February 2016

Impact of the Well Control Rule

Executive Summary

Key Takeaways

The Well Control Rule (WCR) is expected to reduce offshore activity, both development and exploration, due to higher incurred costs and technical constraints of implementation. Based on the study, the most notable impacts of the WCR (assuming an $80 Brent reference oil price) could be:

» Exploration drilling: decreased by 35 – 55% or up to 10 wells per annum

» Industry investment: reduced by up to $11 Billion per annum, on average

» Production at risk by 2030: >1 mmboe/d (~35%)

» Jobs at risk by 2030: 105 – 190k

» GDP reduction: cumulative reduction of $260 - $390 Billion through 2030

» GDP could decrease by $27 – 45 Billion (25 – 40%) in 2030

» Government taxes: cumulative drop of up to $70 Billion (20%) through 2030

» Lease sale bonuses: reduced by $3.5 Bil (>40%) over the period through 2025

» Rig decline: 25-50% by the year 2030

Because the exploration prospect inventory on currently held leases will likely be condensed and fewer leases will be acquired in upcoming bid rounds, it is anticipated the production gap will continue to widen and could be irreversible post-2030, further limiting job, GDP and tax growth.

Impact of the Well Control Rule

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Key Impacts of Scenario Modelling

Assuming an $80 reference Brent oil price, our study found the WCR generally has a 25%+ impact on exploration activity, investment, production, industry revenues and the associated macroeconomic factors. We have summarized the key impacts below.

DW GoM Benchmarking Against Other Deepwater Basins

The Deepwater Gulf of Mexico (DW GoM) is a world-class exploration basin, with substantial Yet-to-Find volumes remaining, particularly in the Subsalt Miocene and Paleogene plays. Although we expect DW GoM to have material activity, value creation relative to other competitive basins could be significantly eroded from the WCR. For example, if we increase drilling costs by 40%, exploration spend could be cut by as much as 70%. The reduced spend would correspond with a lower level of drilling activity, with as much as a 60% reduction in wells drilled (from almost 400 to 166, cumulative through 2035), placing Brazil ahead of the DW GoM in forecasted drilling activity. From a government perspective, significant spend results in job creation—these jobs would potentially be in jeopardy with higher costs. There is also a risk that companies could reallocate the spend to other more relatively attractive Deepwater basins globally, like West Africa or Brazil. As DW GoM economics become even more challenged, other basins may offer more or similar exploration potential but higher returns. Within the subset of Deepwater basins below, the DW GoM could fall from 40% of forecasted Deepwater drilling activity to 20%.

*Source: Wood Mackenzie Exploration Service, assumes long term price of $85/bbl WATM is West Africa Transform Margin and includes Ghana, Cote d’Ivoire, Sierra Leone and Liberia

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Full Report

Cost of Supply for Deepwater Gulf of Mexico

Using Wood Mackenzie's proprietary database, we built cost of supply charts with discovered, but not yet onstream, fields. "Under Development" are fields that have already received development approval, but have not started production. "Probable Developments" have yet to start development, but are included in the partners’ long-term plans, and we expect to be developed under our base case assumptions. "Good technical" are fields that could be economic under our current costs and price projections, but significant uncertainty remains over the nature and timing of their development (we have modelled these as well under our base case assumptions).

In an $80 Base Case (based on Wood Mackenzie's long term forecast which considers oil and gas fundamentals), all discovered deepwater fields, holding an estimated 7 bnboe, breakeven (see Chart 1). Based on the breakeven analysis, we see $80 as the marginal cost of production in the DW GoM and likely the price at which supply and demand are balanced.

Time delays are drilling interruptions we incorporated for all scenarios other than in the Base Case. We deferred each development well by a month to account for timing delays due to the WCR. We also modelled scenarios with 20%, 30% and 40% higher drilling costs. Although the WCR will affect other cost components, we only modelled a cost increase for drilling costs. Even with time delays and 40% higher drilling costs almost all fields breakeven at $80 (see Chart 2. However, at $60, over 50% of the fields are at risk. Our study found that average breakevens increased by ~10% with 40% higher drilling costs and time delays.

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Upstream Forecasts

Lease Sale Revenues: At $80 flat pricing, the WCR could decrease lease sale revenues through 2025 by over 40%, or $3.5 Billion (see Chart 2), by making exploration in the Paleogene Expected Monetary Value (EMV) negative. Lease sales are not projected to return to 2008 levels, but 2018 is expected to see strong interest, with over 5 mil acres expiring and available for re-licencing. We model lease sales based on the pricing environment and whether there would be Paleogene exploration—the $80 flat pricing case without Paleogene is the only lease sale scenario that showcases the impact of the WCR.

