Nigeria

Chart II-1Nigeria: Poor BoP Position Nigeria: Poor BoP Position Nigeria: Poor BoP Position The Nigerian naira is facing a considerable risk of major devaluation stemming from strains on its balance of payments (BoP). That said, the risk of a sovereign default is very low over the next 12-18 months. Nigeria suffers from large external imbalances in an environment of low oil prices and dreadful FDI inflows. The nation’s current account deficit is wide at 5% of GDP and its foreign currency (FX) reserves are low (Chart II-1). Importantly, oil prices have hit a critical technical resistance – their 200-day moving average – and have relapsed (Chart II-2). Global oil demand weakness stemming from some renewed tightening of lockdown measures will result in lower crude prices. We at BCA’s Emerging Markets Strategy team expect Brent prices to be in a trading range of $35-$45 over the next 12 months.2 An Optimal Macro Adjustment A low oil price environment creates a dillemma for Nigeria’s policymakers given their limited FX reserves. They can either (i) draw down FX reserves to support the exchange rate, or (ii) preserve FX reserves and allow a major currency devaluation. So far, Nigerian authorities have avoided these options by resorting to strict capital controls and limiting imports. Yet, capital controls are derailing much needed foreign capital inflows in general and FDIs in particular. These capital account controls are also restricting the ability of domestic firms to access US dollars to service their foreign debt payments, undermining the confidence of foreign investors and multilateral creditors. Allowing currency depreciation is the least-worst macro policy solution. Propping up the currency by administrative restrictions amid low oil prices will foster various imbalances impeding the nation’s structural adjustments and its potential growth rate. Remarkably, Nigeria’s current account excluding oil has been structurally wide, a sign of weak domestic productivity and a non-competitive currency (Chart II-3). Chart II-2A Relapse In Oil Prices Is Likely A Relapse In Oil Prices Is Likely A Relapse In Oil Prices Is Likely Chart II-3Nigeria Has A Current Account Deficit Ex-Oil Nigeria Has A Current Account Deficit Ex-Oil Nigeria Has A Current Account Deficit Ex-Oil   Bottom Line: Capital controls and import restrictions are impeding FDIs and productivity growth in this most populous African country (Chart II-4). While a steep devaluation will spur inflation in the short run, a cheapened currency and the abolishment of import and capital controls will help to attract foreign capital that the nation desperately needs. Running Out Of FX Reserves Critically, the Central Bank of Nigeria (CBN) is running out of FX reserves: Nigeria’s foreign exchange (FX) reserves are very low at $35.6 billion. That compares with foreign debt obligations (FDOs) of $28 billion in the next 12 months and foreign funding requirements of $47 billion in the next 12 months (Chart II-5). Chart II-4Nigeria: Weak FDI = Low Productivity Nigeria: Weak FDI = Low Productivity Nigeria: Weak FDI = Low Productivity Chart II-5Nigeria: Large Foreign Funding Required In Next 12 Months Nigeria: Large Foreign Funding Required In Next 12 Months Nigeria: Large Foreign Funding Required In Next 12 Months   FDOs measure the sum of short-term claims, interest payments and amortization over the next 12 months. Meanwhile, foreign funding requirements is the sum of the current account deficit and FDOs. FDI inflows were a mere $2.5 billion in 2019 compared with a $20 billion current account deficit. Along with foreign portfolio inflows, FDI inflows will remain depressed so long as capital controls persist. The FX reserves-to-broad money ratio currently stands at 0.4. A ratio below one indicates foreign currency reserves do not entirely cover currency in circulation and local currency deposits.  How much should the exchange rate be devalued versus the US dollar for this ratio to reach 1? For the broad money supply coverage ratio to be equal to 1, the currency must depreciate by 56% against the US dollar. Bottom Line: CBN’s FX reserves are insufficient to maintain the current de-facto crawling currency peg in the long run. No Worries About Sovereign Credit For Now Chart II-6Nigeria: Low Public Debt Burden Nigeria: Low Public Debt Burden Nigeria: Low Public Debt Burden While the Nigerian government is reeling from lower oil prices, the likelihood of a sovereign default is presently low. Public debt is low, currently standing at 22.5% of GDP. Notably, foreign debt represents nearly 30% of overall public debt or 6.5% of GDP. Moreover, only 40% of external debt (3% of GDP) is owned to private foreign investors (Chart II-6). The rest is split between bilateral and multilateral creditors. Foreign bilateral and multilateral debt is easier to renegotiate. While overall (domestic and foreign) debt servicing costs have risen to 55% of government revenues, foreign currency debt servicing costs only represent 2% of overall revenues. Provided foreign public debt servicing is minimal, even a large currency depreciation will not make public debt dynamics unsustainable. Crucially, a substantial currency devaluation will ameliorate the fiscal position. A large share (about 55%) of fiscal revenues come from oil, i.e., they are in US dollars. Conversely, expenditures are in local currency terms. As a result, currency depreciation will boost revenues but not expenditures, narrowing the budget deficit. According to the newly revised budget for the 2020 fiscal year, fiscal spending will grow by 8.7% in nominal terms but most likely contract in real terms (Chart II-7). Overall, the fiscal balance will widen to 3.65% of GDP in 2020 according to government projections. In nutshell, policymakers refrained from large fiscal stimulus amid lockdown measures earlier this year. This is bad for the economy but positive for the trajectory of public debt. Finally, public debt dynamics are presently not worrisome with nominal GDP growth above local interest rates (Chart II-8). Chart II-7Nigeria Will Run Tight Fiscal Policy Nigeria Will Run Tight Fiscal Policy Nigeria Will Run Tight Fiscal Policy Chart II-8Nigeria: No Public Debt Sustainability Problem Nigeria: No Public Debt Sustainability Problem Nigeria: No Public Debt Sustainability Problem   Bottom Line: The risk of a sovereign default is low in the coming years. The low starting points in both public debt levels and debt servicing costs will allow the government to boost fiscal spending to support the economy. Investment Implications Overall, a currency devaluation will help restore balance of payment dynamics without causing a major stress for sovereign credit. A 25-30% devaluation over the next 12 months will be the least-worst policy choice. Currency forwards are currently pricing a 20% depreciation in the naira versus the US dollar in next 12 months (Chart II-9). Yet, the average black market exchange rate, currently at around 470, implies almost a 25% discount from the current official rate. Sovereign credit spreads are presently tight (Chart II-10). Investors should consider buying Nigerian sovereign credit only after a substantial devaluation takes place. Chart II-9Naira Forwards Discount Will Widen With Lower Oil Prices Naira Forwards Discount Will Widen With Lower Oil Prices Naira Forwards Discount Will Widen With Lower Oil Prices Chart II-10Nigeria: Buy Sovereign Credit After Devaluation Nigeria: Buy Sovereign Credit After Devaluation Nigeria: Buy Sovereign Credit After Devaluation   Finally, equity investors should continue avoiding the local bourse. Due to capital controls, the latter is uninvestable for now. Andrija Vesic Associate Editor andrijav@bcaresearch.com Arthur Budaghyan Chief Emerging Markets Strategist arthurb@bcaresearch.com Footnotes 2 This differs from BCA Commodity and Energy Strategy service’s expectation that Brent prices will average $65 in 2021.

