference to voting rights is needed in the definitions of Affiliated Company and ### Definitions, control, and voting rights - Recommendation: Where the definition (1.1.3) defines Control, in part, as control of the right to cast votes in respect of not less than two-fifths of the total number of votes in respect of issued equity shares, the reference should be to issued equity shares carrying voting rights. - Rationale: This makes the definition of control refer to two-fifths of the voting shares and not two-fifths of the share capital. Example: redeemable preference shares may form part of share capital but may not carry voting rights. ### Ring-fencing, Contract Area, and consistency with Income Tax Act - Observation: Under the new terminology in the Income Tax Act, “Contract Area” is defined to mean the exploration or development area subject to a Petroleum Agreement. - Clarification: For the Income Tax Act, “exploration area” and “development area” have their meanings in the PEDPA: - “Exploration area” = area constituted by a block or blocks subject to a petroleum exploration license. - “Development area” = area constituted by a block or blocks that, following a commercial discovery, has been delineated for production according to the terms of a petroleum agreement. - Effect: The new terms create ring fencing, in effect, by Production License (PL) Area if more than one PL is granted within an area originally falling within an Exploration License Area (Article 12). - Note: The model refers (1.1.37) to a “Development Area” with respect to a Joint Venture Agreement, but Development Area is not defined in the model (it is defined in the PEDPA). The position is clear but different from the ITA in the Model PSA issued. ### Definitions of Petroleum and Petroleum Activities - Change: The model changes definitions of “Petroleum” and “Petroleum Activities” from the PEDPA (1.1.53 and 1.1.54). - Specific issues: - The model’s definition of petroleum appears to include petroleum derived from shale, whereas the PEDPA definition excludes it. - The model’s definition of Petroleum Activities adds a specific exclusion of activities “beyond the Delivery Point”. - Contradiction: The model contains an Article on pipelines that appears to cover activities beyond the Delivery Point. - Status: The model PSA issued is now clear and consistent with the PEDPA. ### State participation, liability, and taxation - State Participation: - Defined in the model as “commercial involvement” (1.1.63.), which is too broad and does not usually refer to acquisition of a Venture interest by the State or its Nominee as set out in Article 11. - The model PSA issued sets the maximum share of carried state participation at 20 percent. - Liability: - Joint and several liability is appropriate for contractual obligations, but not for income tax liability (2.3.). - Suggested fix: Insert several liability for tax purposes in Article 14 on taxation. - Carry terms: - Terms of the “carry” provided for the State or its Nominee through development to production are not yet clear (11.1). - Current statement: source of repayment is “the Licensee’s cost recovery oil,” which includes cost recovery oil attributed to the state participation share. - Recommendation: If State Participation terms are not to be negotiable, source and terms of repayment (including rate of interest on outstanding liability) should be spelled out. - Model PSA issued: stipulates costs are recoverable from the Government’s (or Government Nominee’s) share of cost petroleum and sets maximum carried state participation at 20 percent. ### Reporting obligations, discoveries, and decommissioning - Discovery reporting: - Licensee must declare discoveries of other minerals but not of water (3.5.). - Recommendation: Sub-surface discovery of water should be treated at least comparably with discovery of other minerals by a petroleum licensee. - Issued model PSA: refers to “natural resources” and thus includes water. - Decommissioning costs: - Recommendation: Decommissioning costs should feature separately in the classification of costs (Section 2). - Treatment: The PEDPA sets out treatment of decommissioning costs; compliance should be subject of reporting under the PSA. - Accounting and financial procedures: - Chart of Accounts: Reflects petroleum industry accounting standards, including International Financial Reporting Standards (IFRS). Any government-prepared Chart of Accounts can be advisory but should not be mandatory for PSA accounting/reporting. - Midstream impacts: Sale of petroleum through export pipeline or regulated midstream facility affects Accounting Procedure; regulated or agreed tariff partly determines value of production (paragraph 1.2.(f).(ii)). - Audit rights: Government audit and inspection rights under PSA (1.5) need to be available for midstream facilities that affect upstream price; paragraph 1.5.(c) of issued model provides necessary extension of audit and inspection rights. ### Royalty, cost recovery, and production-sharing provisions - Royalty base and payment timing: - Issue: PEDPA’s Royalty wording leaves room for interpretation of the base for the Royalty charge. Model PSA (10.1) repeats PEDPA (s 154) wording that “the licensee shall pay to the Government,” specifying a percentage of gross daily production but leaving source unclear. - At point of production, the licensee does not “own” gross production; parties lift and market according to Article 17. - Intention seems for government to take royalty as a primary charge on gross production; as issued, the model PSA now states only “the Government shall take the following royalty...”, making intent clear. - Royalty calculation method: - The Royalty calculation is written as gross on the total daily amount of production (10.1): each increment of production is charged at the highest resulting rate rather than an incremental weighted average. - Example: at rates in excess of 130,000 BOPD, the royalty rate on all production is 18 percent, whereas initial royalty on tranche up to 25,000 BOPD is 8 percent. - Effect: This makes overall royalty impact more severe on the Licensee as production rises and gives incentive to manage production rates to avoid triggering higher royalty rates. - Issued model: makes explicit that royalty is not incremental; applicable rate is levied on total daily production. - Fixed gas royalty: - Observation: A fixed rate of Royalty on natural gas is feasible. - Model: leaves rate for negotiation upon establishment of commerciality. - Comment: Many jurisdictions fix natural gas royalty in advance; a rate of five percent is fairly common. Negotiation offers little advantage to government within R-Factor system and adds uncertainty; “commerciality” may depend on royalty rate. - Production Bonuses: - Production Bonuses tied to cumulative production are redundant under the R-Factor system (9.2). - Rationale: R-Factor sharing scales respond to cumulative levels of the R-Factor, reducing need for cumulative-production bonuses. - Issued model: still contains Production Bonuses but in simpler form with amounts and levels made specific and not negotiable. - Cost recovery and uplift/interest: - Indexing: Escalation index for minimum Exploration Expenditure requires updating (4.6); model PSA issued refers to Industrial Goods Producer Price Index; consider whether composite or petroleum-specific index is appropriate. - Cost recovery limits differ across models and interact with royalty to produce an implicit minimum effective royalty rate. - Uplift: If uplift replaces interest recovery (as proposed in June FAD report), there is no need for a distinct order of recovery. Issued model: does not adopt uplift; interest and financing charges are recoverable provided debt does not exceed 50 percent of Licensee’s financing requirement. - Arm’s length valuation: - Issue: “Arm’s length” price of oil at delivery point in Uganda is affected by non-arm’s length pipeline tariffs; valuation criteria need review. - Suggestion: If agreed pipeline tariff is ‘deemed’ or treated as leading to arm’s length price, Article 15 principles can remain. Issued model: makes “arm’s length sales” consistent at various points and provides a clear procedure for valuing natural gas not sold in arm’s length sales. - Transfer of assets to government: - Concern: Optional provision (Article 21) allowing transfer of assets to government on abandonment may not advantage government given environmental liabilities and technological obsolescence. - Status: Acquisition by government remains optional in the issued model. ### Stability assurances and confidentiality - Stability assurance under Applicable Law: - Concern: Stability assurance is invoked only where Licensee may be disadvantaged (Articles 31.2–31.4 numbered Article 30 in issued model) and is not symmetrical when State may be disadvantaged. - Exception: A tax on additional profits suggests “original economic benefits” accrue at a base level; treatment of surcharges or higher normal income tax rates may need consistency with “additional profits tax” wording. - Confidentiality and public disclosure: - Observation: PSA is both a grant of public rights and a revenue-raising instrument and thus should be in the public domain. - Current: Confidentiality provision (34.1 or 33.1 as issued) applies to information treated as confidential and also applies to the PSA and its terms. - Recommendation: Parties can agree to make a PSA public. Mission supports Uganda’s intention to be a candidate in the Extractive Industries Transparency Initiative and for public disclosure of PSAs per IMF guidance. ### Simulations of fiscal terms in the new model PSA (FARI modeling) - Modeling framework: FAD’s Fiscal Analysis of Resource Industries (FARI). - Project example: - Price assumption: $80/bbl FOB Mombasa. - Result: yields a real pre-tax IRR of 29 percent. - Project: the large project described in FAD (June 2015). - Fiscal regime options evaluated: - (i) PSA applying to area EA1, signed in 2004 (PSA EA1 (2004)) - (ii) July 2015 draft of the new model PSA (Model PSA (July 2015)) - (iii) Terms included in R-factor option 1 discussed in June 2015 (Option 1 (June 2015)) - Key fiscal term comparisons (as presented): - Royalty: - PSA EA1 (2004): Increments of DROP; incremental rate; DROP structure; First 2,500 = 5%; Next 2,500 = 7.5%; Next 2,500 = 10%; > 7,500 = 12.5%. - Model PSA (July 2015): Rate fixed; < 25,000 = 8%; 25,000 - 50,000 = 10%; 50,000 - 75,000 = 12%; 75,000 - 100,000 = 14%; 100,000 – 130,000 = 16%; > 130,000 = 18%. - Option 1 (June 2015): Fixed rate 8%. - Cost recovery limit and interest/uplift: - PSA EA1 (2004): 60%; Interest/uplift 15% uplift on development costs. - Model PSA (July 2015): Interest recoverable; 65%. - Option 1 (June 2015): Interest recoverable; 70%. - Production sharing (government share by tranches): - PSA EA1 (2004): Increments of DROP with Gov. Share: First 5,000 = 45.0%; Next 5,000 = 47.5%; Next 10,000 = 52.5%; Next 