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ENERGY 2020 Year-End Energy Review

December 2020

Jefferies LLC. Member SIPC. The information provided in this document, including discussions, represents the views of Jefferies Investment Banking. There is no assurance that the views expressed herein will be consistent with the views expressed by Jefferies Research or its Analysts. Nothing in this document should be understood as a promise or offer of favorable research coverage. Disclosure

Important Disclosures

This communication is being provided strictly for informational purposes and is not intended as a recommendation or an offer or solicitation for the purchase or sale of any referenced herein. This material has been prepared by Jefferies LLC, a U.S.-registered -dealer (“Jefferies”), employing appropriate expertise, and in the belief that it is fair and not misleading. The information upon which this material is based was obtained from sources believed to be reliable, but has not been independently verified; therefore, we do not guarantee its accuracy. This is not an offer or solicitation of an offer to buy or sell any security or investment. Any opinions or estimates constitute our best judgment as of the date hereof, and are subject to change without notice. Jefferies and Jefferies International Limited (“Jefferies International”) and their affiliates and their respective directors, officers and employees may buy or sell securities mentioned herein as agent or principal for their own account. This report was created by members of the investment banking division of Jefferies, and has not been reviewed by, or discussed with, any member of Jefferies’ research department. This report is not intended to be, and in no way constitutes, a “research report” as such term is defined in Rule 137 promulgated under the Securities Act of 1933, as amended. Jefferies’ investment banking department has done, and may continue to do, business with and limited partnerships included in this report. This report is a marketing communication and is not and should not be construed as investment research. Reproduction without written permission of Jefferies is expressly forbidden.

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1 Jefferies Oil & Gas Practice Unmatched Track Record & Expertise

Key Points Energy Investment Banking ▪ One of the largest energy investment banking teams Ralph Eads III, Chairman in the world ▪ Extensive network of relationships from high-profile roles in energy and ▪ Has served 40 of the 50 ▪ Significant M&A experience includes working on over $200 Bn in merger transactions largest worldwide energy ▪ Broad-based background in structured energy finance companies ▪ Previous positions at El Paso ; Donaldson, Lufkin & Jenrette; S.G. Warburg; and Lynch ▪ Foremost advisor in oil and gas transactions in Peter Bowden, Global Head of Energy Investment Banking unconventional basins ▪ Global Head of Energy Investment Banking; joined Jefferies in 2012 ▪ Professionals with expertise ▪ Previously a Managing Director at , where he was Head of Midstream across a wide spectrum ▪ Lead advisor on over $225 Bn of Energy M&A ─ Corporate M&A

─ Acquisitions & Divestitures Upstream Midstream Oilfield Services ─ Capital Markets ─ Leveraged Finance Guy Oliphint Greg Chitty Brian Conner Brian Bravo Daniel Anderson Co-Head of Co-Head of Co-Head of Co-Head of Head of Oilfield ─ and Upstream, Americas Upstream, Americas Midstream Midstream Services ─ , Geology, Petrophysics and Other Industry Experience

Corporate Finance / A&D Engineers / Geoscientists Energy Capital Markets International ▪ Bill Marko ▪ Ananth Shankar ▪ Carson Carruthers Leveraged Finance ▪ Richard Kent (Chair) ▪ Conrad Gibbins ▪ Brody Rollins ▪ Pablo Madrid ▪ Paul Cugno (Co-Head) ▪ Paul Wheeler (Head) ▪ John Antel ▪ Chris Howey ▪ Earl Wells ▪ Robert Anderson (Co-Head) ▪ Simon Frost Andrew Picoli Ryan Gitomer ▪ ▪ ▪ Travis Call ▪ Michael Singer ▪ Hartley Clay ▪ Simon Wu ▪ Raymond Brickey ▪ Jordan Smith ▪ Schuyler Evans

2 Jefferies Advised on Several Transformative Transactions in the Energy Sector in 2020

M&A and Capital Markets Leadership

Largest E&P Private Financing Largest E&P Private Capital Transaction Largest Appalachian A&D Transaction

September 2020 October 2020 Pending October 2020

$300,000,000 $1,000,000,000 $735,000,000 of Joint Venture with Acquisition of Appalachia assets from Second Lien Secured Notes Oaktree Capital Management L.P. Chevron Corporation Sole Financial Advisor Sole Financial Advisor Sole Financial Advisor

Largest Storage Transaction since 2006 Largest LNG M&A Transaction in History Largest Oilfield Services Restructuring

Pending Nov 2020 Dec 2020 August 2020 Pending

$2,685,000,000 $500,000,000 Acquisition of Senior Secured Term International-Matex to Finance Acquisition by $7,000,000,000 $7,096,300,000 Tank Terminals Riverstone Holdings Sale of 42% stake in Sole Financial Advisor Lead Left Arranger Restructuring Financial Advisor to Cheniere Energy Partners the Official Committee of Unsecured Creditors Lead Financial Advisor Largest Energy Term Loan B in 2020

3 Jefferies’ Recent International Experience Up to the minute buyer knowledge informed by recent experience spanning multiple geographies, asset type, and deal size

Sale of a material non-operated UK Sale of a robust non-operated UK CNS Acquisition of an FPSO in one of the portfolio production hub Largest Redevelopments in the North

◼ Interaction with the key buyer universe for ◼ Material working interest in a collection of Sea

material non-operated North Sea portfolios well-established producing fields in the ◼ Jefferies advised the BlackRock / Hav Energy ◼ Commercially complex structure Central North Sea consortium on the potential acquisition and (1) ◼ ◼ c. 40 mboe/d & 170 mmboe reserves Long life, oil-weighted producing hub with a leaseback of an FPSO in the North Sea well diversified reserve base across nine fields ◼ ◼ Bids due end October 2020 FPSO requires significant refurbishment capex to be funded by the buyer

Current Acquisition of Shell onshore upstream Farm-down of Large Oil-Weighted Private Placement For Leading ESG- assets in Egypt Producing Concessions in Egypt Technology

◼ Material operated, producing portfolio with ◼ Producing field with material development ◼ Technology portfolio includes “net zero” significant exploration potential upside accessed through 57 infill wells carbon solutions ranging from zero-emission

◼ Attractive E&P investment terms – one of the ◼ Concessions includes material low-cost electricity / hydrogen, H2S Sour Gas to Sweet Gas, Direct Air Capture of CO2 to carbon Advising on acquisition of Shell’s most competitive fiscal terms in the region exploration acreage with a vast number of Western Desert Portfolio capture ◼ Large, experienced operating team with strong identified targets

Financial Advisor to the Buyer track record of reserves replacement

Sale of a UK production platform Current Sale of an operated, producing

◼ Platform sale comprising producing and portfolio in Kazakhstan development assets in the Central North Sea ◼ Operatorship of assets in one of Kazakhstan’s ◼ Interaction with a wide array of potential most prolific basins buyers Sale of Kazakhstan Portfolio ◼ Experienced management team with decades ◼ Over 30 CAs signed with potential purchasers of operational knowledge operating the assets

◼ HoA for a transaction with DNeX announced ◼ Material oil volumes in place with scope to

August 2020 Financial Advisor to the Seller increase recovery factors significantly

Pending October 2020 Creating the largest listed independent Pending July 2020 One of the largest African Sale of two of the largest development in the UK developments assets in the North Sea

◼ Combined production > 250mboe/d and 2P ◼ 5 bnbbls of in-place resources with 500 ◼ The largest Barents Sea transaction in over a Sale of interest in SNE development reserves of 717mmboe; H1 of offshore Senegal mmbbls and 0.5 tcf recoverable decade Merger of Premier Oil and Chrysaor to create the largest independent oil and $1.76bn and H1 EBITDAX of $1.27bn ◼ Phase 1 production >100 mbbls/d ◼ c.70 mmboe net contingent resources gas company listed on the LSE ◼ Diversified portfolio, significant growth ◼ Additional development phases, nearby ◼ Reduction of c. $1bn capex exposure for projects and resilient restructured balance $400,000,000 discoveries and exploration potential adds Idemitsu Norge sheet Joint Corporate Broker to Premier Oil Financial Advisor to the Seller resource potential in excess of 1bnbbls