Kenya: An Incomplete Adjustment The Kenyan shilling will depreciate by 15-20% in the next 12 months. The downward pressure on the currency stems from the country’s sizeable current account deficit. In addition, Kenya needs lower local interest rates and a weaker exchange rate to boost nominal growth and stabilize public debt dynamics.  Kenya has gone through an extensive macro adjustment since 2015 when the current account deficit was 10% of GDP and the primary fiscal deficit was 8% of GDP. Since then the current account deficit has narrowed to 6% of GDP as the private sector deleveraged and fiscal policy tightened substantially over the past 3-years (Chart I-1, top panel). Remarkably, the primary fiscal deficit has narrowed to a mere 0.4% of GDP as of June 2020 (Chart I-1, bottom panel). Yet, the macro adjustment is incomplete with a lingering current account deficit and public debt on an unsustainable path. Further, economic growth is extremely weak (Chart I-2). Crucially, core inflation is at 2% - an all-time low, suggesting that low inflation/deflationary pressures is the main problem in Kenya (Chart I-3). Chart I-1Kenya: The Twin Deficits Remains Large Kenya: The Twin Deficits Remains Large Kenya: The Twin Deficits Remains Large Chart I-2Kenya: Tame Domestic Growth Kenya: Tame Domestic Growth Kenya: Tame Domestic Growth   In this context, the optimal policy choice for Kenya is to reduce local interest rates, while allowing the currency to depreciate. This will reduce the interest burden on public debt, boost both economic activity (real growth) and inflation as well as make exports more competitive. Balance Of Payments Strains Persist Kenya’s balance of payments will weigh on the currency in the next 6-9 months. While improving, its exports will remain tame over the next 6-12 months. The volume of tea, horticulture and coffee exports, which account for about 50% of total Kenyan exports, has rebounded. Yet, their prices have failed to rebound meaningfully. Meanwhile, substantial fiscal tightening – an 11% drop in government non-interest nominal expenditures – has led to a collapse in imports (Chart I-4). If and when fiscal policy is relaxed, it will boost imports weighing on the trade balance. Chart I-3Kenya Suffers From Low Inflation Kenya Suffers From Low Inflation Kenya Suffers From Low Inflation Chart I-4Tight Fiscal Policy = Weak Domestic Demand Tight Fiscal Policy = Weak Domestic Demand Tight Fiscal Policy = Weak Domestic Demand Chart I-5Kenya Is Losing Market Share In Export Markets Kenya Is Losing Market Share In Export Markets Kenya Is Losing Market Share In Export Markets The biggest headwind to the balance of payments has been the drastic fall in both tourism revenues and remittances. Combined, they represent around $4 billion (4.2% of GDP). It is unlikely that international travel will resume in the next six months. Remittances will also remain subdued in the coming months as unemployment rates remain elevated worldwide. Kenya has been losing its export market share in neighboring countries such as Uganda and Tanzania (Chart I-5). Hence, this nation needs to improve its competitiveness via tolerating a cheaper currency and undertaking structural reforms to bolster productivity growth. FDI inflows have been subdued. In the near term, FDI inflows will be discouraged by very weak domestic demand. Critically, the outlook for Chinese FDI inflows into the country remains uncertain due to the debacle with previous China-financed projects in Kenya. In particular, Kenyan courts declared the construction contract awarded to the China Road and Bridge Corporation for the Nairobi-Mombasa railway illegal.1 This impasse between Kenyan courts and Chinese companies could for now dissuade financing and investment from China. In the medium term, international organizations such as the IMF and World Bank could step in to fill in for Chinese investments. As recent financing by the World Bank and IMF of $1.74 billion (1.9% of GDP) to Kenya suggest, the US might be enticed alongside European nations to step in to fill the vacuum left by the withdrawal of China’s financial backing. However, this might take some time and there will be shortage in foreign financing in the coming months. Chart I-6Kenya Lacks Foreign Exchange Reserves Kenya Lacks Foreign Exchange Reserves Kenya Lacks Foreign Exchange Reserves Finally, another risk is the considerable amount of foreign debt obligations (FDOs) and the lack of foreign currency reserves at the central bank to meet these obligations (Chart I-6). Kenya’s FDOs in the next 12 months are about $6 billion, while the central bank has only $8.8 billion of foreign exchange reserves. In this case, FDOs measure the sum of short-term claims, interest payments and amortization over the next 12 months. Bottom Line: The exchange rate will continue facing depreciation pressures. The optimal policy for the central bank will be to allow the currency to weaken meaningfully and to reduce interest rates rather than use high interest rates or deplete its foreign exchange reserves to defend the exchange rate. Public Debt Sustainability Despite substantial fiscal tightening, Kenya’s public debt trajectory remains worrisome. Two prerequisites for capping the rise in the public debt-to-GDP ratio are (1) running continuous primary fiscal surpluses and (2) for local government borrowing costs to be below nominal GDP growth. Neither of these two are presently satisfied in Kenya. Crucially, interest payments are taking up a quarter of overall government revenues (Chart I-7). This necessitates considerably lower domestic interest rates to reduce this ratio. In brief, public debt sustainability hinges on the central bank reducing local borrowing costs, which will both boost nominal growth/government revenues and lower interest costs of public debt. The government of President Uhuru Kenyatta announced a new budget in June (for the period of July 1, 2020 to June 30, 2021) with a projected primary deficit of -3% and -1.8% of GDP, for 2020/21 and 2021/22 respectively (Chart I-1, bottom panel on page 1). Meanwhile, the new budget’s nominal annual growth projections for 2020/21 and 2021/22 are 10.6% and 11.5%, respectively. Chart I-8presents both the government’s as well as our projections for public debt dynamics until the end of 2022 based on assumptions for nominal GDP, government expenditures and revenues for the next two fiscal years. The public debt-to-GDP ratio will reach 75% of GDP in our scenario and 66% in the government’s scenario. Chart I-7Public Debt Servicing Costs Are High Public Debt Servicing Costs Are High Public Debt Servicing Costs Are High Chart I-8Kenya: Public Debt Will Continue To Rise Kenya: Public Debt Will Continue To Rise Kenya: Public Debt Will Continue To Rise   The key difference between the two projections are expectations for nominal GDP and government revenue growth. If fiscal and monetary policy remain tight, nominal output growth will disappoint. Notably, broad money supply growth is tame (Chart I-9). Sluggish nominal growth risks derailing government revenue projections. Notably, recent comments by finance minister Ukur Yatani suggests that revenues have already begun underperforming government expectations in the first two months of the new fiscal year. On the whole, public debt will rise by more than what the government expects over the next two years as borrowing costs remain above nominal GDP growth (Chart I-10). Chart I-9Kenya: Weak Policy Response To Low Growth Kenya: Weak Policy Response To Low Growth Kenya: Weak Policy Response To Low Growth Chart I-10Kenya: Local Rates Are Above Nominal Growth Kenya: Local Rates Are Above Nominal Growth Kenya: Local Rates Are Above Nominal Growth   Faced with the prospect of rising public debt dynamics over the next two years, the economically less painful response for policymakers is for the central bank to lower interest rates and to instruct domestic commercial banks to buy government domestic debt. This will boost nominal GDP growth and push local interest rates below nominal GDP growth. There is scope for the central bank to cut interest rates and allow the currency to depreciate without feeding into runaway inflation. Notably, core consumer price inflation excluding fuel and food items is presently at an all-time low, running below the lower bound of the central bank’s inflation target (Chart I-2 on page 2). Higher inflation also feeds into higher nominal growth, which is good for public debt dynamics. A weaker currency will augment the cost of servicing foreign debt. The latter accounts for 52% of public debt and 32% of GDP. However, a large share (65%) of foreign debt is owed to bilateral and multilateral creditors. This debt can be renegotiated/restructured, which would in turn benefit private creditors. Bottom Line: To stabilize public debt dynamics, local interest rates should be lowered considerably. This will increase nominal GDP and government revenue growth as well as lower debt servicing costs. In this scenario, currency will depreciate a lot. Investment Implications Faced with very depressed economic growth, very low inflation, unsustainable public debt dynamics and a wide current account deficit, the optimal policy for Kenya is to ease monetary policy dramatically and tolerate material currency depreciation. So long as the central bank does not reduce interest rates, the economy will continue to underwhelm, public debt dynamics will be worrisome and share prices will stumble (Chart I-11). Critically, as the public debt-to-GDP ratio continues rising, sovereign credit will underperform (Chart I-12). Chart I-11Weak Domestic Dynamics = Lower Share Prices Weak Domestic Dynamics = Lower Share Prices Weak Domestic Dynamics = Lower Share Prices Chart I-12Rising Public Debt Burden = Sovereign Credit Underperformance Rising Public Debt Burden = Sovereign Credit Underperformance Rising Public Debt Burden = Sovereign Credit Underperformance   If and when the central bank brings interest rates down substantially, nominal growth will improve and share prices will fare well. Lower domestic borrowing costs and higher nominal GDP growth will help stabilize public debt dynamics. In such a scenario, EM sovereign credit portfolios should overweight the nation’s US dollar bonds. The Kenyan shilling also is set to depreciate materially. If the government embarks on this macro adjustment early, currency depreciation could be gradual. If the government delays this macro adjustment and resists currency weakness by tolerating high interest rates, the exchange rate depreciation could be delayed, but will be