10,000 = 57.5%; Next 10,000 = 62.5%; Over 40,000 = 62.7%. - Model PSA (July 2015) and Option 1 (June 2015): R-factor schemes with Gov. Share = 50% for 0 < 1; Formula for 1 – 3; > 3 = 75%. - Corporate tax: 30% across PSAs. - State participation: - PSA EA1 (2004): 15% carried through development. - Model PSA (July 2015): 20% carried through development. - Option 1 (June 2015): 15% carried through development. - Minimum effective royalty and government share of profit petroleum: - Mechanism: Combination of royalty, cost recovery limit, and minimum government share of profit petroleum creates an implicit minimum effective royalty rate. - Example calculation (Model PSA): - Cost recovery limit: 65 percent implies 35 percent of gross production is profit petroleum. - Government share of profit petroleum: 50 percent of 35 percent = 17.5 percent of gross. - Formal royalty: starts at 8 percent. - With royalty applied first and cost oil calculated on balance after royalty: cost oil = 65 percent of 92 percent = 32.2 percent. - Minimum share of profit oil to government = 16.1 percent. - Effective minimum royalty to government = 8 + 16.1 = 24.1 percent. - Comparative results: - Option 1 (fixed 8% royalty and cost recovery limit 70%) results in a minimum effective royalty rate of 21.8 percent. - Figure 1 (first year of production minimum effective royalty): PSA EA1 (2004) = 32.0%; R-factor Option 1 = 21.8%; Model PSA (July 2015) = 25.8%. - Observation: The combination of a modest flat-rate royalty or a royalty structured not to reach maximum early, a higher cost recovery limit, and R-factor reduces minimum effective royalty rate compared to existing PSAs. The Model PSA’s minimum effective royalty is higher than Option 1 due to lower cost recovery limit (65 vs. 70 percent) and royalty reaching 10 percent in the first year vs. fixed 8 percent in Option 1. *Source: cr17368 - 10. Reference to voting rights is needed in the definitions of Affiliated Company and (cr17368 - 10. Reference to voting rights is needed in the definitions of Affiliated Company and, PDF).* ### 37. Once each royalty rate is triggered in the new model PSA, this rate applies to total ### Once each royalty rate is triggered in the new model PSA, this rate applies to total production instead of each production increment as in existing PSAs ### Royalty design and comparison with DROP - New model PSA royalty scheme: - Midpoint rate: "12 to 14 percent" as its midpoint, starting at "8" and rising to "18". - Once triggered, a royalty rate applies to total production rather than to each production increment. - At DROP rates up to "75,000 barrels of oil per day (bpd)", achievable at sustained plateau production on a field of "300 million barrels (mm bbl)" of recoverable reserves, the royalty rate stays at or below "12 percent". - Works in conjunction with a slightly higher cost oil limit of "65 percent" included in the July draft of the new model PSA. - Sliding scale could be useful late in field life to prolong field life if production tails off slowly without discretionary remission of royalty. - DROP (existing PSAs) vs R-factor (new model PSA) mechanics: - DROP determines government share by increments of daily production (tranches); increases in effective government share are gradual and based on weighted averages across tranches. - R-factor determines government share from the tranche reached by the R-factor at the end of a period; the highest tier is achieved once its R-factor threshold is reached. - DROP does not respond to project profitability: after peak production government share can decrease even if project profitability rises. - R-factor responds to project profitability: government share increases with profitability (measured as the R-factor). - Illustration of DROP tranche-weighting (Daily rate of production 20,000 to 50,000 bpd): - First 5,000 b/d: Government share "45%", Government share of profit petroleum (in b/d) "2,250", Effective Government Share "45.00%". - Next 5,000: Government share "47.5%", Government share of profit petroleum (in b/d) "2,375", Effective Government Share "46.25%". - Next 10,000: Government share "52.5%", Government share of profit petroleum (in b/d) "5,250", Effective Government Share "49.38%". - Next 10,000: Government share "57.5%", Government share of profit petroleum (in b/d) "5,750", Effective Government Share "52.08%". - Next 10,000: Government share "62.5%", Government share of profit petroleum (in b/d) "6,250", Effective Government Share "54.69%". - Next 10,000: Government share "67.5%", Government share of profit petroleum (in b/d) "6,750", Effective Government Share "57.25%". - Key implication from the example: - Under DROP the effective government share never reaches the highest tier; at a daily rate of production of "50,000 bpd" the effective government share is "57.25 percent", below the highest tier of "67.5 percent". - Under R-factor, if the R-factor ratio at the end of a period is above "3", the effective government share for the next period would be "75 percent". ### Government revenue profiles and progressivity - Revenue timing and composition: - In all three PSAs modeled (EA1, new model PSA, and R-factor options) the government starts receiving revenue from day one, mainly due to royalty and the combination of a cost recovery limit with a minimum share of profit petroleum. - Early revenues are larger under the EA1 PSA than under the R-factor options, largely due to higher levels of royalty in early years and a lower cost recovery limit. - As project profitability improves, government share from R-factor alternatives more than offsets the early-year revenue shortfall. - Price sensitivity of total government revenue: - EA1 PSA generates slightly more revenue under low price conditions (below "$75/bbl"). - In medium to high price scenarios ("$75/bbl and above"), the new model PSA and option 1 generate more revenue than existing PSAs. - Progressivity and government take: - Average Effective Tax Rate (AETR) undiscounted: the three regimes yield relatively similar AETRs between "81 and 85 percent". - Using a discount rate of "10 percent": - Model PSA AETR "93 percent". - EA1 PSA AETR "91 percent". - R-factor option 1 AETR "89 at percent" (as presented). - The new model PSA and option 1 are more progressive than the EA1 PSA; option 1 exhibits a higher degree of progressivity. - Progressivity allows higher government share when projects are highly profitable but can reduce government share on the downside unless minimum government revenue is ensured whenever production is occurring. ### Breakeven price, METR, and marginal projects - Breakeven price definition: minimum price required to meet the investor's minimum rate of return (assumed "12.5 percent" in real terms). - The new model PSA places a higher burden on marginal projects than option 1 and EA1 PSA due to: - Higher royalty rates that apply to total production once triggered. - A lower cost recovery limit. - Higher state participation. - Marginal Effective Tax Rate (METR): - The new model PSA has the highest METR of the three regimes, consistent with breakeven price analysis. ### Sensitivity analysis on fiscal parameters (Model PSA, July 2015, at "$80/bbl") - Parameters tested: Min royalty rate (↓ to "6%" - ↑to "10%"), Cost recovery limit (↓ to "55%" - ↑to "75%"), Min. gov. share (↓ to "40%" - ↑to "60%"), Max. gov. share (↓ to "65%" - ↑to "85%"), CIT rate (↓ to "25%" - ↑to "35%"), State participation (↓ to "15%" - ↑to "25%"). - Key quantified sensitivities: - A "10 percentage point" increase in the maximum government share increases government revenue by "$170 million". - A "10 percent point" decrease in the maximum government share reduces revenue by "$199 million". - A "10 percent point" increase in the maximum government share would reduce the post-tax IRR of the project from "13.1" to "12.4 percent". - A "10 percent point" decrease in the maximum government share would increase post-tax IRR to "13.7 percent". - Changes to minimum and maximum government share of profit petroleum have the greatest effect on both government revenue and post-tax IRR. ### Cost recovery rules for financing costs and uplift alternative - Proposal: eliminate recovery of interest expense and replace it with a one-time uplift for development costs; FAD June 2015 recommended "15 percent". - Uplift granted in the year of investment at "15 percent" of capital costs incurred. - Under uplift, the licensee recovers development costs plus a "15 percent" amount; uplift is limited to the first five years of development expenditure. - Advantages of uplift vs recovery of interest: - If modest, likely less expensive for the government and brings forward triggering of higher R-factor tiers. - Avoids detailed provisions limiting recoverability of interest. - Does not discriminate between sources of finance. - Viewed by companies as an incentive to development investment; accelerates or increases cost recovery and reduces licensee risk. - Simple simulation results (assumptions and comparisons): - Example assumption: total development costs of "$500 million". - Five D/E ratio rules tested for interest expense recovery, ranging from D/E of "1:1" to "3:1". - Under a fixed "7.5 percent" annual interest rate in nominal terms, the "15 percent" uplift amount is always lower than the interest expense across all five D/E scenarios. - Assuming a strict D/E ratio of "1:1", the interest rate would have to be "5 percent" or lower for the uplift amount to exceed recoverable interest expense. - Note: in all loan scenarios the repayment period is assumed to be "10 years". ### Midstream infrastructure: pricing of crude oil (pricing and pipeline tariff design) - Pricing principle: - Pricing of crude oil is market-determined; PSAs provide for an arm’s length standard. - FAD Report June 2015 assumption: crude sold to refinery at export parity pricing, derived from netback from an arm’s length price at a seaport of export to the inlet flange of export pipeline facilities in Uganda. - Pipeline tariff considerations: - The tariff modeled is an annual reservation charge for pipeline capacity. - Capital cost and rate of return yield an annuity payment over "21 years" that repays capital with the specified return. - Operating costs divided approximately "25 percent fixed" and "75 percent variable" to reflect throughput variation. - Calculation implies an average tariff per barrel over life of fields and backloads tariff payments; alternatives that mirror throughput more closely would increase throughput risk for pipeline owners. - Pricing interactions between upstream and refinery: - Crude price into refinery will be a negotiated outcome using the adjusted pipeline tariff as a guide; typically an indicative deduction per period from the FOB price at the seaport. - Possible contractual arrangements: average price for each month could be the average export price netted back for the average tariff that month; provisional price with adjustment