Pending November 2019 Sale of the world class ACG asset in October 2019 Sale of a Chinese SOE’s Indonesian Largest ever Upstream deal in Norway Azerbaijan portfolio ◼ Largest ever by ExxonMobil ◼ 5th largest offshore field in the world ◼ Producing assets in one of Indonesia’s most ◼ Sale of a 25-field non-operated portfolio ◼ 3 bnbbls of gross remaining reserves with 16 prolific onshore basin Sale of Chevron’s interest in the ACG Sale of Non-Operated Indonesian possessing over 500 mmboe of reserves field and the BTC pipeline to bnbbls of STOIIP Interests to: ◼ Stable current production with the potential to

◼ Gross daily production of c. 600 mbbls/d with double current rates through workovers and an ◼ Creates the largest independent E&P infill drilling campaign $1,570,000,000 additional phases of development planned Undisclosed company in Norway Financial Advisor to the Seller Financial Advisor to Seller

(1) Based on Wood Mackenzie

4 Addition of Oil & Gas Dedicated Debt Advisory & Restructuring Practice Michael O’Hara – Biography & Experience

Michael O’Hara Oil & Gas Credentials US Co-Head Debt Advisory & Restructuring

◼ Joined Jefferies in September 2020 from PJT Partners, where he was a Partner in the Restructuring and Special Situations Group (re: Opti Canada)

◼ Mr. O’Hara assists in advising on a variety of restructuring and assignments for companies, creditors, corporate board committees, and acquirers and sellers of distressed assets

◼ He has served as a guest lecturer Other Notable Clients at the University of Chicago Booth School, Columbia Business School, the Wharton School at the University of Pennsylvania and many industry Sovereign Advisory conferences

◼ Before joining PJT, Mr. O’Hara worked in the M&A groups at Wasserstein Perella & Co. and Stephens Inc.

◼ Mr. O’Hara holds a BS in Sovereign Advisory Finance from Georgetown University and an MBA from Columbia Business School

5 Oil and Gas Macro Outlook

6 Long-Term Forecasts Indicate Oil and Gas Will Continue to Play a Foundational Role for Decades

Long-Term Global Oil Production Forecast (MMBbl/d) Long-Term Global Gas Production Forecast (Bcf/d)

120 525 5-Year 10-Year 20-Year 5-Year 10-Year 20-Year

Avg CAGR % 0.3% 0.2% 0.1% Avg CAGR % 1.1% 1.2% 1.1% 115 500

110 475

105 450

100

425 95

400 90 Even under the most bearish scenario, the Unanimous consensus for increasing global global economy is expected to require 375 gas demand over the coming decades 85 >90 MMBbl/d in 2040

80 350

75 325 2021 2024 2027 2030 2033 2036 2039 2021 2024 2027 2030 2033 2036 2039 EIA Energy Projection Equinor Energy Forecast EIA Energy Projection Equinor Energy Forecast BP Energy Outlook IEA Production Forecast BP Energy Outlook IEA Production Forecast Average Average

Sources: EIA, BP Energy Outlook, IEA, and Equinor Forecast.

7 Market Dynamics Support Long-Term Growth in Lower 48 Gas Production

Key Points

◼ While the transition toward increased use of renewable energy is underway and the cost of large-scale solar and wind technologies continues to decrease, there remains a multi-decade secular growth story for natural gas within the

◼ Adding to the long-term need for continued Lower 48 natural gas production growth is rapidly increasing demand from LNG exports and pipeline exports to Mexico, of which almost all will flow from Texas and specifically, the Permian Basin

Domestic Gas Consumption (Bcf/d) U.S. Gas Net Exports (Bcf/d)

Power Industrial Residential & Commerical Transportation & Other LNG Exports to Mexico 101

6 1 14 5 34 85 5 3

8 8 24

23 2019A 2040E CAGR 5k Power 30 35 0.70% 21

Industrial 23TBU 28 0.93% 28 CAGR table 23 Residential & 23 24 0.22% Commercial 26 Transportation 11 8 14 2.53% & Other

Total 85 101 0.86% 5 35 30

5

2019 Power Industrial Residential & Transportation 2040E 2019 LNG Exports to Mexico 2040E Commerical & Other

Source: EIA & Research. 8 International Trends in 2021

Theme Jefferies’ Commentary

◼ Sustained oil price recovery to $55-$60/bbl, with scope for a price spike

─ Medium term oil price is caught between $1 trillion dollars of underinvestment in supply and 2021 non-OECD demand recovery, catalyzed by a vaccine, and already evident in China Macro Known Unknowns? ◼ Gas market will tighten in 2021-2024, although not as much as oil, as LNG projects are delayed from COVID and LNG demand resumes 4-5% annual growth.

─ After 2024, c.105 mmtpa of new volumes from Qatar, Mozambique and US cap the market

◼ European Majors focus on M&A with utilities and securing renewable project exposure

─ Material disconnect in relative valuations, scarcity of opportunities and legacy coal, nuclear or city heating portfolios in many utilities Investors have a ◼ US big oil gets bigger Diverging Corporate choice in the next ─ Balance sheet used to drive portfolio high grading; cost synergies and enhanced ability to return capital Strategies cycle ◼ Formation of a class of super independents with scale, differentiated attributes (regional and/or technical), ROACE focus and ESG narrative (e.g. CCUS)

─ E&P continues in the US and picks up internationally

◼ Palpable sense of mini-majors and smaller independents being left behind in the recovery

◼ Irreversible commitments have been made by the Majors, even with improving commodity macro Ironically, the Decarbonisation Green Transition ─ Improvement in price will be an enabler of acquisitions or mergers with utilities (and avoid Class One transaction complexity) Momentum Needs a Higher Oil ◼ A higher oil price will be an enabler for to fund the transition Price ◼ Inconceivable for European Majors to make large upstream acquisitions

◼ Global deal pipeline is $160bn

◼ Despite making a big push in early 2020 to capitalize on COVID disruption, the Asian NOCs have not been successful in major M&A; nonetheless, they tend to perform better as pro-cyclical buyers and activity levels are still high. Many also have a home country advantage

◼ Poor returns and focus on ESG have made new energy capital formation difficult Divestments It Takes Two ─ A trend already established in 2019 when, on average, funds closed at 40% of initial target level; for the limited raises attempted in 2020 could be as low as 25%

◼ Reduced RBL availability particularly in and LatAm

─ Outside of the North Sea, the market for borrowing base facilities is markedly reduced as struggle with volatile prices, US E&P bankruptcies (40 to end Q3), ESG headwinds and higher syndication risk

9 Upstream Market Outlook

10 Current Themes in Upstream M&A and Capital Markets

Capital ◼ With E&P companies generally focused on reinvestment rates less than 80% and developing only their Budgets Are 1 highest returning inventory, capital budgets in 2021 are expected to remain slightly below 2020 levels Not Expected to Increase ◼ A sustained decrease in capital budgets presents a material tailwind for commodity prices in 2021

◼ While S&P 500 valuations are at all-time highs primarily driven by the tech sector and an expectation of Companies a broad economic recovery, E&P valuations have remained reasonable and have the most potential upside Have Shifted 2 in a recovery as a result of the industry’s transition to a FCF focused model Focus to FCF Generation ◼ Cash return to shareholders is expected to increase with the industry focused on FCF generation over production growth

Capital Is Slowly ◼ Both private capital and the high yield market is slowly returning to the E&P sector with an emphasis on 3 Returning to supporting growth for disciplined public and private operators and reducing RBL exposure the Sector

Commercial ◼ Since Q1 2020, , Citi, JPMorgan and Wells Fargo have in aggregate reduced their energy Lenders loan exposure by ~$12 Bn 4 Sharply ◼ Over time, RBL replacement capital will become a large portion of E&P company funding Reducing ◼ Jefferies has had active dialogue with the institutional market and believes an RBL replacement financing Exposure underpinned by strong asset coverage and structural protection is viable today

We Expect the Above Themes to Set Up a More Constructive Upstream Industry Backdrop in 2021

11 Low Capital Investment Will Remain in 2021

1 Capital Cuts Remain 2 FCF Model Emerging 3 Capital Returning 4 Commercial Lenders Retreating

Capital Cuts to Remain in Order to Facilitate Higher Cash Returns to Investors

Upstream E&P Sector Reinvestment Rate (1)(2) U.S. Lower 48 Horizontal Rig Count Remains Low

