Cowen and Company 4th Annual Ultimate Energy Conference
- Dr. Peter Hill, Interim CEO
MIDSTATES PETROLEUM COMPANY, INC. Cowen and Company 4 th Annual - - PowerPoint PPT Presentation
MIDSTATES PETROLEUM COMPANY, INC. Cowen and Company 4 th Annual Ultimate Energy Conference Dr. Peter Hill, Interim CEO December 3, 2014 Forward-Looking Statements This presentation contains forward-looking statements within the meaning of the
This presentation contains forward-looking statements within the meaning of the federal Securities laws. All statements included in this presentation,
projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words ‘‘could,’’ ‘‘believe,’’ ‘‘anticipate,’’ ‘‘intend,’’ ‘‘estimate,’’ ‘‘expect,’’ ‘‘may,’’ ‘‘continue,’’ ‘‘predict,’’ ‘‘potential,’’ ‘‘project,’’ “guidance,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Without limiting the generality of the foregoing, these statements are based on certain assumptions made by the Company based on management’s experience, expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Although the Company believes that its plans, intentions and expectations reflected in or suggested by the forward-looking statements made in this presentation are reasonable, the Company gives no assurance that actual future results will not differ materially from those forecasted in this
the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Each investor must assess and bear the risk of uncertainty inherent in the forward looking statements in this presentation. The Company discloses important factors that could cause its actual results to differ materially from its expectations in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections of the Company’s Form 10-K for the year ended December 31, 2013, and Form 10-Q for the quarters ended March 31,2014, June 30,2014, and September 30,2014 each filed with the Securities and Exchange Commission (“SEC”); and its other filings with the SEC. These factors include risks or liabilities assumed as a result of acquisitions, increases in our indebtedness, ability to complete any divestitures or other strategic transactions, ability to meet financial and operating guidance, ability to achieve production targets, successfully manage capital expenditures, and to complete and to test and produce the wells and prospects identified in this presentation; risks related to variations in the market demand for, and prices of, oil and natural gas; uncertainties related to commodity prices, uncertainties about the Company’s estimated quantities of oil and natural gas reserves or potential locations; infrastructure for salt water disposal and electricity; the adequacy of the Company’s capital resources and liquidity including, but not limited to, access to additional borrowing capacity under its revolving credit facility; general economic and business conditions; failure to realize expected value creation from property acquisitions; uncertainties about the Company’s ability to replace reserves and economically develop its current reserves; risks related to the concentration of the Company’s operations; drilling results; pending litigation; and potential financial losses or earnings reductions from the Company’s commodity derivative positions. Accordingly, you should not place undue reliance on any of the Company’s forward-looking statements. All forward-looking statements speak only as
whether as a result of new information, future events or otherwise, except as required by applicable law.
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This presentation also includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), including Adjusted EBITDA and Cash Operating Expense. While management believes such measures are useful for investors because they allow for greater transparency with respect to key financial metrics, they should not be used as a replacement for financial measures that are in accordance with GAAP. The SEC permits oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. SEC rules also permit the disclosure of “probable” and “possible” reserves. We disclose proved reserves but do not disclose probable or possible reserves. We may use certain broader terms such as “EUR” (as defined below) and other descriptions
These broader classifications do not constitute "reserves" as defined by the SEC, and we do not attempt to distinguish these classifications from probable or possible reserves as defined by SEC guidelines. We define EUR as the cumulative oil and gas production expected to be economically recovered from a reservoir or individual well from initial production until the end of its useful life. Our estimates of EURs and resource potential have been prepared internally by our engineers and management without review by independent engineers. These estimates are, by their nature, more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. We include these estimates to demonstrate what we believe to be the potential for future drilling and production by the Company. Actual locations drilled and quantities that may be ultimately recovered from our properties could differ substantially. In addition, we have made no commitment to drill all of the drilling locations which have been attributed to these quantities. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. Estimates of resource potential and other figures may change significantly as development of our properties provides additional data. Our forecast and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking and outcome of future drilling activity and activity that may be affected by significant commodity price declines or drilling cost increases. The Company’s estimates of total proved reserves at December 31, 2013 are based on reports provided by Netherland, Sewell & Associates, Inc. and Cawley, Gillespie & Associates, Inc., independent petroleum engineers.