abrupt and disorderly. Andrija Vesic Associate Editor andrijav@bcaresearch.com Arthur Budaghyan Chief Emerging Markets Strategist arthurb@bcaresearch.com Nigeria: Devaluation As The Least-Worst Policy Choice Chart II-1Nigeria: Poor BoP Position Nigeria: Poor BoP Position Nigeria: Poor BoP Position The Nigerian naira is facing a considerable risk of major devaluation stemming from strains on its balance of payments (BoP). That said, the risk of a sovereign default is very low over the next 12-18 months. Nigeria suffers from large external imbalances in an environment of low oil prices and dreadful FDI inflows. The nation’s current account deficit is wide at 5% of GDP and its foreign currency (FX) reserves are low (Chart II-1). Importantly, oil prices have hit a critical technical resistance – their 200-day moving average – and have relapsed (Chart II-2). Global oil demand weakness stemming from some renewed tightening of lockdown measures will result in lower crude prices. We at BCA’s Emerging Markets Strategy team expect Brent prices to be in a trading range of $35-$45 over the next 12 months.2 An Optimal Macro Adjustment A low oil price environment creates a dillemma for Nigeria’s policymakers given their limited FX reserves. They can either (i) draw down FX reserves to support the exchange rate, or (ii) preserve FX reserves and allow a major currency devaluation. So far, Nigerian authorities have avoided these options by resorting to strict capital controls and limiting imports. Yet, capital controls are derailing much needed foreign capital inflows in general and FDIs in particular. These capital account controls are also restricting the ability of domestic firms to access US dollars to service their foreign debt payments, undermining the confidence of foreign investors and multilateral creditors. Allowing currency depreciation is the least-worst macro policy solution. Propping up the currency by administrative restrictions amid low oil prices will foster various imbalances impeding the nation’s structural adjustments and its potential growth rate. Remarkably, Nigeria’s current account excluding oil has been structurally wide, a sign of weak domestic productivity and a non-competitive currency (Chart II-3). Chart II-2A Relapse In Oil Prices Is Likely A Relapse In Oil Prices Is Likely A Relapse In Oil Prices Is Likely Chart II-3Nigeria Has A Current Account Deficit Ex-Oil Nigeria Has A Current Account Deficit Ex-Oil Nigeria Has A Current Account Deficit Ex-Oil   Bottom Line: Capital controls and import restrictions are impeding FDIs and productivity growth in this most populous African country (Chart II-4). While a steep devaluation will spur inflation in the short run, a cheapened currency and the abolishment of import and capital controls will help to attract foreign capital that the nation desperately needs. Running Out Of FX Reserves Critically, the Central Bank of Nigeria (CBN) is running out of FX reserves: Nigeria’s foreign exchange (FX) reserves are very low at $35.6 billion. That compares with foreign debt obligations (FDOs) of $28 billion in the next 12 months and foreign funding requirements of $47 billion in the next 12 months (Chart II-5). Chart II-4Nigeria: Weak FDI = Low Productivity Nigeria: Weak FDI = Low Productivity Nigeria: Weak FDI = Low Productivity Chart II-5Nigeria: Large Foreign Funding Required In Next 12 Months Nigeria: Large Foreign Funding Required In Next 12 Months Nigeria: Large Foreign Funding Required In Next 12 Months   FDOs measure the sum of short-term claims, interest payments and amortization over the next 12 months. Meanwhile, foreign funding requirements is the sum of the current account deficit and FDOs. FDI inflows were a mere $2.5 billion in 2019 compared with a $20 billion current account deficit. Along with foreign portfolio inflows, FDI inflows will remain depressed so long as capital controls persist. The FX reserves-to-broad money ratio currently stands at 0.4. A ratio below one indicates foreign currency reserves do not entirely cover currency in circulation and local currency deposits.  How much should the exchange rate be devalued versus the US dollar for this ratio to reach 1? For the broad money supply coverage ratio to be equal to 1, the currency must depreciate by 56% against the US dollar. Bottom Line: CBN’s FX reserves are insufficient to maintain the current de-facto crawling currency peg in the long run. No Worries About Sovereign Credit For Now Chart II-6Nigeria: Low Public Debt Burden Nigeria: Low Public Debt Burden Nigeria: Low Public Debt Burden While the Nigerian government is reeling from lower oil prices, the likelihood of a sovereign default is presently low. Public debt is low, currently standing at 22.5% of GDP. Notably, foreign debt represents nearly 30% of overall public debt or 6.5% of GDP. Moreover, only 40% of external debt (3% of GDP) is owned to private foreign investors (Chart II-6). The rest is split between bilateral and multilateral creditors. Foreign bilateral and multilateral debt is easier to renegotiate. While overall (domestic and foreign) debt servicing costs have risen to 55% of government revenues, foreign currency debt servicing costs only represent 2% of overall revenues. Provided foreign public debt servicing is minimal, even a large currency depreciation will not make public debt dynamics unsustainable. Crucially, a substantial currency devaluation will ameliorate the fiscal position. A large share (about 55%) of fiscal revenues come from oil, i.e., they are in US dollars. Conversely, expenditures are in local currency terms. As a result, currency depreciation will boost revenues but not expenditures, narrowing the budget deficit. According to the newly revised budget for the 2020 fiscal year, fiscal spending will grow by 8.7% in nominal terms but most likely contract in real terms (Chart II-7). Overall, the fiscal balance will widen to 3.65% of GDP in 2020 according to government projections. In nutshell, policymakers refrained from large fiscal stimulus amid lockdown measures earlier this year. This is bad for the economy but positive for the trajectory of public debt. Finally, public debt dynamics are presently not worrisome with nominal GDP growth above local interest rates (Chart II-8). Chart II-7Nigeria Will Run Tight Fiscal Policy Nigeria Will Run Tight Fiscal Policy Nigeria Will Run Tight Fiscal Policy Chart II-8Nigeria: No Public Debt Sustainability Problem Nigeria: No Public Debt Sustainability Problem Nigeria: No Public Debt Sustainability Problem   Bottom Line: The risk of a sovereign default is low in the coming years. The low starting points in both public debt levels and debt servicing costs will allow the government to boost fiscal spending to support the economy. Investment Implications Overall, a currency devaluation will help restore balance of payment dynamics without causing a major stress for sovereign credit. A 25-30% devaluation over the next 12 months will be the least-worst policy choice. Currency forwards are currently pricing a 20% depreciation in the naira versus the US dollar in next 12 months (Chart II-9). Yet, the average black market exchange rate, currently at around 470, implies almost a 25% discount from the current official rate. Sovereign credit spreads are presently tight (Chart II-10). Investors should consider buying Nigerian sovereign credit only after a substantial devaluation takes place. Chart II-9Naira Forwards Discount Will Widen With Lower Oil Prices Naira Forwards Discount Will Widen With Lower Oil Prices Naira Forwards Discount Will Widen With Lower Oil Prices Chart II-10Nigeria: Buy Sovereign Credit After Devaluation Nigeria: Buy Sovereign Credit After Devaluation Nigeria: Buy Sovereign Credit After Devaluation   Finally, equity investors should continue avoiding the local bourse. Due to capital controls, the latter is uninvestable for now. Andrija Vesic Associate Editor andrijav@bcaresearch.com Arthur Budaghyan Chief Emerging Markets Strategist arthurb@bcaresearch.com   Footnotes 1 The standard gauge railways project built between the port city of Mombasa and its capital Nairobi has been heavily scrutinized by Kenyan authorities. After only three years of operation, the Kenyan Railways Company (KRC) has already defaulted on its loan from Chinese lenders. Kenyan courts have been arguing that Kenyan government and state-owned enterprises are facing sovereign risk over Chinese debt overhang. More than half of Kenya’s loans from China are attached to the construction of the Mombasa-Nairobi railway project. 2 This differs from BCA Commodity and Energy Strategy service’s expectation that Brent prices will average $65 in 2021.

Highlights The market will not give OPEC 2.0 until March to sort out a durable modus operandi to manage supply and maintain the discipline required to defend crude oil prices. While the odds of Libya and Nigeria being able to keep production at current levels - much less grow output - are less than 50:50 in our estimation, the fact remains the Kingdom of Saudi Arabia (KSA) and Russia need to start communicating post-haste how OPEC 2.0 will manage higher Libyan and Nigerian production. Critically, these leaders will need to follow through on whatever they guide the market to expect. We think OPEC 2.0 will stand by its "whatever it takes" proclamations. Not acting in the face of more than 300k b/d of unexpected supply from a once-moribund Libya placed in the market since October will send a signal, as well: OPEC 2.0 will not defend its Agreement. Should this occur, it likely would result in a breakdown in production discipline within the coalition, sending crude oil prices lower. Energy: Overweight. Crude oil prices remain under pressure as markets price the likelihood of continued increases in production in Libya and the U.S. Spoiler alert: We think OPEC 2.0 will act to accommodate Libya's and Nigeria's return to export markets. Base Metals: Neutral. Workers at the Zaldivar copper mine owned by Antofagasta and Barrick Gold voted to strike earlier this week. If government mediation fails to resolve the issues separating labor and management this week, workers will walk. Precious Metals: Neutral. Gold is recovering from last week's "flash crash" in silver, but markets continue to process recent hawkish guidance from systematically important central banks that could lift real rates and pressure precious metals. Ags/Softs: The USDA's WASDE was published just before our deadline. We will review it in next week's publication. Feature Markets may have tacitly assumed OPEC 2.0 would have until March to figure out how KSA, Russia, and