2017 - 2019 Avg. Current(3) 816 117%

71% 61% 378 287 160 108 72 71 64 51 46 40 13 23 27 9 10 25 5

2017 - 2019 Avg. 2020E 2021E Total Permian Others(4) Eagle Ford Appalachia Mid-Con Bakken Haynesville Niobrara

Significant Reduction in Capital in 2020 Is Likely to Remain ($ Bn)

$20.1 $19.7

Average capital budgets decreased ~45% in 2020 compared to 2017-2019 $14.3 $14.0 average and are expected to decrease by another ~10% in 2021

$11.2 $11.5

$8.8

$7.1 $6.1 $5.5 $4.9 $5.2 $3.5 $3.6 $3.5 $3.2 $3.2 $2.9 $2.7 $2.6 $2.4 $2.3 $2.3 $2.3 $2.2 $2.3 $2.1 $2.0 $1.9 $1.7 $1.8 $1.5 $1.8 $1.7 $1.3 $1.2 $1.3 $1.2 $1.3 $1.1 $1.1 $1.1 $1.0 $0.8 $0.6

XOM C VX C OP OXY E OG P XD FA NG A PA DVN TS X:OV V C LR MRO HE S E QT AR (5) (5)(6) (6) (5)(6) (6) (6) (6) (5) (5) (5)

2017-2019 Average CAPEX 2020E CAPEX 2021E CAPEX

Source: Baker Hughes, CapIQ estimates. (4) Includes Powder River Basin, Barnett, Fayetteville, California and other non-core regions. (1) Includes North America E&P companies >$0.5 B TEV and publicly traded since 2017. (5) Historicals and estimates reflect upstream capital only. (2) Estimate as of 12/14/2020. Calculated as EBITDA / CAPEX for respective time period. (6) Pro forma for material mergers including historical years prior to transaction close date. (3) Baker Hughes Rig Count as of 12/04/20. 12 Upstream Transitions to Model as Tech Boom Drags Broader Valuations Higher

1 Capital Cuts Remain 2 FCF Model Emerging 3 Capital Returning 4 Commercial Lenders Retreating

S&P 500 PerformanceS&P Performance Last Three YearshgkLast Three Years (1) S&P 500 ValuationS&P Last Valuation Three Years at All Time Highs (1) 100% 20x

S&P outperformance has been driven by the tech Relative to the broad markets at all time high valuations, 80% sector and expectation of a broad economic recovery 16x E&P companies make a compelling bet for recovery +94% 60% 12x

40% +39% 8x

20% TEV NTM / EBITDA 4x

-% Dec-17 Jun-18 Dec-18 Jun-19 Dec-19 Jun-20 - Dec-17 Jun-18 Dec-18 Jun-19 Dec-19 Jun-20 (20%) S&P 500 S&P Tech Index (2) S&P 500 S&P Upstream (3)

9.0x 1 E&P Companies Well Positioned for 2021

8.0x 9.0x 14.0% Constructive Valuations Free Cash Flow Generation Sustainable & Improving Capital Structures

7.0x 8.0x TEV / 2021E EBITDA 12.0% 2021E FCF Yield Net Debt / 2021E EBITDA

7.0x 6.0x

10.0% 9.4% 6.0x 5.6x 5.0x

8.0% 5.0x

4.0x

4.0x 6.0% 3.0x 2.3x 3.0x

4.0% 2.0x

2.0x

2.0% 1.0x 1.0x

0.0x 0.0x 0.0%

Companies have generated free cash flow and reduced ,Jan-19 while still trading at attractive valuations

Source: CapIQ, Company filings. (3) S&P Upstream includes integrated and pure-play E&Ps in S&P 500 index; XOM, CVX, COP, EOG, PXD, OXY, HES, (1) Market data as of 12/14/2020. CXO, FANG, COG, DVN, APA and MRO. Index is market cap weighted. (2) S&P Tech Index defined as components and holdings of XLK index. 13 Companies Adopting (& Validating) the Free Cash Flow-Focused …

1 Capital Cuts Remain 2 FCF Model Emerging 3 Capital Returning 4 Commercial Lenders Retreating

◼ Employing cash flow roll-up strategy ◼ Long-life, low decline production model ◼ Early adopter of FCF focused, modest Background that mitigates downside, while protecting ◼ Current management team began in August reinvestment rate business model 2018 upside; aggressive financing strategy

Financings (Since 2018) ✓ Support from Shareholders / Capital Markets

7 7 3 Transaction Volume (5 Common Equity / 1 Preferred / (3 ABS Issuances / 3 Follow-On Offerings / (Issued shares to sellers for two acquisitions / ATM Program) Acquisition Joint Venture) High Yield offering)

Proceeds / Commitments ~$220 MM ~$2,050 MM ~$505 MM

M&A (Since 2018) ✓ Active in M&A

Transaction Volume 7 (1) 8 5

Transaction Value $342 MM ~$1,623 MM ~$402 MM

Market Statistics

Market Capitalization (2) $370 MM $1,049 MM $1,885 MM

Enterprise Value(2) $547 MM $1,791 MM $2,136 MM

Select Metrics ✓ Attractive Valuations

2020 YTD (3) 39.5% 8.0% 65.0% Reinvestment Rate

LQA FCF Yield (2) 17.2% 21.3% (3) 10.1%

(1) Includes fee for service strategy and initial partnership with MCEP ($4 MM / year service fee and warrants struck at $4.00). (2) Market data as of 12/14/2020. (3) DGOC metrics based on 1H 2020 metrics. 14 Capital Slowly Returning to the E&P Sector

1 Capital Cuts Remain 2 FCF Model Emerging 3 Capital Returning 4 Commercial Lenders Retreating

Bank Disintermediation Private High Yield

◼ RBL lenders all in various speeds of ◼ Growth capital is available to disciplined public New Issue Activity Continues to Build ($MM) reducing/eliminating oil and gas exposure and private operators with a proven track record ◼ RBL extensions are universally more difficult and significant paydowns are being required to 2020 ◼ Significant opportunity exists to aggregate $19,900 get to desired outcomes in many cases high-quality, production-weighted assets YTD

◼ Over time, RBL replacement capital will become a large portion of company funding

Q4 $6,200 Case Study Case Study 2020(2)

◼ Callon issued $300 MM of Senior Second Lien ◼ Diversified (“DGO”) and Oaktree formed an Notes and sold an ORRI to Kimmeridge Energy acquisition joint venture to focus on mature, for $140 MM(1) PDP assets across the Lower 48 Q3 ◼ ◼ $5,550 The Company used the proceeds to repay DGO will acquire the assets on a 50% basis 2020 borrowings under its credit facility and earn an upfront and back-end promote

September 2020 October 2020

Q2 $3,600 2020

Q1 Joint Venture with $4,550 Private Placement of 2020 Second Lien Secured Notes Oaktree Capital Management L.P. and Royalty Interest Sale $300,000,000 FY $9,308 $140,000,000 $1,000,000,000 2019 Sole Financial Advisor Joint Financial Advisor (ORRI) Sole Financial Advisor

(1) The Senior Second Lien Notes included at the market warrants exercisable for approximately 15% of the Company’s pro forma issued and outstanding common . (2) Inclusive of Talos Energy which is currently in-market. 15 Commercial Lenders Have Been Swiftly Reducing Energy Exposure

