NYSE:CRK. Second Quarter 2018 Results

Transcription

1 NYSE:CRK Second Quarter 2018 Results

2 This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of Forward-looking statements give our current expectations or forecasts of future events. These statements include estimates of future natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, budgeted capital expenditures and other anticipated cash outflows, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in market prices for oil and gas, operating risks, liquidity risks, including risks relating to our debt, political and regulatory developments and legislation, and other risk factors and known trends and uncertainties as described in our Annual Report on Form 10-K for fiscal year 2017 filed with the Securities and Exchange Commission. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in the forward-looking statements. 2

3 2018 Q2 Summary Contribution of properties by Jerry Jones expected to be completed on August 14 th Cash flow from contributed properties will fund an expanded Haynesville shale drilling program to drive future growth Comprehensive refinancing plan will also be completed on August 14 th New credit facility with $700 million borrowing base $850 million in new eight year unsecured notes Haynesville/Bossier shale program continues to deliver strong results Consistent results from a proven drilling program as we have drilled and completed 52 operated wells since 2015 which have an average IP rate of 25 MMcf/day Drilling program expected to grow natural gas production by ~30% in 2018 and ~50% in 2019 Bolt-on Haynesville shale acquisition completed on July 31 st Adds approximately 9,900 net and 112 (31.0 net) undrilled locations 3

4 Jerry Jones Asset Contribution Jerry Jones is contributing Bakken Shale producing oil and gas properties valued at $620 million to Comstock in exchange for common stock in the Company. The effective date of the acquisition of the properties is April 1, 2018 Jones will receive approximately 88.6 million newly issued shares of Comstock common stock based on an agreed upon share price of $7.00 per share and will own approximately 84.5% of the Company's pro forma outstanding shares The contribution is subject to approval of the issuance of the common stock by our stockholders on August 10 th The contribution provides Comstock with substantial cash flow to invest in our high return Haynesville shale drilling program and the capital to further grow our drilling prospect inventory The contribution allows us to refinance and simplify our capital structure 4

5 Bakken Assets Provide Substantial Cash Flow Bakken Shale Properties Bakken Play Gross / Net Producing 348 / 55.1 Wells: Gross / Net DUCs: 85 / 11.8 Gross / Net PUDs: 7 / 2.6 Williston Basin Net 1P Reserves (By Operator) 348 (55.1 net) producing oil wells, 85 (11.8 net) drilled uncompleted wells and 7 (2.6 net) undrilled locations In the first quarter of 2018, produced on average approx. ~13,170 Boe/day Proved reserves of 22.8 million barrels of oil and 49.3 billion cubic feet of natural gas The Bakken Shale Properties generated $155.1 million of revenues in excess of operating costs, excluding depreciation, depletion, amortization, in % 4% 4% 20% 10% Total: ~31 MMBoe (1) 11% Whiting Continental Rimrock Other 47% Oasis Enerplus XTO 5

6 Enduro Acquisition Operated Non-OP 120 (26.2 net) producing wells and 112 (31.0 net) undrilled locations 9,893 net acres Producing approximately 26 MMCF per day Proved reserves of 288 billion cubic feet of natural gas 6

7 2018 Second Quarter Financial Results $ in millions except per share and unit amounts 2018 Second Quarter 2017 Second Quarter % Change Oil Production (Mbbls) % Gas Production (MMcf) 21,718 17,321 25% Production (MMcfe) 22,258 18,781 19% Oil Price (Per Barrel) $57.56 $ % Gas Price (Per Mcf) $2.64 $ % Oil and Gas Sales (1) $62.6 $ Lifting Costs % General and Administrative % Depreciation, Depletion and Amort % Loss on Sales of Properties Operating Income (Loss) before Taxes (1) $8.5 $11.9 Net Income (Loss) ($34.0) ($21.4) Net Income (Loss) per Share ($2.22) ($1.45) Net Income (Loss) per Share (2) ($0.78) ($1.07) EBITDAX $44.0 $ Cash Flow from Operations (3) $26.1 $25.9 1% (1) (3) Includes Realized Hedging Gains and Losses (2) Excludes property impairments, unrealized gain or losses from derivatives, gain or losses on property sales, costs of the unsuccessful April 2018 tender offer and the amortization of original issue discount from note exchange in Excludes Working Capital Changes 7

8 2018 First Six Months Financial Results $ in millions except per share and unit amounts 2018 First Six Months 2017 First Six Months % Change Oil Production (Mbbls) % Gas Production (MMcf) 43,364 31,320 38% Production (MMcfe) 45,044 34,368 31% Oil Price (Per Barrel) $65.12 $ % Gas Price (Per Mcf) $2.73 $2.98-8% Oil and Gas Sales (1) $136.6 $ % Lifting Costs % General and Administrative Depreciation, Depletion and Amort % Loss on Sales of Properties Operating Income (Loss) before Taxes (1) $4.8 $14.8 Net Income (Loss) ($75.9) ($44.4) Net Income (Loss) per Share ($4.99) ($3.06) Net Income (Loss) per Share (2) ($1.01) ($2.81) EBITDAX $97.7 $ % Cash Flow from Operations (3) $61.9 $ % (1) (3) Includes Realized Hedging Gains and Losses (2) Excludes property impairments, unrealized gain or losses from derivatives, gain or losses on property sales, costs of the unsuccessful April 2018 tender offer and the amortization of original issue discount from note exchange in Excludes Working Capital Changes 8

9 Shut-in Production 19.1 NATURAL GAS (MMcf per day) st Quarter nd Quarter rd Quarter th Quarter st Quarter nd Quarter Wells shut-in for pipeline curtailment or offset frac activity. 9

