Mid-Con Energy Partners LP. The Oil and Gas Conference August 2018

Transcription

1 LP The Oil and Gas Conference August 2018

2 Forward-Looking Statements This presentation includes forward-looking statements that is, statements related to future, not past, events within the meaning of the federal securities laws. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as "anticipate," "believe," "estimate," "intend," "expect," "plan," "project," "should," "goal," "forecast," "guidance," "could," "may," "continue," "might," "potential," "scheduled," or "will" and the negative of such terms or other comparable terminology. These forward-looking statements involve certain risks and uncertainties and ultimately may not prove to be accurate. Actual results and future events could differ materially from those anticipated in such statements. For further discussion of risks and uncertainties, you should refer to Mid-Con Energy's filings with the Securities and Exchange Commission (SEC) available at or Mid-Con Energy undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after this presentation. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. All forward-looking statements are qualified in their entirety by this cautionary statement and other SEC filings. These forward looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our: business strategies; volatility of commodity prices; future financial and operating results, and our ability to pay distributions; ability to replace the reserves we produce through acquisitions and the development of our properties; revisions to oil and natural gas reserves estimates as a result of changes in commodity prices; technology; realized oil and natural gas prices; production volumes; lease operating expenses; general and administrative expenses; cash flow and liquidity; availability of production equipment; availability of oil field labor; capital expenditures; Future capital requirements and availability and terms of capital; marketing of oil and natural gas; general economic conditions; competition in the oil and natural gas industry; effectiveness of risk management activities; environmental liabilities; counterparty credit risk; governmental regulation and taxation; developments in oil producing and natural gas producing countries; and plans, objectives, expectations and intentions. NASDAQ: MCEP 2

3 Partnership Profile Market Highlights Symbol / Exchange: MCEP / NASDAQ GP / LP Units Outstanding: 30.8MM Preferred Units Outstanding: 21.4MM Equity Value: $93.9MM Debt Outstanding: $98.0MM Enterprise Value: $191.3MM 1) Based on 30,436,124 limited partner units and 360,000 general partner units outstanding as of July 31, ) Based on 11,627,906 of Class A Convertible Preferred Units and 9,803,921 Class B Convertible Preferred Units as of July 31, ) Based on July 31, 2018 market close price of $1.75 per common unit and previously announced Unit Purchase Price of $2.15 per Class A Convertible Preferred Unit and $1.53 per Class B Convertible Preferred Unit 4) $98.0 million debt outstanding as of July 31, (1) (2) (3) (4) Strategic Focus Waterflood development and operations; primary focus of the company since inception in 1986 Managing mature fields with complex histories, optimizing cash flow through production enhancements, and top quartile operational efficiencies Managing through the Downturn Minimizing Debt/Ebitda by allocating CAPEX spend aimed at boosting near term production, cash flow and reserves Cash Flow Optimization through oil field management (shut-ins, vendor engagement, G&A reduction, and consolidation of resources) Strategic Asset Divestitures Acquisition of Growth Assets through preferred capital raises Positioned for Growth Reduced debt from $205 MM in 4Q14 to $87 MM in the 2Q18 In excess of $24MM in acquisitions in 2018 NASDAQ: MCEP 3

4 Partnership Profile Oklahoma Base of operations for over 30 years Long-lived, low decline, mature waterfloods Low lifting and development costs Stacked pay in key fields Acquired 14 additional fields in July 2018 Texas Conventional oil assets Assets held in 10 counties within the Eastern Shelf of the Permian Basin Four new waterflood developments in the last two years Wyoming Established position in the Powder River Basin in 1Q 2018 Significant growth assets with planned waterflood developments Optimization projects scalable across >100,000 HBP acres and ~600 existing well bores NASDAQ: MCEP 4

