![]() Constellation Energy Partners LLC Fourth Quarter and Full Year 2012 Earnings Presentation March 5, 2013 Exhibit 99.2 |
![]() 2 Forward-looking Statements Disclaimer This presentation contains forward–looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about: the volatility of realized oil and natural gas prices; the conditions of the capital markets, inflation, interest rates, availability of a credit facility to support business requirements, liquidity, and general economic and political conditions; the discovery, estimation, development and replacement of oil and natural gas reserves; our business, financial, and operational strategy; our drilling locations; technology; our cash flow, liquidity and financial position; the ability to extend or refinance our reserve-based credit facility; the level of our borrowing base under our reserve-based credit facility; the resumption or amount of our cash distributions; our hedging program and our derivative positions; our production volumes; our lease operating expenses, general and administrative costs and finding and development costs; the availability of drilling and production equipment, labor and other services; our future operating results; our prospect development and property acquisitions; the marketing of oil and natural gas; competition in the oil and natural gas industry; the impact of the current global credit and economic environment; the impact of weather and the occurrence of natural disasters such as fires, floods, hurricanes, tornados, earthquakes, snow and ice storms and other catastrophic events and natural disasters; governmental regulation, including environmental regulation, and taxation of the oil and natural gas industry or publicly traded partnerships; developments in oil-producing and natural gas producing countries; lack of support from a sponsor; and our strategic plans, objectives, expectations, forecasts, budgets, estimates and intentions for future operations. In some cases, forward–looking statements can be identified by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. The forward–looking statements contained in this presentation are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward–looking statements contained in this presentation are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward–looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward–looking statements due to factors listed in the “Risk Factors” section in our SEC filings and elsewhere in those filings. All forward–looking statements speak only as of the date of this presentation. We do not intend to publicly update or revise any forward–looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. |
![]() 3 Updates • Q412 operating performance: – Average daily net production of 33.9 MMcfe includes average daily net oil production of approximately 396 Bbl, which is up 45% vs. Q312 – Operating cost of $3.38 per Mcfe, which is down 2% vs. Q312 – Resulted in $6.6 million in Adjusted EBITDA, which is up 18% vs. Q312, for Adjusted EBITDA of $24.5 million in 2012 • Completed 38 net wells and recompletions in Q412 resulting in 100 net wells and recompletions in 2012 with 18 additional net wells and recompletions in progress at year-end • Capital spending of $5.4 million in Q412 resulted in total capital spending of $15.9 million in 2012 (1) See Appendix (1) (2) (2) 35.8 35.5 34.5 34.0 33.9 37.5 34.5 0.0 10.0 20.0 30.0 40.0 50.0 Q411 Q112 Q212 Q312 Q412 FY11 FY12 Average Daily Net Production (MMcfe per day) $3.26 $3.40 $3.24 $3.44 $3.38 $3.37 $3.37 $- $1.00 $2.00 $3.00 $4.00 Q411 Q112 Q212 Q312 Q412 FY11 FY12 Operating Cost ($ per Mcfe) Includes lease operating expenses, production taxes, general and administrative expenses; excludes exploration costs and unit-based compensation program expenses, which are non-cash items |