1 Capital Cuts Remain 2 FCF Model Emerging 3 Capital Returning 4 Commercial Lenders Retreating

Key Points Bank’s Energy Exposure Continues to Sharply Decline

◼ Bank capital availability to upstream companies is Funded Exposure % of Total meaningfully constrained as a result of the 38% Decrease Since 2014 and 35% Decrease Since 2014 and significant losses, the prospect of future capital 16% Decrease since Q1 2020 8% Decrease since Q1 2020 markets fees being unclear and ESG considerations Q4 2014 6.4% ◼ Banks have made a concerted effort to reduce their Q1 2020 4.6% 4.2% energy (and specifically E&P) exposure since the Q3 2020 2.8% last downturn 2.1% 1.7% ─ Energy funded loans as a percent of total loans decreased ~38% and ~35% for large cap and Large Cap Banks (1) Mid Cap / Regional Banks (2) mid cap / regional banks, respectively (1)(2) ─ E&P funded loans as a percent of total loans E&P Exposure Has Been Reduced the Most in 2020 decreased ~31% for mid cap / regional banks, while large cap banks seek to reduce visibility of Mid Cap / Regional Banks Funded Exposure % of Total Loans (2) lending practices to the sector (1)(2) 31% Decrease Since 2014 and 21% Decrease since Q1 2020 ◼ Bank of America, Citi, JPMorgan and Wells Fargo have been the most aggressive in reducing energy 3.1% 2.7% exposure in 2020 having ~$12 Bn of reduction in 2.2% aggregate from Q1 to Q3 2020

At a recent conference hosted by the Dallas and Kansas City Federal Reserves, Wells Fargo Managing Director for Q4 2014 Mid Q1Cap 2020 Banks Q3 2020 Energy Credit and Risk Management Chris Holmgren said banks had essentially shut off the upstream segment after years of disappointment. The Largest Lenders Have Pulled Back the Most in 2020 Funded Energy Exposure - $ Bn (3) “The core reserve-based lending model began to break down. It became not successful in grasping the risks 26% Decrease Since 2014 and 17% Decrease since Q1 2020 involved in shale development,” he said. “Lenders began $24 Q4 2014 $19 $18 $15 $18 $16 $18 $16 $16 to realize that they made decisions based on exaggerated Q1 2020 $14 $11 $13 potential.” Q3 2020

(4) S&P Global Market Intelligence % of Total Loans Bank of America Wells Fargo JP Morgan December 7, 2020 Q4 2014 4.7% 2.7% 2.1% 2.1% Q1 2020 2.5% 2.8% 1.4% 1.5% Q3 2020 2.4% 2.4% 1.2% 1.3% Source: Company filings, presentations and earnings calls. (3) Energy Exposure defined as “Energy” of Bank of America, “Energy and ” for Citigroup, “Oil, Gas and Pipelines” for Wells (1) Large Cap Banks include as BAC, C, WFC, JPM, PNC, GS. Fargo and “Oil & Gas” for JP Morgan. (2) Mid Cap and Regional Banks include CMA, RF, ZION, BOK, FITB, CFR, HWC, CIT, TCBI, CADE and PB. (4) Does not include energy-related exposures classified in other industries. 16 Midstream Market Outlook

17 Current Themes in the Midstream M&A and Capital Markets

Broad-based Midstream industry grappling with excess capacity in the face of broad-based volumetric declines, Volumetric 1 including – for the first time in over a decade – the Permian Declines

Utilities Once a reliable buyer of high quality midstream assets, utilities are now focused on trimming midstream Exiting 2 exposure and divesting their asset portfolios Midstream

The total number of midstream M&A transactions was far fewer than in any year in recent memory, and Decreased those that did occur tended to be larger in size and tilted toward demand-pull businesses rather than those 3 M&A Activity with wellhead exposure. The market continues to expect significant consolidation but meaningful activity has not yet materialized

Investors Public and private midstream investors have increasingly transitioned away from yield-based valuations and Focused on 4 focused on free cash flow generation; companies responded with meaningful cost reductions and lower Cash Flow capital budgets Certainty

Global LNG regasification capacity under construction hit a 10-year high at 144 mtpa in 2020 and U.S. Growth in LNG 5 LNG exports hit at all-time high in early-December 2020 of ~11.5 Bcf/d

We Expect the Above Themes to Set Up a More Constructive Midstream Industry Backdrop in 2021

18 Declining Production Across All Basins Resulting in Under Utilization of Midstream Assets

1 Volumetric Decline 2 Utilities as Sellers 3 Decreased M&A 4 Reliable Cash Flows 5 LNG Growth

U.S. Production Forecast by Basin

Crude Oil (MMBbl/d) Natural Gas (Bcf/d)

CAGR 2019A 2021E

(0.1%) (7.3%) (15.3%) (1.5%) (0.5%) (5.6%)

4.3 4.3 32. 31.6 1

11. 1.4 4 1.2 1.4 9.6 0.8 0.7 0.7

2019APermian2021E 2019ABakken2021E 2019AEagle Ford2021E 2019ANiobrara2021E 2019AAppalachia2021E 2019AHaynesville2021E

Forecasted Long-Haul Crude Pipeline and Natural Gas Processing Plant Utilization

Crude Oil Long-Haul (MMBbl/d) Natural Gas Processing (Bcf/d)

98% 100% 88% 83% 85% 92% 80% 78% 85% 67% 65% 71% 70% 56% 54% 56% 2019A 2019A

2021E 2021E

Year Permian Eagle Ford Bakken DJ Year Permian Northeast DJ Bakken

Volumes 4.4 4.3 1.8 1.4 1.4 1.3 1.1 0.9 Volumes 15.1 15.7 10.9 10.9 2.8 2.5 2.2 2.5

Capacity 4.5 7.7 2.6 2.6 1.6 1.5 1.3 1.4 Capacity 19.0 22.2 10.9 11.8 3.6 4.4 2.6 3.6

Source: Wall Street research, presentations and SEC filings. 19 U.S. Utilities, Once Midstream Buyers, Now Exiting

1 Volumetric Decline 2 Utilities as Sellers 3 Decreased M&A 4 Reliable Cash Flows 5 LNG Growth

Key Points Utilities Were Historically An Active Acquiror in the Midstream M&A Market…

◼ Given their inherent $11.0 of natural gas, Select Midstream Aggregate Transaction Value utilities sought to M&A Transactions in Excess of $22 Bn acquire natural gas with Utility Providers midstream assets to $4.4 vertically integrate $2.3 $1.5 $1.3 $1.2 their business $0.3 $0.4 $0.3

◼ Between 2012 and 2019, Dominion, Year 2012 2013 2016 2016 2017 2018 2018 2019 2019 DTE Energy and Company OGE and CenterPoint, Dominion DTE acquires CenterPoint OGE, & DTE acquires acquires DTE acquires Dominion forms Dominion Enable acquires Haynesville acquired billions of ArcLight M3’s Enable acquires remaining WGL’s interest Blue Racer a JV acquires Velocity gathering Description combine assets Appalachia Align Midstream 39.1% stake in in the Stonewall dollars worth of with Caiman II Questar Energy Holdings system from M5 to form Enable assets Dominion Gas Gathering midstream assets and Indigo Midstream Midstream ─ More recently, their midstream …Recently Utilities Have Been Decreasing Midstream Exposure and, in Certain Cases, Affecting Full Midstream Exits segments have come to be $9.7 2020 + viewed as being Company at odds with ESG Date October 20, 2020 October 27, 2020 December 2, 2020 mandates in Intends to sell a Working towards addition to non-controlling minimizing exposure to $2.0 Announcement Midstream Spin-off interest in weighing on $1.2 midstream and weighing midstream and earnings and $0.3 sale of Enable creating LNG business unnecessary Year 2018 2019 2019 2020 “I don't expect we'll be making any further investments in those types of volatility gas transmission assets. We made those investments five to seven years Company ago, and at that time we – and frankly many others – viewed natural gas as Dominion sells having a fairly large role in the transition to the clean energy economy. Dominion sells Sempra sells gas transmission That view has largely changed, and natural gas, while it can provide 50% stake in non-utility US Dominion Sells and storage Blue Racer natural gas 25% Stake in emissions reductions, is no longer... part of the longer-term view.” Description assets to Midstream to storage assets to Cove Point Berkshire – Chairman, President and CEO John McAvoy k First Reserve ArcLight Hathaway

20 2020 Midstream M&A Was Dominated by a Few Large Transactions with Financial Buyers

1 Volumetric Decline 2 Utilities as Sellers 3 Decreased M&A 4 Reliable Cash Flows 5 LNG Growth

Key Points Asset-Level Midstream Transactions by Buyer Type ($ Bn)

