UBS Energy Conference May 2017

Transcription

1 UBS Energy Conference May 2017

2 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 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.

3 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.

4 1Q 2017 Highlights 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

5 Overview of LINN s Assets As of year end 2016 unless otherwise noted Jonah Williston Salt Creek Michigan 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 Washakie Hugoton Panhandle Permian SCOOP STACK Merge Illinois Eastern Oklahoma Waterfloods Arkoma East Texas North Louisiana 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 South Texas 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) 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 $3.27/$ $3.03/$ $2.85/$ $2.84/$ $2.84/$ $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

6 LINN Asset Detail As of year end 2016 unless otherwise noted Mid-Continent Core Growth Emerging Growth Long Life Stable Base Assets 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 ~30, Natural Gas 372 $ 274 $ 389 Mixed Williston ~20, Oil 119 $ 139 $ 230 Non-Operated East Texas (ETX) ~115, Natural Gas 276 $ 101 $ 156 Majority Operated Washakie ~200, Natural Gas 211 $ 60 $ 118 Majority Operated Bluebell Altamont ~45,000 9 Oil 35 $ 61 $ 89 Majority Operated Arkoma ~49, Natural Gas 126 $ 50 $ 75 Majority Operated North Louisiana (NLA) ~150, Natural Gas 41 $ 20 $ 31 Majority Operated Hugoton ~1,100, Natural Gas 961 $ 524 $ 716 Majority Operated California ~3, Oil 170 $ 233 $ 347 Operated Permian ~90, Mixed 136 $ 114 $ 222 Majority Operated Michigan / Illinois ~200, Natural Gas 269 $ 82 $ 122 Majority Operated Eastern Oklahoma Waterfloods ~30, Oil 75 $ 47 $ 99 Majority Operated Salt Creek ~5, Oil 46 $ 28 $ 84 Non-Operated South Texas ~130, Natural Gas 68 $ 42 $ 67 Majority Operated Texas Panhandle ~140, Mixed 60 $ 33 $ 63 Operated Drunkards Wash ~50, 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, ,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 $3.27/$ $3.03/$ $2.85/$ $2.84/$ $2.84/$ $2.85/$54.96 (4) Refer to slide 2 for the PV-10 disclosure 5

7 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 SCOOP / STACK / Merge position Integrated development in the Merge creates a significant competitive advantage Jefferies LLC continues as lead advisor to evaluate strategic alternatives 6

8 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 Increasing Value North Louisiana Horizontal East Texas Horizontal ~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 Rockies Horizontal Expanding Capacity in the Merge Chisholm Trail Plant from 60 to 250 MMcf/d + Emerging Growth + 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 $3.27/$ $3.03/$ $2.85/$ $2.84/$ $2.84/$ $2.85/$54.96 (2) Refer to slide 2 for the PV-10 disclosure 7

9 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

10 Top tier position across SCOOP / STACK / Merge NW STACK ~185,000 total net acres 96%+ HBP provides optionality for development pace STACK Concentrated core position in the Merge Merge Significant and consolidated exposure to emerging NW STACK with the majority in Major and Blaine counties SCOOP Jefferies LLC continues as lead advisor to evaluate strategic alternatives 9

11 Merge Premier acreage position with strong recent results ~53,000 net acres Key targets are Mississippi, Woodford and Hunton Canadian LINN Acreage 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 Chisholm Trail Plant 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 H 90% Mar-16 Woodford 4, ,587 29% 50% 2 Hinparr XH 90% Nov-16 Mississippi 9,898 2,268 2,291 70% 76% 3 McNeff H 99% Dec-16 Mississippi 4, ,189 44% 54% 4 Braum XH 95% Dec-16 Woodford 10,206 1,445 1,416 13% 30% 5 Braum XH 77% Dec-16 Woodford 10, % 56% 6 Langston XH 34% Jan-17 Woodford 10, % 42% 7 Jackson XH 62% Jan-17 Mississippi 9,769 1,612 1,650 47% 63% 8 Doris XH 58% Mar-17 Woodford 10,042 1,455 1,449 47% 62% 9 Dream Cooler XH 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 10

12 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) YE 2016 Exit 1Q 2017 Exit YE 2017 Exit (1) Projected annual growth based on 2 rig program 11

13 Chisholm Trail Midstream Building a Premier Midstream Business in the Merge 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 Merge Midstream Infrastructure Doris At full capacity a midstream business of this type could generate annual EBITDAX between $100M and $125M Integrated Merge development plan improves LINN operated well economics Braums (2) Dream Cooler Jackson McNeff Hinparr 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 $ (1) Actual capital spend during 2016 MMcf/d Estimated Plant Capacity

14 NW STACK Industry activity continues to de-risk acreage Asset Highlights Contiguous and majority operated position of ~105,000 net acres that is 99%+ held by production Primary targets Osage and Meramec Mounds 16-1H (Carrera) First Prod. Date: 12/15 Peak IP-30: 447 Boe/d Oil: 41% Lateral Length: 4,322' Elwell 29-1H (Comanche) First Prod. Date: 10/14 Peak IP-30: 1,121 Boe/d Oil: 51% Lateral Length: 4,405' Medill 1-27H (Sandridge) First Prod. Date: 10/16 Peak IP-30: 925 Boe/d Oil: 77% Schoeppel H (Chesapeake) Peak IP-30: 1,025 Boe/d Oil: 50% Lateral Length: 4,764' Bell Gene 1H-2 (Valpoint) First Prod. Date: 07/14 Peak IP-30: 572 Boe/d Oil: 47% Lateral Length: 4,059' 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 Hoskins H (Chesapeake) Peak IP-30: 1,213 Boe/d Oil: 60% LL / Zone: 4,886' Hoskins H (Chesapeake) Peak daily rate: 1,401 Boe/d Oil: 65% Lateral Length: 4,841' Robison-Payday 16-1H (Carrera) First Prod. Date: 04/15 Peak IP-30: 773 Boe/d Oil: 46% Chain Ranch 1H-2 (Devon) First Prod. Date: 02/16 Peak IP-30: 1,214 Boe/d Oil: 16% Lateral Length: 4,589' Legend LINN Acreage Meramec Well Osage Well 22 rigs running in the area 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. 13

15 $ Millions Debt Reduction 1Q 2017 Total Debt to Adjusted EBITDAX (1) of 1.6x as of 3/31/2017 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, $3,088 $2,215 $ $540 $274 - $284 12/31/2015 with Berry 12/31/15 excluding Berry 3/31/2017 Estimated 5/31/2017 RBL Term Loan Second Lien Notes Unsecured Notes $497 million $415 million $60 million (3) Expected Jonah Sale Proceeds Total $8,161 $8,171 (2) (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 Does not reflect the anticipated effect of the Jonah asset sale 14

16 Capital Structure Common Equity 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 $294 million outstanding as of March 31, 2017 Matures February 27, 2021 Term Loan LIBOR 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 Initial conforming borrowing base of $1.4 billion - LIBOR +350 Matures in July 2020 $1.4 Billion Revolver ~$540 million (1) drawn on RBL A as of March 31, 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 nonconforming borrowing base with interest payable at LIBOR

17 Volume (MMMBtu/d) Volume (Bbls/d) Commodity Hedge Portfolio Natural Gas Positions Oil Positions ,000 12,000 12, , $ ,000 6,000 6,500 5, $3.01 4,000 $ ,000 $ $55.50 $ $ $ $ Swaps Swaps Collars Note: Hedge portfolio as of May 11 th,

18 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's financial results. The following presents a reconciliation of 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. The following presents the Company s calculation of total debt to adjusted EBITDAX: (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). 17