the following month is possible. - Refinery may offer a higher price to upstream producers if it needs supply and exports through pipeline are an attractive option for producers; example contractual delivery obligation "30,000 bpd" could be priced via an arm’s length pricing formula. - Analysis in FAD (June 2015) suggested a strongly positive pretax result for the refinery on the assumptions used; a refinery purchasing crude on contract at a higher price than pipeline export could expand and provide higher returns to upstream producers. *IMF Country Report content unit (excerpt) — cr17368* ### 56. Two core models for commercial structure of a pipeline offering transportation ### Two core models for commercial structure of a pipeline offering transportation services ### Pipeline commercial models: Model 1 and Model 2 - Model 1: - Pipeline owners bear no throughput risk and earn the minimum return on capital. - Compatible with ownership in proportions identical to those for the upstream. - Compatible with initial reservation of capacity entirely for crude oil from the Uganda Oil Project. - Pipeline provides only transportation services; the owners do not engage in trading. - Model 2: - Pipeline company is freestanding, negotiating tariffs and contracts with shippers but taking no throughput risk once a contract is made. - In mature form, may also make spot transactions. - Requires owners to take risk on obtaining throughput contracts initially (negligible if constructed with a prior contract commitment from the Uganda Oil Project). - Owners do not engage in trading of crude oil themselves. - Access implications: - Model 1 will restrict access to the “foundation shippers” who provided initial capital. - Model 2 may have foundation shippers, but provides access to other users on negotiated terms. ### Likely commercial evolution, ownership, and third-party use - Most likely path: start with Model 1 and evolve toward Model 2. - Expected arrangements: - Pipeline owned by an independent entity; pipeline costs and revenues excluded from the PSAs (not under the upstream fiscal regime). - Interests in the pipeline company probably mirror those in the upstream venture, though the State might or might not participate. - Ownership could remain the same in the transit country; e.g., Kenya and Uganda could maintain state participation over the pipeline as a whole. - Variations in ownership shares are possible: - Upstream producers may seek effective control of pipeline operations without identical share proportions. - Pipeline construction firm or a third party might hold equity. - Government share might be higher than its share in the upstream. - Upstream producers’ pipeline shares could differ from upstream shares. - Pipeline owners’ incentives: - Because oil pipeline throughput will fall as fields mature, owners have an interest in encouraging new sources and third-party use. - Access for oil from Kenyan fields might require an initial commitment to larger capacity. ### Capacity choice, tariffs, and cost of capital - Initial capacity choice trade-off: - Whether to size initial capacity above the Uganda Oil Project plateau so additional sources can use spare capacity later, or to assume initial plateau capacity becomes spare over time. - Decision affects initial commercial configuration and access arrangements for partial pipeline length (e.g., Kenyan crude). - Tariff implications by model: - Under Model 1: exact match of capital cost recovery with oil throughput is not necessary. - Under Model 2: exact match is essential; pipeline revenue will fluctuate with capacity use. - Cost of capital and tariff setting where investors take throughput risk: - FAD (June 2015) used a post-tax real return of 7.5 percent (discounted cash flow return on total capital over project life). - This 7.5 percent post-tax real return approximates a pre-tax real return of 10 percent and a nominal pretax return of 12.5 percent. - The equivalent nominal pre-tax figure from an industry rates of return data base is 9.3 percent. ### Refinery pricing, capacity, and profitability - Role of imported products: - Imported products are the marginal supply in the Uganda market; cost of importing determines domestic product prices. - Refinery assumptions (FAD, June 2015): - Refinery purchases crude at export parity from the upstream and sells products into domestic market or neighboring countries at market prices. - Initial refinery capacity: 30,000 bpd, increasing to 60,000 bpd after approximately seven years. - Uganda’s current consumption: about 28,000 bpd, but expected to exceed 30,000 bpd when refinery comes on stream. - Market implications: - With 30,000 bpd initial capacity, the refinery will be able to sell into the domestic market at prices up to the price of imported products (the marginal supply). - The refinery may undercut imported product prices to increase market share but will not initially meet full domestic demand. - When capacity increases to 60,000 bpd, the refinery may be able to fully supply the domestic market up to that level for a few years. - Cost drivers and design: - Profitability depends on refining costs and transporting products by pipeline to Kampala (product pipeline to Kampala is integral to the refinery project). - Refinery will be designed for Uganda crude’s high wax content; design trade-off between a more costly refinery producing more light/middle distillates and a less costly refinery producing fewer light/middle distillates. - Designing specifically for Uganda crude reduces costs versus a more flexible refinery, but small refinery size raises costs per barrel relative to larger refineries processing several 100,000 bpd. - Crack spread and price inputs: - Crack spread = difference between cost of crude delivered to refinery and domestic market price of petroleum products from a barrel. - Crude delivered at approximation of export parity price (Brent minus quality differential and transportation to port) unless refinery offers a higher price for crude. - Current import price of gasoline and diesel refined in Mombasa and shipped by pipeline to Eldoret, then by truck to Kampala: - Petrol: UGX 2,300 per liter (excluding excise). - Diesel: UGX 2,000 per liter (excluding excise). - Planned continuation of product pipeline from Eldoret to Kampala will reduce price of imported products and improve the crack spread. - At current crude delivery price and gasoline/diesel prices, the refinery is projected to be highly profitable. - Note: assumption used that there are 159 liters in one barrel of oil; mission used official midpoint monthly USD:UGX exchange rate published by the Bank of Uganda. - Historical variation: - The implied margin between Brent and domestic fuels is not constant over time (examples: 2009 and 2011 saw significantly lower implied margins than recent years). - Future variation in the implied margin will directly affect refinery profitability. ### Tax and regulatory options for the refinery; excise and VAT - Profitability implications: - Refinery likely to be highly profitable because of (1) projected crack spread and (2) guaranteed supply of initial 30,000 bpd rising to 60,000 bpd. - Tax policy options: - Excess (windfall) profit tax: - Tax earnings in excess of a “normal” rate of return at a higher rate. - Preferred option because it would not tax away all “excess profits,” preserving incentives to minimize costs and maximize revenues. - Regulate rate of return and adjust price paid for crude oil: - Would shift profits to upstream producers. - Less preferable than excess profit tax. - General taxation of products: - Petroleum products produced will be subject to excise duty and VAT. - If VAT is fixed at the standard rate, excise should normally be fixed to cover negative externalities (local and global pollution). - Excise could be set higher or lower depending on government preference for additional revenue or for encouraging lower cost fuel supplies. - Reducing excise to encourage consumption amounts to a subsidy, diverting revenue and increasing environmental costs. - Subsidies to fuel consumption tend to benefit richer segments of society rather than the poor and should be avoided. ### Mining fiscal issues: downstream processing (beneficiation) and royalties - Draft mining policy: - Draft Green Paper on Minerals and Mining Policy (dated July 9, 2015) was not yet a functioning policy document at time of mission. - Draft needs further work; should describe the problem, analyze options (including impact), and justify proposed policy. - Draft presupposes major decisions including reassignment of functions within government (e.g., Department of Mines in MEMD given primary responsibility for legal and fiscal framework and administration/monitoring). - Draft does not take account of recent tax law changes or the 2015 Public Expenditure Management Act. - Export rules and subsidies for domestic processing: - Governments use instruments like export prohibitions, export taxes, differential royalties, and reduced corporate tax rates to encourage downstream processing. - Cautions: - Such restrictive measures can be costly in lost government revenue, export earnings and FDI if net returns are higher when ores/concentrates are exported to efficient processors abroad. - Long-term reliance on downstream processing increases dependence on exhaustible mineral production rather than diversification. - Source country may sacrifice premium export prices and resulting revenue for infrastructure, social capital and diversification. - Examples and effects: - Zambia’s 10 percent export tax on ores/concentrates led to stockpiling (100,000 tons of copper concentrate at Kansanshi in 2013, potential royalty payments of about US$10 million) and delay or suspension of projects; levy suspended from October 2013. - Differential royalty rates can be poorly targeted (e.g., South Africa sliding-scale: top rate 5 percent for processed minerals and 7 percent for unprocessed). - Madagascar’s lower corporate tax rate for processing produced windfall benefit for Ambatovy; differential tax rates create profit-shifting incentives. - Alternatives and recommendations for promoting processing: - Prefer direct tax incentives linked to actual investment in processing facilities only if absolutely necessary (e.g., initial allowance or tax credit equal to a percentage of cost of depreciable assets). - Prefer direct government support for economically efficient processing (direct spending or infrastructure support) because it is more transparent than tax subsidies. - Recommendations (explicit): - Refrain from export prohibitions and export taxes on unprocessed minerals. - If a subsidy is wanted for domestic processing it should take the form of direct government spending or an initial tax allowance directly related to the amount of investment in the processing facility. - Royalties—gaps and uncertainties: - Gaps relate to royalty base, royalty rates, and allocation of royalty revenue