J.P.Morgan Energy Equity Conference June 2017
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 performance and results, ability to improve our financial results and profitability following emergence from bankruptcy, availability of sufficient cash flow to execute our business plan, ability to execute planned 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, the regulatory environment and other important factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. 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. 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, using strip prices as of February 15, 2017, 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.
Recent Highlights 1Q 2017 Highlights Successfully emerged from restructuring and reduced debt to $834 million as of March 31, 2017 Entered into an agreement to sell the Jonah and Pinedale assets in Wyoming for $581.5 million Commenced trading on OTCQB market under ticker symbol LNGG Average daily production of 779 MMcfe/d, exceeding midpoint of production guidance Merge horizontal net production increased to 8,000 BOE/d at the end of first quarter and added a second rig LINN s midstream business in the Merge is now processing ~40 MMcf/d from the Chisholm Trail refrigeration facility Approved construction of the Chisholm Trail cryogenic plant - designed capacity of 250 MMcf/d G&A expenses were lower than guidance and the Company continues to improve its cost structure Recent News Announced the sale of the South Belridge field in California for a contract price $263 million Announced the sale of Salt Creek in Wyoming for a contract price of $71.5 million Announced strategic exit from California with Brea sale of a contract price of $100 million (1) Closed on the sale of the Jonah and Pinedale assets for net cash proceeds of ~$560 million Expected to extinguish all debt pro forma for the announced transactions Amended credit agreement and authorized an initial share repurchase program (1) Does not includes an additional $7 million contingent payment if certain operational requirements are satisfied within one year
Overview of LINN s Assets As of year end 2016 unless otherwise noted Jonah Williston Michigan Salt Creek Mid-Continent Core Growth Merge / NW STACK / STACK / SCOOP Exposure across the entirety of this premier U.S. onshore resource play includes significant and strategic operated position in the core of the Merge Net Acres: ~185,000 Net Production: ~56 MMcfe/d Additional ~112,000 net acres in Western Oklahoma California Bluebell Altamont Drunkards Wash Sale Closed PSA Executed Marketing Hugoton Panhandle Permian Washakie SCOOP STACK Merge South Texas Illinois Eastern Oklahoma Waterfloods Arkoma East Texas North Louisiana LINN Total 2.6+ Million Net Acres Net Production of ~828 MMcfe/d ~3.3 Tcfe of Proved Developed Reserves (65% Natural Gas) $3.1 Billion Proved Developed PV-10 (1&2) Emerging Growth Rockies (Bluebell Altamont, Jonah, Washakie, Williston) Concentrated acreage positions with significant scale and upside in core areas Net Acres: ~295,000 Net Production: ~294 MMcfe/d East Texas / North Louisiana Includes exposure to core horizontally prospective Bossier / Cotton Valley resource plays Net Acres: ~265,000 Net Production: 72 MMcfe/d Arkoma Concentrated, majority operated acreage position with significant scale and upside through advanced completion design Net Acres: ~49,000 Net Production: 31 MMcfe/d Diverse Long Life Producing Assets Mature producing assets provide steady and predictable cash flows requiring very little capital to maintain Net Acres: ~1,700,000+ Net Production: ~375 MMcfe/d (1) Strip pricing as of February 15, 2017 shown as Natural Gas / Oil per year: 2017 $3.27/$54.17 2018 $3.03/$54.93 2019 $2.85/$54.50 2020 $2.84/$54.32 2021 $2.84/$54.46 2022 $2.85/$54.96 (2) Refer to slide 2 for the PV-10 disclosure Note: Unless otherwise noted, all volumes are average daily full year 2016 actual production and acreage is as of year end 2016 4