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Balance 2014 Operating Capex with Adjusted EBITDA $500-550MM Assure Liquidity Through 2015 to Fund Current Program Target Cash Flow Breakeven by 2016 Evaluate All Options to Improve Balance Sheet & Unlock Value
Focus on Miss Lime & Anadarko Control Costs & Expand Cash Margins High-Grade & Expand Inventory Allocate Rigs Where Returns are Highest
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I. Release the Value in the Asset Base
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Oil 33% Gas 41% NGLs 26% Oil 40% Gas 38% NGLs 22%
Anadarko Basin
Gulf Coast (Fleetwood)
sold by 12/31/14
prospects to be initially funded by JV partner
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Gulf Coast ~1% Miss Lime ~72% Anadarko ~26%
2014E Capex By Area
Balanced Commodity Mix
Midstates has a robust, strategically-located portfolio offering significant growth
Mississippian Lime(1)
Lincoln County
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(1) Includes Hunton acreage and reserves (2) Year end 2013 reserves prepared by NSAI in the Mississippian and Cawley Gillespie in the Anadarko
111 MMBoe
Growing Resource Base in Diverse Portfolio
Balanced growth – both through the drillbit and with strategic acquisitions Proved Reserves – YE2013 Net Resource Potential Reserves Growth
550-650 MMBoe
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Tonkawa and Cottage Grove formations
development from Upper Miss and proven Anadarko Basin plays
plays from multi-stacked horizons with compelling economics
improvements
Company anticipates significant reserves growth through additional horizons, downspacing and well performance enhancements from completion and operational improvements
Overview Gross Undeveloped Locations Net Undeveloped Resource Potential: 550-650MMBoe
(1)
577 344 794 1,715 788 623 1,411 142 142 3,268 500 1,000 1,500 2,000 2,500 3,000 3,500
Upper Miss Upper Miss Downspacing
Base Additional Horizons Fleetwood Total Locations
Gross Well Locations
325 - 375 150 - 250 20-60
Miss Anadarko Fleetwood
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Robust economics even in challenged commodity price environments
Upper Miss IRRs at Various Prices Single Well Economics and Detail Anadarko IRRs at Various Prices
(1)
Key Economic Parameters Upper Miss Altered Upper Miss Enhanced Upper Miss Grainstone Cleveland Marmaton Tonkawa Cottage Grove Gross 24-hr IP, 2-stream (boepd) 750 1083 658 398 452 593 435 Gross EUR, 2-stream (MBoe) 520 527 471 203 221 283 309 % Liquids 56% 60% 63% 62% 67% 73% 79% D,C&F Cost ($mm) $3.8 $3.8 $3.8 $2.9 $3.2 $3.9 $4.0 F&D Cost, ($/Boe) $8.18 $8.14 $9.19 $15.61 $15.94 $15.15 $14.38 BT NPV-10 ($mm) (@$80/$4) $5.5 $5.7 $4.9 $1.5 $1.7 $3.1 $2.8 Locations 225 72 280 264 78 208 238
Note: Anadarko Basin economics run using best well costs by formation
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MPO Acreage Sandridge Acreage
KANSAS OKLAHOMA
Woods Alfalfa Grant Woodward Garfield Major
PETRA 8/13/2014 11:22:10 AMAlfalfa Counties, which are largely HBP, in the recognized core of the play
resource potential of ~225 MMBoe
prospective horizons on our acreage with estimated net resource potential of ~125 MMBoe
(1) Includes Hunton Play in Lincoln County, OK (2) Includes workover expense
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Chesapeake Acreage
Woods Alfalfa
PETRA 8/13/2014 11:14:49 AM7,207 9,468 10,426 14,364 17,579 16,381 20,698 23,834
10,000 15,000 20,000 25,000 30,000 Q4 2012 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014E Gas NGL Oil