their respective allies would work together to re-gain some control over oil prices. However, given almost-daily reductions in banks' oil-price forecasts in the wake of steadily increasing Libyan and U.S. production, belief in OPEC 2.0's strategy and commitment appears to be all but exhausted. Stronger-than-expected output from Libya and Nigeria - up some 400k b/d vs. the October production levels OPEC 2.0 benchmarks to (Chart of the Week) - is being offset by strong inventory draws in high-frequency data from the U.S. and Europe, as we expected. In addition, a reduction in 2018 U.S. shale-growth forecasts in the EIA's just-released estimates of global supply and demand boosted sentiment some. Even so, markets remain skeptical. Libya's production now is estimated at 850k b/d, and accounts for 300k b/d of newly arrived OPEC supply since October. Nigeria, at close to 1.6mm b/d, accounts for another 90k b/d of the unexpected supply on the market since October. OPEC's total crude output is running at just over 32.6mm b/d, down 470k b/d from October's levels, based on the EIA's tally.1 This was 300k b/d more than May's output. Taking Libyan and Nigerian output out of the tally leaves OPEC crude production at 30.21mm b/d, or 860k b/d below October's level. Close to 26mm b/d of OPEC's output is being exported, according to Thompson Reuters data, surpassing OPEC's 4Q16 export levels when Cartel members' output was surging ahead of the OPEC 2.0 production cuts that took effect in January.2 Although benchmark crude oil prices had recovered from their bear-market lows of late June, the steady increase in Libyan production, in particular, reversed this recovery, taking $2.70 and $2.80/bbl off the interim highs registered by WTI and Brent prompt contracts between July 3 and July 10 (Chart 2). Chart of the WeekLibya, Nigeria Add Close ##br##To 400k b/d To OPEC 2.0 Production Libya, Nigeria Add Close To 400k b/d To OPEC 2.0 Production Libya, Nigeria Add Close To 400k b/d To OPEC 2.0 Production Chart 2Libya's Resurgence Clobbers ##br##Benchmark Prices Libya's Resurgence Clobbers Benchmark Prices Libya's Resurgence Clobbers Benchmark Prices Prices have since moved higher of the back on larger-than-expected draws in crude and products in the OECD, led by the U.S. On Wednesday, the EIA reported U.S. crude inventories declined by a whopping 10.7 million barrels, although product inventories grew by 3.7 million barrels for the week ended July 7. These sharp draws (over 17 million barrels of crude storage reduction in the past two weeks, including SPR withdrawals) are what we have been expecting, so we are not surprised, although this is the second week in a row in which the inventory draws exceeded market expectations for the EIA's reporting week. WTI was trading just above$45/bbl, while Brent was just over $47.60/bbl as we went to press. OPEC 2.0's Problem The problem for OPEC 2.0 is that Libya's unexpectedly strong return will retard the drawdown in OECD inventories around which the reformed Cartel is organized. This is compounded by higher U.S. production, which the EIA's latest estimates put at 9.2mm b/d. U.S. crude production in June was up 410k b/d vs. 4Q16 levels, and 510k b/d yoy, by the EIA's reckoning. The bulk of this increase comes from shale-oil production, which is running at ~ 5.1mm b/d (Chart 3). Lower prices will slow the growth of U.S. shale-oil output, but it won't reverse the absolute increase unless prices once again push below $40/bbl for an extended period. We do not expect such an evolution of prices, and continue to expect Brent will average $55/bbl and will reach $60/bbl by the end of the year, with WTI trading at ~ $58/bbl by then. OPEC 2.0's production is not as sensitive to price as the U.S. shales. The coalition banded together to remove some 1.8mm b/d of oil production from the market, and, based on media reports, continues to maintain production discipline. We reckon actual cuts have been on the order of 1.4 to 1.5mm b/d from OPEC 2.0, favoring the lower end of that range, given the latest estimates of the EIA. Given demand growth of ~ 1.6mm b/d on average this year and next, we are expecting a net physical deficit this year of ~ 900k b/d (Chart 4). This will draw OECD inventories down by March below five-year average levels (Chart 5). Chart 3Higher Prices Lifted U.S. ##br##Shale-Oil Production, But Lower Prices Will Slow The Growth Higher Prices Lifted U.S. Shale-Oil Production, But Lower Prices Will Slow The Growth Higher Prices Lifted U.S. Shale-Oil Production, But Lower Prices Will Slow The Growth Chart 4Output Declines And Demand ##br##Gains Will Produce A Physical Deficit ... Output Declines And Demand Gains Will Produce A Physical Deficit ... Output Declines And Demand Gains Will Produce A Physical Deficit ... Chart 5OPEC 2.0 Has To Defend Its Strategy, ##br##If OECD Inventories Are To Fall OPEC 2.0 Has To Defend Its Strategy, If OECD Inventories Are To Fall OPEC 2.0 Has To Defend Its Strategy, If OECD Inventories Are To Fall It is worth remembering Libya and Nigeria are not parties to the OPEC 2.0 deal. Nor did the leaders of this coalition anticipate a sustained increase in production by these states when the OPEC 2.0 deal was agreed at the end of last year. This is particularly true for Libya, which is a failed state. The suggestion by Kuwait that Libya and Nigeria be brought into the OPEC 2.0 production-cutting agreement beggars belief: The Arab Spring destroyed Libya as a state, and its oil production. Since March 2011, when the state collapsed, Libya's oil production has averaged 650kb/d, versus 1.65mm b/d in 2010. Even if there were a government in place, it is unlikely it would agree to cap its production. Nigeria's production also has been hampered by civil unrest, particularly in the Niger Delta region, where insurgents periodically sabotage pipelines and loading platforms, which forces oil exports to be suspended until repairs can be made. Nigeria's production averaged over 2mm b/d until 2013, when it fell to 1.83mm b/d. Since then, it has averaged 1.66mm b/d, with 2017 production to June averaging 1.43mm b/d. Any increase in production resulting in export sales is "found money" for these states. And their need for this money is as great, if not greater, than that of the OPEC 2.0 coalition members. Who In OPEC 2.0 Is Likely To Cut Production? KSA, Kuwait and the UAE were producing close to 2.4mm b/d more in June than they were in 2010, the last year Libya was an intact state, even with the cuts agreed under the OPEC 2.0 deal accounted for. Even at its recent high of 850k b/d of production, Libya still is producing 800k b/d less than it did in 2010. We believe an accommodation involving KSA, and possibly Kuwait and the UAE, can and will be reached at the upcoming OPEC 2.0 technical committee meeting in St. Petersburg on July 24. Something on the order of 500k b/d from these Gulf Arab producers will allow Libya and Nigeria to flex into higher production without undermining the OPEC 2.0 production-cutting deal. The stakes are sufficiently high for the OPEC 2.0 members - KSA and Russia in particular - that an accommodation for Libya will be found. Libya's maximum production likely is no more than 1mm b/d, given the damage years of neglect has caused its fields and productive capital. Rebuilding this province will take years, if a way can be found to reconstitute the organs of a functioning state. Absent an accommodation, OPEC 2.0's leaders risk undermining the credibility of the coalition and causing production discipline to collapse as each state in the group rushes to increase output before prices take their inevitable dive. This would severely reduce the proceeds KSA could expect from IPO'ing Aramco, and would again put Russia's revenue under pressure, forcing it to draw down foreign reserves. OPEC 2.0's End Game Hasn't Changed Neither KSA nor Russia wants to re-visit the conditions that prevailed in 1Q16, when markets were pricing a global full-storage event that would require prices to push through $20/bbl to kill off supply so that storage could drain. For this reason, both have shown their commitment to the production-cutting pact they negotiated at the end of last year. Both, we are convinced, are working closely to map a strategy to allow U.S. shale production to co-exist - within limits - with OPEC and Russian production. In earlier research, we laid out a strategy that could work to achieve this result - draw storage down enough to backwardate the WTI forward curve so that deferred prices trade below prompt-delivery prices. This will moderate - but not stop - the rate at which horizontal rigs return to the shale fields.3 OPEC 2.0's leaders will have to find a way to use their production and storage - which is why it is critical to open some space now - to guide markets to expect higher production and crude availability in the future and tighter market conditions in the present. Bottom Line: We expect OPEC 2.0 to accommodate Libya's and Nigeria's increased production with further cuts in their own production, particularly from KSA, Kuwait and the UAE. This will allow Libya and Nigeria to flex into higher output, should they find a way to maintain it going forward. We continue to believe the odds of sustained higher production from these states is less than 50:50, but that does not matter. What matters is that markets see OPEC 2.0 defending their production-cutting strategy so that inventories continue to draw. OPEC 2.0's end-game has not changed. But the leaders of the coalition will have to adapt if they are to succeed in drawing storage to five-year averages or lower. Critically, they must begin to communicate their longer-term strategy to the market, or risk undermining their coalition. 2Q17 Trade Recommendations Re-Cap We closed out 2Q17 with an average loss of 77% on trades recommended and closed during the quarter (Table 1). The primary driver of this underperformance was a return to contango in the WTI and Brent forward curves, as inventories failed to draw as quickly as we expected. Directional trade recommendations anticipating higher prices also performed poorly. Table 1Trade Recommendation Performance In 2Q17 Time For "Whatever It Takes" In Oil Markets! Time For "Whatever It Takes" In Oil Markets! Open trades at the end of 2Q17 were up an average of 26%, led by good performances in option recommendations - i.e., long call spreads in WTI and Brent in Dec/17. Year to date, our trade recommendations are up 72.6%, on the back of strong 1Q17 results. Robert P. Ryan, Senior Vice President Commodity & Energy Strategy rryan@bcaresearch.com 1 This is adjusted for the inclusion of Equatorial Guinea and the recent opting out of Indonesia. We will be updating our global supply-demand balances next week. 2 Please see "Oil slides as OPEC exports rise, prices end 8 days of gains," published by reuters.com July 5, 2017. 3 Please see BCA Research's Commodity & Energy Strategy reports of April 6, 2017, entitled "The Game's Afoot in Oil, But Which One," and March 30, 2017, entitled "KSA's, Russia's End Game: Contain U.S. Shale Oil." Both are available at ces.bcaresearch.com. Investment Views And Themes Recommendations Strategic Recommendations Tactical Trades Trades Open And Closed In 2017 Time For "Whatever It Takes" In Oil Markets! Time For "Whatever It Takes" In Oil Markets! Summary Of Trades Closed In 2016 Trades Closed In 2017 Commodity Prices And Plays Reference Table