to local governments, landowners and lawful occupiers. - Consider shifting administration of the royalty to URA. - Royalty base specifics and issues: - Reliance on the term “gross value” is not sufficient to create a practicable base for assessment. - Under the Mining Act (s 98), royalties apply to minerals based on “gross value” at prevailing market price. - Mining Act Regulations (s 72) provide for reference prices (latest price on the London Metal Exchange or any other Metal Exchange or market known to the Commissioner). - In absence of proof to the contrary: - gold deemed to be 95 percent fine; - tin ore deemed to contain 75 percent tin; - valuable contents of other metals, ore or minerals as Commissioner may determine. - If a mineral is exported to a refinery, value shall be the gross sum realized without any reduction or abatement for transport, marketing, insurance, or other charges (net smelter return). *Italic line: Source: cr17368 - 56. Two core models for commercial structure of a pipeline offering transportation* ### 83. The gross sales value offers a more workable royalty base. The gross sales value ### cr17368 - 83. The gross sales value offers a more workable royalty base. ### Royalty base and valuation - The gross sales value is proposed as the royalty base: the sales value before any selling, transport, and insurance costs attributable to the minerals sold. - For mineral products that are smelted or refined, the “gross sales value” would be the net smelter return. - Reference prices would be used in determining the value of precious metal or non-precious mineral, as under current law. - If minerals are exported before being sold, a provisional royalty would be imposed on the mineral. - If the first saleable mineral product is sold to a related party, the government should have the power to adjust prices where the price of a mineral product has been understated. - The simplification to gross sales value would be similar to current practice but with easier-to-understand rules for determining the royalty base. - Advance pricing agreements (APAs) are recommended to minimize disputes in related-party sales and where international prices are lacking: - APAs would set out, in considerable detail, how the sales value would be determined for a period of years. - APAs are now used by many countries and have proved useful in reducing transfer-pricing disputes. ### Royalty rates (statutory structure and levels) - Under a reasonable reading of the Mining Act, all royalty rates are ad valorem, as the base is “gross value”. - The Mining Regulations prescribe both ad valorem and specific royalty rates. - The rates are: - (i) 5 percent for precious metals, - (ii) 10 percent for precious stones, - (iii) 5 percent for base metals and ores, - (iv) specific rates for various listed minerals including coal, vermiculite, limestone, marble and granite. - The rate for phosphate rock is UGX 10,000 per ton. - The 5 percent ad valorem rate for base metals and ores applies unless a specific rate is given for the mineral or the mineral is included under (i) or (ii). - The specific rate of UGX 10,000 per ton is about 2.5 percent of the current benchmark price (US$115 per ton) for phosphate rock 32-33 percent P2O5 FOB Morocco. - An Amendment to the Mining Act could specify which minerals are subject to ad valorem and which to specific rates: - High value minerals, mainly metals, should be subject to ad valorem rates. - Construction minerals, such as clay and limestone, and marble should be subject to specific rates. - Specific rates should be reviewed every year or two and adjusted in line with any change in the value of the Uganda shilling and mineral prices. - If specific royalty rates are given fiscal stability in a mining agreement, the rates should be set in US dollars or be adjusted by formula each year. - Uganda’s ad valorem royalty rate for base metals is on the high side by African standards, but a reduction is not recommended. ### Advance Pricing Agreements (Box 2) - Designed to resolve actual and potential pricing disputes in a principled, cooperative manner. - Binds the taxpayer and the country usually for a period of up to five years. - Could be unilateral (between the taxpayer and the government of Uganda) or multilateral (between the taxpayer, the government of Uganda and the governments of one or more foreign countries). - The government and the taxpayer will need to employ experts to develop an APA. ### Royalty assessment and administration - Administration is currently shared between the Department of Mines and URA: - The Commissioner of Mines assesses the royalty. - Under the Mining Act Regulations, the royalty is payable within 30 days from the assessment date. - Payment is made to URA. - Best international practice: mineral companies self-assess the royalty and make monthly or quarterly payments; the administering agency undertakes risk-based audits and may make default assessments where a royalty return is not submitted. - Under Uganda’s current rules, each company must be assessed before royalty is payable. - Strong case for shifting royalty administration to URA: - Reduces duplication and overlap with income tax administration. - Once administered by URA, the rules and powers in the Tax Procedures Act of 2014 would apply, including registration, tax identification numbers, record keeping, tax returns, self-assessment, objection and appeals, tax collection, and interest on late payments. - Uganda’s Mining Act and Regulations have only limited enforcement powers; s 104 of the Mining Act includes a penalty for failure to pay royalty on the due date requiring the Commissioner to prohibit the company from disposing any mineral obtained, which is considered too harsh and likely seldom imposed. - Under s 71(3) of the Regulations, the Commissioner may issue an export permit only where the royalty due on the minerals has been paid or secured. - Other countries (Liberia, Sierra Leone, Zimbabwe) have shifted royalty administration to the tax authority; Liberia has shifted authority to impose royalty out of mining legislation to the Liberian Revenue Code. - Amendments to the Tax Procedure Act required to shift administration to URA: - Tax would be defined to include mineral royalties and the Mining Act of 2003 would be added to the list of tax laws in Schedule 2. - Tax return would be defined to include a royalty return. - The Mining Act of 2003 would be amended to state that URA administers the royalty. - The power of the Commissioner to issue an export permit only where the royalty has been paid or secured would be retained in the Mineral Regulations. - Department of Mines would continue to cooperate with URA on valuation and other mining-specific issues after the shift. ### Sharing royalty revenue - Royalty payments are shared among: - central government (80 percent), - district council (10 percent), - urban or sub county council (7 percent), - owners or lawful occupiers of the land subject to mineral rights (3 percent). - Central government is responsible for allotment of royalty revenues to local governments and owners and lawful occupiers. - If a mine is located in multiple district councils or urban/sub county councils, allocation of respective shares could be according to the population and land area. - Allocation to owners or lawful occupiers is problematical where customary communal title exists; ownership can be separated from lawful occupancy or ownership of developments by lawful occupiers. - If the mining company is the owner of the land subject to the mineral right, the 3 percent reserved for owners should be allocated back to the mine company; mine companies may attempt to short circuit payment by reducing royalty payment by 3 percent. - Payments to local governments should be paid promptly even if allocation to owners or local occupiers is being determined. - Processing facilities located off the surface location of the mineral right may justify sharing royalty revenue with local governments and landowners where the processing facilities are located. ### Recommendations (explicit list from the source) - Define the royalty base for ad valorem royalties as the gross sales value of the mineral product. - Allow the government to enter into Advance Pricing Agreements when there are related party sales. - Amend the Mining Act to provide for specific royalty rates for construction minerals. - Ensure that specific rates are reviewed every year or two to keep them in line with the value of the Uganda shilling and changes in the market value of minerals subject to specific rates. - Require mineral companies to self-assess the royalty and make monthly or quarterly payments. - Shift the administration of the royalty to URA. - Study the allocation of royalty revenue to local governments and owners and lawful occupiers of the land and consider amending the Mining Act or issuing a statutory order. ### General taxation issues affecting extractive industries (overview of key points) - Laws to amend the Income Tax Act (“ITA”) and the Value Added Tax Act (“VAT Act”) as they apply to extractive industries were passed with effect from July 1, 2015. - The amending legislation implements many tax law recommendations made in FAD (June 2015), including introduction of the deemed paid VAT system and reverting to the pre-2010 regime for computation of chargeable income of licensees based on normal ITA rules. - VAT: The VAT Amendment Act 2015 implements the deemed paid VAT regime: - Applies to taxable supplies made by a contractor to a licensee for use by the licensee solely and exclusively for mining or petroleum operations. - “Licensee” = person granted a mining right or has entered into a petroleum agreement with the Government. - “Contractor” = person supplying goods or services (other than as employee) to a licensee in respect of mining or petroleum operations. - “Petroleum operations” extends to authorized operations under a petroleum agreement for the construction of a pipeline or refinery; includes export, transportation and storage of petroleum. - The deemed paid VAT regime applies only when the taxable supply is for use by the licensee solely and exclusively in mining and petroleum operations; there is no scope for apportionment where supplies are partly for mining/petroleum operations and partly for other uses. - Implementation requires a Practice Note under s 44 of the Tax Procedures Code Act, designed in consultation with petroleum licensees: - The Practice Note could include guidance on when taxable supplies are for use solely and exclusively in mining or petroleum operations. - Outstanding FAD recommendations (June 2015): - Recommend that imports by a contractor for direct and exclusive use in mining or petroleum operations be exempt from duty. - Recommend broadening the scope of the exemption for mining licensees to align with petroleum licensees; exemptions should also be extended to VAT. - Implementation requires amendments