Net Production (Boe/d) (1)
24,000 – 25,000
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Manning Updip limit Top “St. Gene.” Updip Limit Base “St. Gene.” Updip Limit
Primary Porosity Highly Altered
Middle Miss
Individual Depositional Porosity Intervals
Enhanced Porosity
– High-graded locations – Optimized well placement and completion techniques – Opportunistically expanded acreage position
– Additional downspacing and multi-lateral potential – Stacked pay zones – Multiple Mississippian benches, other horizons in addition to the Miss
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3D seismic and application of new technologies are considerably expanding the inventory of the Mississippian section
SSW NNE
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1320’ well spacing
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Peak 30-Day Production Rates through October 2014
Nearly 50% of all wells are >500 Boe/d; for those wells, IRRs are ~80% at 11/3/14 strip pricing
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$4.5 $3.5 $3.6 $3.6 $3.7 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014
Well Cost $MM
– Pad drilling up to 6 wells per pad and re-built mud systems – Eliminated tank rentals and trucking and switched to 100% produced water for fracs
– Frac design: use most cost-effective design by well – Potential service cost reductions due to soft macro environment estimated at 5% - 15%
Sandridge Average Lateral: $2.9mm
Q3 Results Midstates Sandridge Wells Online 20 122 D&C Cost $3.7mm $2.9mm 21% higher Avg 30 day peak rates(1) 660 368 79% higher Liquids Percentage 60% 52% 8% higher
Midstates Miss Target: $3.2mm
Focused on continuous improvements to maximize returns
(1) Rate is for Q3 wells only, MPO rate for all Miss wells is 575boe/d, SD is ~425boepd
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Acreage position overlays stacked pay zones which provide additional upside potential
Zone Future Gross Locations Estimated Net Resource (MMBoe) D&C ($mm) Upper Miss 577 125-150 $3.5-3.7 Upper Miss Downspacing 344 70-80 $3.5-3.7 Middle & Lower Miss 111 20-25 $4.0 (1) Viola 138 20-25 $3.6 (1) Woodford 68 5-10 $4.2 (1) Hunton 57 10-15 $2.5 (1) Cherokee (Red Fork) 83 15-20 $2.1 (1) Marmaton (Oswego) 143 30-40 $3.2 (1) Cottage Grove 96 15-20 $2.0 (1) Chester 98 10-15 $3.6 (1) Total 1,715 325-375
Oil Zone Gas Zone (1) Projected D&C costs
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MPO differentiated results driven by premium acreage and our understanding of the geology
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MPO Apache
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OKLAHOMA TEXAS
Beaver Harper Woods Woodward Ellis Dewey Roger Mills Custer Ochiltree sford Lipscomb Roberts Hemphill inson
PETRA 8/13/2014 11:05:55 AMJones Sandridge Chesapeake
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$3.4 $3.8 $4.2 $4.1 $2.9 $3.2 $4.0 $3.9 0.0 1.0 2.0 3.0 4.0 5.0 Cleveland Marmaton Cottage Grove Tonkawa
Well Cost $MM
Historical Average* Best Well
– Consistent cost performance – Majority of drilling activity since acquisition – Significant cost performance improvement since acquisition
– Limited activity since acquisition – Opportunity to apply learnings from other horizons to realize efficiency gains
32 Wells 10 Wells 7 Wells 3 Wells
Focused on well cost improvements consistent with successful improvements in the Mississippian Lime
*Historical Average: Excludes wells with major mechanical issues
