First Quarter 2018 Supplemental Presentation

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1 First Quarter 2018 Supplemental Presentation

2 Forward-Looking Statements and Risk Factors Statements made in this presentation that are not historical facts are forward-looking statements. These statements are based on certain assumptions and expectations made by the Company which reflect management s experience, estimates and perception of historical trends, current conditions, and anticipated future developments. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to financial and operational performance and results of the Company and Roan Resources LLC, timing of and ability to execute planned separation transactions and asset sales, continued low or further declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to hedge future production, ability to replace reserves and efficiently develop current reserves, the capacity and utilization of midstream facilities and the regulatory environment. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Please read Risk Factors in the Company s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and other public filings. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. Reserve Estimates The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC s definitions for such terms. The Company may use terms in this presentation that the SEC s guidelines strictly prohibit in SEC filings, such as estimated ultimate recovery or EUR, resources, net resources, total resource potential and similar terms to estimate oil and natural gas that may ultimately be recovered. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves as used in SEC filings and, accordingly, are subject to substantially greater uncertainty of being actually realized. These estimates have not been fully risked by management. Actual quantities that may be ultimately recovered will likely differ substantially from these estimates. Factors affecting ultimate recovery include the scope of the Company s actual drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, actual drilling results and recoveries of oil and natural gas in place, and other factors. These estimates may change significantly as the development of properties provides additional data.

3 Non-GAAP Measures Adjusted EBITDA(X) The non-gaap financial measure of adjusted EBITDA(X), as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, this non-gaap measure should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP. Adjusted EBITDA(X) should not be considered in isolation or as a substitute for GAAP. Adjusted EBITDA(X) is a measure used by Company management to evaluate the Company's operational performance and for comparisons to the Company's industry peers. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results. PV-10 PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows. The Company s calculation of PV-10 herein differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is calculated before income taxes and including the impact of helium, rather than after income taxes and not including the impact of helium, using the average price during the 12- month period, determined as an unweighted average of the first-day-of-the-month price for each month. The Company s calculation of PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC.

4 Recent Highlights Announced strategic plan to separate into two public companies, Roan Resources ( Roan ) and Riviera Resources ( Riviera ) during midsummer 2018 Completed strategic divesture program resulting in ~$2 billion of closed or announced asset sales Strong balance sheet with no debt and a first quarter ending cash balance of approximately $227 million Returned more than $600 million of capital to LINN shareholders through share repurchases Blue Mountain Midstream ( Blue Mountain ) anticipates to commission Chisholm Trail cryogenic plant by the end of the second quarter Once the plant reaches full capacity, forecasted to generate annualized adjusted EBITDA of $100 million $125 million Outperformed guidance on production, operating expenses and adjusted EBITDAX for the quarter. Estimated Pro-Forma EBITDAX of $133 million - $138 million, see slide 15 for reconciliation 3

5 Strategic Update Proposed Separation Into Two Public Companies Mid-summer 2018 LNGG RVRA Mid-Continent - NW STACK - Arkoma STACK Hugoton / Jayhawk Plant East Texas North Louisiana Michigan / Illinois Drunkards Wash 50% Equity Interest ROAN Merge/SCOOP/STACK Pure Play Growth Company Blue Mountain Midstream LLC Chisholm Trail System - Gathering - Processing 4