10 Low Cost Structure (Per Mcfe) OPERATING COSTS $5.74 DD & A.20 $1.48 $1.35 $ $ $2.26 $1.54 $1.60 $1.18 $ Q Q1 Gathering Production Taxes Lifting 2018 Q Q Q Q2 10

11 Oil and Gas Hedging Program Natural gas hedge positions to support Haynesville drilling program Swaps at $3.00 (a) Collars for $2.50 to $3.30 (a) Mcf per day Collars for $2.50 to $3.50 (a) Total Hedged 2018 Q3 60,000 30,000 30, , Q4 60,000 30,000 30, , Q1 47,000 30,000 30, , Q2-30,000 30,000 60,000 (a) Contracts are per MMBtu at an index price based on the NYMEX-Henry Hub monthly future prices Comstock targets having 50% to 60% of its expected future twelve months oil and gas production hedged on a rolling basis 11

12 Balance Sheet ($ in millions) As of 6/30/18 Pro Forma (1) Cash and cash equivalents $158 $37 Revolving Credit Facility ($700 million borrowing base) - $340 9¾% Senior Notes due $850 10% First Lien Secured Notes $697 - Convertible Second Lien PIK Notes (including accrued interest) $498 - Unsecured Senior Notes $26 - Total Debt (at face amount plus accrued PIK interest) $1,221 $1,190 Net Debt $1,063 $1,153 Available Credit Line $50 $360 Total Liquidity $208 $397 (1) Pro Forma for the Jones Contribution transaction which is expected to close on August 14,

13 Pro Forma Proved Oil & Gas Reserves Proved Reserves as of 3/31/2018 *: Oil MBbls Gas Bcf Total Bcfe Producing Non-Producing / Behind Pipe Total Developed Undeveloped , ,684.6 Total Proved Reserves , ,310.3 PV 10 Value (000s) $1,318.5 Reserves by Type Reserves by Commodity Mix *SEC Prices were $49.70/Bbl and $2.89/Mcf Excludes proved reserves related to Euduro Acquisition Reserves by Region PV-10 by Region Total: ~2.3 Tcfe 27% Total: ~2.3 Tcfe 10% 8% 5% Total: ~2.3 Tcfe 33% 2% 0% Total: ~$1.3Bn 65% 73% 90% 87% Developed Undeveloped Oil (MMcfe) Gas (MMcfe) Haynesville Eagle Ford Bakken Other Haynesville Eagle Ford Bakken Other 13

14 Capital Expenditures $179 Net Wells Drilled 2018 Drilling Program $ E ($ in millions) Haynesville/Bossier Shale: 2018 $ Gross Wells WI Net Wells Drilling and Completion $ Completion of 2017 Wells 22.0 ReFracs (7) 31.8 Other Non-operated Eagle Ford Shale Total Legacy Comstock $ Bakken Properties Total Capital Expenditures $ Operated Haynesville Laterals: <=5,000 ft. 5 7,500 ft. 7 10,000 ft. 24 Total 36 (1) (1) Average Lateral Length 2018E ,085 ft. 8,519 ft E 14 (1) Includes DUCs.

15 Comstock s Acreage Drilled 52 operated wells since 2015 with average IP rate of 25 Mmcf/d Cotton Valley Cotton Valley Haynesville Shale Bossier Shale Haynesville/Bossier Shale Net Acres 80,000* Resource Potential 10+ Tcf *47,000 net acres prospective for the Bossier shale 15

16 2 nd Quarter Drilling Results Nissen #1 27 MMcf/d Furrh #2 20 MMcf/d Harrison Cook #2 27 MMcf/d Nissen #2 25 MMcf/d Caddo Furrh #3 21 MMcf/d Cook #1 26 MMcf/d Wool #1 29 MMcf/d Panola Wool #2 33 MMcf/d Sibley #1 33 MMcf/d Wool #3 30 MMcf/d Lena Crews #1 34 MMcf/d Bagley #1 26 MMcf/d DeSoto BSMC #1 16 MMcf/d 16

17 Haynesville/Bossier Wells 30 Wells exceeding expectations 25 Gen 1 Type Curve (7500' Lateral) Gen I HV Wells (Average of 12 wells) 20 Bossier Wells (Average of 4 wells) MMcf per day Gen II HV Wells (Average of 24 wells) Gen ll HV Short Lateral Wells (Average of 8 wells) 5 0 Type Curve Days on production 17

18 Haynesville/Bossier Drilling Inventory Extensive inventory of drilling opportunities in the Haynesville and Bossier shales Gross Drilling Locations 10,000 ft. 7,500 ft. 5,000 ft locations (582 Haynesville/394 Bossier) (728 Operated/248 Non-Operated) Average WI 74% Average Royalty Burden 80% 18

19 The New Comstock Comstock s Haynesville and Bossier Shale assets provide consistent, high-return and low-risk drilling opportunity Enhanced completion design and regional price advantage have transformed the Haynesville into one of North America s highest return natural gas basins Extensive acreage position underpins 976 gross locations Bakken Shale oil-weighted production contributed by Jerry Jones provides leverage to oil prices Asset contribution represents a $620 million equity investment into the Company Substantial cash flow generated by Bakken properties to be redeployed in Haynesville and Eagle Ford to generate substantial production growth within cash flow Eagle Ford joint venture across ~23,000 acres targets 327 potential locations and adds future oil growth Strategy of disciplined growth by operating within cash flow Pro Forma Net Debt / LQA EBITDAX is ~ 2.9x, with goal to reduce net leverage <2.0x 50% to 60% of next twelve month expected production hedged on rolling basis Pro forma liquidity of $397 million 19