5 Operating Strategy Develop Potential Of Existing Property Base Rationalizing the CAPEX allocation between lower risk high priority projects and de-risking future developments Maintain pace of spending on priority drilling, workover, and injection projects while incorporating new assets into development planning De-risking scalable concepts to setup future organic production growth in newly acquired assets in Wyoming and Oklahoma Acquire High Quality Properties For Secondary Recovery Increasing inventory of new secondary projects through targeted pursuit of internally generated prospects and marketed asset sales Focus on assets with scalable development and operational concepts Existing fields with significant new waterflood potential Maintain Operational Control and Cost Effectiveness Operating ~100% of assets allows control of expenses, CAPEX timing, and allocation Utilizing existing high-quality company personnel within legacy core areas to operate as efficiently as possible Building teams of quality personnel in new core areas, trained and supported by legacy supervisors Maintain Liquidity and Financial Flexibility Reaffirmed $125 MM borrowing base in June 2018 Continue to drive down Debt to EBITDA ratio Maintain CAPEX spend within operating cash flow Focus on acquisitions that are accretive to the balance sheet NASDAQ: MCEP 5

6 Navigating Oil Prices Managing Production 5,000 1 Net Boe/d 4,000 3, , ,000-1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18E 4Q18E NEOK HUG SOK GC PERMIAN PERMIAN BOLT-ON WHEATLAND WYOMING OK WATERFLOODS (1) New core area established in 4Q14 with acquisition of Permian properties (2) Permian Bolt-on properties acquired in 3Q16 (3) Divestiture of Hugoton properties in 3Q16 (4) Wheatland properties acquired in 2Q17 (5) Divestiture of Southern Oklahoma properties in 4Q17 (6) Wyoming core area established with acquisitions in 1Q18 (7) Acquisition of additional Oklahoma Waterflood properties in early 3Q18 NASDAQ: MCEP 6

7 Navigating Oil Prices - Strengthening Our Balance Sheet $ x Reduced Debt by $118 MM since 4Q14 from cash flow, asset sales, and preferred equity raises $ x $ x $150 $ x $ x $ x $- $123 $139 $168 $205 $203 $200 $194 $180 $169 $110 $128 $122 $121 $121 $122 $99 $89 $87 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Debt Balance Non-Conforming Borrowing(1) Conforming Borrowing Base Bank Calculated Debt/EBITDA (RHS)(2) 0.00x (1) Borrowing Base of $163.0 million consisted of $110.0 million conforming tranche and $53.0 million permitted over-advance. (2) Debt/EBITDA calculated per our credit agreement NASDAQ: MCEP 7

8 2018 YTD Operating Results Strengthening the Balance Sheet Reaffirmed $125 MM borrowing base in June 2018 Decreased leverage ratio from 3.58x (1) in 2Q17 to 3.14x (1) in 2Q18 $26.9 million in liquidity, net of acquisitions made in July 2018 Optimizing Capital Allocation Distributing capital between organic growth with opportunistic acquisitions, as of June 2018 $3.8 MM CAPEX $12.0 MM Debt Reduction $24.0 MM Acquisition Activity (includes July 2018) Building Inventory Added Wyoming as a new core area to our operations 3 optimization and 2 substantial growth acquisitions made YTD Expanded Oklahoma core area with 14 fields and new project inventory (1) As calculated per our credit agreement NASDAQ: MCEP 8

9 New Core Area Wyoming Acquisitions Numerous acquisitions throughout 2018 Mixture of mature and grassroots waterflood projects High growth potential through implementation of new waterfloods and optimization of existing units Positioned for additional opportunistic acquisitions as they become available Final Purchase Price: Current Net Production (1) : Total Proved Reserves (2) : $16.7 MM 785 Boe/d 4,404 MBoe Gross Daily Oil Production (BOPD) H15 2H15 1H16 2H16 1H17 2H17 1Q18 2Q18 Gross Oil (BOPD) Well Count Active well Count (1) Net production numbers for May 2018 (2) Net proved reserves based on NYMEX strip pricing as of June 29, 2018 NASDAQ: MCEP Newly acquired properties 9

10 Wyoming Optimization Project Gross Daily Oil Production House Creek Sussex Unit Cumulative Oil to Date 28.6 MMBO MCEP took over operations Jan 16, 2018 (WI 48.2%, NRI 41.5%) Acquired additional 47.5% WI effective April 1 st, 2018 Power has been restored to the north battery and wells activated. Since taking over operations, 43 wells have been returned to active status through June. Operations continue to focus on returning wells to production, approximately 25 additional producing wells. Planned remediation of 6 producing wells in 3Q NASDAQ: MCEP 10