Highlights This week, Commodity & Energy Strategy is publishing a joint report with our colleagues at BCA's Energy Sector Strategy. Driven by the leadership of the Kingdom of Saudi Arabia (KSA) and Russia, OPEC 2.0 formalized the well-telegraphed decision to extend its production cuts for another nine months, carrying the cuts through the seasonally weak demand period of Q1 2018. The extension is will be successful in bringing OECD inventories down to normalized levels, even assuming some compliance fatigue (cheating) setting in later this year. Energy: Overweight. We are getting long Dec/17 WTI vs. short Dec/18 WTI at tonight's close, given our expectation OPEC 2.0's extension of production cuts, and lower exports by KSA to the U.S., will cause the U.S. crude-oil benchmark to backwardate. Base Metals: Neutral. Despite "catastrophic flooding" in March, 1Q17 copper output in Peru grew almost 10% yoy to close to 564k MT, according to Metal Bulletin. This occurred despite strikes at Freeport-McMoRan's Cerro Verde mine, where production was down 20.5% yoy in March. Precious Metals: Neutral. Our strategic gold portfolio hedge is up 2.61% since it was initiated on May 4, 2017. Ags/Softs: Underweight. The USDA's Crop Progress report indicates plantings are close to five-year averages, despite harsh weather in some regions. We remain bearish. Feature Chart 1Real OPEC Cuts Of ~1.0 MMb/d##BR##For Over 400 Days Real OPEC Cuts Of ~1.0 MMb/d For Over 400 Days Real OPEC Cuts Of ~1.0 MMb/d For Over 400 Days OPEC 2.0's drive to normalize inventories by early 2018 will be accomplished with last week's agreement to extend current production cuts through March 2018. In total, OPEC has agreed to remove over 1 MMb/d of producible OPEC oil from the market for over 400 days (Chart 1), supplemented by an additional 200,000-300,000 b/d of voluntary restrictions of non-OPEC oil through Q3 2017 at least, perhaps longer if Russia can resist the temptation to cheat after oil prices start to respond. Many of the participants in the cut, from both OPEC and non-OPEC, are not actually reducing output voluntarily, but have had quotas set for them that merely reflect the natural decline of their productive capacity, limitations that will be even more pronounced in H2 2017 than in H1 2017. With production restricted by the OPEC 2.0 cuts, global demand growth will outpace supply expansion by another wide margin in 2017, just as it did last year (Chart 2). As shown in Chart 3, steady demand expansion and the slowdown in supply growth allowed oil markets to move from oversupplied in 2015 to balanced during 2016; demand growth will increasingly outpace production growth in 2017, creating sharp inventory draws (Chart 4) that bring stocks down to normalized levels by the end of 2017 (Chart 5). Chart 2 Chart 3Production Cuts And Demand##BR##Growth Will Draw Inventories Production Cuts And Demand Growth Will Draw Inventories Production Cuts And Demand Growth Will Draw Inventories Chart 4Higher Global Inventory##BR##Withdrawals Through Rest Of 2017 Higher Global Inventory Withdrawals Through Rest Of 2017 Higher Global Inventory Withdrawals Through Rest Of 2017 Chart 5OECD Inventories To Be##BR##Reduced To Normal OECD Inventories To Be Reduced To Normal OECD Inventories To Be Reduced To Normal The extension of the cut through Q1 2018 will help prevent a premature refilling of inventories during the seasonally weak first quarter next year. The return of OPEC 2.0's production to full capacity in Q2 2018 will drive total production growth above total demand growth for 2018, returning oil markets from deliberately undersupplied during 2017 to roughly balanced markets in 2018, with stable inventory levels that are below the rolling five-year average. 2018 inventory levels will still be 5-10% above the average from 2010-2014, in line with the ~7% demand growth between 2014 and 2018. Compliance Assessment: Only A Few Players Matter In OPEC 2.0 OPEC's compliance with the cuts announced in November 2016 has been quite good, with KSA anchoring the cuts by surpassing its 468,000 b/d cut commitment. In addition to KSA, OPEC is getting strong voluntary compliance from the other Middle Eastern producers (except Iraq), while producers outside the Middle East lack the ability to meaningfully exceed their quotas in any case. OPEC's Core Four Remain Solid. The core of the OPEC 2.0 agreement has delivered strong compliance with their announced cuts. Within OPEC, the core Middle East countries Kingdom of Saudi Arabia, Kuwait, Qatar, and UAE have delivered over 100% compliance of their 800,000 b/d agreed-to cuts. We expect these countries to continue to show strong solidarity with the voluntary cuts through March 2018 (Chart 6). Iraq And Iran Make Small/No Sacrifices. Iraq and Iran were not officially excluded from cuts, but they were not asked to make significant sacrifices either. We estimate Iran has little-to-no capability to materially raise production in 2017 anyhow, and KSA is leaning on Iraq to better comply with its small cuts. Chart 7 shows our projections for Iran and Iraq production levels through 2018. Chart 6KSA, Kuwait, Qatar & UAE Carrying##BR##The Load Of OPEC Cuts KSA, Kuwait, Qatar & UAE Carrying The Load Of OPEC Cuts KSA, Kuwait, Qatar & UAE Carrying The Load Of OPEC Cuts Chart 7Iran And Iraq Production##BR##Near Full Capacity Iran And Iraq Production Near Full Capacity Iran And Iraq Production Near Full Capacity Iraq surged its production above 4.6 MMb/d for two months between OPEC's September 2016 indication that a cut would be coming and the late-November formalization of the cut. Iraq's quota of 4.35 MMb/d is nominally a 210,000 b/d cut from its surged November reference level, but is essentially equal to the country's production for the first nine months of 2016, implying not much of a real cut. Despite the low level of required sacrifice, Iraq has produced about 100,000 b/d above its quota so far in 2017 at a level we estimate is near/at its capacity anyway. KSA and others in OPEC are not pleased with Iraq's overproduction and have pressured it to comply with the agreement. We forecast Iraq will continue producing at 4.45 MMb/d. Iran's quota represented an allowed increase in production, reflecting the country's continued recovery from years of economic sanctions. We project Iran will continue to slowly expand production, but since the country is almost back up to pre-sanction levels, there is little remaining easily-achievable recovery potential. South American & African OPEC Capacity Eroding On Its Own. Chart 8 clearly shows how production levels in Venezuela, Angola and Algeria started to deteriorate well before OPEC formalized its production cuts, with productive capacity eroded by lack of reinvestment rather than voluntary restrictions. The quotas for these three countries (as well as for small producers Ecuador and Gabon) are counted as ~258,000 b/d of "cuts" in OPEC's agreement, but they merely represent the declines in production that should be expected anyway. With capacity deteriorating and no ability to ramp up anyway, these OPEC nations will deliver improving "compliance" (i.e. under-producing their quotas) in H2 2017, and are happy to have the higher oil prices created by the extension of production cuts by the core producers within OPEC 2.0. Libya and Nigeria Exclusions Unlikely To Result In Big Production Gains. Both Libyan and Nigerian production levels have been constrained by above-ground interference. Libyan production has been held below 1.0 MMb/d since 2013 principally by chronic factional fighting for control of export terminals, while Nigerian production--on a steady natural decline since 2010--has been further limited by militants sabotaging pipelines in 2016-2017. While each country has ebbs and flows to the amount of oil they are able to produce, we view both countries' problems as persistent risks that will continue to keep production below full potential (Chart 9). Chart 8 Chart 9Libya And Nigeria Production Could Go Higher##BR##Under Right (But Unlikely) Circumstances Libya And Nigeria Production Could Go Higher Under Right (But Unlikely) Circumstances Libya And Nigeria Production Could Go Higher Under Right (But Unlikely) Circumstances For Nigeria, we estimate the country's crude productive capacity has eroded to about 1.8 MMb/d from 2.0 MMb/d five years ago due to aging fields and a substantial reduction in drilling (offshore drilling is down ~70% since 2013). Within another year or two, this capacity will dwindle to 1.7 MMb/d or below. On top of this natural decline, we have projected continued sabotage / militant obstruction will limit actual crude output to an average of 1.55 MMb/d for the foreseeable future. Libyan production averaged just 420,000 b/d for 2014-2016, a far cry from the 1.65 MMb/d produced prior to the 2011 Libyan Revolution that ousted strongman Muammar Gaddafi. Since Gaddafi was deposed and executed, factional strife and conflict has persisted. Each faction wants control over oil export revenues and, just as importantly, wants to deny the opposition those revenues, resulting in a chronic state of conflict that has limited production and exports. If a détente were reached, we expect Libyan oil production could quickly rise to about 1.0 MMb/d of production within six months; however, we put the odds of a sustainable détente at less than 30%. As such, we forecast Libyan crude production will continue to struggle, averaging about 600,000 b/d in 2017-2018. Non-OPEC Cuts Hang On Russia In November, ten non-OPEC countries nominally agreed to restrict production by a total of 558,000 b/d, but Russia--with 300,000 b/d of pledged cuts--is the big fish that KSA and OPEC are relying on. Mexico's (and several others') agreements are window