Fourth Quarter and Full Year 2017 Supplemental Presentation

Transcription

1 Fourth Quarter and Full Year 2017 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 EBITDAX 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. 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 Executed on the plan to sell non-core assets, eliminate all debt and evaluate strategic alternatives for all assets Formed a Merge/SCOOP/STACK pure play company Commenced construction on a Merge midstream business Exceeded $1.9 billion from closed and pending asset sales Repurchased ~5.9 million shares for ~$206 million as part of the $400 million share repurchase program Completed $325 million tender offer for ~6.8 million shares Announced strategic plan to separate into three standalone companies during 2018 Roan Resources LLC ( Roan ) Blue Mountain Midstream LLC ( Blue Mountain ) NewCo

5 Strategic Update Proposed Separation Into Three Standalone Companies During 2018 LNGG Roan Resources LLC 50% Equity Interest Blue Mountain Midstream LLC NewCo Merge/SCOOP/STACK Pure Play Growth Company Chisholm Trail Merge Midstream Growth Company Hugoton Michigan / Illinois NW STACK East Texas North Louisiana Arkoma 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 ~ 40,800 BOE/d Field level cash margin of $ $22.50 per BOE (2) 6 active drilling rigs and 2 active frac fleets Blue Mountain Midstream LLC Plan to separate LINN into 3 standalone companies during 2018 Michigan / Illinois Chisholm Trail - Merge Midstream Current 60 MMcf/d refrigeration facility Constructing a 250 MMcfe/d Cryogenic Plant that will be commissioned in 2Q 2018 More than 80,000 net acres dedicated At full capacity the Cryogenic plant could generate annual EBITDAX between $100 $125 million With the currently dedicated acreage we anticipate the need to expand this plant in the future Altamont Bluebell* Drunkards Wash Hugoton NW STACK Roan Resources LLC NewCo Mature long life, low decline assets: Hugoton Michigan / Illinois Emerging growth assets: NW STACK North Louisiana East Texas Arkoma Net Production: ~305 MMcfe/d (1) This company upon separation is expected to have no debt and assets that generate significant free cash flow Remaining Permian Panhandle* Conventional West Texas* Blue Mountain Midstream LLC Arkoma East Texas Oklahoma Waterfloods* North Louisiana Currently Marketing * PSA Executed (1) Average volumes from the fourth quarter of 2017 (2) Assuming $55 per bbl for oil and $2.75 per MMBtu for natural gas 5

7 Asset Sales Update Williston More than $1.9 billion of closed or pending asset sales ACTIVE SALES PROCESS Drunkards Wash Remaining Permian California Jonah Altamont Bluebell* Drunkards Wash TX Panhandle* Remaining Permian Conventional West Texas* Salt Creek Washakie Oklahoma Waterfloods* South Texas 2017 Closings 2018 Closings Proved Developed PV-10 (1) $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 $ 57 $ 50 Washakie $ 102 $ 200 $ 193 Williston $ 186 $ 285 $ 255 Total $ 1,066 $ 1,558 $ 1,473 Proved Developed PV-10 (2) $3 / $50 $ in millions Contract Price $ in millions Estimated Proceeds $ in millions Oklahoma Waterfloods* $ 35 $ 42 $ 38 Texas Panhandle* $ 63 $ 80 $ 74 Altamont Bluebell* $ 45 $ 132 $ 122 Permian* (3) $ 106 $ 157 $ 144 Total $ 249 $ 411 $ 378 (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 2017 * Signed purchase and sale agreement 6