11 Wyoming Growth Assets Pine Tree Unit Muddy Sand Project Cumulative Oil to Date: 11.3 MMBO Waterflood Unitization process underway 1 st injection expected in 2H 2018 Injection sets up 2019 drilling campaign Prolific producer on primary, >22 MMBO Located in Muddy Sand waterflood trend Unitization process in 2019 Already infilled to 80-acre spacing NASDAQ: MCEP 11

12 Q3 Oklahoma Waterflood Acquisition Core Area Expansion Near Term Upside Gross Daily Oil Production (BOPD) Active well Count Legacy MCEP Holdings Recent Acquisition 0 1H15 2H15 1H16 2H16 1H17 2H17 1Q18 Aug Gross Oil (BOPD) Well Count Significant increase in NEOK inventory 12 Existing Secondary Units 21,700 Net HBP Acres >350 Existing Wellbores Restoring low-decline, mature assets RTP workover program underway High-confidence in expense reductions Leveraging legacy field supervision NASDAQ: MCEP 12

13 2018 Acquisition Development and Financial Timeline Optimization Projects 1Q18 2Q18 3Q18 4Q18 House Creek (WY) Oklahoma Waterfloods Worland (WY) 43 wells returned to production through June. 25 remaining possible targets for 2H18 Return wells to production and cost reduction Maintain production and cost reduction Grassroots Projects 1Q18 2Q18 3Q18 4Q18 Pine Tree (WY) Muddy Project (WY) Pending approval for injection Begin unitization process Preparing for unitization in 2019 Financial Plan 1Q18 2Q18 3Q18 4Q18 Borrowing Base Reaffirmed $125MM Lower Debt/EBITDA (1) 3.34x 3.14x Improve Liquidity $35.3MM $37.5MM Redetermination with new assets (1) Debt/EBITDA calculated per our credit agreement NASDAQ: MCEP 13

14 Survive and Thrive Value Creation Managing Through Downturn Held reserves approximately flat with low CAPEX spend and operational efficiency Decreased operating costs across all core areas Added production and reserves through core competencies Reduce debt from $205MM in 4Q14 to $87MM in 2Q18 Divested high operating cost assets with minimal future upside Raised preferred equity to fund strategic acquisitions Managed cash flow through waterflood development optimization Positioned For Growth Increased Liquidity to $37.5MM at 2Q18 Acquired multiple waterflood optimization projects and new waterflood development prospects in 2018 NASDAQ: MCEP 14

15 Appendix

16 Oil Recovery Overview Original Oil In Place "OOIP" Primary Production 10 to 25% Initial production from the reservoir typically recovered as a result of expansion of reservoir fluids which are naturally pressured within the producing formation Secondary Production 10 to 20% Waterflooding is the most commonly used method Additional oil is recovered by injecting water into the reservoir, which displaces oil to producing wellbores Tertiary Potential This type of recovery seeks to alter the properties of oil in ways that facilitate additional production Examples include chemical flooding, thermal recovery (steamfloods) and CO 2 injection At this time, no estimated reserves or production associated with potential tertiary recovery projects are assigned to Mid- Con Energy s properties NASDAQ: MCEP 16

17 Waterflooding Overview Waterflooding increases production and recovery of oil in place by displacing oil from injection wells to producing wells Historically, the success of waterfloods has been attributable to the quality of the reservoir rock, favorable reservoir fluid characteristics, availability of water for injection and ease with which it can be injected Typical Waterflood "5-Spot" Pattern Water Injected To Displace Oil Injector Surface Producer Waterflood Target NASDAQ: MCEP 17

18 2018 Guidance & Capital Budget 03/01/2018 Guidance 08/01/2018 Guidance Production (Boe/d) 2,800-3,200 Production (Boe/d) 3,200-3,400 LOE $ $19.50 LOE $ $21.00 Production Taxes 6.00% % Production Taxes 6.50% % Capex $12.0 Capex $12.0 NOTE: This outlook is subject to all the cautionary statements and limitations described under the "Forward-Looking Statements" caption included at the beginning of this presentation. (1) Production volumes in Boe equivalents calculated at a rate of six Mcf per Bbl. NASDAQ: MCEP 18