Long Life Stable Base Assets Emerging Growth Mid-Continent Core Growth LINN Asset Detail As of year end 2016 unless otherwise noted Net Acres Merge ~49,000 NW STACK ~105,000 STACK ~24,000 SCOOP ~7,000 Other Western Oklahoma ~112,000 Production ( 1) (MMcfe/d) Primary Commodity Proved Developed (2) Bcfe Proved Developed (2&4) SEC Pricing PV-10 $ in millions Proved Developed (3&4) Strip Pricing PV-10 $ in millions Operatorship 56 Mixed 224 $ 163 $ 243 Majority Operated Jonah (Sale Closed) ~30,000 152 Natural Gas 372 $ 274 $ 389 Mixed Williston (Marketing) ~20,000 59 Oil 119 $ 139 $ 230 Non-Operated East Texas (ETX) ~115,000 57 Natural Gas 276 $ 101 $ 156 Majority Operated Washakie ~200,000 74 Natural Gas 211 $ 60 $ 118 Majority Operated Bluebell Altamont ~45,000 9 Oil 35 $ 61 $ 89 Majority Operated Arkoma ~49,000 31 Natural Gas 126 $ 50 $ 75 Majority Operated North Louisiana (NLA) ~150,000 15 Natural Gas 41 $ 20 $ 31 Majority Operated Hugoton ~1,100,000 155 Natural Gas 961 $ 524 $ 716 Majority Operated California (PSA Executed) ~3,000 32 Oil 170 $ 233 $ 347 Operated Permian (Marketing) ~90,000 56 Mixed 136 $ 114 $ 222 Majority Operated Michigan / Illinois ~200,000 30 Natural Gas 269 $ 82 $ 122 Majority Operated Eastern Oklahoma Waterfloods ~30,000 14 Oil 75 $ 47 $ 99 Majority Operated Salt Creek (PSA Executed) ~5,000 13 Oil 46 $ 28 $ 84 Non-Operated South Texas (Marketing) ~130,000 27 Natural Gas 68 $ 42 $ 67 Majority Operated Texas Panhandle ~140,000 23 Mixed 60 $ 33 $ 63 Operated Drunkards Wash ~50,000 23 Natural Gas 57 $ 30 $ 45 Non-Operated Other Non-Op / Other Royalties ~15,000 2 Natural Gas 8 $ 10 $ 12 Non-Operated Total 2,600,000+ 828 3,254 $ 2,011 $ 3,108 (1) Average daily full year 2016 actual production (2) SEC pricing of $2.48 per MMBtu for natural gas and $42.64 per bbl for oil (3) Strip pricing as of February 15, 2017 shown as Natural Gas / Oil per year: 2017 $3.27/$54.17 2018 $3.03/$54.93 2019 $2.85/$54.50 2020 $2.84/$54.32 2021 $2.84/$54.46 2022 $2.85/$54.96 (4) Refer to slide 2 for the PV-10 disclosure 5
Corporate Strategy UPSTREAM MLP DIVEST NON-CORE ASSETS ACCELERATE MERGE HORIZONTAL PROGRAM DEVELOP MERGE MIDSTREAM BUSINESS DE-RISK NW STACK POSITION TEST HORIZONTAL POTENTIAL NLA / ETX ARKOMA ROCKIES GROWTH E&P CONTINUE TO IDENTIFY AND EXECUTE ON STRATEGIC OPPORTUNITIES TO MAXIMIZE VALUE Committed to the capital investment and cost reductions necessary for the strategic shift Focus on our top tier Merge / SCOOP / STACK position Integrated development in the Merge creates a significant competitive advantage Jefferies LLC continues as lead advisor to evaluate strategic alternatives 6
Increasing Value Net Asset Value Upside Value 2.6+ million net acres majority HBP with exposure to future stacked pay Significant additional inventory at higher commodity prices Inventory that benefits from technology and cost improvements + Additional Upside North Louisiana Horizontal East Texas Horizontal Rockies Horizontal + Emerging Growth ~185,000 net acres in the SCOOP / STACK including ~53,000 net acres in the core of the Merge targeting the Mississippi, Woodford and Hunton Expanding Capacity in the Merge Chisholm Trail Plant from 60 to 250 MMcf/d + SCOOP/STACK / Merge Growth Proved Developed Reserves of ~3.3 Tcfe Proved Developed PV-10 ~$3.1 Billion (1&2) (1) Strip pricing as of February 15, 2017 shown as Natural Gas / Oil per year: 2017 $3.27/$54.17 2018 $3.03/$54.93 2019 $2.85/$54.50 2020 $2.84/$54.32 2021 $2.84/$54.46 2022 $2.85/$54.96 (2) Refer to slide 2 for the PV-10 disclosure 7