◼ 2020 experienced a Three Deals with Financial fundamental shift in the In 2015, Strategics In 2017, ~40% of Strategics’ In 2018 & 2019, Private Accounted for ~90% of Transaction Value Came from Capital Accounted for >60% Buyers Have Accounted for types of buyers for Total Transaction Value Two Deals of Total Transaction Value the Overwhelming Majority of midstream assets and the 2020 Transaction Volume types of assets that have $24.9 drawn investor interest $20.9 $20.2 ─ Strategics have largely $17.2 spent the year on the $16.2 sidelines $19.4 $11.0 $7.6 $15.6 ─ Three deals with $1.2 $7.1 D / BRK $9.5 BX / CQP financial buyers account $0.8 $9.9 $8.7 RS / IMTT for >95% of 2020 M&A $6.3 $5.2 volume $0.8 2015 2016 2017 2018 2019 2020 ◼ Berkshire Hathaway’s Strategic Buyer Non-Strategic Buyer acquisition of Dominion’s midstream assets for $10 Bn Asset-Level Midstream Transactions by Asset Type (%)

◼ Brookfield / Wellhead M&A Was Almost Non-Existent in 2020, Whereas Transmission, Storage and LNG Represented Vast Majority of Transactions Blackstone Infrastructure’s 1.8% 0.3% 0.9% 7.6% 1.2%3.5% 0.6% 8.0% 8.1% acquisition of 2.9% 19.4% 12.8% Blackstone Energy’s 22.2% 36.8% 48.8% ~42% interest in 12.2% 12.1% 8.0% Cheniere Energy 1.2% Partners for $7 Bn 89.5% ◼ Riverstone’s 65.9% 66.9% 34.6% acquisition of IMTT for 58.4% 59.6% $2.7 Bn

◼ Dramatic shift to demand- 14.5% pull assets in 2020, with 2.1% very few G&P asset 2015 2016 2017 2018 2019 2020 transactions G&P Terminals LNG Transmission Compression Storage Other

21 Investors No Longer Rewarding Growth; Increasingly Focused Cash Flow Quality

1 Volumetric Decline 2 Utilities as Sellers 3 Decreased M&A 4 Reliable Cash Flows 5 LNG Growth

The Relationship Between Distribution Growth and Yield Has Faded

2014 (1) 2020 (1)

Company TEV / EBITDA Yield Dist. CAGR Company TEV / EBITDA Yield Dist. CAGR 30% ENB 12.9x 3.4% 18.9% 30% ENB 11.7x 7.2% 6.0% R² = 0.7184 EPD 15.9x 3.9% 6.2% R² = 0.1958 EPD 9.2x 9.3% 1.9% ETP 17.1x 6.0% 6.5% 25% 20% ET 7.9x 15.0% (11.2%) KMI 17.2x 4.3% 11.6% KMI 10.1x 6.6% 7.0% PAA 18.4x 5.1% 8.8%

20% PAA 7.5x 7.4% 3.3% Yr Yr CAGR

Yr Yr CAGR 10% - PSX 10.6x 1.9% 25.7% - PSX 10.0x 4.8% 1.0% TRP 13.7x 3.5% 6.8% 15% TRP 11.9x 5.2% 7.0% 0% 0% 10% 20% 30% 40% 50% 10%

(10%)

Distribution Distribution 3 Distribution Distribution 3 5% (20%) 21 Companies with No or 0% Negative Growth 0% 2% 4% 6% 8% 10% 12% (30%) Yield Yield

Expectations for Lower Production Growth Have Compressed Multiples for Volumetrically Exposed Midstream

YTD Price Performance Pure-Play Long-Haul Infrastructure Majority Long-Haul Infrastructure Majority G&P

0.2% (17.1%) (16.4%) (6.8%) (30.3%) (25.6%) (17.1%) (30.8%) (42.3%) 12.9x 11.2x 10.9x 10.0x 9.5x 9.4x 8.2x 7.8x 7.0x

Company LNG ENB TRP WMB KMI EPD DCP ENLC ENBL

% Take or Pay 91% 77% 80% 44% 70% 55% 14% 28% 35%

Source: Wall Street research. (1) Other companies include, but are not limited to: MMP, NS, CAPL, SUN, USAC, PBFX, CEQP, DKL, MPLX, HEP, NGL, WES, WMB, OKE, ENBL, DCP, GEL, etc. 22 Global LNG Demand Normalizing to Pre-COVID Levels

1 Volumetric Decline 2 Utilities as Sellers 3 Decreased M&A 4 Reliable Cash Flows 5 LNG Growth

Key Points Gas Prices by Region Gas Price by Region

◼ After significant cargo Henry Hub NBP TTF JKM cancellations due to $8 Spread COVID-19 amidst an overall $7 decline in international Asia vs Europe >$2.00 demand, US LNG is quickly $6 recovering to pre-COVID $5

levels MMbtu

$/ $4 Spread ◼ International pricing Asia vs Europe <$0.10 spreads have widened, $3 allowing for marketing arms to take advantage of pricing $2 $1 ─ As a result, both LNG inlet volumes and $- number of cargoes Jan-20 Feb-20 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 delivered recently hit all- time highs Record Overseas Demand for AmericanRecord Gas Overseas Demand for American Gas Pipeline Deliveries to U.S. LNG Export Terminals 12 Peak of ~11.5 Bcf/d U.S. LNG Cargoes Above Pre-COVID Levels 10 Nov-19 Nov-20 Inc / (Dec) % Sabine Pass 32 32 - 8 Cove Point 7 7 - Corpus Christi 11 14 27.3%

Bcf/d Cameron 4 14 250.0% 6 Freeport 3 14 366.7% Elba Island 0 3 NA 4

2

- Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20

Source: Bloomberg and EIA. 23 Significant Capital Investment and Public Policy Steps Support Long-Term LNG Demand

1 Volumetric Decline 2 Utilities as Sellers 3 Decreased M&A 4 Reliable Cash Flows 5 LNG Growth

Gas as % of Total Primary Pipeline Infrastructure Market Population Regas Capacity Coal to Gas Conversion Energy Demand Plans

165 15.0% 120 19.7 GW gas-fired plants under 1.4 Bn 7.8% Double by 2025 construction to replace coal-fired plants China 2019A 2030E 2019A 2025E

15.0% 100 million metric 57 1.4 Bn 6.0% 33 Double by 2024 tons converted to natural gas by 2030 India 2019A 2030E 2019A 2025E

25.5% 130 16.3% 126 5.7 GW of gas-fired 52 MM N/A plants to replace coal- fired plants by 2034 South Korea 2019A 2030E 2019A 2025E

Despite the Economic Challenges of 2020, Global LNG Regasification Capacity Additions are the Highest in Ten Years

LNG Regasification Capacity Under Construction and Planned by 2025

65 Under Construction Regasification Capacity (mtpa) 60 ~144 mtpa of new regasification capacity is Under-construction 50 under construction in 2020, which is equivalent Newbuild Terminals Expansion of Existing Terminals Total Planned 55 to 40% of the 2020 global LNG supply 33 93 51 45

40 mtpa 35 30 25 20 15 10 5

-

India

China

Brazil

Benin

Japan

Ghana

Turkey

Cyprus

Kuwait Poland

Taiwan Greece

Croatia Mexico

Bahrain

Panama

Vietnam

Morocco

Thailand Pakistan

Germany Australia

Myanmar

Sri Sri Lanka

Indonesia

Philippines

El El Salvador Mozambique

Source: Bloomberg, World Bank, International Gas Union and Cheniere investor presentations. 24 Oilfield Services Market Outlook

25 Current Themes in the Oilfield Services

Notwithstanding the recent oil price rally, E&P operators continue to work through a volatile Commodity Price commodity price environment that continuously balances an anticipated economic recovery Volatility and Macro 1 driven by the proliferation of COVID-19 vaccinations and a “return to normal” against the threat Outlook of economic disruptions from rising infections and potential economic shutdowns

Significant Reduction in In response to sharply lower commodity prices, E&Ps rapidly reduced capital spending E&P Capital Spending 2 programs resulting in a new “lower for longer” activity environment that most acutely impacted and Oilfield Service U.S. shale; market currently anticipating a recovery to take hold in 2H 2021 Activity

Diminished cash flow profiles, significant debt maturities and limited capital markets access Restructuring Underway accelerated Q2 and Q3 2020 corporate ; outlook suggests distress likely to 3 and More to Come continue into 2021, which risks another wave of bankruptcies given 2021 and 2022 debt maturity wall