dressing, reframing natural production declines as voluntary action to rebalance markets. Through H1 2017, Russia has delivered on about 60-70% of its cut agreement, with compliance growing in Q2 (near 100%) versus Q1 (under 50%). From the start, Russia indicated it would require some time to work through the physical technicalities of lowering production to its committed levels, implying that now that production has been lowered, Russia could deliver greater compliance over H2 2017 than it delivered in H1 2017. We are a little more skeptical, expecting some weakening in Russia's compliance by Q4, especially if the extended cuts deliver the expected results of bringing down OECD inventories and lifting prices. Russia surprised us with stronger-than-expected production during 2016. Some of the outperformance was clearly due to a lower currency and improved shale-like drilling results in Western Siberia, but it is unclear whether producers also pulled too hard on their fields to compensate for lower prices, and are using the OPEC 2.0 cut as a way to rest their fields a bit. We have estimated Russian production returning to 11.3 MMb/d by Q4 2017 (50,000 b/d higher than 2016 average production) and holding there through 2018 (Chart 10), but actual volumes could deviate from this level by as much as 100,000-200,000 b/d. Mexico, the second largest non-OPEC "cutter," is in a position similar to Angola, Algeria, and Venezuela. Mexican production has been falling for years (Chart 11), and the nation's pledge to produce 100,000 b/d less in H1 2017 than in Q4 2016 is merely a reflection of this involuntary decline. As it has happened, Mexican production has declined by only ~60,000 b/d below its official reference level, but continues to deteriorate, promising higher "compliance" with their production pledge in H2 2017. Chart 10Russia Expected##BR##To Cheat By Q4 Russia Expected To Cheat By Q4 Russia Expected To Cheat By Q4 Chart 11Mexican Production Deterioration##BR##Unaffected By Cut Pledges Mexican Production Deterioration Unaffected By Cut Pledges Mexican Production Deterioration Unaffected By Cut Pledges Kazakhstan and Azerbaijan are not complying with any cuts, and we don't expect them to. Despite modest pledges of 55,000 b/d cuts combined, the two countries have produced ~80,000 b/d more during H1 2017 than they did in November 2016. We don't expect any voluntary contributions from these nations in the cut extension, but Azerbaijan's production is expected to wane naturally (Chart 12). While contributing only a small cut of 45,000 b/d, Oman has diligently adhered to its promised cuts, supporting its OPEC and Gulf Cooperation Council (GCC) neighbors. We expect Oman's excellent compliance will be faithfully continued through the nine-month extension (Chart 13). Chart 12Kazakhstan And Azerbaijan Not Expected##BR##To Comply With Any Cut Extension Kazakhstan And Azerbaijan Not Expected To Comply With Any Cut Extension Kazakhstan And Azerbaijan Not Expected To Comply With Any Cut Extension Chart 13Oman Has Faithfully Complied##BR##With Cut Promises To Date Oman Has Faithfully Complied With Cut Promises To Date Oman Has Faithfully Complied With Cut Promises To Date OPEC Extension Will Continue To Support Increased Shale Drilling Energy Sector Strategy believed OPEC's original cut announced in November 2016 was a strategic mistake for the cartel, as it would accelerate the production recovery from U.S. shales in return for "only" six months of modestly-higher OPEC revenue. As we cautioned at the time, the promise of an OPEC-supported price floor was foolish for them to make; instead, OPEC should have let the risk of low prices continue to restrain shale and non-Persian Gulf investment, allowing oil markets to rebalance more naturally. However, despite our unfavorable opinion of the strategic value of the original cut, since the cut has not delivered the type of OECD inventory reductions expected (seemingly due to a larger-than-expected transfer of non-OECD inventories into OECD storage), we view the extension of the cut as a necessary, and logical, next step. OPEC 2.0's November 2016 cut agreement signaled to the world that OPEC (and Russia) would abandon KSA's professed commitment to a market share war, and would instead work together to support a ~$50/bbl floor under the price of oil. Such a price floor dramatically reduced the investment risk for shale drilling, and emboldened producers (and supporting capital markets) to pour money into vastly increased drilling programs. Now that the shale investment genie has already been let out of the bottle, extending the cuts is unlikely to have nearly the same stimulative impact on shale spending as the original paradigm-changing cut created. The shale drilling and production response has been even greater than we estimated six months ago, and surely greater than OPEC's expectations. The current horizontal (& directional) oil rig count of 657 rigs is nearly twice the 2016 average of 356 rigs, is 60% higher than the level of November 2016 (immediately before the cut announcement), and is still rising at a rate of 25-30 rigs per month (Chart 14). The momentum of these expenditures will carry U.S. production higher through YE 2017 even if oil prices were allowed to crash today. Immediately following OPEC's cut, we estimated 2017 U.S. onshore production could increase by 100,000 - 200,000 b/d over levels estimated prior to the cut, back-end weighted to H2 2017, with a greater 300,000-400,000 b/d uplift to 2018 production levels. Drilling activity has roared back so much faster than we had expected, indicative of the flooding of the industry with external capital, that we have raised our 2017 production estimate by 500,000 b/d over our December estimate, and raised our 2018 production growth estimate to 1.0 MMb/d (Chart 15). Chart 14Rig Count Recovery Dominated##BR##By Horizontal Drilling Rig Count Recovery Dominated By Horizontal Drilling Rig Count Recovery Dominated By Horizontal Drilling Chart 15Onshore U.S. Production##BR##Estimates Rising Sharply Onshore U.S. Production Estimates Rising Sharply Onshore U.S. Production Estimates Rising Sharply Other Guys' Decline Requires Greater Growth From OPEC, Shales, And Russia We've written before about "the Other Guys' in the oil market, defined as all producers outside of the expanding triumvirate of 1) U.S. shales, 2) Russia, and 3) Middle East OPEC. While the growers receive the vast majority of investors' focus, the Other Guys comprise nearly half of global production and have struggled to keep production flat over the past several years (Chart 16). Chart 17 shows the largest offshore basins in the world, which should suffer accelerated declines in 2019-2020 (and likely beyond) as the cumulative effects of spending constraints during 2015-2018 (and likely beyond) result in an insufficient level of projects coming online. This outlook requires increasing growth from OPEC, Russia and/or the shales to offset the shrinkage of the Other Guys and simultaneously meet continued demand growth. Chart 16The Other Guys' Production##BR##Struggling To Keep Flat The Other Guys' Production Struggling To Keep Flat The Other Guys' Production Struggling To Keep Flat Chart 17 Risks To Rebalancing Our expectation global oil inventories will draw, and that prices will, as a result, migrate toward $60/bbl by year-end is premised on the continued observance of production discipline by OPEC 2.0. GCC OPEC - KSA, Kuwait, Qatar, and the UAE - Russia and Oman are expected to observe their pledged output reduction, but we are modeling some compliance "fatigue" all the same. Even so, this will not prevent visible OECD oil inventories from falling to their five-year average levels by year-end or early next year. Obviously, none of this can be taken for granted. We have consistently highlighted the upside and downside risks to our longer term central tendency of $55/bbl for Brent crude, with an expected trading range of $45 to $65/bbl out to 2020. Below, we reprise these concerns and our thoughts concerning OPEC 2.0's future. Major Upside Risks Chief among the upside risks remains a sudden loss of supply from a critical producer and exporter like Venezuela or Nigeria, which, respectively, we expect will account for 1.9 and 1.5 MMb/d of production over the 2017-18 period. Losing either of these exporters would sharply rally prices above $65/bbl as markets adjusted and brought new supply on line. Other states - notably Algeria and Iraq - highlight the risk of sustained production losses due to a combination of internal strife and lack of FDI due to civil unrest. Algeria already appears to have entered into a declining production phase, while Iraq - despite its enormous potential - remains dogged by persistent internal conflict. We are modeling a sustained, slow decline in Algeria's output this year and next, which takes its output from 1.1 MMb/d in 2015 down to slightly more than 1 MMb/d on average this year and next. For Iraq, where we expect a flattening of production at ~ 4.4 MMb/d this year and a slight uptick to ~ 4.45 MMb/d in 2018, continued violence arising from dispersed terrorism in that country in the wake of a defeat of ISIS as an organized force, will remain an ongoing threat to production. Longer term - i.e., beyond 2018 - we remain concerned the massive $1-trillion-plus cutbacks in capex for projects that would have come online between 2015 and 2020 brought on by the oil-price collapse in 2015-16 will force prices higher to encourage the development of new supplies. The practical implication of this is some 7 MMb/d of oil-equivalent production the market will need, as this decade winds down, will have to be supplied by U.S. shales, Gulf OPEC and Russia, as noted above. Big, long-lead-time deep-water projects requiring years to develop cannot be brought on fast enough to make up for supply that, for whatever reason, fails to materialize from these sources. In addition, as shales account for more of global oil supplies and "The Other Guys" continue to lose production to higher depletion rates, more and more shale - in the U.S. and, perhaps, Russia - and conventional Persian Gulf production will have to be brought on line simply to make up for accelerating declines. This evolution of the supply side is significantly different from what oil and capital markets have been accustomed to in previous cycles. Because of this, these markets do not have much historical experience on which to base their expectations vis-à-vis global supply adjustment and the capacity these sources of supply have for meeting increasing demand and depletion