Rig Counts: Shelf rig count is based on the time it takes to drill a well in the Gulf of Mexico Shelf. Well type and geological play data was used to determine the number of days to drill and non-utilization days. Deepwater rig count is based on the time it takes to drill a well in the DW Gulf of Mexico. For each scenario, we made assumptions on days to drill and non-utilization days based on:

x Well type: (Exploration, Appraisal, Development, Side Track or Water Injection) x Play: (Plio-Pleistocene, Mid-late Miocene, Ultra Deepwater Subsalt Plio-Miocene, Subsalt

Miocene, Paleogene or Jurassic

Overall offshore rig counts are expected to be reduced by at least a quarter, and up to a half (at $80), with most of the impact on the Deepwater (see Chart 5).

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Exploration Drilling: For $80 oil, we used our base case exploration drilling assumptions from the Exploration Service (based on similar long term pricing) as the baseline exploration drilling forecast (~20 wells per annum). We also made an assumption on undrillable wells (see Chart 6). This assumption was developed in collaboration between Wood Mackenzie and members of GEST and is an input into the modelling. We defined undrillable wells as those that could not be drilled using current technology and practice with 20%, 30% or 40% increased drilling costs. Although there will be an additional impact from the effect of undrillable wells for brownfield developments, we did not model this impact. We also did not include Plio-Pliestocene drilling, in which we see very limited upside.

Exploration drills could be reduced from the Base Case by ~35% as a result of our assumptions on undrillable wells due to the WCR (see Chart 6). The $80 (30% and 40%) cases assume some play economics are further challenged with higher costs.

Exploration is even further reduced if we assume the Paleogene will not see further exploration due to higher costs, thereby reducing exploration from the Base Case by over half (see Charts 7 and 8).

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Production: We model a reserve reduction of 20% for discovered, but not yet online, fields.

~0.8 to 1.1 mmboe/d are at risk in an $80 environment. Exploration success and pre-FID discovered fields drive production in the medium and long term.

Production is most affected in the longer term due to reduced exploration and development activity today (see Charts 10 and 11). The gap between the Base Case and WCR scenarios will continue to widen, which will have a waterfall effect on industry revenues and government taxes.

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Industry Revenues: The impact on industry revenue widens in the longer term as the production gap relative to the Base Case grows (see Charts 12 and 13).

Capital Investment: WCR reduces investment by ~20-35%, largely due to lower exploration (see Chart 15). The longer term is impacted more from lengthier discovery to first oil lead times. The reduction in CAPEX will lead to a reduction in jobs required to support the industry (discussed in the macroeconomic section).

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Operating Expenditures: OPEX impact is $1 Bil per annum, on average, through 2025 (see Chart 16). There is a slightly higher impact in the long term due to fewer fields coming online from forecast exploration activity.

Macroeconomic Forecasts

We analyzed granular industry level economic analysis for the Gulf Coast states and state-level impacts for the other Lower 48 states. We modelled economic data for 400+ industries:

x Direct Industries: Extraction of natural gas liquids; Drilling oil and gas wells; Support activities for oil and gas operations; Oil and gas field machinery and equipment manufacturing; Construction of other new nonresidential structures

x Indirect Industries: Examples include Employment services; Maintenance and repair construction of nonresidential structures; Architectural, engineering, and related services; Other financial investment activities; Legal services; Limited-service restaurants

x Induced Industries: Examples include Full-service restaurants; Limited-service restaurants; Hospitals; Offices of physicians; Wholesale trade

Offshore oil and gas extraction takes place primarily in Federal waters, and as such, does not fall within state boundaries. To look at the economic impacts at the state level, we made assumptions on where expenditures go and where the value add is captured.

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Employment: In the Base Case, we forecast an average of ~400k annual jobs related to offshore activity, with ~80% of those in Texas and Louisiana (see Charts 18 and 19).

The investment in the GoM impacts and employs a large cross-section of different job sectors (see Chart 20).

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The impact on employment will continue to grow as capex declines, with overall job loss figures potentially reaching 190k by 2030 (see Chart 22).

We assumed most of the CAPEX spent for Gulf of Mexico activity will be in Texas, while most of the OPEX will be spent in Louisiana. Texas employment will continue to decline as capex declines, with overall jobs at risk potentially reaching 125k by 2030 (Charts 24 and 26).

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For Louisiana, the overall jobs at risk could be as much as 35k by 2030 (see Charts 28 and 30).