19 Annual Cash Expenses Per Boe (1) $38.61 $4.04 Cash interest expense $/BOE $6.08 $5.56 $28.72 $3.53 $3.61 $2.03 $25.33 $4.16 $3.86 $1.96 $27.53 $3.94 $4.13 $2.59 Cash G&A Production taxes LOE $22.93 $19.55 $15.35 $16.87 Total cash expeneses LOE $22.93 $19.55 $15.35 $16.87 Production taxes $5.56 $2.03 $1.96 $2.59 Cash G&A $6.08 $3.61 $3.86 $4.13 Cash interest expense $4.04 $3.53 $4.16 $3.94 Total cash expeneses $38.61 $28.72 $25.33 $27.53 (1) Production volumes in Boe equivalents calculated at a rate of six Mcf per Bbl. NASDAQ: MCEP 19

20 Commodity Derivatives: Positions as of June 30, % 60% 40% 20% Collar (% Hedged, LHS) Swap (% Hedged) Put (% Hedged, LHS) Floor Price ($/Bbl, RHS) WTI Futures ($/Bbl, RHS) $90 $80 $70 $60 $50 $40 Average Hedge Price ($/Bbl) 0% 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 $30 Oil Hedges 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 WTI Swap Volume (Bbl/d) ,938 1,798 1,720 1,664 1,646 1,607 1,554 Swap Price ($/Bbl) $ $ $ $ $ $ $ $ $ Collar Volume (Bbl/d) 1,141 1, Call Strike Price ($/Bbl) $ $ $ - $ - $ - $ - $ - $ - $ - Put Strike Price ($/Bbl) $ $ $ - $ - $ - $ - $ - $ - $ - Put Volume (Bbl/d) Put Strike Price ($/Bbl) $ $ $ - $ - $ - $ - $ - $ - $ - Total Hedged Volume (Bbl/d) 1,977 1,934 1,938 1,798 1,720 1,664 1,646 1,607 1,554 Floor Strike Price ($/Bbl) $ $ $ $ $ $ $ $ $ % PVD Hedged 64% 62% 62% 58% 55% 54% 53% 52% 50% (1) Deferred premium puts include premiums that are to be paid monthly as the contracts settle. (2) % Hedged Estimated Reserve Oil Production based on 2018 guidance (updated as of 07/31/2018) mid-point of production forecast, assuming 94% oil. NASDAQ: MCEP 20

21 Operating and Financial Results Sequential and YoY Variance Three Months Ended Variance Analysis June 30 March 31 June 30 Quarter-over-quarter Year-over-year (unaudited, in thousands, except per unit data) # % # % Select Operating Results Oil (MBbl) % (55) -18.0% Natural gas (MMcf) % (18) -16.4% Total production (Mboe)(1) % (57) -17.7% (1) Average daily production (Boe/d) 2,934 2,800 3, % (626) -17.6% Select Financial Results Oil sales $ 15,931 $ 14,544 $ 13,657 $ 1, % $ 2, % Natural gas sales % (24) -8.3% Cash settlements on matured derivatives (2,181) (1,324) (981) (857) 64.7% (1,200) 122.3% Oil & natural gas sales plus cash settlements from matured derivatives, inclusive of premiums, net 14,014 13,388 12, % 1, % Lease operating expenses $ 5,251 $ 4,801 $ 5,581 $ % $ (330) -5.9% Oil and gas production taxes $ 963 $ 872 $ 707 $ % $ % (2) General and administrative $ 1,358 $ 1,894 $ 1,471 $ (536) -28.3% $ (113) -7.7% Net (loss) income $ (6,855) $ (10,418) $ (15,199) $ 3, % $ 8, % (3) Select Non-GAAP Measures 0 Adjusted EBITDA $ 6,630 $ 6,049 $ 5,474 $ % $ 1, % Free Cash Flow $ 2,501 $ 2,514 $ 2,878 $ (13) -0.5% $ (377) -13.1% Select Results per Boe (unless otherwise noted) Oil sales (per Bbl) $ $ $ $ % $ % Natural gas sales (per Mcf) $ 2.87 $ 1.95 $ 2.62 $ % $ % Oil & Natural Gas Sales $ $ $ $ % $ % Cash settlements for matured derivatives, inclusive of net premiums $ (8.17) $ (5.25) $ (3.02) $ (2.91) 55.5% $ (5.14) 170.1% Oil & natural gas sales revenues $ $ $ $ (0.64) -1.2% $ % Lease operating expenses $ $ $ $ % $ % Oil and gas production taxes $ 3.61 $ 3.46 $ 2.18 $ % $ % General and administrative $ 5.09 $ 7.52 $ 4.54 $ (2.43) -32.3% $ % Select Non-GAAP Measures Adjusted EBITDA $ $ $ $ % $ % Free Cash Flow $ 9.37 $ 9.98 $ 8.87 $ (0.61) -6.1% $ % (1) Production volumes in Boe equivalents calculated at a rate of six Mcf per Bbl. (2) General and administrative include non-cash equity-based compensation expense. (3) This presentation includes "Adjusted EBITDA", and Free Cash Flow", each of which are non-generally accepted accounting principles ("Non-GAAP") measures, and should not be considered an alternative to net income (loss), net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. NASDAQ: MCEP 21