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AVG BEST AVG BEST AVG BEST AVG BEST (1) At $80 WTI & $4.00 HH
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Lowering D&C costs can significantly improve returns at any commodity price
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Zone Future Gross Locations Estimated Net Resource (MMBoe) D&C ($mm) Cleveland 264 25-35 $3.4 Marmaton 78 10-15 $3.8 Tonkawa 208 20-30 $4.1 Cottage Grove 238 20-30 $4.2 Atoka (Oil) 94 5-10 $3.6 (1) Atoka (Gas) 22 2-5 $3.6 (1) Oswego (Upper) 142 25-50 $3.7 (1) Oswego (Lower) 181 30-60 $3.7 (1) Other (2) 184 15-25 $2.0-$3.5 (1) Total 1,411 150-250
Oil Zone Gas Zone (1) Projected D&C costs (2) “Other” includes Douglas, Kansas City, Red Fork and Morrow
Acreage position overlays stacked pay zones which provide additional upside potential
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reductions or more favorable commodity prices
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Learnings from the Miss Lime, stacked pay potential, and new D&C techniques will drive improvements
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– Gross Resource Potential: 191 MMBOE (Mean); 557 MMBOE (P10)
– $10mm cash consideration, $14mm future carry – PetroQuest will operate all but one prospect
– 2014 wells: Bayou Cholpe (Lower Wilcox) Spudding in Q4 – 2015 wells: Konik (Cockfield) Likely Spudding early Q1 and TBD (Big Red Stick West & Lower Rowe)
– Kenmore AMI (Konik/Maringouin): MPO 25% (50% Vitol group; 25% PQ) – Bayou Cholpe: MPO 25% (50% Vitol; 25% PQ) – Remainder of Inventory: MPO 50%, PQ 50%
Fleetwood Overview
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Miss Miss Miss Anadarko Anadarko Gulf Coast Gulf Coast Gulf Coast 9,999 23,926 32,000-35,000
10,000 15,000 20,000 25,000 30,000 35,000 40,000 2012 2013 2014E
Boed
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$145 $330
100 200 300 400 500 2012 2013 2014E
$MM
Q2 $114 Q3 $132 Q2 $123
Market understates Midstates’ performance and progress allowing for an attractive investment opportunity
Production Growth over Time Balancing Operational Capex with Adjusted EBITDA $102 $119 $114 $123 $132 $160 $135 $135 $141 $134 $- $50 $100 $150 $200 Q3'13 Q4'13 Q1'14 Q2'14 Q3'14 EBITDA OP CAPEX Adjusted EBITDA Growth over Time
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$42.35 $34.96 $32.75 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 MPO Peer 1 Peer 2
(1) See reconciliation in the appendix (2) Peers include Sandridge and Jones, Q3 data used where available, if unavailable Q2 data used
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Quarterly Adjusted EBITDA(1) / Boe
performance, focus on liquids rich areas and aggressive operating cost management
costs and strong Miss Lime results
$3.36/Boe
from Q3 2013 to Q3 2014
macro pricing weakness
with potential for continued improvement Q3 2014 EBITDA / Boe vs. Mid Con Peer Group(2)
$39.04 $41.35 $43.71 $42.26 $42.35 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014
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$8.32 $7.04 $7.71 $6.79 $5.46 $4.58 $4.27 $3.89 $3.90 $2.63 $3.09 $2.31 $2.93 $1.94 $1.86 $1.09 $1.01 $1.26 $16.98 $14.61 $15.62 $13.63 $11.21 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 $/BOE Gathering & Transportation Severance & Other Taxes G&A (Cash) OpEx
Cash Operating Expense Improvements Over Time (1)
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RAMP UP
Production: 35,000 – 36,000 BOEPD Capital: $475 mm - $525 mm
Rigs: 7-8 Miss, 2-3 Anadarko
Production: 34,000 – 35,000 BOEPD Capital: $450 mm - $475 mm