![]() 4 Robinson’s Bend Sale • Closed the sale of Robinson’s Bend Field assets on February 28, 2013 – Sale encompassed all of CEP’s assets in the Black Warrior Basin – Under the terms of the agreement, a base sale price of $63.0 million resulted in $58.9 million in proceeds received at closing – Allowing for estimated sales-related cost impacts, net sales proceeds were approximately $55.3 million – CEP used net sales proceeds to reduce debt by $50.0 million – CEP is now $34.0 million drawn on a borrowing base of $37.5 million (net debt of approximately $21.9 million) – Since Q309, CEP has reduced debt outstanding by $186.0 million or 85% – Decreased leverage allows CEP to remain focused on the oil opportunities in our Mid-Continent asset base $ in millions Amount Sales Price (Dec. 1, 2012 Effective Date) $63.0 NORM Deduction -2.6 Adjustment for Dec. 1, 2012 Effective Date -0.4 Escrowed Funds (NORM/NPDES) -1.1 Proceeds Received at Closing $58.9 Sales Commission -0.9 Transaction Costs (Legal, Opinions, etc.) -0.6 Swap Liquidation -2.1 Net Sales Proceeds $55.3 Debt Reduction -50.0 Cash Retained at Closing $5.3 Cash on Hand Prior to Closing 6.8 Proforma Cash on Hand at Closing $12.1 Debt Outstanding at Closing $34.0 Debt Outstanding (-) Proforma Cash on Hand at Closing $21.9 |
![]() 5 Our Continuing Focus on Oil Opportunities • Our capital program has been focused on the oil potential we see in our existing asset base and our most capital efficient recompletion opportunities • As a result of this focus, oil continues to be an increasingly important part of our production mix • Drilling efforts are focused in the Pennsylvanian aged horizon with the Burgess, Bartlesville, Red Fork and Skinner sandstones as primary targets • In 2013, we forecast capital spending of between $19.0 million and $21.0 million and anticipate that oil will account for about 15% of our production mix (~ 548 Bbl/day) and about 50% of our sales revenue * * Excludes hedge settlements, gains (losses) on mark-to-market activities, and other revenue ** FY2013 Forecast oil production is based on the mid-point of CEP’s 2013 production forecast |
![]() 6 Q412 Financial Results 19 (1) Includes lease operating expenses, production taxes, general and administrative expenses and unit-based compensation program expenses (2) Includes loss (gain) on asset sale and exploration costs (3) Includes accretion expense and asset impairments (4) 2011 results exclude $41.3 million in hedge settlements related to the company’s Jun-11 hedge restructuring; including these hedge settlements, Adjusted EBITDA was $97.1 million See Appendix Q412 vs. Q312 Full Year ($ in 000’s unless noted) Q412 Q312 2012 2011 Production (MMcfe) 3,119 3,126 12,613 13,679 Oil & Gas Sales $17,521 $16,653 $68,041 $144,639 Gain (Loss) from Mark-to-Market Activities (253) (10,158) (8,706) (39,422) Revenue $17,268 $6,495 $59,335 $105,217 Operating Expenses (1) 10,889 11,254 43,977 47,445 Cost of Sales 376 287 1,299 2,188 Other (Income) Expense (2) (33) (21) (147) (99) EBITDA $6,036 $(5,025) $14,206 $55,683 DD&A (3) 81,148 4,604 95,016 25,981 Net Interest Expense 1,143 1,534 5,733 10,116 Net Income (Loss) $(76,255) $(11,163) $(86,543) $19,586 Adjusted EBITDA $6,635 $5,639 $24,445 $55,257 |
![]() 7 Net Asset Value ($ in millions) * Adjusted to reflect the sale of the Robinson’s Bend Field assets, which closed February 28, 2013 (1) Estimated by Netherland, Sewell & Associates in a report dated as of the last day of the quarter shown using SEC reserve guidelines using a five year limit on PUDs (2) Based on (a) forward market prices on the last day of the quarter shown and (b) a 10% discount rate (PV10) (3) Current assets less current liabilities less the value of current risk management balance sheet items (4) Value of probable reserves is: Q412 $40.8 million (5) Value of possible reserves is: Q412 $14.5 million (6) Price shown is as of the market close on the last day of trading for the quarter Quarter Ending: Q412* Value of Proved Reserves (1),(2) $116.4 +/- Adjustments for: Debt -34.0 Working Capital (3) 4.4 ARO -7.7 Value of Hedges in Place (2) 26.2 = Net Asset Value (NAV) -- Proved Reserves (1),(2) $105.3 ÷ Units Outstanding (millions) 24.2 = NAV/Unit -- Proved Reserves (1),(2) ($/Unit) $4.35 + NAV/Unit -- Probable Reserves (1),(2),(4) ($/Unit) $1.69 + NAV/Unit -- Possible Reserves (1),(2),(5) ($/Unit) $0.60 = NAV/Unit -- Total Reserves (3P) (1),(2) ($/Unit) $6.64 |