2017 Capital Allocation ~57% of total 2017 budgeted capital is allocated to the Merge $234 million in the Merge $413 million of Total Capital $34 $11 $95 $100 $165 $40 $100 Horizontal Development Plant and Pipeline / Midstream (Chisholm Trail) Land, Seismic, and Water Infrastructure $102 Horizontal Development Plant and Pipeline / Midstream Land, Seismic, and Water Infrastructure Vertical Development and Optimization Administrative 8
Asset Sale Update Jonah Sale $581.5 million California South Belridge Sale $263 million Jonah Williston Salt Creek Salt Creek Sale $71.5 million California Brea Sale $100 million (3) California Expects to extinguish all debt pro forma of announced transactions Continue to market Permian, South Texas and Williston Permian South Texas During 2017, we have announced sale agreements totaling more than $1 billion. Asset Production ( 1) (MMcfe/d) Operatorship Proved Developed Reserves (2) Bcfe Proved Developed (2) PV-10 @ $3/$50 $ in millions Contract Price $ in millions Estimated Proceeds $ in millions Jonah 129 Mixed 384 $ 369 $ 581.5 $ 560 California South Belridge 18 Operated 70 $ 168 $ 263 $ 246 California Brea 11 Operated 106 $ 126 $ 100 (3) $ 92 Salt Creek 12 Non-Operated 55 $ 54 $ 71.5 $ 71.5 Total 170 615 $ 717 $ 1,016 $ 969.5 (1) Average daily actual production from the first quarter 2017 (2) Proved reserves as of March 1, 2017 with updated pricing of $3.00 per MMBtu for natural gas and $50.00 per bbl for oil. (3) Does not includes an additional $7 million contingent payment if certain operational requirements are satisfied within one year 9
Top tier position across SCOOP / STACK / Merge ~185,000 total net acres NW STACK 96%+ HBP provides optionality for development pace Concentrated core position in the Merge STACK Significant and consolidated opportunity in the emerging NW STACK with the majority in Major and Blaine counties Merge SCOOP Jefferies LLC continues as lead advisor to evaluate strategic alternatives 10
Merge Premier acreage position with strong recent results ~53,000 net acres Canadian LINN Acreage Key targets are Mississippi, Woodford and Hunton Running 2 rigs in 2017 with plans for 25 gross wells Chisholm Trail Plant More than 1,400 gross locations assuming 15 wells per section 1 9 8 3 Testing upsized completions and down-spacing throughout 2017 4 5 7 6 2 Recent Drilling Activity Grady LINN Operated Well Working Interest First Production Zone Lateral Length (ft) Peak IP-30 (BOE/d) (1) Normalized Peak IP-30 (1&2) (BOE/d) % Oil (1) Total % Liquids 1 Barbour 12-10-7 1H 90% Mar-16 Woodford 4,209 668 1,587 29% 50% 2 Hinparr 31-6-10-5 1XH 90% Nov-16 Mississippi 9,898 2,268 2,291 70% 76% 3 McNeff 22-10-5 1H 99% Dec-16 Mississippi 4,391 961 2,189 44% 54% 4 Braum 28-21-10-6 1XH 95% Dec-16 Woodford 10,206 1,445 1,416 13% 30% 5 Braum 33-4-10-6 1XH 77% Dec-16 Woodford 10,179 769 755 35% 56% 6 Langston 13-24-9-6 1XH 34% Jan-17 Woodford 10,135 842 831 19% 42% 7 Jackson 25-24-10-6 1XH 62% Jan-17 Mississippi 9,769 1,612 1,650 47% 63% 8 Doris 12-13-10-6 1XH 58% Mar-17 Woodford 10,042 1,455 1,449 47% 62% 9 Dream Cooler 13-12-10-6 2XH 59% Mar-17 Mississippi 9,637 1,242 1,289 23% 53% (1) Calculated from gross 2-stream volumes (2) The average Peak IP-30 rate shown has been normalized to a 10,000 ft. lateral 11
Merge Core Growth Asset Significant production growth on the horizon assuming 2 rig drilling program Flexibility to add rigs quickly 20 MERGE AVG DAILY PRODUCTION (MBOE/D) 15 16.7 10 5 6.7 8.0 0 YE 2016 Exit 1Q 2017 Exit YE 2017 Exit (1) Projected annual growth based on 2 rig program 12