Rigs: 7 Miss, 1-2 Anadarko
Production: 33,000 – 34,000 BOEPD Capital: $400 mm - $450 mm
Rigs: 6-7 Miss, 0-1 Anadarko
Base Oil Price $80 - $90 High Oil Price $90 - $100 Low Oil Price $70 - $80
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Midstates is positioned to tackle the uncertain macro environment heading into 2015
2015 estimate: $1 change in oil price results in ~ $2.5mm change in Adjusted EBITDA
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$ millions
predictability of cash flow
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Cash Balance Borrowing base Net Liquidity September 30 Liquidity $26,000 ($370,000) $525,000 $181,000 Revolver
4.4 4.1 4.0 3.6 0.0 1.0 2.0 3.0 4.0 5.0 YE'13 Q1'14 Q2'14 Q3'14
Net Debt / Adjusted EBITDA
Potential Actions to Further Improve Liquidity:
further focus on Miss Lime
could be possible allowing us to focus on our core Mid continent assets
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by year end
debt metrics
Midstates has the flexibility, cost structure and asset base to withstand the current macro price uncertainty
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Solid repeatable results with compelling well economics; Midstates outperforming peers
Upper Miss Type Curves
Key Economic Parameters Altered Enhanced Grainstone Oil 24-hr IP (bpd) 400 575 350 Gas 24-hr IP (mcfd) 2,100 3,050 1,850 NGL Yield (bbl/Mmcf) 65 65 65 Gross EUR, 2-stream (MBoe) 520 527 471 D&C Cost ($mm) $3.8 $3.8 $3.8 F&D Cost, ($/Boe) $8.18 $8.14 $9.19 Gas Diff $ ($0.19) ($0.19) ($0.19) Oil Diff $ ($2.70) ($2.70) ($2.70) NGL as % of Oil Price 36% 36% 36%
IRR Sensitivity Type Curve Assumptions – Upper Miss
# of Locations Upper Miss Altered 225 Upper Miss Enhanced 72 Upper Miss Grainstone 280 Upper Miss Altered (Downspace) 83 Upper Miss Grainstone (Downspace) 261 Total (With Downspacing) 921
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Low-risk portfolio ranging from mature to high-growth assets, with diverse product mix and competitive D&C capital requirements Cleveland Type Curve IRR Sensitivity Type Curve Assumptions – Cleveland
Key Economic Parameters Oil 24-hr IP (bpd) 203 Gas 24-hr IP (mcfd) 1,167 NGL Yield (bbl/Mmcf) 77 Gross EUR, 2-stream (MBoe) 203 D&C Cost ($mm) $2.9 - $3.4 F&D Cost, ($/Boe) $15.61 - $18.31 Gas Diff $ ($0.36) Oil Diff $ ($4.00) NGL as % of Oil Price 40%
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Low-risk portfolio ranging from mature to high-growth assets, with diverse product mix and competitive D&C capital requirements Marmaton Type Curve Type Curve Assumptions – Marmaton
Key Economic Parameters Oil 24-hr IP (bpd) 315 Gas 24-hr IP (mcfd) 826 NGL Yield (bbl/Mmcf) 82 Gross EUR, 2-stream (MBoe) 221 D&C Cost ($mm) $3.2 - $3.8 F&D Cost, ($/Boe) $15.54 - $18.22 Gas Diff $ ($0.36) Oil Diff $ ($4.00) NGL as % of Oil Price 40%
IRR Sensitivity
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Low-risk portfolio ranging from mature to high-growth assets, with diverse product mix and competitive D&C capital requirements Tonkawa Type Curve Type Curve Assumptions – Tonkawa
Key Economic Parameters Oil 24-hr IP (bpd) 454 Gas 24-hr IP (mcfd) 836 NGL Yield (bbl/Mmcf) 92 Gross EUR, 2-stream (MBoe) 283 D&C Cost ($mm) $3.9 - $4.1 F&D Cost, ($/Boe) $15.15 - $15.92 Gas Diff $ ($0.36) Oil Diff $ ($4.00) NGL as % of Oil Price 40%
IRR Sensitivity
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Low-risk portfolio ranging from mature to high-growth assets, with diverse product mix and competitive D&C capital requirements Cottage Grove Type Curve Type Curve Assumptions – Cottage Grove