![]() G&A Cost Reductions • Changes that will impact our future operating results include: – Closure of our Tulsa, OK and Dewey, OK offices (employees relocated to our Skiatook,OK field office) – Headcount reductions (impacts G&A and LOE) – Changes in compensation structure for employees and CEP’s board of managers – Changes in employee benefits structure – In-sourcing of accounting activities related to CEP’s Mid-Continent assets – Cancellation of the 2009 board advisory engagement with Tudor, Pickering, Holt & Co. Securities, Inc. (1) Excludes LTIP (2) Excludes one-time cost of $0.8 million incurred in connection with headcount reductions 33% Reduction Since 2010, Our First Full Year Without a Sponsor 8 $18.6 $15.4 $14.6 $12.4 $0 $10 $20 2010 2011 2012 2013 Forecast (Midpoint) General & Administrative Costs ($ millions) (2) (1) |
![]() 9 2013 Forecast Forecast Component 2013 Forecast Total Capital Spending $19.0MM - $21.0MM Total Net Production 7.6 Bcfe – 8.6 Bcfe Production Mix Mcfe, Oil / Natural Gas 15% / 85% Natural Gas 6.5 – 7.3 Bcfe Oil 190,000 – 210,000 Bbls Sales Revenue (Excludes Hedges) Oil / Natural Gas 50% / 50% NYMEX Hedges Natural Gas 8.8 Bcfe at $5.59 per Mcfe Basis Only Hedges Mid-Con Basis – Natural Gas 5.2 Bcfe at ($0.39) per Mcfe WTI Hedges Oil 147 Mbl at $96.28 per Bbl Hedges as a % of Natural Gas Production 128% (At Midpoint) Hedges as a % of Oil Production 74% (At Midpoint) Differentials: Mid-Con Natural Gas (Basis to NYMEX) ($0.14) per Mcfe Mid-Con Oil (Marketing) ($2.50) per Bbl Mid-Con Natural Gas (Gathering) ($0.50) per Mcfe Operating Costs: LOE (1) $17.0 MM – $18.2 MM Production Taxes $1.6 MM - $2.4 MM G&A – Corporate and Field Level (2) $12.8 MM - $13.6 MM Total $31.4 MM - $34.2 MM Margin from Third Party Sales/Services $1.75 MM - $2.25 MM Adjusted EBITDA (3) $23.0 MM - $25.0 MM Interest Expense $2.0 MM Maintenance Capital $21.0 MM (1) Excludes exploration costs and unit-based compensation program expenses, which are non-cash items (2) Excludes unit-based compensation program expenses, which is a non-cash item; Includes a one-time cost of $0.8 million incurred in connection with headcount reductions (3) We are unable to reconcile our forecast range of Adjusted EBITDA to GAAP net income or operating income because we do not predict the future impact of adjustments to net income (loss), such as (gains) losses from mark-to-market activities and equity investments or asset impairments due to the difficulty of doing so, and we are unable to address the probable significance of the unavailable reconciliation, in significant part due to ranges in our forecast impacted by changes in oil and natural gas prices and reserves which affect certain reconciliation items |
![]() Appendix |
![]() Cherokee Basin Central Kansas Uplift Woodford Shale • Proved reserves: 130 Bcfe - PDP as a % of total proved: 60% - Natural gas: 123 Bcfe (95%) - Oil: 1,042 MBbl (5%) • Net producing wells: 2,310 • Net acres: over 727,000 • Average working interest: 100% operated, 50% non-operated • Average net revenue interest: 80% operated, 40% non-operated • Pricing: ONEOK, Southern Star, CEGT East, NGP MidCon, PEPL, WTI • Proved reserves: ~ 0.2 Bcfe - PDP as a % of total proved: 100% - Oil: 38 MBbl (100%) • Net producing wells: 6 • Net Acres: approximately 893 • Non-operated • Average working interest: 20% • Average net revenue interest: 16% • Pricing: WTI • Proved reserves: ~ 6 Bcfe - PDP as a % of total proved: 100% - Natural gas: 6 Bcfe (100%) • Net producing wells: 9 • Net Acres: N/A, wellbores • Non-operated • Average working interest: 11% • Average net revenue interest: 9% • Pricing: CEGT East 11 Portfolio Summary Statistics as of December 31, 2012; excludes assets divested in Q113; reserve values are estimates based on forward prices on December 31, 2012; numbers may not add due to rounding Portfolio Existing Reserves • Total: 402 Bcfe • Proved reserves, total: 136 Bcfe • Proved oil reserves: 1,080 MBbl • Proved gas reserves: 129 Bcfe • Proved developed as a % of total proved reserves: 62% • Proved R/P ratio: 17 years • Probable reserves, total: 119 Bcfe • Probable oil reserves: 876 MBbl • Probable gas reserves: 114 Bcfe New Activity • Drilling focus: Cherokee Basin oil opportunities in the Pennsylvanian aged horizon with the Burgess, Bartlesville, Red Fork and Skinner sandstones as primary targets • New well costs: $170,000 to $450,000 • Initial daily production, new wells: 1 to 40 Bbl • Well depths: 700 to 2,700 feet • Well spacing: 10 to 160 acres • Recompletion costs: $45,000 to $65,000 • Incremental daily production, recompletions: 1 to 15 Bbl |