Against this challenging backdrop, oilfield services M&A activity has suffered, but consolidation is M&A Activity Has expected to accelerate in 2021 as service providers seek to enhance scale, rationalize Lagged But Expected to 4 oversupplied markets and drive synergies in a difficult operating environment that includes an Accelerate increasingly consolidated customer base

ESG and Energy The recent downturn has accelerated oilfield service providers’ participation in the energy 5 Transition Initiatives transition movement in an effort to repurpose valuable expertise, replace shrinking traditional Have Begun In Earnest oil and gas revenue and satisfy key stakeholder concerns

We Expect the Above Themes to Set Up a More Constructive OFS Industry Backdrop in 2021

26 Oilfield Service Price Performance

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives Over the last five years, oilfield services has broadly underperformed commodity prices as well as the upstream and midstream subsectors

OSX Price Performance vs. Various Indices – Last 5 Years

250%

200% S&P 500: 79%

150%

NYMEX Gas: 16% 100% NYMEX Oil: (20%) S&P 500 Energy: (34%)

50% Alerian MLP ETF: (47%) SPDR E&P ETF: (54%) OSX Index: (72%) 0% Dec-15 Dec-16 Dec-17 Dec-18 Dec-19 Dec-20

OSX Price Performance vs. Various Indices – 2019 to Present OSX Price Performance vs. Various Indices – YTD

160% 160% S&P 500: 47% 140% 140%

120% 120% S&P 500: 14% NYMEX Gas: 10% 100% 100% NYMEX Oil: (8%) NYMEX Oil: (18%) NYMEX Gas: (16%) Alerian MLP ETF: (35%) 80% S&P 500 Energy: (30%) 80% Alerian MLP ETF: (36%) S&P 500 Energy: (35%) 60% SPDR E&P ETF: (44%) 60% SPDR E&P ETF: (38%) OSX Index: (45%) OSX Index: (44%) 40% 40%

20% 20% Dec-18 Mar-19 Jun-19 Sep-19 Dec-19 Mar-20 Jun-20 Sep-20 Jan-20 Apr-20 Jul-20 Oct-20

Source: CapitalIQ database. Market data as of 12/07/20. 27 E&P Capital Spending Outlook

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives Currently the Market Expects 2021 E&P Capital Budgets to be Relatively Flat Compared to 2020 levels, however Budgets remain ~ $150 Billion below 2019 Spending

Key Points ~ Upstream Investment by Supply Source ($ Billions)

◼ In response to the precipitous crude oil price decline, E&Ps dramatically $884 reduced 2020 capital budgets by ~$165 billion and are expected to cut 2021 budgets by a further ~$10 $658 ~$170 Billion Decline billion $558 $522 $543 $502 $491 $491 ─ Current outlook suggests modest $422 recovery in 2022 with E&P $378 $371 spending remaining below pre- pandemic levels through 2024

◼ Cuts most acutely focused on U.S. shale which have fallen ~$75 billion from 2019 levels, a year-on-year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 decline of more than 50% Other Onshore Oil Sands Shale/Tight Oil Offshore Shelf Offshore Deepwater ◼ Offshore to see more moderate cutbacks ($25 – $35 billion), with reductions mainly to exploration and Upstream Investment vs. 2019 Levels Upstream Investment by Supply Source infill drilling programs

2020 vs. 2019 2021 vs. 2019 2020 vs. 2019 - 2024 2019 CAGR

($73) ($73) Offshore Deepwater (18.4%) 2.2%

Offshore Shelf (17.8%) 0.6%

($64) ($67) Oil Sands (40.3%) (0.1%)

($28) ($33) Other Onshore (25.3%) (2.0%) ($165) ($172)

Shale / Tight Oil Other Onshore(1) Offshore (2) Shale / Tight Oil (51.7%) (6.4%)

Source: Rystad Energy. (2) Includes Offshore Shelf and Offshore Deepwater. (1) Includes Oil Sands and Other Onshore. 28 U.S. Onshore Drilling Rig Outlook

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives

Key Points U.S. Onshore Rig Count(1)

◼ U.S. rig count now stands at 323, falling 1,938 ~450 rigs since mid- March, which represents the steepest and deepest rig count decline in the unconventional era 1,045 990 1,026 967 925 896 ─ However, U.S. rig 798 767 756 813 count has steadily 629 686 recovered since early 538 486 501 543 386 416 September 253 266 ─ Rig Count has increased by 79 rigs

by mid-December

2014 2015 2016 2017 2018

1Q19 2Q21 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 3Q21 4Q21 1Q22 2Q22 3Q22 4Q22 from August lows, and 2Q19 has experienced 13 straight weekly increases(2) Comparison of Horizontal Rig Count Declines from Peak Horizontal Rig Count Rolling 2-Week Percent Change

◼ The near-term onshore 100% drilling outlook remains 10% challenged under a range of scenarios 5% 80% ─ Initial declines - % surpassed original (27%) downside expectations 60% (5%) ─ Outlook for rig count (43%) to remain depressed (54%) (10%) in Q4 2020 with a 40% (58%) (15%) more meaningful (57%) recovery occurring in (20%) Q1 2021 and beyond 20% (25%) 0 13 26 39 52

Current October 2008 November 2014

Jul-19 Jul-20

Apr-19 Oct-19 Jan-20 Oct-20

Jun-19 Jun-20

Feb-19 Feb-20

Mar-19 Nov-19 Mar-20 Nov-20

Dec-18 Aug-19 Dec-19 Aug-20 Sep-20 May-20 August 2015 January 2019 May-19

Source: Rystad Energy ShaleIntel, Baker Hughes Rig Count, Spears and Associates and company filings and presentations. (1) Forecast represents Rystad Energy Base Case which includes 2020, 2021 and 2022 WTI prices of $37/Bbl, $44/Bbl and $66/Bbl, respectively. (2) Per Baker Hughes rig count as of December 11, 2020.

29 U.S. Completion and Pressure Pumping Outlook

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives

Key Points Pressure Pumping Horsepower Supply vs. Demand (MM HHP)

◼ Completion activity has rebounded 25 from the April / May 2020 trough, as operators elected to accelerate completion of DUC inventories after 20 instituting a “frac holiday” in Q2 2020

─ However, current and future activity 15 17.7 16.3 16.8 levels expected to remain well below 15.4 15.7 pre-pandemic levels 15.0 14.7 13.3 ◼ Completion activity likely to outpace 10 11.9 drilling activity due to drawdown of 9.9 10.3 DUC inventory 8.2 5 6.4 ◼ Outlook for pressure pumping demand 4.7 5.4 to increase more meaningfully, 4.4 beginning in Q1 2021 as operators 0 reset their capital budgets 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 Active Warm-Stacked Cold-Stacked Demand

Q4 2020 Hz DUC Inventory Lower 48 Horizontal Wells Frac’d (1)

15,039 14,262 14,012

Other 11,947 24% 10,112 10,146 9,494 8,536 7,921 Permian 8,499 43% 8,085 6,832 5,105 5,074 5,532 Marcell 6,237 5,240 4,873 4,654 us 4,156 8% 3,107 2,865 6,091 2,919 5,545 5,726 5,007 5,072 Bakken 3,862 3,845 2,425 2,375 2,676 10% DJ 1,953 Basin 15% 2017 2018 2019 1Q20 2Q20 3Q20 4Q20 1Q21 2Q21 3Q21 4Q21 Permian Other Lower 48 Basins

Source: EIA and Rystad Energy ShaleIntel. (1) Base case assumes WTI prices of $37/Bbl and $44/Bbl in 2020 and 2021, respectively. Quarterly figures were annualized for comparison purposes.