Key Economic Parameters Oil 24-hr IP (bpd) 336 Gas 24-hr IP (mcfd) 594 NGL Yield (bbl/Mmcf) 103 Gross EUR, 2-stream (MBoe) 309 D&C Cost ($mm) $4.0 - $4.2 F&D Cost, ($/Boe) $14.38 - $15.10 Gas Diff $ ($0.36) Oil Diff $ ($4.00) NGL as % of Oil Price 40%
IRR Sensitivity
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D&C 90 - 95%
Land, Seismic, Infrastructure 5 - 10%
By Type
Operating Capital (1) First Glance: $450 to $475 million
8 rigs planned in Q1 2015 with flexibility to ramp up or down
Capital Efficiency and Discipline
Goal: Maintain 2015 Operating Capital Expenditures less than Adjusted EBITDA
Miss Lime 80-90% Anadarko 10-20%
By Area
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(1) Excludes capitalized interest and G&A, asset retirement obligations, office and other expenditures
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– 345-430 Mbwd of capacity permitted – Six high-capacity SWD wells within central loop and pipeline network of ~100 miles – Eight total SWD wells across Woods and Alfalfa allows for significant growth – Currently disposing ~170 Mbwd into the Arbuckle formation at minimal cost
– Significant untapped third-party capacity potential – At a disposal charge of $0.50-$1/bbl and 5x-10x EBITDA, creates attractive value proposition – Opportunity to further enhance financial position
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Intrinsic value exists in Midstates’ existing infrastructure, which will grow with additional development
1 2 Miles
1:115,000
:
Date: 6/26/2014
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Bill WI Owners Add 3rd Party Monetization 50% utilized Monetization fully utilized
Value / Time Options
Time and effort creates substantial opportunity
Low High
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Oil
Q4 Total Q1 Q2 Q3 Q4 Total WTI Swaps Volume (Bbls) 1,097,000 1,097,000 1,080,000 1,092,000 552,000 552,000 3,276,000 Volume (Bbl/d) 11,924 11,924 12,000 12,000 6,000 6,000 8,975 Price ($/Bbl) 89.04 $ 89.04 $ 90.10 $ 90.58 $ 85.51 $ 85.53 $ 88.72 $ WTI Collars Volume (Bbls) 40,200 40,200 Volume (Bbl/d) 437 437 Price ($/Bbl) - Floor 86.49 $ 86.49 $ Price ($/Bbl) - Ceiling 97.71 $ 97.71 $ WTI/LLS Basis Differential Swaps (1) Volume (Bbls) 91,500 91,500 Volume (Bbl/d) 995 995 Price ($/Bbl) 5.35 $ 5.35 $
Natural Gas Liquids
Swaps Volume (Bbls) Volume (Bbl/d) Price ($/Bbl)
Natural Gas
Swaps (2) Volume (Mmbtu) 4,508,000 4,508,000 4,500,000 4,550,000 4,600,000 4,600,000 18,250,000 Volume (Mmbtu/d) 49,000 49,000 50,000 50,000 50,000 50,000 50,000 Price ($/Mmbtu) $4.17 $4.17 $4.13 $4.13 $4.13 $4.13 $4.13 Collars Volume (Mmbtu) 194,001 194,001 Volume (Mmbtu/d) 2,109 2,109 Price ($/Mmbtu) - Floor 3.39 $ 3.39 $ Price ($/Mmbtu) - Ceiling 4.57 $ 4.57 $ 2014 2015
Natural Gas
Swaps (2) Volume (Mmbtu) 4,508,000 4,508,000 4,500,000 4,550,000 4,600,000 4,600,000 18,250,000 Volume (Mmbtu/d) 49,000 49,000 50,000 50,000 50,000 50,000 50,000 Price ($/Mmbtu) $4.17 $4.17 $4.13 $4.13 $4.13 $4.13 $4.13 Collars Volume (Mmbtu) 194,001 194,001 Volume (Mmbtu/d) 2,109 2,109 Price ($/Mmbtu) - Floor 3.39 $ 3.39 $ Price ($/Mmbtu) - Ceiling 4.57 $ 4.57 $
(1) The company enters into swap arrangements intended to fix the differential between the Louisiana Light Sweet (“LLS”) pricing and the West Texas Intermediate (“NYMEX WTI”) pricing. (2) Includes 1,519,000 Mmbtus in natural gas swaps that priced during the period, but had not cash settled as of September 30, 2014. (3) Includes new 3Q & 4Q 2015 oil hedges that were added in October 2014.