22 Non-GAAP Summary (1) Three Months Ended June 30 March 31, June Net income (loss) $ (6,855) $ (10,418) $ (15,199) Interest expense, net 1,410 1,337 1,537 Depreciation, depletion and amortization 3,393 3,441 4,631 Accretion of discount on asset retirement obligations Impairment of proved oil & natural gas properties 959 8,751 17,672 Dry holes and abandonment of unproved properties Loss (gain) on derivatives, net 9,500 3,382 (2,533) Cash settlements paid for matured derivatives, net (2,181) (1,324) 357 Cash premiums paid for derivatives, net - - (1,297) Non-cash equity-based compensation Loss on sales of oil and natural gas properties (12) Adjusted EBITDA $ 6,630 $ 6,049 $ 5,474 Less: Cash interest expense 1, ,764 Total Capital Expenditure 2,167 1,643 2,057 Distributions to preferred unitholders 700 1, Free Cash Flow $ 2,501 $ 2,514 $ 1,153 (1) This presentation includes "EBITDA", "Adjusted EBITDA", and Free Cash Flow", each of which are non-generally accepted accounting principles ("Non-GAAP") measures, and should not be considered an alternative to net income (loss), net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. NASDAQ: MCEP 22

23 Non-GAAP Summary NON-GAAP FINANCIAL MEASURES This presentation, the financial tables and other supplemental information include Adjusted EBITDA and Free Cash Flow which are a non-generally accepted accounting principles ( Non-GAAP ) measures used by our management to describe financial performance with external users of our financial statements. The Partnership believes the Non-GAAP financial measures described above are useful to investors because they are used by many companies in its industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate the financial performance of the Partnership and to compare the financial performance of the Partnership with the performance of other publicly traded partnerships within its industry. Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA is defined as net income (loss) plus (minus): Interest expense, net; Depreciation, depletion and amortization; Accretion of discount on asset retirement obligations; (Gain) loss on derivatives, net; Cash settlements received (paid) for matured derivatives, net; Cash settlements received (paid) for early terminations of derivatives, net; Cash premiums received (paid) for derivatives, net; Cash premiums received (paid) at inception of derivatives, net; Impairment of proved oil and natural gas properties; Impairment of proved oil and natural gas properties held for sale; Dry holes and abandonment of unproved properties; Non-cash equity-based compensation; and (Gain) loss on sales of oil and natural gas properties, net. Free Cash Flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Free Cash Flow is defined as Adjusted EBITDA less: Cash interest expense Total capital expenditure Distributions to preferred unit holders NASDAQ: MCEP 23

24 , LP Investor Relations 2431 E. 61 st Street, Suite 850 Tulsa, Oklahoma