30 Lower 48 Well Count and Production Outlook

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives

Key Points U.S. Oil Production Installed Base of Producing Wells (000s)

◼ U.S. oil production remains Historical Projected relatively resilient and is 14 1,027 expected to largely maintain 993 982 current production levels, 928 depending on the commodity price outlook 12 ◼ In September, the domestic oil product rebounded to nearly 11MMBbl/d as production growth from the GoM outpaced 10 modest production declines from Lower 48 onshore sources

─ Since then, production has held flat around 11MMbbl/d 8

◼ Expectations for Lower 48 2009 2012 2015 2018 onshore production to remain in the 8.5 – 9.0MMBbl/d range 6 through 2021 New Wells Drilled – Lower 48 by Play

─ Similar outlook for GoM and Alaska production which are 18,457 expected to maintain 4 current levels of 1.7 – 2.0MMbbl/d and 12,446 ~0.5MMBbl/d, respectively

◼ Outlook suggests a more 2 8,118 constructive environment for 7,167 production focused services versus those that are more drilling & completion-driven 0

─ Supported by installed base

Jun-19 Jun-17 Jun-18 Jun-20 Jun-21

Dec-16 Mar-17 Dec-17 Mar-18 Dec-18 Mar-19 Dec-19 Mar-20 Dec-20 Mar-21 Dec-21

Sep-18 Sep-19 Sep-20 Sep-21 of nearly one million Sep-17 2019 2020 2021 2022 producing wells Lower 48 Onshore GoM Alaska Permian Eagle Ford Appalachia Bakken Other

Source: Company filings, Wall Street research, EIA and Rystad Energy ShaleIntel.

31 Offshore Project Outlook

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives

Key Points Global Offshore Commitments by Breakeven Price ($Bn) FIDs – Delayed / Postponed

◼ In response to recent $150 Asset Country Operator headwinds, E&Ps quickly reduced capital budgets, Atlanta FDS Brazil Enauta which included delaying 120 certain projects expected Barossa Australia Santos to be sanctioned in 2020 90 ─ 19 high profile projects Bay du Nord Canada Equinor have already been postponed 60 Browse Australia Woodside ─ Operators reworking development plans to Cambo (Phase 1) U.K. Siccar Point optimize costs for the 30 new commodity price Claire South U.K. BP regime 0 Crux Australia Shell ◼ Meanwhile, several 2017 2018 2019 2020 2021 2022 2023 2024 2025 projects sanctioned in >$60/Bbl $40 - $60/Bbl <$40 / Bbl Sactioned Jackdaw U.K. Shell early 2019 are likely to move forward, although Neptun Deep Romania ExxonMobil timelines may be delayed Global Offshore Commitments by Depth ($Bn) not only by reworked North Platte U.S. Total project parameters but also by social distancing $150 Pecan Ghana Aker Energy restrictions slowing construction and drilling 120 Platypus U.K. KNOC / Dana ◼ Expectation for 2020 FIDs to total approximately Pluto Train 2 Australia Woodside $25Bn versus more than 90 $100Bn of new project Rovuma LNG (Area 4) Mozambique ExxonMobil investments in 2019 60 ◼ Increasing probability that Scarborough Australia Woodside activity will improve in Sea Lion Falkland Islands Premier Oil 2021; however, likely to 30 require Brent prices above $45/Bbl Shenandoah U.S. LLOG 0 ─ Current outlook Structure A and E Libya Eni suggests FIDs recover 2017 2018 2019 2020 2021 2022 2023 2024 2025 to $70Bn in 2021 Shelf Deepwater Whale U.S. Shell

Source: Wall Street research and Rystad Energy.

32 Offshore Activity Outlook

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives

Key Points Floater Market Outlook – Floaters Demand (Rig Years) Jackup Market Outlook – Jackup Demand (Rig Years)

◼ While many FIDs have been delayed, a significant amount of development 300 450 activity is expected to move forward in 2021, providing a demand floor until a 250 400 potential recovery 200 ─ Operators restriction of exploration 350 330 317 spending in 2020 expected to 142 309 315 150 129 124 304 304 continue in 2021 109 110111 287 103 300 ◼ Outlook for floater demand to decline 100 to nearly 100 rigs years, differing 250 opinions regarding timing (trough 50 reached in 2021 vs. 2022) 200 ─ In the near-term, activity to skew 0

towards mid- and deepwater projects

2021 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2022 2023 2024 2025

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 ◼ Outlook for jackup demand reflects a Historical Rystad Base Case Historical Rystad Base Case similar dynamic and is expected to decline to nearly 285 rigs years in (1) (1) (1) (1) 2021 and slowly recover thereafter Floater Dem. by Activity Floater Dem. by Geography Jackup Dem. by Activity Jackup Dem. by Geography

─ As was the case during the prior 300 300 450 450 downturn, the jackup market saw a 400 400 shallower demand decline due to 250 250 the resilient nature of shallow water 350 350 projects; benefit from existing 200 200 300 300 infrastructure, shorter development cycles and lower costs 250 250 150 150 ─ Jackup demand also benefits from 200 200 strong NOC demand, which tends to be less cyclical, helping to stabilize 100 100 150 150 utilization in key markets (i.e., 100 100 , Asia Pacific, Mexico) 50 50 50 50

0 0 0 0 2010 2015 2020 2025 2010 2015 2020 2025 2010 2015 2020 2025 2010 2015 2020 2025 Brazil US GoM Middle East Southeast Asia Development Exploration Norway West Africa Development Exploration China Mexico Other N. Sea Other India Other

Source: Wall Street research and Rystad Energy. (1) Per Rystad Energy Base Case forecast.

33 Summary of Distressed OFS Situations

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives

Key Points Selected Reorganizations in Progress Emerged / Auctioned

◼ Through November, ~$41Bn of total oilfield services liabilities filed for bankruptcy in 2020

─ Compares to ~$13Bn in 2016 and ~$35Bn in 2017 total liabilities restructured

◼ Pace of bankruptcy filings accelerated in Q2 and Q3 2020, which saw 11 and 27 oilfield services bankruptcies, respectively

◼ Diminished cash flows as a result of a “lower for longer” activity environment, risks Number of Oilfield Services Bankruptcies Value of Oilfield Services Bankruptcies ($Bn) another wave of bankruptcies given the sector’s 2021 and Cumulative Bankruptcies New Bankruptcies Since Previous Quarter Secured Unsecured 2022 debt maturity wall $41.2 300 12 $35.3 27 250 11 6 7 200 11 $12.2 $26.2 3 1 3 1 9 4 4 15 150 15 13 12 20 $13.5 100 26 14 $5.7 $23.0 $8.1 13 50 11 $5.3 $15.0 9 $3.9 $2.0 $7.8 $0.9 $7.7 0 $3.3 $3.0 $0.3

2015 2016 2017 2018 2019 YTD 2020

Q1 2016Q1 2020Q1 Q1 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q2 2020 Q3 2020 Q4 2020

Source: Haynes & Boone, LLP Oilfield Services Bankruptcy Tracker (November 2020) and company filings. 34 Significant Slowdown in Oilfield Services M&A Activity

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives

Key Points Oilfield Services M&A Activity(1)

◼ Oilfield Service M&A transaction Transaction Value Technip / FMC: $6.8bn McDermott / CB&I: $3.7bn Number of volume decreased for the third straight ($ billions) Transactions(2) year to the lowest level in recent history 120 GE / Baker Hughes: $33.9bn John Wood / AMEC: $3.9bn 160

─ 32 transactions greater than $10 $107.6 Ensco / Rowan: $4.2bn million announced in 2020 vs. 74 SLB / Cameron: $14.8bn in 2019 and 96 in 2018 100 Apergy / ChampionX: $4.4bn ◼ Largest 2019 OFS transactions Siemens / Dresser-Rand: $7.6bn include: 118 Keane / C&J: $0.7bn ─ Apergy / Ecolab’s ChampionX 120 Tenaris / IPSCO: $1.2bn ($4.4Bn) 104 $80 ─ Tenaris / IPSCO ($1.2Bn) 96 Liberty / SLB PP: $0.4bn ─ Keane / C&J ($0.7Bn) Caterpillar / Weir O&G: $0.4bn ─ DP World / Topaz Energy and Marine ($1.1Bn) 60 74 80 ◼ Largest 2020 OFS transactions include: $44.2 72 $44.3 ─ Liberty / Schlumberger Pressure 54 Pumping ($0.4Bn) 63 40 ─ Caterpillar / Weir Oil & Gas 43 41 $33.5 ($0.4Bn) $28.3 32 40 ◼ Expectations for rebound in Oilfield $21.5 Service M&A activity in 2021 as 20 $16.8 restructured companies emerge from bankruptcy $10.5 $5.7 $2.7 0 0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Corporate Asset JV Deal Count

Source: PLS database. (1) Includes water services and infrastructure transactions. (2) Includes transactions with reported transaction values greater than $10 million.