8 2017 Year End Proved Reserves All assets owned by LINN as of December 31, % Natural Gas 22% ~2.0 Tcfe of Proved Reserves 5% 3% PV-10 of ~$1.3 Billion (1) 3%3% 8% 70% Natural Gas Oil NGL 92% PDP PDNP PUD 94% PDP PDNP PUD Proved Reserves as of December 31, 2017 Natural Gas Bcf Oil MMBbl NGL MMBbl Total Bcfe SEC Value ($ in millions) PV-10 (1) ($ in Millions) LINN s 50% Equity Interest in Roan SEC Value ($ in millions) PDP 1, ,804 $ 982 $ 1,267 PDNP $ 32 $ 38 Total Proved Developed 1, ,908 $ 1,014 $ 1,305 PUD $ 31 $ 41 Total Proved 1, ,968 $ 1,045 $ 1,346 $ 303 $ 31 $ 334 $ 264 $ 598 (1) SEC pricing of $2.98 per MMBtu for natural gas and $51.34 per bbl for oil. 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. 7

9 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 LINN retained Chisholm Trail Cryogenic Plant 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 January 2018 Net production of ~40,800 BOE/d as of the end of January 2018 Field level cash flow margin of $22.00 to $22.50 per BOE (2) Current development activity of six drilling rigs and two frac fleets Roan management begins to assume operations Building an organization and currently at more than 50 employees Roan Acreage (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 (2) Assuming $55 per bbl for oil and $2.75 per MMBtu for natural gas 8

10 Roan Resources Strong Offset Results Increase Growth Potential MRO STACK Meramec Volatile oil wells continue to outperform Alta Mesa STACK Oil Window Meramac / Osage 6 Active Rigs XEC Lone Rock Play Best Results to Date Over-pressured Woodford 8-11 well per section spacing test CLR SCOOP Springer Play 24-hr IPs from 1,257 2,300 BOE/d 79%-89% Oil SCOOP Woodford Play Sympson Density Test 12 wells 24-hr IPs averaged 3,145 BOE/d 11% Oil 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 7 recent 1-1/2 mile laterals average IP-30 of ~18 MMcfe/d Note: Sourced from investor presentations for each company Roan Acreage 9

11 Roan Resources Significant Activity in the Merge Roan Activity 6 Active horizontal drilling rigs 19 New wells online in 4Q 1,870 BOE/d Normalized Avg Peak IP-30 (1&2) ~80% Avg Working Interest 73% Avg Liquids% (2) Industry Activity 32 Active horizontal drilling rigs 192 New horizontal permits filed since September 1, Horizontal wells with Peak Month > 1,000 BOE/d (1) Normalized Peak IP-30 numbers are linearly normalized to 10,000 lateral length (2) Calculated from gross three-stream daily volume estimates Note: Rig, permit and peak month data sourced from DrillingInfo as of February 1, 2018 Roan Acreage Roan Pads with 4Q Completions 10

12 Chisholm Trail Midstream Primary growth asset of Blue Mountain Midstream LLC Cryogenic plant with a capacity of 250 MMcf/d under construction and expected to be commissioned in the second quarter of 2018 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 7,200 acres in a 13 township area Anticipate 10 new wells to be connected Increased capital forecast for gathering More than 80,000 net acres now dedicated to the plant Once the plant reaches full capacity, the Chisholm Trail midstream business is forecasted to generate annual EBITDAX 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 currently dedicated acreage we anticipate the need to expand this plant in the future Cryogenic Plant Under Construction 250 MMcf/d Capacity Capital Forecast (in millions) $33 (1) $96 (1) $96 $23 Z Roan AMI LINN Dedicated Acreage (1) Actual capital spent rd Party Dedication Area 11

13 NewCo Asset Map Growth NW STACK Net Production of ~15 MMcfe/d Large HBP acreage position of ~105,000 net acres with positive offset Osage & Meramac horizontal activity 305 MMcfe/d Fourth Quarter 2017 Net Production ~1.6 Tcfe Proved Developed Reserves 76% Natural Gas 23% NGL 11% Approximate Base Decline Rate East Texas Net Production of ~57 MMcfe/d One Bossier and one Cotton Valley Lime horizontal test well drilled in 2017 Michigan / Illinois North Louisiana Net Production of ~34 MMcfe/d Three Upper & one Lower Red horizontal test wells drilled in Ruston in Arkoma Net Production of ~26 MMcfe/d Horizontal Woodford Play More than 150 net infill locations identified Hugoton NW STACK Long life, low decline Arkoma Hugoton North Louisiana Net Production of ~144 MMcfe/d More than 3,400 vertical infill locations Significant helium value + Jayhawk Plant East Texas Michigan / Illinois Net Production of ~29 MMcfe/d Long-life stable gas field in the Antrim shale with a base decline of ~4% 12