6 Overview of LINN s Assets Roan Resources LLC Merge/SCOOP/STACK pure play company LINN holds 50% of the equity interest Current net production of ~ 38,000 BOE/d 11 DUCs as of 3/31/18 6 active drilling rigs and 2 active frac fleets Riviera Resources, Inc. Upstream assets: Mid-Continent NW STACK Arkoma STACK Hugoton East Texas North Louisiana Michigan / Illinois Drunkards Wash Midstream assets include Jayhawk Plant in Hugoton Basin Net Production: ~323 MMcfe/d (1) This company upon separation is expected to have no debt and assets that generate significant free cash flow Drunkards Wash Hugoton Jayhawk Plant Michigan / Illinois NW STACK Roan Resources LLC Blue Mountain Midstream LLC Chisholm Trail System Current 60 MMcf/d refrigeration facility Constructing a 250 MMcfe/d Cryogenic Plant that will be commissioned by end of 2Q 2018 More than 80,000 net acres dedicated At full capacity the Chisholm Trail system could generate annualized EBITDA between $100 $125 million With the forecasted growth from its currently dedicated acreage position, anticipate the need to expand the cryogenic plant Blue Mountain Midstream LLC Arkoma North Louisiana East Texas (1) Average volumes from the first quarter of 2018, excluding volumes before closing for the following: OK Waterfloods closed 2/28/18, TX Panhandle Shallow closed 2/28/18, Permian W TX Conventional closed 3/29/18, Altamont Bluebell closed 4/4/18, Permian NM closed 4/10/18 5

7 Asset Sales Update ~$2 billion of closed asset sales Jonah Altamont Bluebell Williston Salt Creek Washakie ~1.5x Proved Developed PV-10 (1)(2) California TX Panhandle Permian Oklahoma Waterfloods South Texas Closed Transactions Proved Developed PV-10 $3 / $50 $ in millions Contract Price $ in millions Estimated Proceeds $ in millions Jonah $ 369 $ $ 559 Salt Creek $ 54 $ 71.5 $ 73 California $ 294 $ 363 $ 343 South Texas $ 61 $ 58 $ 50 Washakie $ 102 $ 200 $ 193 Williston $ 186 $ 285 $ Total (1) $ 1,066 $ 1,559 $ 1,473 Oklahoma Waterfloods $ 35 $ 42 $ 38 Texas Panhandle $ 63 $ 80 $ 74 Altamont Bluebell $ 45 $ 132 $ 127 Permian (3) $ 123 $ 174 $ Total (2) $ 266 $ 428 $ 401 Grand Total $ 1,332 $ 1,987 $ 1,874 (1) YE 2016 proved reserves as of the effective date of each deal with updated pricing of $3.00 per MMBtu for natural gas and $50.00 per bbl for oil (2) YE 2017 proved reserves as of the effective date of each deal with updated pricing of $3.00 per MMBtu for natural gas and $50.00 per bbl for oil (3) Includes $37 million of contract price and $36 million of estimated proceeds that closed in

8 Roan Resources Focused on the accelerated development of the prolific Merge/SCOOP/STACK play June 2017 LINN & Citizen sign a Contribution Agreement to form a Merge/SCOOP/STACK pure play company Each receive 50% of the equity interest Approximately 140,000 total net acres(1) Aug-Sept 2017 Closed on the transaction to form Roan Established a separate $200 million credit facility Appointment of new Roan Board of Directors Net production of ~23,500 BOE/d in September Nov-Dec 2017 Tony Maranto named as CEO along with two Executive Vice Presidents Acreage increased to approximately 150,000 total net acres(1) Increased credit facility to $275 million LINN retained Chisholm Trail Cryogenic Plant Q Roan management assumes operations in January Average net production rate of ~38,000 BOE/d Operated six drilling rigs by end of first quarter Apr-May 2018 Completed redetermination and increased credit facility to $425 million Completing back office transition Current development activity of six drilling rigs and two frac crews 11 DUCs as of March 31, 2018 Expect DUC inventory to grow until processing capacity is expanded LINN executed a term sheet with Roan Holdings, LLC (the successor to Citizen Energy II, LLC) which is expected to result in the combination of LNGG s 50 percent equity interest with Roan Holdings, LLC s 50 percent equity interest. This will allow for the consolidation of 100 percent of the equity in Roan under LNGG, subject to due diligence and execution of definitive documentation. (1) Total net acres is defined as the sum of LINN net acres and Citizen net acres as represented for each company in the agreement Roan Acreage 7