to the East African Community Customs Management Act and agreement at the EAC level; as an interim measure, including contractor imports as exempt imports for VAT was considered but would create inconsistency if duty still applied. - It is understood the EAC Secretariat has notified member States that imports by contractors for supply to licensees are exempt imports, but legislative authority is required. - Input tax credit for reverse charged VAT on imported services was to be reintroduced for licensees and contractors; VAT Amendment Act 2015 has provided for this but uncertainties remain as to the meaning of imported services for this purpose. - Excise and VAT on petroleum products: - Uganda currently levies excise duty on gasoline, diesel, and illuminating kerosene while exempting these products from VAT. - FAD June 2015 recommended repealing the VAT exemption for petroleum products and adjusting excise duty rates in anticipation of a refinery. - Authorities decided to delay implementation of this reform until closer to commencement of refinery operations to determine appropriate excise adjustments and manage public environment changes. ### Income tax issues: petroleum expenditure definitions - Enacted definitions of “petroleum exploration expenditure” and “petroleum development expenditure” differ significantly from those recommended and differ from equivalent mining definitions; enacted definitions were based on “MEMD advice”. - MEMD advice assumed income tax treatment would continue to be aligned with cost recovery treatment; the legislative intent was instead to revert to pre-2010 approach under which normal ITA rules apply for allowable deductions. - Uncertainties arise as to the scope of the definitions; reverting to definitions earlier suggested by the mission team would align petroleum definitions with mining equivalents. - In the interim, some uncertainties could be addressed through a Practice Note. - “Petroleum exploration expenditure” is defined to mean expenditure incurred by a licensee in undertaking petroleum exploration operations authorized under a petroleum exploration right. - Uncertainty exists whether the following are petroleum exploration expenditure (intended to be expensed under s 89GB of the ITA): - (i) the cost of acquiring an interest in a petroleum exploration license; - (ii) the cost of acquiring petroleum exploration information; - (iii) the cost of acquiring a depreciable asset for use in petroleum exploration operations; - (iv) social infrastructure expenditure compulsorily incurred in relation to petroleum exploration operations. *Source: cr17368 - excerpt from PDF.* ### 106. The cost of acquiring a petroleum exploration right or an interest in such right ### 106. The cost of acquiring a petroleum exploration right or an interest in such right ### Treatment of acquisition costs and related expenditure - The cost of acquiring a petroleum exploration right or an interest in such right would probably not be petroleum exploration expenditure as defined. - The right is an intangible asset; the cost would be deducted under s 31 of the ITA over the useful life of the right (life of the petroleum exploration operations). - Importantly, the cost would not be expensed as would be the case for exploration expenditure. - The cost of acquiring petroleum exploration information: - May be petroleum exploration expenditure if it is authorized expenditure under the petroleum exploration license. - MEMD advice indicates the cost of acquiring information would not be authorized expenditure. - On that basis, treatment would be the same as for acquiring a petroleum exploration license (information treated as an intangible asset). - There may be scope for such expenditure to be treated as petroleum exploration expenditure under a Practice Note. - The cost of acquiring a depreciable asset for petroleum exploration operations: - Would seem to be petroleum exploration expenditure. - The terms of s 89GB(1) support this characterization (as does the MEMD advice). - Therefore, the cost is expensed under s 89GB. - This could be clarified in a Practice Note. - Social infrastructure expenditure: - Will be petroleum exploration expenditure only if authorized under the petroleum exploration license. - MEMD advice states such expenditure would not be authorized expenditure. - Deductibility will be determined under general principles: whether incurred in deriving business income (deductible) or an application of business income after it has been derived (non-deductible). ### Petroleum development expenditure (parallel issues) - Definition: “Petroleum development expenditure” means expenditure incurred by a licensee in undertaking petroleum (development) operations authorized under a petroleum production right. - Characterization issues for: - Cost of acquiring an interest in a petroleum production license, - Cost of acquiring petroleum development information, - Social infrastructure expenditure, - Are the same as for the equivalent exploration expenditure discussed above. - Cost of acquiring a depreciable asset for petroleum development operations: - Would seem to be petroleum development expenditure (position taken in MEMD advice). - Consequence: cost of such assets is depreciated on a straight-line basis under s 89GC(2) of the ITA over the lesser of: - (i) the expected life of the petroleum development operations; or - (ii) six years. - This was not intended; intended treatment was that normal depreciation rules apply to depreciable assets used in petroleum development operations. - Classification scope issue: - Classification as petroleum development expenditure is not limited to capital expenditure. - Technically, operating expenditure incurred during petroleum development operations is amortized under s 89GC, rather than deducted outright under s 22. - This will need technical correction; in the meantime, could be clarified in a Practice Note. ### Computation of Gross Income - Amending legislation reverts to the pre-2010 tax regime under which the chargeable income of a licensee is based on the normal income and deduction rules under the ITA as modified by Part IXA. - Income Tax Amendment Act 2015 inserted a definition of “gross income of a licensee” in s 89A(1). - The definition includes “cost oil, licensee’s share of profit oil and any credits earned by the licensee from petroleum operations”. - The definition was inserted as a result of MEMD advice. - Consequence and issues: - The gross income of a licensee for a year of assessment includes the total sales revenue derived by the licensee on an accrual basis for the year. - While this will largely align with the value of the licensee’s cost and profit oil, the gross income amount under the normal income tax rules may not be exactly the same as the value of the licensee’s production share. - The term “gross income of a licensee” is not actually used anywhere in Part IXA so the definition has no operation. - Petroleum licensees have noted the confusion; the computation of gross income should be clarified in a Practice Note. - Ideally, the definition of “gross income of a licensee” should be deleted. ### Ring Fencing - Ring fencing under s 89GA of the ITA is done by reference to the “contract area” of a licensee. - “Contract area” is defined in s 89A to mean the exploration or development area subject to a petroleum agreement. - “Exploration area” and “petroleum area” are not separately defined in s 89A and thus under s 89A(2) they have their respective meaning under the PEDPA. - Consequently: - “Exploration area” means the area constituted by a block or blocks subject to a petroleum exploration license. - “Development area” means the area constituted by a block or blocks, which, following a commercial discovery, has been delineated for production according to the terms of a petroleum agreement. - The basic definition of “contract area” under the ITA aligns with PEDPA. - For ring fencing when the contract area is a development area: - s 89GA(5) treats the development area as including the relevant exploration area provided the development area is wholly within the exploration area. - This ensures losses arising from petroleum exploration operations can be deducted against income derived from petroleum development operations. - Model PSA comparison: - Article 12.2 of the model PSA applies ring fencing by reference to the contract area as defined in the model PSA. - “Contract area” in Article 1.1.16 means: - (i) initially, the area described in Annex A of the model PSA; and - (ii) thereafter, the whole or any part of such area that, at any particular time, remains subject to a petroleum exploration license or petroleum production license. - While similar to the ITA definition, it may not be exactly the same, particularly for petroleum development operations. - Important to ensure the model PSA definition aligns with the ITA and PEDPA. - Terminal losses: - No provision under s 89C or s 89GA for transfer of a loss for a license/contract area at the end of mining/petroleum operations to another area. - Such losses are terminal losses; MOFPED confirmed this as adopted policy. - Impact reduced by allowance of deductions for contributions to a rehabilitation fund (mining) or decommissioning fund (petroleum). ### Farm-outs - S 89GD(2)(a) of the ITA provides that the value of work commitments undertaken by a farmee, in relation to the part of the mining or petroleum right retained by the farmor under a farm-out agreement, is subject to tax to the farmor. - FAD June 2015 proposed excluding the value of work commitments from both gross income and the consideration for the transfer of the interest to encourage exploration or development. - The decision to tax the value of work commitments was based on MEMD advice. - FAD (June 2015) recommended that the value of work commitments is not taxed as an incentive (para 169). ### Changes in Underlying Ownership of Licensees - S 89GF(1) obliges a mining or petroleum licensee to immediately notify the Commissioner-General of any change in the underlying ownership of the licensee. - The Bill originally included a threshold: reporting obligation applies only when there is a 10 percent or greater change in underlying ownership. - The 10 percent threshold was apparently deleted in Parliament. - Result: reporting obligation applies to any change, no matter how small. - In practice, this will be next to impossible to enforce, particularly for publicly listed companies. - Suggestion: address by Practice Note providing an administrative de minimis exception to the reporting obligation. ### Non-resident Contractor Tax - S 89GG of the ITA imposes non-resident contractor tax at the rate of 10 percent of the gross amount of a service fee paid by a licensee to a non-resident contractor. - The tax is a final tax and therefore is not included in the gross income of the contractor. - Intended application: - Apply only to service fees paid to a non-resident contractor