MMcf/d Chisholm Trail Midstream Building a Premier Midstream Business in the Merge Construction has been approved on a cryogenic plant with a capacity of 250 MMcf/d when fully operational BCCK Engineering, Inc. has been selected to construct the Chisholm Trail Cryogenic Gas Plant Merge Midstream Infrastructure Doris LINN has signed agreements dedicating its Merge acreage to Chisholm Trail At full capacity a midstream business of this type could generate annual EBITDAX between $100M and $125M Braums (2) Dream Cooler Jackson McNeff Hinparr Integrated Merge development plan improves LINN operated well economics Significant remaining upside from gathering third-party volumes and increasing capacity Future Cryogenic Plant 250 MMcf/d Capacity Jesse Chisholm Langston $33 (1) Capital Forecast (in millions) $100 $52 $10 2016 2017 2018 2019 (1) Actual capital spend during 2016 Estimated Plant Capacity 300 250 200 150 100 50 0 2017 2018 2019 2020 13
NW STACK Industry activity continues to de-risk acreage Moss 2018 1H-23 (SD) Peak IP-30: 1,026 BOE/d 6% Oil 4,845 Lateral Medill 2015 1-27H (SD) Peak IP-30: 895 BOE/d 74% Oil 4,681 Lateral Johnson 1H (Comanche) Peak IP-30: 704 BOE/d 10% Oil 3,664 Lateral Willamette 1H (CHK) Peak IP-30: 1,367 BOE/d 62% Oil 2-mile Lateral Schoeppel 16-20-1H (CHK) Peak IP-30: 983 BOE/d 46% Oil 4,764 Lateral Howard 5-19-17-1H (TE) Peak IP-30: 2,461 BOE/d 28% Oil 4,779 Lateral Hoskins 5-19-12-1H (CHK) Peak IP-30: 1,185 BOE/d 62% Oil 4,972 Lateral Russell 17-19-17-1H (TE) Peak IP-30: 1,125 BOE/d 62% Oil 4,767 Lateral Merle 32-19-17-1H (TE) Peak IP-30: 746 BOE/d 53% Oil 4,708 Lateral Haigler 1-4H (Council Oak) Peak IP-30: 540 BOE/d 10% Oil 4,320 Lateral FrankieJo 1-25-24XH (CLR) Peak IP-30: 1,343 BOE/d 15% Oil 9,746 Lateral Herod FIU 1-8-5XH (CLR) Peak IP-30: 1,907 BOE/d 59% Oil Swaim (CLR) Peak IP-30: 2,865 BOE/d 74% Oil Legend Note: Sourced from IHS, DrillingInfo and Investor presentations LINN Acreage Meramec Well LINN NW STACK ~105,000 net acres that is 99%+ held by production Osage Well 36 horizontal rigs running in the area Hoskins 5-19-12-2H (CHK) Peak IP-30: 1,126 BOE/d 65% Oil 4,669 Lateral Farber 1MH6 (Chaparral) Peak IP-30: 497 BOE/d 67% Oil 4,219 Lateral Marjorie 1-25XH (MRO) Peak IP-30: 2,422 BOE/d 32% Oil 7,532 Lateral Castonguay 1H (NFX) Peak IP-30: 1,229 BOE/d 74% Oil 10,054 Lateral Ludwig 6 well pad (CLR) 6 well averages below Peak IP-30: 1,568 BOE/d 36% Oil 9,649 Lateral 14
$ Millions Debt Reduction Expected to extinguish all debt pro forma for the announced transactions 8,000 $8,445 Debt Reduction Contributors Berry Separation $1,707 7,000 6,000 3,857 $6,738 Equitize Second Lien / Unsecured Notes 4,023 Hedge Unwind 1,190 5,000 3,023 New Money Investment 530 4,000 1,000 Other 161 3,000 2,000 1,000 0 Pro Forma Annual Interest Expense 500 1,000 500 $3,088 $2,215 $834 294 $0 $540 12/31/2015 with Berry 12/31/15 excluding Berry 3/31/2017 Estimated 7/31/2017 RBL Term Loan Second Lien Notes Unsecured Notes $497 million $415 million $60 million (2) Expected Sale Proceeds to Reduce Debt (2) 834 Total $8,445 (1) (1) Assumes $834 million of proceeds used to pay down debt from the previously announced asset sales after closing adjustments and all transactions close as anticipated by 7/31/17. Proceeds are expected to exceed the total outstanding debt and the excess will be added as cash on the balance sheet. (2) Estimated interest expense for 2017. Does not reflect the anticipated effect of the announced and completed asset sales 15
Volume (MMMBtu/d) Volume (Bbls/d) Commodity Hedge Portfolio Natural Gas Positions Oil Positions 400 350 300 370 14,000 12,000 12,000 250 10,000 200 150 $3.17 131 8,000 6,000 6,500 5,000 100 50 $3.01 4,000 $52.13 31 2,000 $50.00- $55.50 $50.00- $55.50 - $2.97 2017 2018 2019 - $54.07 2017 2018 2019 Swaps Swaps Collars Note: Hedge portfolio as of May 11 th, 2017 16