9 Roan Resources Strong Offset Results Increase Growth Potential MRO STACK / Meramec Consistent outperformance of STACK volatile oil wells Alta Mesa STACK Oil Window Meramac / Osage 7 Active Rigs XEC Lone Rock Play Best Results to Date Over-pressured Woodford 8-12 well per section spacing test CLR SCOOP Springer 24-hr IPs from 1,257 3,000 BOE/d 79%-89% Oil SCOOP Woodford/Sycamore Dicksion Unit 6 wells (1/2 unit) recent 24-hr Ips ranged from 1,267 to 2,185 BOE/d (43% to 56% oil) for single-mile laterals EOG Eastern Anadarko Woodford Oil Window High-Return Premium Play in Crude Oil Window 210 MMBoe Resource Potential Typical Well Gross EUR 1,000 MBoe $7.8 million for 9,500 Lateral 70% Oil, 20% NGL, 10% Gas GPOR SCOOP Woodford / Sycamore / Springer Play 17 recent 1-1/2 mile laterals average IP-30 of ~15 MMcfe/d Note: Sourced from investor presentations for each company Roan Leasehold 8

10 Roan Resources Significant Activity in the Merge Roan Activity: 6 operated horizontal drilling rigs 13 operated wells drilled in Q1 11 DUCs at March 31, active horizontal drilling rigs Griffin Pad Collins Pad Highlight Q Activity: Collins pad (2-mile laterals) Collins XH and Collins XH per well average 90-day rate of 2,515 Boe per day (76% liquids) Collins XH produced ~132,000 barrels of oil during its first 90 days Griffin pad (1.5-mile laterals) Griffin XH and Griffin XH per well average 90-day rate of 1,730 Boe per day (74% liquids) Roan Leasehold Roan 1Q 2018 Pad site Roan operated rig Peer rig 9

11 Blue Mountain Midstream Chisholm Trail System Primary growth asset of Blue Mountain Midstream LLC Cryogenic plant with a capacity of 250 MMcf/d under construction and expected to be operational by the end of the second quarter of 2018 ~ 90 miles of gathering pipelines LINN signed agreements dedicating its acreage contributed to Roan to Chisholm Trail Recent third party dedication is accelerating the growth of our midstream business Approximately 8,500 acres in a 13 township area Anticipate 10 new wells to be connected in 2018 Increased capital forecast for gathering More than 80,000 net acres now dedicated to the plant Blue Mountain estimates a 2018 exit-rate for the plant of 150 MMcf/d to 200 MMcf/d and expects to reach full capacity in 2019 Once the plant reaches full capacity, the plant and gathering business is forecasted to generate annualized EBITDA between $100 million and $125 million. This estimate does not include potential future expansions Significant remaining upside from additional third-party volumes and increasing capacity With the forecasted growth from its currently dedicated acreage position, Blue Mountain anticipates the need to expand the cryogenic plant Z Roan AMI Cryogenic Plant Under Construction 250 MMcf/d Capacity LINN Dedicated Acreage 3 rd Party Dedication Area 10

12 MMcf/d Blue Mountain Key Statistics Operating Margin (in millions) Capital Forecast (in millions) $ $ $ $ $ $ $3 $1 $2 Q A Q E Q E Q E Estimated Throughput MMcf / Day - Upper Range Estimated Throughput MMcf / Day - Lower Range Plant Operating Margin Estimate - Lower Range Plant Operating Margin Estimate - Upper Range $33 $ A 2017A 2018E (1) 2019E (1) (1) Estimate does not assume capital for second Cryo facility or new producer dedications 11