who does not have a branch in Uganda. - If a non-resident contractor has a branch in Uganda, the service fee should be included in the computation of the chargeable income of the branch and taxed on an ordinary assessment basis. - Parliamentary amendment: - S 89GG was amended to apply to service fees paid to non-resident contractors irrespective of whether the contractor has a branch in Uganda. - Given the change was made in Parliament, it may be difficult to revisit. - One possibility: retain withholding tax for service fees paid to all contractors but amend s 89GG so that the tax is non-final (and creditable) for a non-resident contractor who derives the fee through a Ugandan branch. - Policy and base erosion: - Petroleum companies continue to argue against the tax despite reduction in withholding rate from 15 to 10 percent. - Absence of withholding tax on service fees paid by a licensee to a non-resident contractor will lead to tax base erosion in Uganda (FAD June 2015). - Base erosion arises because the licensee deducts the fee at the corporate rate of 30 percent but without any corresponding Ugandan tax imposed on the fee. - The 10 percent withholding tax limits the impact of such base erosion. - Footnote: Base erosion under the income tax arising from cross-border services is part of the OECD Base Erosion Profit Shifting (“BEPS”) project. A likely outcome of the BEPS project is greater recognition of source country taxing rights in relation to cross-border services in line with the approach taken in s 89GG. - Priority of application: - Non-resident contractor tax (s 89GG) applies in priority to the taxes imposed under s 83 and s 85 of the ITA by the principle that the specific prevails over the general. - This should be clarified in a Practice Note. ### Source Rules and Transitional Provisions - Source rules: - S 79 of the ITA source rules should be modernized, including in relation to an indirect transfer of immovable property (defined in s 78(aa) to include an interest in a mining or petroleum right). (FAD June 2015.) - Source rules were drafted over 20 years ago and have not kept pace with modern cross-border trade and investment. - Modernizing source rules is on the agenda but revisions postponed until finalization of some cases before the courts concerning application of existing rules. - MOFPED concerned changes now may prejudice outcomes of those cases. - Transitional rules: - Necessary to prepare transitional rules in relation to the new regime for taxation of mining and petroleum operations. - Section 164(2)(a) of the ITA provides that transitional rules can be promulgated by regulations. - These should be prepared in consultation with the petroleum licensees. ### Technical Corrections to Part IXA (listed) - (1) Definition of “immovable property” in s 79(aa) includes “petroleum information”. S 79(c) cross-references “petroleum information” in s 89A. Based on MEMD advice, the definition of “petroleum information” was deleted from s 89A. A definition of “petroleum information” will need to be re-included in s 89A or included in s 79. - (2) Definition of “licensee” in s 89A(1) – delete “Petroleum (Refining, Conversion, Transmission and Midstream) Act and substitute “Petroleum (Exploration, Development and Production) Act”. - (3) The definition of “mining exploration right” in s 89A(1) is repeated. Conflict between two definitions as the first version does not include a reference to a prospecting license. The first version should be deleted. - (4) Delete definition of “participation dividend” in s 89A(1) as the term is not used in Part IXA. - (5) Definition of “petroleum development right” in s 89A(1) – delete “exploration operations” and substitute “petroleum development operations”. - (6) Delete s 89G(4) and (5) as they reproduce s 89GA(4) and (5). - (7) Delete s 89GC(6), which defines “commercial production” in relation to petroleum operations. There is also a definition of “commercial production” in s 89A that is in different terms to the s 89GC definition. The definition in s 89A aligns with the model PSA and, therefore the definition in s 89GC(6) should be deleted. The definition in section 89A should be renamed “commencement of commercial production”. - (8) Delete “or licensee” in s 89GG(1). - (9) Change the cross-reference in s 89GG(4) to “subsection (3)”. - (10) Delete s 89GG(7). What is now s 89GG(8) was intended to replace s 89GG(7). - (11) The amendment made to s 89MA(b) needs to be corrected. The paragraph should read: - “(b) taxes payable to the Government not included in Government mining or petroleum revenues, in this Part referred to as “other taxes”.” - (12) In s 89QA(3), the cross-reference to “subsection (2)” needs to be changed to “subsection (1)”. ### Recommendations (extracted) - Prepare a Practice Note on the operation of the deemed paid VAT regime. - Pursue at EAC level the following amendments to the East African Community Customs Management Act: - (i) the exemption of imports by a contractor for direct and exclusive use in mining or petroleum operations; and - (ii) the alignment of the exemption for imports by a mining licensee with that applicable to imports by a petroleum licensee. - Plan to delete the exempt supply treatment under the VAT for petroleum products and adjust the excise duty rates accordingly. - Revert to the original proposed definitions of “petroleum exploration expenditure” and “petroleum development expenditure”. If the current definitions are retained, amend the definition of “petroleum development expenditure” to cover only capital expenditure. Prepare a Practice Note on the scope of the definitions. - Delete the definition of “gross income of a licensee”. Prepare a Practice Note on the determination of the gross income of a petroleum licensee. - Ensure that the definition of “contract area” and the ring-fencing rule in the model PSA align with the ITA and PEDPA. - Amend s 89GD(2)(a) so that the value of work commitments is not taxable. - Prepare a Practice Note to give effect to a de minimis exception to the reporting obligation in s 89F(1) for small transactions, particularly on a stock exchange. - Provide that the non-resident contractor tax is non-final and creditable for service fees paid to a Ugandan branch of a non-resident contractor. Clarify in a Practice Note that s 89GG has priority over ss 83 and 85. - Modernize the source rules, including for indirect transfers of immovable property. - Make transitional provisions by regulations. - Make the technical corrections to Part IXA listed at paragraph 32. ### B. VAT and Imported Services — General principles - Taxation of imported services is more complicated than taxation of imported goods because services do not “pass through” any border control; VAT on imported services cannot be collected at the border. - Two situations distinguished: - (i) services provided in a “business-to-business” (B2B) transaction when the recipient is a registered person; and - (ii) services provided in a “business-to-consumer” (B2C) transaction. ### B2B Transactions — reverse charge rationale and situations - The most effective way to collect VAT on the service is by reversing the normal operation of the VAT and charging VAT on the registered person receiving the service (“reverse charging”). - Two situations: - (1) If the registered person receiving the imported services uses those services solely to make taxable supplies: - The reverse charged VAT and the resulting input tax credit offset each other so there is no net VAT payable by the registered person in respect to the imported services. - The VAT on the imported services is then effectively captured in the VAT imposed on the subsequent taxable supplies for which the imported services were an input. - Because the net VAT position is unchanged, some countries do not apply the reverse charge rule in this case. - (2) If the registered person uses the services wholly or partly for purposes other than making taxable supplies: - The reverse charge rule produces a net VAT liability as no offsetting input tax credit is allowed to the extent that the imported services are not used to make taxable supplies. - Main example: imported services used in making exempt supplies (such as supplies of financial services). - Importance: - A reverse charge rule should apply in (2) to avoid incentive for registered persons who also make exempt supplies to acquire services from outside the jurisdiction, which would otherwise exclude the value added by the services from the domestic VAT base and put local suppliers at a competitive disadvantage. _Italic: Source: cr17368 - 106. The cost of acquiring a petroleum exploration right or an interest in such right (PDF chapter)._ ### 129. Taxation of imported services in a B2C transaction is more problematic. It is ### cr17368 - 129. Taxation of imported services in a B2C transaction is more problematic. It is ### Taxation of imported services (B2C) — core issues - It is generally not feasible to require the recipient of the services (usually a final consumer) to report and pay VAT on imported services received under a reverse charge rule. - VAT law therefore typically uses place of supply rules that locate certain foreign-provided services to unregistered persons as supplied in the country if they are consumed in the country. - Provided the other conditions are satisfied, the provision of the services is a taxable supply. - If the taxable value of taxable supplies made by a foreign-service provider exceeds the registration threshold, the foreign-service provider is registered for VAT. - If the foreign-service provider does not have a physical presence in the country, then they are required to appoint an agent in the country who is responsible for meeting their VAT obligations. ### Internal transfer of services (avoidance risk) - The reverse charge rule can be avoided through acquisition of services from another part of the same entity located abroad (e.g., headquarters or a foreign branch). - Example: a Ugandan branch of a foreign bank may acquire services related to making exempt supplies in Uganda from its foreign headquarters rather than from a supplier in Uganda, thereby avoiding VAT on the acquisition and disadvantaging Ugandan providers. - This is avoided by extending the reverse charge rule to the internal acquisition of services from another part of the same entity located outside the country. ### Taxation of imported services under the VAT Act — provisions and gaps - S 4(c) of the VAT Act imposes VAT on the “supply of imported services (other than an exempt service) by any person”. - S 5(c) provides that the recipient of a supply of imported services is the person obliged to pay the VAT due in respect of the supply; s 5(c) therefore creates a reverse charge rule in respect of a supply of imported services. - Prior to the VAT Amendment Act 2015, no input tax credit was allowed for the reverse charged VAT paid by a registered person. - The VAT Amendment