![]() 12 Natural Gas Hedge Positions (1) (1) As of March 5, 2013 (2) NYMEX (3) Excludes an offset trade executed on 1,041,814 MMBtu at a fixed price of $3.662; this trade will settle financially over the course of the year against the fixed price trades shown NOTE: The company accounts for derivatives using the mark-to-market accounting method. Fixed Price Swaps (2) MMBtu Hedged Weighted Average Sales Price ($/MMBtu) BOY 2013 6,187,500 5.75 (3) 2014 6,387,500 5.75 2015 1,839,490 4.30 Basis Swaps MMBtu Hedged Weighted Average Sales Price ($/MMBtu) BOY 2013 3,832,587 0.39 2014 4,443,677 0.39 |
![]() 13 Oil Hedge Positions (1) Fixed Price Swaps Bbl Hedged Weighted Average Sales Price ($/Bbl) BOY 2013 106,757 $96.31 2014 113,127 $94.02 2015 87,680 $93.53 2016 66,117 $85.50 (1) As of March 5, 2013 NOTE: The company accounts for derivatives using the mark-to-market accounting method. |
![]() 14 Non-GAAP Financial Measures Use of Non-GAAP Financial Measures: EBITDA and Adjusted EBITDA are non-GAAP financial measures that are reconciled to their most comparable GAAP financial measure under Reconciliation of Non-GAAP Financial Measures in this presentation. The reconciliations are only intended to be reviewed in conjunction with the oral presentation to which they relate. EBITDA is defined as net income (loss) adjusted by interest (income) expense, net; depreciation, depletion and amortization; write-off of deferred financing fees; asset impairments; and accretion expense. Adjusted EBITDA is defined as EBITDA adjusted by (gain) loss on sale of assets; exploration costs; (gain) loss from equity investment; unit-based compensation programs; (gain) loss from mark-to-market activities; and unrealized (gain) loss on derivatives/hedge ineffectiveness. Although not presented herein, we define Distributable Cash Flow as Adjusted EBITDA less maintenance capital expenditures and cash interest expense. Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our asset base (including our undeveloped leasehold acreage) at a steady level over the long term. These expenditures include the drilling and completion of additional development wells to offset the expected production decline during such period from our producing properties, as well as additions to our inventory of unproved properties or proved reserves required to maintain our asset base. These financial measures are used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure. These financial measures are not intended to represent cash flows for the period, nor are they presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Summary of Non-GAAP Financial Measures: Non-GAAP Measure Slide(s) Where Used in Presentation Most Comparable GAAP Measure Slide Containing Reconciliations Adjusted EBITDA, EBITDA 3, 6 Net Income 15 |
![]() Reconciliation Items 15 (1) Includes accretion expense and asset impairments (2) YTD 2011 results include $41.3 million in hedge settlements related to the company’s Jun-11 hedge restructuring (3) Includes lease operating expenses, production taxes, general and administrative expenses, exploration costs, and unit-based compensation program expenses Reconciliation of Net Income (Loss) to Adjusted EBITDA ($ in 000s) YTD 2012 Q412 Q312 Q212 Q112 YTD 2011 Q411 Net income (loss) $(86,543) $(76,255) $(11,163) $(5,010) $5,885 $19,586 $15,127 Interest (income) expense, net 5,733 1,143 1,534 1,437 1,619 10,116 1,186 DD&A (1) 95,016 81,148 4,604 4,550 4,714 25,981 5,745 EBITDA $14,206 $6,036 $(5,025) $977 $12,218 $55,683 $22,058 (Gain) loss on sale of assets 7 7 -- (4) 4 19 (10) Exploration costs -- -- -- -- -- 131 -- Unit-based compensation programs 1,526 339 506 394 287 1,341 317 (Gain) loss from mark- to-market activities (2) 8,706 253 10,158 4,897 (6,602) 39,422 (8,524) Adjusted EBITDA $24,445 $6,635 $5,639 $6,264 $5,907 $96,596 $13,841 Operating Expense to Operating Cost ($/Mcfe) YTD 2012 Q412 Q312 Q212 Q112 YTD 2011 Q411 Operating expenses (3) $3.49 $3.49 $3.60 $3.37 $3.49 $3.48 $3.36 Less: Exploration costs -- -- -- -- -- 0.01 -- Less: Unit-based compensation incl. in operating expense $0.12 0.11 0.16 0.13 0.09 0.10 0.10 Operating cost $3.37 $3.38 $3.44 $3.24 $3.40 $3.37 $3.26 |