35 Oilfield Service Participation in ESG and Energy Transition

1 Macro Outlook 2 Decline in Activity 3 Restructuring Underway 4 Decreased M&A Activity 5 Increase in ESG Initiatives

Key Points 1 ESG Initiatives for Legacy Hydrocarbon Development ◼ Oilfield services companies Focus Area Select Companies Commentary have begun to strategically ramp up clean energy ◼ Flaring, venting and leaks account for more than half of oil-related emissions initiatives Minimizing Flaring, ◼ To reduce flaring, eliminate venting and pinpoint fugitive emissions, OFS companies have Venting & Fugitives ◼ Given applied expertise in begun developing advanced sensing, control and capture technologies EPCI and O&M support, oilfield service providers are ◼ uniquely positioned to The provision of fuel is one of the principle costs facing well service operators actively participate in the Utilizing Wellhead ◼ Recognizing the financial and environmental implications of diesel fuel, OFS companies have energy transition Gas as Fuel Source started to use wellhead gas to fuel operations at a well site, most clearly evidenced by the proliferation of electric frac equipment ◼ Several companies have recognized the potential to ◼ Unconventional development has rapidly expanded the industry’s water footprint supplement shrinking ◼ To mitigate issues of sustained freshwater sourcing and wastewater treatment, service providers upstream revenue with Recycling of Water have started to treat and reuse wastewater emerging clean energy projects ◼ With the surge in freshwater prices, recycling produced and flowback water can also lower costs

◼ Most immediately, the industry can participate in 2 Energy Transition and the Intersection with Oilfield Service Companies the energy transition through two primary avenues: Focus Area Select Companies Commentary

─ Improved operational 1 Carbon Capture ◼ Carbon capture technologies are a critical component to reaching long-term emissions targets efficiency and solutions for legacy hydrocarbon and Storage ◼ With expertise in gas compression & processing, pipelines, petroleum EPCI and geoscience, development (“CCUS”) oilfield service providers are qualified to execute CCUS projects at an industrial scale

─ Application of seasoned 2 ◼ Wind provides a unique opportunity for unlocking supplemental revenue streams, especially for expertise to clean energy offshore service providers that have experienced substantial activity reductions from prior peak infrastructure development Offshore Wind ◼ Due to the overlap of equipment, engineering & construction and operations & maintenance, ◼ Stemming from initial ESG OFS companies have begun to spearhead EPCI and O&M projects for commercial scale offshore initiatives, several oilfield wind projects services companies have pledged meaningful long- ◼ Oilfield EPCI and O&M expertise also translates well to the solar market term carbon footprint EPCI and O&M for ◼ The overlap of equipment, including converter & inverters, switchgear and electrical equipment, reduction targets Solar Installations well positions OFS companies to assist in the develop solar infrastructure ◼ Certain service companies have undertaken EPCI roles in solar project development

Source: Rystad Energy and other publicly available information.

36 Leveraged Finance and Restructuring Outlook

37 Current State of Liability Management Transactions

1 Bonds Remain Primarily in the Hands of Long-Term, Real-Money Investors

◼ Unlike previous credit cycles, large asset managers continue to hold the majority of the outstanding stressed and distressed notes outstanding

◼ With limited investor turnover, basis remains elevated thus increasing the difficulty to execute liability management transactions 2 Investors are Unwilling to Crystallize a Loss and Take a Discount to Solely Benefit the Equity

◼ Investors will entertain par exchanges which may be enhanced by equity upside

◼ There is a willingness to aid companies with a large, transformational recapitalization; however, these are complicated transactions and require significant coordination

3 Ad Hoc Creditor Groups are Forming Quickly and are Holding Their Ground

◼ Given the number of stressed and distressed credits along with investor connectivity, Ad Hoc credit groups are forming quickly

◼ The creditor groups have been reticent to break rank once formed

4 Alternative Capital Providers Offer Flexible Solutions via Asset and Equity Consideration

◼ Alternative capital providers are willing to take a creative approach to create mutually-attractive financing solutions

◼ The ability to pair cash flowing assets and equity / equity-like securities is an appealing path to create value for investors while reducing the to

Source: Jefferies Restructuring Group. 38 Key Recent Upstream Contract Rejections / Renegotiations

◼ Distressed upstream businesses increasingly looking to midstream providers for concessions in various forms including: (i) rate reductions, (ii) volume commitment changes and (iii) drill incentives, among others

◼ Midstream businesses have started to actively negotiate with upstream companies and potential buyers in a number of situations as an alternative to litigation

◼ The significant in court issue remains the argument regarding contracts that have covenants running with the land such as Chesapeake, Extraction, and Southland and the different jurisdictions that the law is being interpreted

◼ Additionally, interstate pipelines regulated by FERC have been rejected in several cases and are currently on appeal

E&P Operator

Midstream Service Provider

Date Filed ◼ 1/27/2020 ◼ 5/14/2020 ◼ 6/14/2020 ◼ 6/28/2020 ◼ 11/13/20

Court ◼ Delaware ◼ Texas ◼ Delaware ◼ Texas ◼ Texas

Judge ◼ Karen Owens ◼ Marvin Isgur ◼ Chris Sontchi ◼ David Jones ◼ David Jones

◼ Firm transportation contract on the ◼ Extraction attempting to reject ◼ ETC inter-state firm transportation Rockies Express pipeline that numerous contracts in bankruptcy ◼ Immediately moved to reject 6 of contract for Haynesville assets shipped gas east 17 long-haul gas transportation ◼ 2 G&P agreements with minimum Description ◼ Focus thus far has been on oil contracts across 4 different volume commitment ◼ Williams (Access) gathers and ◼ G&P contract with Pinedale LGS gathering and transportation processes volumes across the midstream operators as well as 3 that gathered infield volumes; agreements (Grand Mesa/NGL, Chesapeake legacy asset base G&P agreements assets previously owned by UPL Elevation, and ARB Midstream)

◼ Week long trial in Delaware court in ◼ Two key elements of the rejection ◼ On October 14, Judge Sontchi ◼ On October 28, Judge Jones ◼ Plan approval conditioned on 50% September include: (i) satisfaction of the ruled that Grand Mesa (NGL), approved CHK’s motion to reject its reduction of firm transportation business judgement standard Platte River/DJ South (ARB gas purchase agreement with ETC, reservation fees ◼ Of the two gathering agreements, (estate better off) and (ii) no Midstream), and Elevation ruling that the contract does not Southland is trying to reject the interruption of gas supply to contracts do not create covenants establish a covenant “running with ◼ Rejected long-haul contracts contract with less-favorable terms customers as a result of the “running with the land” the land” include Rockies Express (Tallgrass/P66), ANR Pipeline ◼ Bank syndicate arguing to reject the rejection ◼ On November 2, Judge Sontchi ◼ Decision currently on appeal (TCP), two Texas Gas contracts contract as it has transferred value ◼ Rockies Express contract was granted Extraction’s motion to (TCP), and Rover (ET) to Williams that would otherwise be rejected reject its transportation services ◼ On December 17, Williams subject to liens from their loan agreements, applying the received court approval of a global ◼ Filed an adversary proceeding Commentary ◼ Pinedale LGS contract (structured deferential business judgment resolution it reached with against Midship (Cheniere) seeking as a leaseback financing) was due standard instead of a heightened Chesapeake to end litigation punitive damages for an improper to be rejected, however, the system public interest standard that was draw of letters of credit was acquired by UPL in bankruptcy requested by midstream ◼ Rejected G&P agreements includes for $18 MM (original lease required counterparties annual payments of $20 MM Rice Olympus Midstream (Equitarns), Strike Force through 2027) ◼ Extraction rejected its Grand Mesa and Platte River contracts; however, (Equitrans), and DCP NGL Services ◼ FERC has filed two appeals: (i) the company reached an agreement (DCP) related to the ruling and (ii) related with Elevation prior to ruling that to the bankruptcy courts ability to included a settlement with a reject FERC-regulated contracts damage claim

39