13 Riviera Resources, Inc. Upstream Asset Map Growth Mid-Continent Net Production of ~49 MMcfe/d NW STACK Large HBP acreage position of ~105,000 net acres with significant offset activity throughout play Arkoma STACK ~37,000 net acres, 100% HBP with large inventory of remaining horizontal locations 323 MMcfe/d (1) First Quarter 2018 Net Production ~1.7 Tcfe Proved Developed Reserves 76% Natural Gas 22% NGL 11% Approximate Base Decline Rate East Texas Net Production of ~56 MMcfe/d ~ 110,000 net acres HBP Bossier and Cotton Valley development potential Two successful horizontal wells drilled in 2017 Michigan / Illinois North Louisiana Net Production of ~27 MMcfe/d ~ 100,000 net acres HBP Significant offset activity in region. Four operated horizontal wells drilled in 2016/2017 with excellent results Long life, low decline Hugoton Drunkards Wash Hugoton Jayhawk Plant NW STACK Arkoma Net Production of ~143 MMcfe/d Base decline of ~ 6% More than 3,400 infill drilling locations Jayhawk Plant derives significant value from helium recovery and third party processing Michigan / Illinois Net Production of ~28 MMcfe/d Base decline of ~4% Drunkards Wash East Texas North Louisiana Net Production of ~20 MMcfe/d Base decline of ~ 11% Non-Operated position (1) Excludes volumes before closing for the following: OK Waterfloods closed 2/28/18, TX Panhandle Shallow closed 2/28/18, Permian W TX closed 3/29/18, Altamont Bluebell closed 4/4/18, Permian NM closed 4/10/18 12

14 2018 Guidance Q2 2018E FY 2018E Net Production (MMcfe/d) Natural gas (MMcf/d) Oil (Bbls/d) 1,650 1,750 3,000 3,500 NGL (Bbls/d) 9,250 10,000 10,200 11,300 Other revenues, net (in thousands) (1) $ 10,000 - $ 12,000 $ 68,000 $ 75,000 Costs (in thousands) $ 48,000 $ 54,000 $ 215,000 $ 238,000 Lease operating expenses $ 24,000 $ 27,000 $ 115,000 $ 127,000 Transportation expenses $ 17,000 $ 19,000 $ 70,000 $ 77,000 Taxes, other than income taxes $ 7,000 $ 8,000 $ 30,000 $ 34,000 Adjusted general and administrative expenses (2) $ 20,000 $ 22,000 $ 75,000 $ 82,000 Severance expenses $ 11,000 $ 14,000 $ 33,000 $ 37,000 Costs per Mcfe (Mid-Point) $ 1.81 $ 1.89 Lease operating expenses $ 0.90 $ 1.01 Transportation expenses $ 0.64 $ 0.61 Taxes, other than income taxes $ 0.27 $ 0.27 Targets (Mid-Point) (in thousands) Adjusted EBITDAX $ 6,000 (3) $ 108,000 (3) Interest expense (4) $ $ Oil and natural gas capital $ 9,000 $ 35,000 Blue Mountain Midstream capital $ 43,000 $ 120,000 Total capital $ 54,000 $ 160,000 Weighted Average NYMEX Differentials Natural gas (MMBtu) ($ 0.52) ($ 0.43) ($ 0.50) ($ 0.40) Oil (Bbl) ($ 2.90) ($ 2.50) ($ 3.10) ($ 2.50) NGL price as a % of crude oil price 30% 34% 32% 36% Unhedged Commodity Price Assumptions Apr May Jun 2018E Natural gas (MMBtu) $ 2.69 $ 2.74 $ 2.77 $ 2.85 Oil (Bbl) $ $ $ $ NGL (Bbl) $ $ $ $ Excludes LINN s 50% equity interest in Roan Includes assets sold in 2018 (1) Includes other revenues and margin on marketing activities (2) Excludes share-based compensation expenses and severance expenses (3) Includes a reduction to EBITDAX for estimated severance expenses, costs associated with managing assets divested during 2018, associated divestment costs, required transition services under purchase and sale agreements and estimated separation costs (4) Excludes non cash amortization of deferred financing costs 13

15 FY 2018 Capital Allocation Total Capital $160 million ($ in millions) Chisholm Trail Midstream Sold (1), (3) Assets Remaining O&G Assets Blue Mountain Midstream 1H'18 $100 Blue Mountain Midstream 2H'18 $20 Remaining Assets Oil & Gas Capital (1) $31 Asset Sales (2) $4 Other P&P / Admin $5 Excludes LINN s 50% equity interest in Roan (1) Remaining Assets include Hugoton, Michigan, Drunkards Wash, Arkoma, NW STACK, North Louisiana, and East Texas (2) Asset Sales include Oklahoma Waterfloods, and Texas Panhandle closed 2/28/18, for each respectively, Permian Conventional West TX closed 3/29/18, Altamont Bluebell closed 4/4/18, and Permian NM closed 4/10/18. 14

16 $ Millions Pro-Forma Adjusted Riviera Upstream 2018 EBITDAX Outlook 150 LINN Guidance as of 5/3/18 Pro forma Estimates Adjusted Riviera Upstream Guidance ($22) $48- $53 75 ($36) $35 $133- $ $ $50 0 FY 18 Guidance Pre-Close EBITDAX from Assets Sales (1) FY18 Operating Margin from Blue Mountain Midstream (2) Implied Riviera Upstream Pro- Forma FY 18 E Severance Expense (1) Represents EBITDAX before closing for the following: OK Waterfloods closed 2/28/18, TX Panhandle Shallow closed 2/28/18, Permian Conventional W TX closed 3/29/18, Altamont Bluebell closed 4/4/18, Permian NM closed 4/10/18 (2) Only includes the Chisholm Trail business, and excludes G&A (3) Further G&A reductions, including Blue Mountain G&A, that will result in a pro-forma run-rate of approximately $25 to $30 million annually Expected G&A Reductions (3) Pro-Forma FY18 Estimate Excludes LINN s 50% equity interest in Roan 15

17 Quarter End Cash Reconciliation ($ in millions) Previous Guidance as of 2/27/18 Cash Balance 3/31/18 EBITDA Asset Sales Timing (1) Permian / STX Acreage Additional Share Repurchases (2) Higher Capital Spending (3) Working Cash Balance Capital / Other 3/31/2018 $1 $405 $405 ($134) $4 $272 $272 ($62) $214 ($7) $20 $207 $207 $227 (1) Represents estimated proceeds from the sale of assets that were previously estimated to close in the first quarter; $122 million related to Altamont Bluebell sale, and $12 million related to the receipt of escrow deposit on Permian West TX Conventional assets. (2) Includes ~$40 million of employee shares repurchased associated with the Company s long term incentive program (3) Primarily incremental capital spent for gathering related to third party dedications and pipeline interconnects 16

18 Pro-Forma Cash 6/30/2018 ($ in millions) Ending Cash 3/31/18 Adjusted G&A Field Level and Severance Cash Flow (1) Expenses (2) Capital Asset Sales (3) Open Market Share Repurchases (4) Other Projected Cash Balance 6/30/2018 ($6) $334 $330 ($4) $40 ($34) $161 $227 $227 $233 ($54) $179 $179 $330 (1) Represents Adjusted EBITDAX before deducting adjusted general and administrative expenses, and severance expense, see slide 13 for detail (2) Represents adjusted G&A expense and severance expense included in Adjusted EBITDAX, see slide 13 for detail (3) Represents estimated proceeds from the sale of assets received in the second quarter (4) Shares repurchased through April 23,

19 Share Buybacks As of April 23, 2018 Over $600 million returned to shareholders 2017 Open Market Share Repurchases Tender Offer Retirement of Profits Interest Shares (1) 2018 Employee 2018 Open Market Share Repurchases Liquidity Program (2) Total $20 $523 $41 $543 $40 $584 $624 $325 $198 $198 Number of Shares Average Price Per Share 5,690,192 6,770, ,788 1,061,806 1,030,819 15,024,438 $ $ $ $ $ $ (1) Class A-2 shares of LINN HoldCo LLC held by management retired as a result of common stock repurchases (2) 120,829 shares previously issued as a result of vested Restricted Stock Units ( RSUs ) and subsequently repurchased and 909,990 vested RSUs settled in cash prior to shares being issued 18

20 Volume (MMMBtu/d) Volume (Bbls/d) Commodity Hedge Portfolio Natural Gas Positions Oil Positions 250 1,600 1, ,400 1, $3.17 1, $ $ $3.02 $ $ $ Swaps Swaps Note: Hedge portfolio as of April 16,

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