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For the Three Months Ended Sept 30, For the Three Months Ended June 30, For the Three Months Ended March 31, For the Year Ended December 31, 2014 2014 2014 2013 2012 2011 Adjusted EBITDA reconciliation to net income (loss): Net income (loss) 74,597 (2,098) (83,645) (343,985) (150,097) 16,657 Depreciation, depletion and amortization 73,109 71,074 66,901 250,396 125,561 91,699 Impairment in carrying value of oil and gas properties 86,471 453,310
(50,978) 31,467 22,673 44,284 11,158 4,844 Net cash (paid) received for commodity derivative contracts not designated as hedging instruments (7,265) (17,138) (14,810) (17,585) (15,825) (16,733) Income tax expense (benefit) 2,216 (41) (2,270) (146,529) 157,886
(10) (9) (10) (33) (245) (23) Interest expense, net of amounts capitalized 34,288 33,813 33,947 83,138 12,999 2,094 Asset retirement oglibation accretion 406 432 497 1,435 723 334 Share-based compensation 1,690 2,127 1,541 5,713 2,459 53,744 Adjusted EBITDA 130,399 119,627 111,295 330,144 144,619 152,616 Acquisition and transaction costs 1,283 2,483 128 11,803 14,884 Adjusted EBITDA, before acquisition and transaction costs 131,682 122,110 111,423 341,947 159,503 152,616
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2014 2013 Q3 Q2 Q1 Q1 Q2 Q3 Q4 Operating Expenses - GAAP $113,670 $ 116,325 $ 196,640 $ 73,082 $ 104,061 $ 122,376 $ 577,396 Adjustments for certain non-cash items: Asset retirement accretion (406) (432) (497) (254) (313) (421) (447) Share-based compensation, net of amounts capitalized (1,690) (2,127) (1,541) (1,244) (1,770) (1,908) (792) Depreciation, depletion, and amortization (73,109) (71,074) (66,901) (41,976) (52,830) (74,789) (80,801) Impairment on oil and gas properties (86,471)
Other (2,346) (609) (330)
(614) (1) Cash Operating Expenses - Non-GAAP (1) $ 36,119 $ 42,083 $ 40,900 $ 29,608 $ 49,148 $ 44,644 $ 42,045 Cash Operating Expenses - Non-GAAP, per Boe (1) $ 11.62 $ 14.49 $ 15.67 $ 20.29 $ 27.50 $ 17.05 $ 14.65 Acquisition and transaction costs per Boe $ 0.41 $ 0.86 $ 0.05 $ - $ 6.43 $ 0.07 $ 0.04
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Tranche Rating Amount ($mm) Coupon Maturity Date Trading Price YTW Call Dates Call Price Caa1 / CCC+ $600 10.75% October 1, 2020 90.75 13% 10/1/16 – 9/30/17 10/1/17 – 9/30/18 After 10/1/18 105.38 102.69 100.00 Caa1 / CCC+ $700 9.25% June 1, 2021 86.25 12.4% 6/1/16 – 5/30/17 6/1/17 – 5/30/18 6/1/18 – 5/30/19 After 6/1/19 106.94 104.63 102.31 100.00
NYSE: MPO | www.MidstatesPetroleum.com 40 Summary of MPO Bonds Capitalization
As of September 30, 2014 Cash and Equivalents $ 25.7 Debt RCF Borrowings $ 369.2 10.75% Senior Notes due 2020 $ 600.0 9.25% Senior Notes due 2021 $ 700.0 Total Debt $ 1,669.2 Shareholders' Equity $ 334.3 Total Capitalization $ 2,003.4 RCF Borrowing Base $ 525.0 Less: Borrowings (369.2) RCF Availability $ 155.9 Total Liquidity $ 181.6 Debt / 2014E EBITDA 3.4x Debt / Capitalization 83% Net Debt / 2014E EBITDA 3.4x Net Debt / Capitalization 83%
Liquidity Credit Metrics Capitalization
Net Debt / 2014E EBITDA 3.4x Net Debt / Capitalization 83%
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Key Tems Dividend Payment dates: March 30 September 30 Rate: 8% per annum Compounding: Semi-annually Number of shares: 325,000 Initial liquidation preference: $ 1,000 per share Year: 360 days NYSE: MPO | www.MidstatesPetroleum.com 41
(a) Calculated assuming $13.50 conversion. (b) Calculated assuming $11.00 conversion. Includes $2,103,242 related to prior periods for change in conversion rate dividend valuation purposes.