Act 2015 amended s 28(1)(b) to allow a contractor or licensee an input tax credit for the VAT paid on imported services. - There are no further provisions relating to supplies of imported services in the VAT Act. - Technically, under the VAT Act, every supply of imported services is charged to VAT and the recipient, whether they are a registered person or a final consumer, is liable to pay the VAT on the supply. - Regulation 13(1) obliges a person receiving imported services to account for the VAT payable in respect of the services. - Regulation 13(2), which provides a taxable value rule for imported services, refers only to a registered person. ### Place of supply for foreign-provided services to unregistered persons and resulting uncertainty - Certain foreign-provided services made to unregistered persons are treated as supplied in Uganda (s 16(2)), consistent with the usual place of supply rule for B2C foreign-provided services. - The combined operation of the reverse charge for imported services and s 16(2) has created uncertainty in the application of the VAT to foreign-provided services to unregistered persons; both rules can appear to apply with no clear priority rule. - It is unusual to apply the reverse charge rule to unregistered persons. - Previously, during the exploration phase, a mining or petroleum licensee could not voluntarily apply for registration as the licensee was not making supplies of goods or services during that phase; such licensees may have been the main class of unregistered person liable for the reverse charged VAT on imported supplies. - As a result of amendments made by the VAT Amendment Act 2015, mining and petroleum licensees are now permitted to apply for registration during the exploration phase. - It would be better practice to confine the reverse charge rule to registered persons, consistent with regulation 13(3), which applies the reverse charge rule to internal transfers of services only by registered persons. ### Definition gap and proposed definitional conditions - There is no definition of “imported services” in the VAT Act; this has been a source of confusion in applying the reverse charge rule. - On the basis that the reverse charge rule applies only to registered persons, imported services could be defined as a supply of services that satisfies all the following conditions: - (1) An unregistered person makes the supply of the services to a registered person. - (2) The supply is not made in Uganda under the place of supply rules for services. - (3) The supply would have been a taxable supply if a registered person had made the supply in Uganda. ### Place of business and agent requirement - S 16(2) specifies a place of supply rule for foreign-provided services to unregistered persons. - If the person providing the services exceeds the registration threshold, then the person must register for VAT. - If the person does not have a place of business in Uganda, the person should be required to appoint an agent in Uganda responsible for meeting their VAT obligations. ### Recommendations (VAT / imported services) - The reverse charge rule in s 4(c) and s 5(c) of the VAT Act should apply only to registered persons. Amend regulation 13 accordingly. - Include a definition of “imported services” in s 1 of the VAT Act. - Require a non-resident person who is a registered person but who does not have a place of business in Uganda to have an agent in Uganda for the purposes of the VAT Act. ### Double Tax Agreements (DTAs) — background and revenue risk - DTAs can have a significant negative impact on the level of government revenue from the resources sector. - A DTA is an international agreement between two or more countries (“Contracting States”). - The preamble to a DTA will often state that the purpose of the DTA is to provide relief from double taxation; today most countries provide relief unilaterally, so the main role of a DTA is allocation of taxing rights between Contracting States. - A DTA will usually involve a Contracting State accepting reduced taxing rights as source country. - Over the last few years, there has been a moratorium in practice on the negotiation of new DTAs. - Uganda has nine DTAs currently in force. - An East African Community tax treaty has been negotiated but to date ratified by only two countries (Rwanda and Kenya). ### DTA policy guidance — objectives and required elements - The Government should develop a DTA policy to ensure future DTAs operate in the best interests of Uganda. - The DTA policy should include: - (i) clear guidelines for choosing DTA partners; - (ii) a baseline for negotiations (what is negotiable and what is not); - (iii) the development of a Uganda draft model DTA that can be shared with a potential DTA partner to strengthen Uganda’s negotiation position; - (iv) the preparation of a DTA impact statement once the DTA has been negotiated but before it is signed. - It is vital that finance and tax officials trained and highly skilled in the application of DTAs are involved in Uganda’s DTA negotiations so that the process is fully integrated with national tax policy. - Clear guidelines should be developed for choosing DTA partners, taking into account the current level of trade and investment from the potential DTA partner into Uganda. - Uganda’s DTA policy should prohibit negotiations with any country whose rules or practices pose a revenue risk to Uganda. - Alternate mechanisms to DTAs include exchange of information, reciprocal assistance in recovery of tax and service of process via a TIEA or the Multinational Convention for Multinational Administrative Assistance; these provide administrative benefits without giving up taxing rights. ### DTA impact statement — recommended contents - A DTA impact statement should set out: - (1) The reasons for choosing the other country as a DTA partner, including a statement of the current volume of trade and investment into Uganda from the country. - (2) An assessment of how the DTA will increase the level of trade and investment into Uganda. - (3) A statement of any other benefits to Uganda that may be obtained under the DTA. - (4) A quantification of the potential revenue loss for Uganda under the DTA. ### Model DTA selection and development - It is good practice for Uganda to develop its own model DTA. - Two main model DTAs to use as a base: the OECD Model DTA and the UN Model DTA. - Given that the UN Model DTA provides for greater protection of source country taxing rights, it should form the basis of Uganda’s model DTA, although some elements from the OECD Model can be incorporated. - The Ugandan model DTA should take account of regional efforts to develop a common approach to DTA negotiation. - Uganda is developing its own model DTA; a draft (“Draft Model DTA”) was supplied but it does not clearly follow the UN or OECD Model DTAs nor adequately take into account Uganda’s domestic law and existing DTAs. - It would be preferable for Uganda to develop a new model DTA that clearly and independently sets out Uganda’s negotiating position on all the articles of a DTA. - The model DTA should take account of any new developments in tax treaty policy resulting from finalization of the BEPS Actions by the OECD, particularly in relation to the definition of “permanent establishment”. ### Business income — domestic law and branch / PE alignment - A non-resident person is liable for income tax only on Ugandan-source business income (s 17(2)(b) of the ITA). - Income derived by a non-resident person in carrying on a business through a branch in Uganda is Ugandan-source income (s 79(a)(ii) of the ITA (inserted by the 2015 Amendment Act)). - The definition of “branch” in s 78(a) of the ITA is broadly similar to the DTA concept of permanent establishment (“PE”) and includes: - (1) Standard branch – a place where a person carries on business. - (2) Agency branch – a place where a person is carrying business through an agent, other than an agent of independent status acting in the ordinary course of business. - (3) Substantial equipment branch – a place where a person has, is using, or is installing substantial equipment or machinery for a period of more than 90 days. - (4) Construction branch – includes supervisory activities and with a 90-day threshold before the branch is established. - (5) Services PE – based on a 90-day period (inserted by the 2015 Amendment Act). - The taxable income of a branch of a non-resident is calculated in the same way as the taxable income of a resident person, namely gross income minus allowable deductions. - Regulation 4 of the Transfer Pricing Regulations provides for the separate entity approach in the attribution of income and expenses to a Ugandan branch. - The taxable income of the branch is taxed on an assessment basis. ### Uganda draft model DTA — PE and attribution observations relevant to the resources sector - Article 7 of the Uganda draft model DTA provides for the taxation of business profits: business profits derived by a resident of a Contracting State are taxable only in that State unless the resident has a PE in the other Contracting State; if there is a PE, that State can tax only so much of the business profits that are attributable to the PE. - Article 5 of the Uganda draft model DTA defines “permanent establishment” for the purposes of the DTA and is relevant to Articles 7, 11, 12, 13 and 14 of the draft model. - The definition of PE in the Uganda draft model DTA largely follows the OECD and UN Model DTAs. - Observations and recommendations regarding Article 5 of the Uganda draft model DTA: - (1) The definition should include the substantial equipment and services PE inclusions to align with the definition of “branch” in s 78 of the ITA. The inclusion of a services PE rule is particularly relevant to extractive industries because of the high use of contractors in the sector. It is important that the services PE rule is based on a period of presence in Uganda (rather than a fixed place of business) as a non-resident contractor may have employees moving around the country between different mining or petroleum sites. - (2) Article 5(2)(h) includes “a mine, an oil or gas well, a quarry or any other place of extraction of natural resources” and Article 5(2)(i) includes “an installation or structure used for the exploitation of natural resources”. The references to “extraction” and “exploitation” are unlikely to include exploration. While it is expected that there would be a fixed place of business through which exploration activities are conducted and, therefore, a PE within Article 5(1), it is preferable that Article 5(2)(h) and (i) expressly refer also to exploration to avoid any doubt. - (3) The time limit for a construction PE is one month. This is very short by international standards (the equivalent in the OECD Model DTA is 12 months and the UN Model DTA is 6 months). It is also short in comparison to the definition of “branch” in s 78(a) of the ITA (90 days). The time limit for a construction PE in the Uganda draft model DTA should be aligned with the 90-day period in the s 78 definition of branch. - (4) While Article 5(4) excludes delivery as a preparatory or auxiliary activity (consistent with the UN Model DTA), delivery by an agent is not included in the agency PE rule in Article 5(5). ### Profit attribution methods and recommendation - Article 7(2) and (3) of the Uganda draft model DTA provide for the attribution of profits to a PE and are based on the pre-2010 OECD Model DTA. - Two methods of attribution have been identified: - (i) the separate entity approach — internal transfers of goods and services are valued based on separate entity accounting (the two parts of the entity are treated as separate entities dealing with each other at arm’s length). - (ii) the single entity approach — the overall profit of the entity is computed and then attributed through sourcing rules to the different parts of the entity. - The OECD has officially adopted the separate entity approach; this is reflected in the new Article 7(2) in the OECD Model DTA. - Not all OECD countries have accepted the separate entity approach; some continue to apply the single entity approach. - In light of this, retaining Article 7(2) and (3) from the pre-2010 OECD Model DTA is the preferred position for the Uganda draft model DTA. *Italic line: IMF country report content (cr17368) excerpt.