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Government Taxes: Government taxes are expected to decrease up to $70 Bil through 2030 (see Chart 32). The reduction will be further compounded past 2030 from lower activity today as the production gap between the WCR scenarios and the Base Case continues to widen.

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The tax impact continues to grow as production declines. For a 15 year period, Texas and Louisiana could be impacted by as much as $5 Billion and $1.1 Billion, respectively (see Charts 34 and 36).

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In the Base Case, we forecast a growth in jobs, GDP, and government taxes of 50% from 2016 to 2030 (see Table 2). This value add for the overall economy is at risk from the WCR—the WCR could destroy a majority of job creation as well as future GDP and tax growth (see Table 1).

$60 Oil Outputs (Brent)

In a $60 environment, we assume overall base costs will be 20% lower than the base costs in the $80 cost cases. We then apply the cost increases from the WCR on these lower base costs. In general, the impact of the WCR will mostly be seen in price ranges of $60-$80 because most discovered but undeveloped assets breakeven in this price range, and are, therefore, more sensitive. At $60 (assuming a 20% supply cost decrease), most future exploration is EMV (Expected Monetary Value) negative and therefore the price alone would reduce exploration activity with the WCR further dampening it. As will be illustrated in this section, there is a substantial difference between industry investment at $80 and at $60. Costs in the DW GoM are already quite high relative to other Deepwater regions, with most of the Yet-to-Find volumes in the Paleogene and Subsalt Miocene. A majority of discovered volumes that are not yet onstream are in the Paleogene. The Paleogene becomes increasingly challenged as price drops below the $70 range, and we assume is not economic at $60 from a development standpoint (we assume the same for the Jurassic, which has much less exploration activity in the Base Case and does not affect the outcome as much as the Paleogene does). As a result, at $60 we have far fewer options for production growth as future volumes are driven by a combination of exploration and the larger discovered, undeveloped fields, both of which have a high proportion of Paleogene activity. The lower overall activity levels at $60 lead to reduced production, investment, and macroeconomic variables like jobs, taxes and GDP.

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However, even at $60 oil, the WCR still has at least a 10% impact on spend, production, etc.

In addition to the summary metrics above, we have highlighted a few key differences between the $80 and $60 scenarios. The upstream and macroeconomic outputs that are not covered below will directly flow from the other outputs. Lease sale revenues are expected to be much lower than in the $80 Base Case due to overall lower exploration activity at $60 relative to $80 oil (see Chart 37).

The lower leasing activity is largely a result of poor development economics, and therefore, full-cycle economics for exploration prospects in the Deepwater. In general, we assume there will not be exploration drilling in any plays that have a negative development EMV. At $60, the Paleogene and Jurassic are both uneconomic and are not included in our exploration drilling program. Prior to the assumption on uneconomic wells and undrillable wells, we assume a baseline for exploration drilling. We used 2015 exploration activity as a guide for $60 oil and forecast ~15 wells per annum.

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When accounting for the EMV negative plays, we only assume an average of 8 wells per annum in the $60 Base Case. This is further reduced to 5 wells post the undrillable wells assumption (see Chart 38).

Economics in the higher impact plays (Paleogene & Jurassic) are challenged in a $60 environment, even assuming supply costs are slightly reduced for the lower oil price. Looking back at the cost of supply stack for the Deepwater (see Chart 39), about half of the 7 bnboe of discovered, but not yet onstream, assets do not breakeven at $60. We do not model these projects going forward in our $60 Base Case.

Impact of the Well Control Rule

This report has been prepared for GEST and the Back to Work Coalition by Wood Mackenzie, Inc. The report is intended solely for the benefit of GEST and the Back to Work Coalition. No other party may re-publish or re-produce this report in its entirety or substantial portions of this report without Wood Mackenzie’s prior written permission. The information upon which this report is based has either been supplied to us by GEST or comes from our own experience, knowledge and databases. The opinions expressed in this report are those of Wood Mackenzie. They have been arrived at following careful consideration, research, and enquiry but we do not guarantee their fairness, completeness or accuracy. The opinions, as of this date, are subject to change. We do not accept any liability for your reliance upon them.

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The lower level of exploration and development activity directly translates to depressed production forecasts. The WCR impact on production is as much as 220 kboe/d, or 15%, by 2030 (see Chart 40).

The reduced activity levels further flow to the macroeconomic figures. For example, there are 70% fewer jobs in 2030 in the $60 Base Case as compared to the $80 Base Case. The impact of the WCR still may be as much as 20% (or 25k jobs at risk) in 2030 at $60 but the overall level of employment will be much lower due to the reduced investment required by the industry to support the lower activity.