14 NewCo Asset Detail NewCo Asset Detail Net Production (1) MMcfe/d Proved Developed (2) Reserves Bcfe Proved Developed (3) PV-10 $ in millions Hugoton East Texas North Louisiana Michigan / Illinois Arkoma NW STACK Total 305 1, (1) Average daily fourth quarter 2017 actual production (2) SEC reserves as of December 31, 2017 (3) SEC pricing of $2.98 per MMBtu for natural gas and $51.34 per bbl for oil adjusted for helium revenue and excluding income taxes 13

15 NW STACK Asset Highlights NW STACK Majority operated position of ~105,000 net acres that is 99%+ held by production is retained by LINN Net Production of ~15 MMcfe/d (1) Significant and consolidated opportunity in the emerging NW STACK with the majority in Major and Blaine counties Meramec and Osage plays in northern Blaine, Dewey and Major counties are evolving into economic targets based on recent results Activity continues to increase in the area LINN Acreage Roan Acreage 33 Active Horizontal Rigs (1) Volumes are average daily fourth quarter 2017 actual production Note: Rig and permit data sourced from DrillingInfo as of February 1, horizontal drilling permits filed since September 1,

16 North Louisiana & East Texas Asset Highlights Net Production of 91 MMcfe/d (1) Targeting Upper and Lower Red horizontals in the Ruston field of North Louisiana Targeting Bossier Sand and Cotton Valley Lime horizontals in East Texas Key Developments Recently completed two operated horizontal wells in Ruston testing the Upper and Lower Red Personville Nan-Su-Gail Oakes Lassater Overton Rocky Mount Lisbon Pettit Waterflood Ruston Calhoun Recently drilled and completed two new wells in East Texas with positive results Bald Prairie Recent operated recompletions to the Cotton Valley and Travis Peak have seen high rates-ofreturn at current prices Significant inventory of additional recompletion opportunities provide the potential to offset base decline with minimal capital ETX Development NLA Development TexLa Development Program Working Interest First Production Zone Lateral Length (ft) Peak 24-hr IP Rate 1 Elliott et al 1 11 HC-1 49% Feb-16 Upper Red 6,503 ~24 MMcfe/d; choke managed 2 Carter et al 6H No. 1 Alt 77% Jan-17 Upper Red 4,021 ~18 MMcfe/d; choke managed 3 Elliott et al 1H No. 1 Alt 71% July-17 Lower Red 3, MMcf/d; choke managed 4 JP Graham 2H No. 2 Alt 71% Aug-17 Upper Red 4, MMcf/d; choke managed 1 McFerran U Burleson U 1 HA 97% Oct-17 Bossier HZ 5, MMcfe/d; choked managed 2 Nettles U McFerran LCCO 1 HA 99% Nov-17 CV Lime HZ 6, MMcfe/d; choked managed (1) Volumes are average daily fourth quarter 2017 actual production 15

17 Arkoma Asset Highlights Net Production of ~26 MMcfe/d (1) (82% Natural Gas, 18% NGL) NFX Ellis 2H-34XX Woodford 30-day Peak: ~13.1 MMcf/d Base decline of approximately 9% Contiguous majority operated acreage in the core of Arkoma Basin Primary target is the Woodford NFX Ellis 3H-34XX Woodford 30-day Peak: ~12.2 MMcf/d Highly delineated area with widely acknowledged geologic boundaries and understanding of gas BTU content Primary opportunity exists in infill drilling, refracs and recompletes Key Developments Renegotiated gas contract improves new drill economics Recent offset results with next generation fracs have shown potential of the Woodford to deliver improved economics More than 150 net locations (80 acre spacing) ~40% of operated sections have only one producing well BP Bowen 2-18/7H Woodford 30-day Peak: ~10.2 MMcf/d XOM HOOE 1-3H Woodford 30-day Peak: ~13.6 MMcf/d (1) Volumes are average daily fourth quarter 2017 actual production 16