rates. Lower-Cost Production, Demand Worries On The Downside Downside risks, in our estimation, are dominated by higher production risks. Here, we believe the U.S. shales and Russia are the principal risk factors, as the oil industry in both states is, to varying degrees, privately held. Because firms in these states answer to shareholders, it must be assumed they will operate for the benefit of these interests. So, if their marginal costs are less than the market-clearing price of oil, we can expect them to increase production up to the point at which marginal cost is equal to marginal revenue. The very real possibility firms in these countries move the market-clearing price to their marginal cost level cannot be overlooked. For the U.S., this level is below $53/bbl or so for shale producers. For Russian producers, this level likely is lower, given their production costs are largely incurred in rubles, and revenues on sales into the global market are realized in USD; however, given the variability of the ruble, this cost likely is a moving target. While a sharp increase in unconventional production presently not foreseen either in the U.S. or Russian shales will remain a downside price risk, an increase in conventional output - chiefly in Libya - remains possible. As discussed above, we believe this is a low risk to prices at present; however, if an accommodation with insurgent forces in the country can be achieved, output in Libya could double from the 600k b/d of production we estimate for this year and next. We reiterate this is a low-risk probability (less than 25%), but, in the event, would prove to be significant additions to global balances over the short term requiring a response from OPEC 2.0 to keep Brent prices above $50/bbl. Also on the downside, an unexpected drop in demand remains at the top of many lists. This is a near-continual worry for markets, which can be occasioned by fears of weakening EM oil-demand growth from, e.g., a hard landing in China, or slower-than-expected growth in India. These are the two most important states in the world in terms of oil-demand growth, accounting for more than one-third of global growth this year and next. We do not expect either to meaningfully slow; however, we continue to monitor growth in both closely.1 In addition, we continue to expect robust global oil-demand growth, averaging 1.56 MMb/d y/y growth in 2017 and 2018. This compares with 1.6 MMb/d growth last year. OPEC 2.0's Next Move Knowing the OPEC 2.0 production cuts will be extended to March 2018 does not give markets any direction for what to expect after this extension expires. Once the deal expires, we expect production to continue to increase from the U.S. shales, and for the key OPEC states to resume pre-cut production levels. Along with continued growth from Russia, this will be necessary to meet growing demand and increasing depletion rates from U.S. shales and "The Other Guys." Yet to be determined is whether OPEC 2.0 needs to remain in place after global inventories return to long-term average levels, or whether its formation and joint efforts were a one-off that markets will not require in the future. Over the short term immediately following the expiration of the production-cutting deal next year, OPEC 2.0 may have to find a way to manage its production to accommodate U.S. shales without imperiling their own revenues. This would require a strategy that keeps the front of the WTI and Brent forward curves at or below $60/bbl - KSA's fiscal breakeven price and $20/bbl above Russia's budget price - and the back of the curve backwardated, in order to exert some control over the rate at which shale rigs return to the field.2 As we've mentioned in the past, we have no doubt the principal negotiators in OPEC 2.0 continue to discuss this. Toward the end of this decade, such concerns might be moot, if growing demand and accelerating decline curves require production from all sources be stepped up. Matt Conlan, Senior Vice President Energy Sector Strategy mattconlan@bcaresearchny.com Robert P. Ryan, Senior Vice President Commodity & Energy Strategy rryan@bcaresearch.com 1 Please see the May 18, 2017, issue of BCA Research's Commodity & Energy Strategy article entitled "Balancing Oil-Shale's Resilience And OPEC 2.0's Production Cuts," in which we discuss the outlook for China's and India's growth. Together, these states account for more than 570k b/d of the 1.56 MMb/d growth we expect this year and next. The article is available at ces.bcaresearch.com. 2 A backwardated forward curve is characterized by prompt prices exceeding deferred prices. Our research indicates a backwardated forward curve results in fewer rigs returning to the field than a flat or positively sloped forward curve. We explored this strategy in depth in the April 6, 2017, issue of BCA Research's Commodity & Energy Strategy, in an article entitled "The Game's Afoot In Oil, But Which One?" It is available at ces.bcaresearch.com. Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Commodity Prices and Plays Reference Table Trades Closed In 2017 Summary of Trades Closed in 2016 Extending OPEC 2.0's Production Cuts Will Normalize Global Oil Inventories Extending OPEC 2.0's Production Cuts Will Normalize Global Oil Inventories Extending OPEC 2.0's Production Cuts Will Normalize Global Oil Inventories Extending OPEC 2.0's Production Cuts Will Normalize Global Oil Inventories

Highlights This week, we are reprising and updating "The Other Guys In The Oil Market" from our sister service Energy Sector Strategy (NRG), because it so well captures the state of oil production outside the U.S. shales, Middle East OPEC and Russia. "The Other Guys" account for ~ half of global supply. Next week, we'll publish a joint report with NRG analyzing today's OPEC meeting. The aptly named "Other Guys" account for ~ 42mm b/d of production, which they are struggling to maintain at current levels, let alone increase. These producers supply nearly half of global production, and have been stuck in a pattern of slow decline for years despite high oil prices. Beginning in 2019, we expect production declines to accelerate. This will put enormous pressure on the three primary growth regions, which markets likely will start pricing in toward the end of next year. Energy: Overweight. OPEC 2.0 is expected to extend its 1.8mm b/d of production cuts to the end of 1Q18 at its meeting in Vienna today. Going into the meeting, markets were being guided to expect even deeper cuts. Our long Dec/17 Brent $65/bbl calls vs. short $45/bbl puts, and our long Dec/17 vs. Dec/18 Brent positions are up 75.0% and 509.5% respectively, following their initiation on May 11, 2017. Base Metals: Neutral. Steel and iron-ore prices are getting a boost from China's anti-pollution campaign, which is expected to run through the end of this month. This was launched ahead of the anti-pollution campaign we expected after the Communist Party Congress in the fall. Iron ore delivered to Qingdao is up 3.1% since May 9, when Reuters reported the campaign began.1 Precious Metals: Neutral. Gold was well bid earlier in the week on the back of a weaker USD. Our long gold position is up 1.9%, while our long volatility trade, which we will unwind at tonight's close, is down 98.5%. Ags/Softs: Underweight. The weaker USD takes some pressure off wheat and beans over the short term, and might prompt a short-covering rally. We remain bearish, however, as the USD likely will bottom in the near future.2 Feature U.S. Onshore, Middle East OPEC (ME OPEC), and Russia combine to produce ~43 MMb/d of oil plus another ~11 MMb/d of other liquids (NGLs, biofuels, refinery gains, etc.). Combined, these producers increased crude production by 5 MMb/d plus another 1 MMb/d of other liquids production over the past three years (2014-2016), creating the oversupply that crashed prices. We expect these producers to add another 1.60 MMb/d of oil plus 1.14 MMb/d of other liquids by 2018 (over 2016 levels), dominated by nearly 2.0 MMb/d of oil and NGLs from the U.S. shales. Oil production from the other 100+ global oil producers also represents about ~42 MMb/d, but on balance has been slowly eroding since 2010, failing to grow even when oil prices were $100+/bbl. Despite some 2017 recovery from Libya, we expect total production to continue to fall in both 2017 and 2018. The few recently expanding producers among the Other Guys are running out of growth. Canada, Brazil, North Sea and GOM account for ~13 MMb/d of oil production in 2016, adding ~1.5 MMb/d over the past three years (2014-2016). North Sea production is projected to resume declines starting in 2017; GOM will reach it peak production sometime in 2017 or 2018, then start to ebb; large new Canadian oil sands projects will add ~310k b/d in 2017-2018, but scarce additions are scheduled beyond that; and Brazil's once-lofty growth plans have slowed to a crawl in 2016-2018. Global deepwater drilling activity and exploration spending have collapsed, lowering the reserve base, and undermining the stability of current production levels. Outside Of Just Three Regions, Oil Supply Picture Looks Worrisome Often overlooked in our discussions about world oil markets are the supply contributions of over 100 geographic regions. This collection of suppliers (which we will call the "Other Guys") is defined as all producing regions in the world other than: 1) U.S. Onshore (shales, specifically), 2) OPEC's six Middle East members, and 3) Russia. The Other Guys deliver nearly half of global production, try to maximize production every day (even OPEC nations among the Other Guys have not had production constrained by quotas), and still have endured consistent, albeit modest, production declines over the past six years. Chart 1Outside Of A Very Few Regions,##BR##Oil Production Has Struggled Outside Of A Very Few Regions, Oil Production Has Struggled Outside Of A Very Few Regions, Oil Production Has Struggled At the end of 1Q17, oilfield-services leader Schlumberger voiced sharp concerns regarding stability of supplies from these ignored producers, warning that aggregate capital expenditures within these regions will sustain an unprecedented third straight year of decline in 2017, with total spending only about half of 2014 levels. Chart 1 shows the divergent production histories of the three growing regions versus the rest of the world. Chart 1 also shows production of the Other Guys excluding the especially dramatic declines/volatility of Libyan production. Even though these producers benefitted from the same incentives and profitability from high oil prices as the three