* ### 154. The Transfer Pricing Regulations provide for the separate entity approach in the ### The Transfer Pricing Regulations provide for the separate entity approach in the ### Transfer pricing and branch attribution - The Transfer Pricing Regulations provide for the separate entity approach in the attribution of income and deductions to a Ugandan branch. - Recommendation: Regulation 4 should be amended to apply the separate entity approach only when the other country also applies the same approach. This will give Uganda flexibility to use the single entity approach when used by the other country and thereby limit any mismatches in the attribution of income and expenses between the two countries. - Specific amendment referenced: amend regulation 4 of the Transfer Pricing Regulations so that separate entity approach does not have to be followed when the other country does not use it. ### Services income and domestic tax law - The provision of independent services is a form of business activity; taxation of services income derived by a non-resident depends on whether the non-resident has a branch in Uganda. - Extractives sector: a non-resident contractor is liable for non-resident contractor tax at the rate of 10 percent on the gross amount of fees derived by the contractor in providing services to a licensee (s 89GG). - Other sectors: the rate of tax on service fees is 15 percent (s 85). - Draft DTA (Article 13) notes: - Article 13 of the Uganda draft model DTA provides for the taxation of administration and management fees. - Definition in Article 13(3) includes payment in consideration for any service of an administrative, technical or managerial nature; recommendation to include technical fees in the heading of the Article. - Suggestion to explicitly include professional and consultancy services in the definition to align with existing DTAs that provide for taxation of technical fees. - Article 13(3) is time limited: applies only when relevant service is performed in Uganda on a regular basis or for a period of three months. - Conflict: time limitation creates inconsistency with the source rule in Article 13(5), which provides that an administrative and management fee arises in Uganda when a resident or a Ugandan PE of a non-resident pays the fee, and it confuses Article 13 with the services PE rule based on presence period. - Recommendation: delete the words “but only to the extent that the services are performed on a regular basis or for period of three months” from Article 13(3) to allow the sourcing rule in Article 13(5) to apply more effectively. ### Investment income — domestic law and DTA alignment - Domestic law (s 83 of the ITA): - Ugandan-source dividends, interest and royalties derived by a non-resident are liable to tax at the rate of 15 percent of the gross amount. - A dividend paid by a resident company is treated as Ugandan-source income. - Interest and royalties are Ugandan-source income if paid by: (i) a resident person; or (ii) a Ugandan branch of a non-resident person. - S 83 does not apply when the dividend, interest or royalty is attributable to a branch in Uganda of the non-resident and such income is taxed on a normal assessment basis through the operation of s 17. - Royalties definition under s 2(mmm) of the ITA includes: 1. Amounts for the use of industrial and intellectual property rights (such as patents, trademarks and copyrights). 2. Know-how payments. 3. Amounts for the use of any tangible movable property (including equipment lease rentals). ### Uganda draft model DTA — Dividends - Article 10 provides for a differential rate structure for dividends: - One rate for participation dividends based on a 25 percent ownership threshold and another rate for all other dividends. - The Uganda draft model DTA specifies the same rate for both, but a lower rate (such as 5 percent) is presumably intended for participation dividends. - This approach is consistent with the OECD and UN Model DTAs. ### Uganda draft model DTA — Interest - Article 11 provides for taxation of interest: - Rate limit under the Model on interest arising in Uganda and derived by a resident of the other Contracting State is 15 percent. - Interest arises in Uganda if it is paid by a resident or a Ugandan permanent establishment of a non-resident. - Article 11 does not apply when the interest derived by a non-resident is effectively connected with a PE of the non-resident in Uganda. - Alignment and recommendation: - Taxation under Article 11 aligns with domestic law for non-residents. - Noted that most of Uganda’s existing DTAs use a 10 percent rate; the 15 percent rate appears in two older DTAs (UK and Italy). - Recommendation: adopt the 10 percent rate in the Model given its presence in Uganda’s recent DTAs and the expectation that negotiating partners will rely on existing DTAs. ### Uganda draft model DTA — Royalties - Article 12 parallels Article 11: - Rate limit under the Model on royalties arising in Uganda and derived by a resident of the other Contracting State is 15 percent. - Royalties arise in Uganda if paid by a resident or a Ugandan PE of a non-resident. - Article 12 does not apply when the royalty derived by a non-resident is effectively connected with a PE of the non-resident in Uganda. - Alignment and recommendation: - Taxation under Article 12 largely aligns with domestic law. - Uganda’s existing DTAs typically reduce the rate on royalties to 10 percent; the only 15 percent example is the UK DTA, which is old. - Recommendation: adopt the 10 percent rate in the Uganda draft model DTA. - Extractives sector issue: - Article 12(3) of the draft model does not include equipment lease payments in the definition of “royalties.” - Consequence: equipment lease rentals would be treated as business profits and taxable in Uganda only when attributable to a PE of the non-resident lessor. - Given high equipment leasing in the resources sector, recommendation that domestic law characterization of equipment lease payments as royalties be carried through to Uganda’s DTAs. ### Gains on indirect transfers of interest in immovable property - Domestic law: - Uganda asserts jurisdiction to tax gains on indirect transfers of immovable property. - S 79(g): a gain derived on disposal of a share in a company the property of which consists, directly or indirectly, principally of an interest or interests in immovable property in Uganda is Ugandan-source income, but only when the share is a business asset. - Definition of “immovable property” in s 78(aa) includes mining and petroleum rights; when immovable property represents such rights, shares are treated as a business asset under s 89GE(3). - Recommendation: S 79(g) should be extended to apply to the disposal of an interest in any entity and not be limited to the disposal of shares in a company to prevent avoidance via interposition of unit trusts or limited partnerships. - MOFPED will revisit source rules once current cases involving s 79 have been finalized. - Uganda draft model DTA: - Article 14 provides for taxation of capital gains; Article 14(4) provides for taxation of indirect transfers of immovable property and is copied from the UN Model DTA. - Concern: Article 14(4)(a) may exclude taxation of gains on indirect transfers of mining or petroleum rights on the basis that the right is used in the business activities of the company holding the right. - Recommendation: adopt Article 13(4) of the OECD Model DTA with two modifications: 1. Extend to cover gains on alienation of interests in non-corporate entities (e.g., partnerships and trusts) in anticipation of a future change in s 79(g). 2. Make clear that “immovable property” in Article 14(4) has the same meaning as in Article 6 (Article 6(2) defines immovable property to have the meaning under the law of the Contracting State where the immovable property is located, which for Uganda will pick up s 78(aa)). ### Treaty shopping and limitation on benefits (LOB) - Recommendation: Uganda’s future DTAs should include protection against treaty shopping. - Article 23 of the Uganda draft model DTA provides for a limitation of benefits (“LOB”). - Article 23 is complex and appears to be copied from developed country DTAs (such as the United States). - Suggestion: adopt a simpler LOB rule based on s 88(5) of the ITA with an additional exception when there is substantial economic activity in the other Contracting State. - A LOB Article should apply generally for the purposes of the DTA and not be limited to specific Articles. - Concern: separate LOB rules limited to dividend, interest and royalties Articles (as in a recent DTA between Malawi and the Netherlands) leave open treaty shopping for other Articles, such as indirect transfers of immovable property. ### Consolidated recommendations - Develop a DTA policy with clear guidelines for choosing DTA partners. - Prepare a DTA impact statement, after negotiations are completed and before signing the DTA, setting out the advantages and disadvantages of the DTA, and including the estimated revenue impact. - Develop a model DTA using the UN Model DTA as the starting point; the model should take account of domestic law and Uganda’s existing DTAs. - Uganda’s future DTAs should include a LOB Article to limit the revenue loss through treaty shopping. - Amend regulation 4 of the Transfer Pricing Regulations so that separate entity approach does not have to be followed when the other country does not use it. *Source: Extract from the provided IMF content unit.* --- _Source: https://www.imf.org/-/media/files/publications/cr/2017/cr17368.pdf_