UBS S En Energy y Conf nferenc rence May ay 2017 - - PowerPoint PPT Presentation

UBS S En Energy y Conf nferenc rence

May ay 2017

Forward-Looking Statements and Risk Factors

Statements made in this press release 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

• r 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

• ther 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

• f 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.

1Q 1Q 20 2017 7 Highlights ghlights

 Successfully emerged from restructuring and reduced total debt to $834 million as of March 31, 2017  Entered into a definitive 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 the construction of the Chisholm Trail cryogenic plant with a designed capacity of 250 MMcf/d  G&A expenses were lower than guidance and the Company continues to improve its cost structure

Ove vervie rview w of f LINN’s Assets

As of year end 2016 unless otherwise noted

California South Texas Michigan Permian East Texas North Louisiana Hugoton Williston Salt Creek Washakie Jonah

Bluebell Altamont

Illinois Panhandle

Eastern Oklahoma Waterfloods

SCOOP STACK Merge

Merge ge / NW STACK / STACK / SCOOP

• Exposure across the entirety of this premier U.S.
• nshore 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

Mid-Continent Core Growth

Rockies es (Blueb ebell ell Altamont, nt, Jonah, Washak akie, e, Williston

• n)
• Concentrated acreage positions with significant scale

and upside in core areas

• Net Acres: ~295,000
• Net Production: ~294 MMcfe/d

East Texas as / North h Louisiana na

• 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

Emerging Growth

• 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

Diverse Long Life Producing Assets

Arkoma

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)

(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

Drunkards Wash

Net Acres 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 Mid-Continent Core Growth Merge ~49,000 56 Mixed 224 $ 163 $ 243 Majority Operated NW STACK ~105,000 STACK ~24,000 SCOOP ~7,000 Other Western Oklahoma ~112,000 Emerging Growth Jonah ~30,000 152 Natural Gas 372 $ 274 $ 389 Mixed Williston ~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 Long Life Stable Base Assets Hugoton ~1,100,000 155 Natural Gas 961 $ 524 $ 716 Majority Operated California ~3,000 32 Oil 170 $ 233 $ 347 Operated Permian ~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 ~5,000 13 Oil 46 $ 28 $ 84 Non-Operated South Texas ~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 5

LINN N As Asset et Detai ail

As of year end 2016 unless otherwise noted

(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

6

Corpo porate rate Str trateg ategy

UPSTREAM MLP GROWTH E&P

Committed to the capital investment and cost reductions necessary for the strategic shift Focus on our top tier SCOOP / STACK / Merge position Integrated development in the Merge creates a significant competitive advantage Jefferies LLC continues as lead advisor to evaluate strategic alternatives

ACCELERATE MERGE HORIZONTAL PROGRAM DIVEST NON-CORE ASSETS TEST HORIZONTAL POTENTIAL NLA / ETX ARKOMA ROCKIES DEVELOP MERGE MIDSTREAM BUSINESS DE-RISK NW STACK POSITION CONTINUE TO IDENTIFY AND EXECUTE ON STRATEGIC OPPORTUNITIES TO MAXIMIZE VALUE

7

Net t As Asset et Val alue ue Ups psid ide

Increasing Value

Proved Developed Reserves of ~3.3 Tcfe

~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 North Louisiana Horizontal

2.6+ million net acres majority HBP with exposure to future stacked pay

East Texas Horizontal Significant additional inventory at higher commodity prices Expanding Capacity in the Merge Chisholm Trail Plant from 60 to 250 MMcf/d Rockies Horizontal Inventory that benefits from technology and cost improvements Value

+ SCOOP/STACK / Merge Growth + Emerging Growth + Additional Upside

(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

Proved Developed PV-10 ~$3.1 Billion(1&2)

20 2017 7 Cap apit ital al Al Allo locati ation

$100 $100 $34 Horizontal Development Plant and Pipeline / Midstream (Chisholm Trail) Land, Seismic, and Water Infrastructure $165 $102 $40 $95

$11

Horizontal Development Plant and Pipeline / Midstream Land, Seismic, and Water Infrastructure Vertical Development and Optimization Administrative