18 Net Production Natural Gas Price ($/MMBtu) Hugoton Asset Highlights Net Production of ~144 MMcfe/d (1) (65% Natural Gas, 35% NGL) ~1.1 million net acres that are 99%+ held by production (2) Very mature, low decline, highly delineated natural gas field Position acquired through a number of transactions from , positioning LINN as one of the largest operators in the basin Focus on Chase and Council Grove formations which produce significant revenue from NGLs and helium Extensive gathering infrastructure and a significant midstream / processing investment 100% interest in the Jayhawk processing plant with capacity of 450 MMcf/d (currently at ~60% utilization) More than 3,400 vertical infill locations identified Estimate a minimal amount of capital to offset base decline Jayhawk Plant 450 MMcf/d Capacity Net Production (MMcfe/d) Decline Rate of ~6% $2.75 $3.00 Price Sensitivity Number of drilling locations greater than 20% ROR Average annual capital of ~$3 million January 2015 to December 2017 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 (1) Volumes are average daily fourth quarter 2017 actual production (2) Acreage as of year end 2016 $3.25 $3.50 $3.75 $ ,000 1,500 2,000 2,500 3,000 3,500 17

19 Michigan / Illinois Asset Highlights Net Production of ~29 MMcfe/d (1) (97% Natural Gas, 3% Oil) Base decline of approximately 4% Approximately 200,000 net acres Michigan is a low decline, biogenic natural gas asset Illinois is a waterflood acquired in 2008 (1) Volumes are average daily fourth quarter 2017 actual production 18

20 2018 Guidance Q1 2018E FY 2018E Net Production (MMcfe/d) Natural gas (MMcf/d) Oil (Bbls/d) 7,327 8,098 2,619 2,894 NGL (Bbls/d) 12,426 13,734 10,073 11,133 Other revenues, net (in thousands) (1) $ 13,000 - $ 15,000 $ 71,000 $ 79,000 Costs (in thousands) $ 72,000 $ 81,000 $ 205,000 $ 226,000 Lease operating expenses $ 43,000 $ 48,000 $ 101,000 $ 111,000 Transportation expenses $ 20,000 $ 23,000 $ 78,000 $ 86,000 Taxes, other than income taxes $ 9,000 $ 10,000 $ 26,000 $ 29,000 General and administrative expenses (2) $ 24,000 $ 27,000 $ 60,000 $ 66,000 Costs per Mcfe (Mid-Point) $ 2.15 $ 1.89 Lease operating expenses $ 1.28 $ 0.93 Transportation expenses $ 0.60 $ 0.72 Taxes, other than income taxes $ 0.27 $ 0.24 General and administrative expenses (2) $ 0.72 $ 0.55 Targets (Mid-Point) (in thousands) Adjusted EBITDAX $ 39,000 $ 153,000 Interest expense $ $ Oil and natural gas capital $ 7,000 $ 34,000 Total capital $ 60,000 $ 134,000 Weighted Average NYMEX Differentials Natural gas (MMBtu) ($ 0.33) ($ 0.29) ($ 0.41) ($ 0.37) Oil (Bbl) ($ 3.45) ($ 3.12) ($ 2.02) ($ 1.83) NGL price as a % of crude oil price 39% 43% 40% 44% (1) Includes other revenues and margin on marketing activities (2) As included in operating cash flow and excludes share-based compensation expenses and severance costs Unhedged Commodity Price Assumptions Jan Feb Mar 2018E Natural gas (MMBtu) $ 2.74 $ 3.63 $ 2.58 $ 2.79 Oil (Bbl) $ $ $ $ NGL (Bbl) $ $ $ $

21 FY 2018 Capital Allocation Total Capital $134 million ($ in millions) Chisholm Trail Midstream Sold (1), (3) Assets Blue Mountain Midstream 1H'18 $73 Remaining O&G Assets Blue Mountain Midstream 2H'18 $23 Asset Sales (2) $5 Remaining Assets Oil & Gas Capital (1) $29 Other P&P / Admin $4 Excludes LINN s 50% equity interest in Roan (1) Remaining Assets include Hugoton, Michigan, Arkoma, NW STACK, North Louisiana, and East Texas (2) Asset Sales include Oklahoma Waterfloods, Texas Panhandle and Altamont Bluebell forecasts assuming 2/28/18 closing for each, respectively, and Drunkards Wash, Permian, Oklahoma Conventional, and Royalties forecasts assuming 3/31/18 closing for each, respectively. 20

22 $ Millions 2018 EBITDAX Outlook 175 Current Guidance Pro forma Estimates Adjusted NewCo Guidance 150 ($23) ($40) $5 $38 75 $153 $ $ FY 18 Guidance Pre-Close EBITDAX from Assets Sales (1) FY18 EBITDAX from Blue Mountain Midstream (2) Implied proforma FY 18 E Severance Expense Expected G&A Reductions (3) Pro-Forma FY18 Estimate (1) Represents EBITDAX before closing for the following: Oklahoma Waterfloods, Texas Panhandle, and Altamont Bluebell forecasts assuming 2/28/18 closing for each, respectively; Drunkards Wash and Permian forecasts assuming 3/31/18 closing for each, respectively. (2) Only includes the Chisholm Trail Midstream business (3) Further G&A reductions to pro-forma run-rate of approximately $25 million annually Excludes LINN s 50% equity interest in Roan 21

23 Pro-Forma Cash 3/31/2018 ($ in millions) Ending Cash 12/31/17 Q1'18 EBITDA Q1'18 Capital 2017 Cash Taxes Tender offer (1) Q1'18 Asset Sales Other Feb '18 Share Repurchases Projected Cash Balance 3/31/2018 $39 ($60) $465 $465 $444 $436 ($8) ($25) $413 $405 ($8) ($340) $342 $405 $96 $96 Pro Forma Est. Beg. Cash $465 $465 $504 $444 $436 $96 $438 $413 $405 Source/(Use) $ - $39 ($60) ($8) ($340) $342 ($25) ($8) $ - Ending Cash $465 $504 $444 $436 $96 $438 $413 $405 $405 (1) Includes $325 tender offer, plus $12 million profits interest, and approximately $3 million for advisor fees 22

24 Tender Offer TENDER OFFER TO PURCHASE SHARES $325 million 6,770,833 SHARES Purchase Price $48.00 per share CLASS A COMMON STOCK 8.1% of company s current Class A common stock Closing price per share January 5, 2018 ~94% Participation Completed January 22, 2018 Payments 8.7% Pro-ration Factor 23

25 $ in millions Share Repurchase and Tender Offer As of February 21, 2018 ~13 million total shares repurchased 14% of all shares issued at emergence ~$194 million remain under the current $400 million authorization 600 ~$531 million ~$325 million 300 ~$198 million 200 ~$8 million Share Repurchases Tender Offer 2018 Share Repurchases Total 24

26 Volume (MMMBtu/d) Volume (Bbls/d) Commodity Hedge Portfolio Natural Gas Positions Oil Positions 250 7,000 6, ,000 5,000 5, $3.17 4,000 $ $ $3.02 $3.02 $ ,000 2,000 1,000 $54.07 $ $ Swaps $2.97 $ Swaps Collars Note: Hedge portfolio as of December 31,