growing regions, as a group, they have been unable to expand production. As oil prices have plunged, drilling activity in these nations has also plummeted, raising concerns that production declines could start accelerating in the near future. Chart 2 shows that oil-directed drilling activity among the international components of the Other Guys (Chart 2 excludes GOM and highly-seasonal Alaska and Canada) has crashed by ~40%, from an average of over 800 rigs during the five-year period of 2010-2014 to under 500 rigs for the past year. Offshore drilling has collapsed even a little more sharply for these producers than overall oil-directed drilling, falling ~43% from an average of over 280 rigs to only 160 today (Chart 3, excludes GOM). Chart 2Other Guys' Drilling##BR##Has Collapsed 40% Other Guys' Drilling Has Collapsed 40% Other Guys' Drilling Has Collapsed 40% Chart 3International Offshore Drilling Is Down Over 40%,##BR##Boding Poorly For The Stability Of Future Production International Offshore Drilling Is Down Over 40%, Boding Poorly For The Stability Of Future Production International Offshore Drilling Is Down Over 40%, Boding Poorly For The Stability Of Future Production Offshore Production Declines To Accelerate Chart 4Other Guys' Offshore Drilling Has Collapsed Other Guys' Offshore Drilling Has Collapsed Other Guys' Offshore Drilling Has Collapsed As a particularly worrisome trend for the Other Guys' production stability, offshore drilling activity has collapsed in some of the most important offshore oil producing regions in the world, including the GOM, North Sea, West Africa, and Brazil (Chart 4). Considering the multi-year lag between drilling activity and the start of oil production, and the large well size and quick declines associated with offshore wells, the oil production impacts of this drilling collapse that started two years ago have not really been felt yet. When these regions get past the wave of new production from 2015-2017 project additions (projects started during 2011-2014), they will face a dearth of new projects maturing in 2018-2022 due to this collapse in drilling, with new production likely to be inadequate to offset the declines of legacy production. Brazil, the North Sea, West Africa, and GOM together account for about 12 MMb/d of oil production (Chart 5). These four offshore regions have benefitted from intense investment from 2010-2015 as shown by the surging rig counts during that period in Chart 4. This investment/drilling drove 1.1 MMb/d of oil production growth in Brazil, the GOM, and the North Sea from 2013 to 2016, without which total production from the Other Guys would have declined by 1.4 MMb/d rather than just 0.3 MMb/d. Despite strong investment, production in West Africa merely held flat outside of Nigeria during 2013-2016 while falling by 0.4 MMb/d within Nigeria (mostly in 2016 due to pipeline disruptions from saboteurs). Chart 5Offshore Production Will Stop Expanding, Then Decline The Other Guys In The Oil Market, Redux The Other Guys In The Oil Market, Redux Brazil offshore drilling activity over the past year is less than half of levels during 2010-2013. As a result, production growth will moderate significantly over the next few years, expanding far less (250k b/d in 2018 vs. 2016, based on our balances data) than the rapid 470,000 b/d step-up in production during 2013-2014. While Brazil still has a rich endowment of pre-salt reserves, marshalling capital and the International Oil Companies' (IOCs) focus to resurrect development activity will take years. We expect no growth during 2019-2020. The North Sea has seen production cut in half from the time of peak production in 1999 until 2013. Production declines were briefly halted and re-expanded by ~300,000 b/d during 2014-2016 due to a concerted drilling effort and brownfield maintenance program incentivized and financed by $100/bbl oil prices. Drilling has since declined 35% from average 2010-2014 levels, and production is expected to resume its downward trend in 2017-2018. Overall oil-directed offshore drilling in the GOM has been cut by over 50% from 2013-2014 levels. Based on our field-by-field analysis published in January, we estimate GOM oil production will hit a peak in a year and a half or less and then will succumb to declines due to lack of new drilling. West Africa has suffered production declines for the past several years due to both geologic challenges as well as more recent (2016-2017) political/sabotage related disruptions in Nigeria. With offshore drilling activity plummeting 70%-80%, we expect production declines will accelerate and it will take years of increased drilling to yield new production that can stem the declines. The collapse in Nigerian drilling, from 10 rigs in 2010-2013 to only 2-3 rigs over the past year, likely means that Nigerian production is incapable of returning to 2015 levels even if its recent sabotage issues are resolved. In aggregate, as shown in Chart 5, we expect production from these four offshore regions to stagnate during 2017-2018 (North Sea and West Africa decline while Brazil and GOM expand) before declining by ~0.5 MMb/d in each 2019-2020 due to the dramatic curtailment of investment during 2015-2017. SLB Talks Its Book, But Makes A Strong Point At an industry conference at the end of March, Schlumberger (again) railed against the inadequacy of the cash flow-negative U.S. shale industry to single-handedly supply enough production growth to satisfy continuing global demand growth, especially once the Other Guys start seeing more pronounced negative production effects from the sharply reduced investments over 2015-2017. "The 2017 E&P spend for this part of the global production base...is expected to be down 50% compared to 2014. At no other time in the past 50 years has our industry experienced cuts of this magnitude and this duration." - Paal Kibsgaard, CEO of SLB. SLB highlighted an analysis of depletion rates constructed with data from Energy Aspects. (The March 27 presentation can be found at www.slb.com). Annual depletion rates (annual production/proved developed reserves) in the GOM had spiked to over 20% in 2016 from a long-term level of only ~10% during 2000-2013. Similarly, depletion rates in the U.K. and Norwegian sectors of the North Sea also surged from ~10% to ~15% over the past three years. In both the GOM and the North Sea, oil production had recently been expanded, but proved developed reserves declined. Due to such low drilling investments during 2015-2016, producers have replaced only about half of the oil reserves that they've produced in the GOM and North Sea over the past three years (2014-2016). Eventually, this lack of investment in cultivating tomorrow's resources will catch up to the industry, and production will decline. Investors must take SLB's commentary with a grain of salt, as they could be construed as sour grapes. The immense pull of new capital spending to the U.S. shales has substantially benefitted SLB's primary competitors more than it has benefitted SLB (SLB is much more focused on international and offshore projects). Still, investors are too complacent about the stability of non-U.S. production. SLB's analysis and warnings of accelerating production declines should not be ignored. Bottom Line: Outside of the three regions of sharply growing production (U.S. onshore, ME OPEC and Russia) that investors are focused on, the other half of global production has been stagnant to declining despite high oil prices and high levels of drilling during 2010-2015. Now that drilling and capex in these regions has declined by 40%-50%, production declines should accelerate in coming years. Offshore production, especially, has not seen enough drilling to replace reserves, and is poised to decline within the next 2-3 years. The accelerating declines of the "Other Guys" will allow more room for growth from U.S. shales, ME OPEC and Russia. Matt Conlan, Senior Vice President, Energy Sector Strategy mattconlan@bcaresearchny.com 1 Please see "China steel hits nine-week peak amid crackdown, lifts iron ore," published by reuters.com May 22, 2017. 2 Please see the feature article in last week's edition of BCA Research's Foreign Exchange Strategy entitled "Bloody Potomac," in which our colleague Mathieu Savary lays out the case for an imminent USD rebound. Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Commodity Prices and Plays Reference Table Trades Closed In 2017 Summary of Trades Closed in 2016 The Other Guys In The Oil Market, Redux The Other Guys In The Oil Market, Redux The Other Guys In The Oil Market, Redux The Other Guys In The Oil Market, Redux

Against a backdrop of continuing supply destruction, particularly in the U.S., and a pick-up in crude demand, markets will remain in balance this quarter and go into a deficit in 2016H2.

A combination of physical rebalancing in the oil markets and geopolitical risk have pushed oil prices above $50/bbl. We therefore close our recommendation - made jointly with BCA's Commodity & Energy Strategy team - to long a December 2016 WTI $50/$55 call spread for a 106.3% gain.

A stunning 9.9 million-barrel build in U.S. oil inventories this week failed to arrest the upward climb in prices.

Global trade is plummeting as commodity prices remain depressed and emerging markets unravel. Even if oil were not plumbing new lows, we would remain bearish on EM economies, where poor governance and low efficiency suggest that more crises will rear their heads. Above all, we are watching China for policy clarity. After seizing 14% of global exports in recent years, it is now exporting surplus goods into an already deflationary world. Protectionism - not a coordinated response among leading countries - is the likely result. In essence, we reiterate our theme that globalization has peaked. Along the way, we call attention to five geopolitical "Black Swans" that <i>no one</i> is talking about.

Global trade is plummeting as commodity prices remain depressed and emerging markets unravel. Even if oil were not plumbing new lows, we would remain bearish on EM economies, where poor governance and low efficiency suggest that more crises will rear their heads. Above all, we are watching China for policy clarity. After seizing 14% of global exports in recent years, it is now exporting surplus goods into an already deflationary world. Protectionism - not a coordinated response among leading countries - is the likely result. In essence, we reiterate our theme that globalization has peaked. Along the way, we call attention to five geopolitical "Black Swans" that <i>no one</i> is talking about.