$234 4 million

• n in the Merge

$413 3 million

• n of Total

al Capit ital  ~57% of total 2017 budgeted capital is allocated to the Merge

8

9

Top tier position across SCOOP / STACK / Merge

 ~185,000 total net acres  96%+ HBP provides optionality for development pace  Concentrated core position in the Merge  Significant and consolidated exposure to emerging NW STACK with the majority in Major and Blaine counties  Jefferies LLC continues as lead advisor to evaluate strategic alternatives

NW STACK STACK Merge SCOOP

10

Merge Merge

Premier acreage position with strong recent results  ~53,000net acres  Key targets are Mississippi, Woodford and Hunton  Running 2 rigs in 2017 with plans for 25 gross wells  More than 1,400 gross locations assuming 15 wells per section  Testing upsized completions and down-spacing throughout 2017

LINN Acreage

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%

Recent Drilling Activity

1 2 5 3 4 6 7 8 9

Chisholm Trail Plant

(1) Calculated from gross 2-stream volumes (2) The average Peak IP-30 rate shown has been normalized to a 10,000 ft. lateral

Canadian Grady

11

Merge Merge

Core Growth Asset

6.7 8.0 16.7 5 10 15 20 YE 2016 Exit 1Q 2017 Exit YE 2017 Exit

MERGE – AVG DAILY PRODUCTION (MBOE/D)

 Significant production growth on the horizon assuming 2 rig drilling program  Flexibility to add rigs quickly

(1) Projected annual growth based on 2 rig program

12

Chisholm Chisholm Trail rail Midstr Midstream eam

Building a Premier Midstream Business in the Merge

Merge Midstream Infrastructure

 Construction has been approved on a cryogenic plant with designed capacity of 250 MMcf/d  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  Integrated Merge development plan improves LINN

• perated well economics

 Significant remaining upside from gathering third-party volumes and increasing capacity

Future Cryogenic Plant 250 MMcf/d Capacity McNeff Lan angston

• n

Jesse Chish isholm lm Hin inpa parr Brau aums (2) Doris

• ris

Jackson Dream am Cool

• ler

50 50 100 100 150 150 200 200 250 250 300 300

201 2017 201 2018 201 2019 202 2020

MMcf cf/d /d Estimated Plant Capacity $33 $33 (1) $100 $52 $52 $10 2016 2016 2017 2017 2018 2018 2019 2019 Capital Forecast (in millions)

(1) Actual capital spend during 2016

13

NW NW ST STACK CK

Industry activity continues to de-risk acreage

 Asset Highlights

• Contiguous and majority
• perated position of ~105,000

net acres that is 99%+ held by production

• Primary targets – Osage and

Meramec  Key Developments

• Asset development focused on

Osage in Major County and Osage and Meramec in Blaine County

• Meramec and fractured Osage

plays in northern Blaine, Dewey and Major Counties are evolving into economic targets based on recent results

• 43 horizontal permits issued in

the first quarter of 2017 compared to 18 in the first quarter of 2016

Note: Peak IP-30 volumes have been normalized to a 5,000 ft lateral length. Data sourced from LINN production history, IHS and public company investor presentations. Note: Rig count sourced from DrillingInfo and based on rigs shown within parameters of NW STACK outline from slide 9. Legend Meramec Well LINN Acreage Chain Ranch 1H-2 (Devon) First Prod. Date: 02/16 Peak IP-30: 1,214 Boe/d Oil: 16% Lateral Length: 4,589' Elwell 29-1H (Comanche) First Prod. Date: 10/14 Peak IP-30: 1,121 Boe/d Oil: 51% Lateral Length: 4,405' Robison-Payday 16-1H (Carrera) First Prod. Date: 04/15 Peak IP-30: 773 Boe/d Oil: 46% Bell Gene 1H-2 (Valpoint) First Prod. Date: 07/14 Peak IP-30: 572 Boe/d Oil: 47% Lateral Length: 4,059' Hoskins 5-19-12 2H (Chesapeake) Peak daily rate: 1,401 Boe/d Oil: 65% Lateral Length: 4,841' Schoeppel 16-20-12 1H (Chesapeake) Peak IP-30: 1,025 Boe/d Oil: 50% Lateral Length: 4,764' Mounds 16-1H (Carrera) First Prod. Date: 12/15 Peak IP-30: 447 Boe/d Oil: 41% Lateral Length: 4,322' Medill 1-27H (Sandridge) First Prod. Date: 10/16 Peak IP-30: 925 Boe/d Oil: 77% Hoskins 5-19-12 1H (Chesapeake) Peak IP-30: 1,213 Boe/d Oil: 60% LL / Zone: 4,886' Osage Well