Per share Total
Conversion into Common Shares @ $13.50 Conversion into Common Shares @ $11.00
Liquidation preference at October 1, 2012: 1,000.00 $ 325,000,000 $ 24,074,074 29,545,455 Dividend Amount at March 30, 2013: 40.00 $ 13,000,000 962,963 1,181,818 Liquidation preference at March 30, 2013: 1,040.00 $ 338,000,000 $ 25,037,037 30,727,273 Dividend amount at September 30, 2013: 41.60 $ 13,520,000 1,001,481 1,229,091 Adjusted liquidation preference at September 30, 2013: 1,081.60 $ 351,520,000 $ 26,038,519 31,956,364 Dividend amount at December 31, 2013: 21.63 $ 7,030,400 520,770 639,127 Adjusted liquidation preference at December 31, 2013: 1,103.23 $ 358,550,400 $ 26,559,289 32,595,491 Accrued dividend amount at March 30, 2014: 21.63 $ 7,030,400 520,770 639,127 Adjusted liquidation preference at March 30, 2014: 1,124.86 $ 365,580,800 $ 27,080,059 33,234,618 Accrued dividend amount at September 30, 2014: 44.99 $ 14,623,232 1,083,202 1,329,385 Adjusted liquidation preference at September 30, 2014: 1,169.86 $ 380,204,032 $ 28,163,262 34,564,003 Calculation
Conversion into Common Shares @ $11.00
Accumulated dividend amount at 9/30/14 14,623,232 Conversion price 11.00 $ Additional shares 1,329,385 Share price at September 30, 2014 5.05 $ Dividend amount as calculated 6,713,393 $ 2013: Reported Q1 Dividend Amount 4,116,667 $
(a)
Q2 Dividend Amount 2,568,800
(a)
Q3 Dividend Amount 2,568,800
(a)
Q4 Dividend Amount 6,334,265
(b)
Full year 2013 Dividend (assuming $11.00 conversion) 15,588,532 $ 2014: Q1 Dividend Amount 2,620,421 $ Q2 Dividend Amount 4,805,726 $ Q3 Dividend Amount 1,907,667 $ Third Quarter 2014
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HOUSTON 4400 Post Oak Pkwy, Suite 2600
Houston, TX 77027 Main Phone (713) 595-9400 Fax (713) 595-9499
TULSA
321 South Boston, Suite 600 Tulsa, Oklahoma 74103 Main Phone (918) 947-8550
Investor Relations Chris Delange
Investor Relations Manager (713) 595-9411 Chris.delange@midstatespetroleum.com
Al Petrie
Investor Relations, Coordinator (713) 595-9427 Al.petrie@midstatespetroleum.com
Investorrelations@midstatespetroleum.com Direct Line: (713) 595-9333 www.MidstatesPetroleum.com NYSE: MPO | www.MidstatesPetroleum.com 42