 22 rigs running in the area

14

Debt bt Redu ductio tion

$3,088 $2,215 $540

$274 - $284

500 500 294

1,000 1,000 3,857 3,023 $8,445 $6,738 $834 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 12/31/2015 with Berry 12/31/15 excluding Berry 3/31/2017 Estimated 5/31/2017

$ Millions

RBL Term Loan Second Lien Notes Unsecured Notes

Pro Forma a Annual Inter erest Expens ense $497 million $415 million $60 million(3) Debt Reduct ction

• n Contributor

utors

Berry Separation

$1,707

Equitize Second Lien / Unsecured Notes

4,023

Hedge Unwind

1,190

New Money Investment

530

Other

161

Expected Jonah Sale Proceeds

550-560 Total $8,161 – $8,171

1Q 2017 Total Debt t to Adjus usted d EBITD ITDAX AX(1)

1) of 1.6x

x as of 3/31/2 /2017

(1) See disclosure on the Company’s calculation of Total Debt to Adjusted EBITDAX on slide 17 (2) Assumes $550-$560 million in Jonah asset sale proceeds after closing adjustments and the transaction closes as anticipated on 5/31/17 (3) Estimated interest expense for 2017. Does not reflect the anticipated effect of the Jonah asset sale (2)

15

Cap apit ital al Str tructure ucture

Common mmon Equity ity

• Approximately 89.2 million shares issued and outstanding
• 9.9 millions shares reserved for issuance under the Company’s Omnibus Incentive Plan of

which 3.7 million shares have been issued to date as restricted stock units Term rm Loan

• $294 million outstanding as of March 31, 2017
• Matures February 27, 2021
• LIBOR + 750
• Mandatory quarterly amortization payments

$25 million in 2017, $37.5 million in 2018, $50 million in 2019 $50 million in 2020, $137.5 million in 2021 $1.4 .4 Billion lion Re Revolv volver er

• Initial conforming borrowing base of $1.4 billion - LIBOR +350
• Matures in July 2020
• ~$540 million(1) drawn on RBL A as of March 31, 2017. Redeterminations semi-annually every

April 1 and October 1 starting 2018

• If borrowing base is redetermined below $1.4 billion, the difference is reallocated to a non-

conforming borrowing base with interest payable at LIBOR +550

12 12,00 000 5,000 00

• 2,000

4,000 6,000 8,000 10,000 12,000 14,000 2017 2018 2019

370 13 131 31 31

• 50

100 150 200 250 300 350 400 2017 2018 2019

Oil Po Position tions Natur tural al Gas Po Positions tions

Volume (MMMBtu/d)

Swaps ps

Volume (Bbls/d)

Swaps ps Collars rs $3.17 .17 $3.01 .01 $52.13 2.13 $50.00 0.00- $55.50 5.50 $50.00 0.00- $55.50 5.50 $54.07 4.07

6,500 00

Comm mmodi

• dity

ty Hedg dge Po Portf tfolio lio

Note: Hedge portfolio as of May 11th, 2017

$2.97 .97

16

17

Total Debt to Adjusted EBITDAX Reconciliation

The non-GAAP financial measure of adjusted EBITDAX, 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 EBITDAX should not be considered in isolation or as a substitute for GAAP. Adjusted EBITDAX 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'sfinancial results. The followingpresents a reconciliationof net income (loss) to adjusted EBITDAX:

(1) All amounts reflect the combined results of the one month ended March 31, 2017 (successor) and the two months ended February 28, 2017 (predecessor). (2) Represent amounts related to oil derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period. (3) Primarily represent gains or losses on the sale of assets, gains or losses on inventory valuation and amortization of basis difference for equity method investments. (4) Represent costs and income directly associated with the Company’s filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code since the petition date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined. (1) Adjusted EBITDAX reflects the combined results of the one month ended March 31, 2017 (successor) and the two months ended February 28, 2017 (predecessor). (2) Information presented for 2016 relates only to LINN Energy’s continuing operations. (3) Total debt as of March 31, 2017, and March 31, 2016, respectively. (4) Calculated as total debt divided by adjusted EBITDAX (annualized twelve months).

The following presents the Company’s calculation of total debt to adjusted EBITDAX: