Attached files
| file | filename |
|---|---|
| 8-K - 8-K - PETROQUEST ENERGY INC | disposition8k.htm |
| EX-99.3 - EXHIBIT 99.3 - PETROQUEST ENERGY INC | exhibit993dispositionprofo.htm |
| EX-99.1 - EXHIBIT 99.1 - PETROQUEST ENERGY INC | exhibit991pressrelease0605.htm |
| EX-10.1 - EXHIBIT 10.1 - PETROQUEST ENERGY INC | exhibit101eleventhamendment.htm |
Arkoma Divestiture June 2015
Forward-Looking Statements 2 This presentation contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this presentation are forward-looking statements. Although PetroQuest believes that the expectations reflected in these forward-looking statements are reasonable, these statements are based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014, our estimate of the sufficiency of our existing capital sources, including availability under our senior secured bank credit facility and the result of any borrowing base redetermination, our ability to raise additional capital to fund cash requirements for future operations, the effects of a financial downturn or negative credit market conditions on our liquidity, business and financial condition, the declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our ability to find oil and natural gas reserves that are economically recoverable, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, our ability to realize the anticipated benefits from our joint ventures or divestitures, the timing of development expenditures and drilling of wells, hurricanes, tropical storms and other natural disasters, changes in laws and regulations as they relate to our operations, including our fracking operations or our operations in the Gulf of Mexico, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports PetroQuest has filed with the Securities and Exchange Commission. PetroQuest undertakes no duty to update or revise these forward-looking statements. Prior to 2010, the Securities and Exchange Commission generally permitted oil and gas companies, in their filings, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Beginning with year-end reserves for 2009, the SEC permits the optional disclosure of probable and possible reserves. We have elected not to disclose our probable and possible reserves in our filings with the SEC. We use the terms “reserve inventory,” “gross unrisked reserves,” “EUR,” “inventory”, “unrisked resource potential” or other descriptions of volumes of hydrocarbons to describe volumes of resources potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines prohibit us from including in filings with the SEC. Estimates of reserve inventory, gross unrisked reserves EUR, inventory or unrisked inventory do not reflect volumes that are demonstrated as being commercially or technically recoverable. Even if commercially or technically recoverable, a significant recovery factor would be applied to these volumes to determine estimates of volumes of proved reserves. Accordingly, these estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. The methodology for estimating unrisked inventory, gross unrisked reserves, EUR or unrisked resource potential may also be different than the methodology and guidelines used by the Society of Petroleum Engineers and is different from the SEC’s guidelines for estimating probable and possible reserves. Version 1
Arkoma Divestiture Overview 3 Sold majority of Woodford and Mississippian Lime Assets Gross proceeds of $280 million Net operating cash flow of approximately $7.5 million (1Q15) from sold assets Sold approximately 227 Bcfe proved reserves (63% Developed) as of 12/31/14 and 46 MMcfe/d (1Q15) Attractive Valuation Metrics Price/2015E CF(1): 9.3x $/Mcfe Proved Reserves (12/31/14): $1.23 $/Flowing Mcfe/d (1Q15): ~$6,000 ~ $7,000/acre Use of Proceeds Repaid all borrowings under credit facility ~$130 million of cash proceeds and $14 million in deferred payments to balance sheet to fund future Cotton Valley drilling and/or additional deleveraging (1) 1Q15 annualized field level cash flow
Liquidity and Debt Metrics Post Arkoma Divestiture 14.2 147.2 -99.6 -45.6 19.6 171.6 -100 -50 0 50 100 150 200 1Q15 1Q15 PF $ M M Cash BB Availability Working Cap Deficit (1) Total Liquidity 4 Liquidity Position (net of working capital) Total Debt (net of cash) 421 203 0 100 200 300 400 500 1Q15 1Q15PF $ M M (1) Excluding cash and 1QPF includes working capital deficit reductions post 3/31/15 (including $14MM of deferred sales proceeds in A/R) (2) $350 MM 10% Senior Notes due 2017 (net of estimated cash) Up 775% (2)
Leverage Ratio Post Arkoma Divestiture 5 Total Debt (net of cash) vs Adjusted EBITDA 421 203 130 89 0 50 100 150 200 250 300 350 400 450 1Q15 1Q15PF Total Debt (net of cash) 3/31/15 TTM Adjusted EBITDA (1) (1) See appendix 1 for reconciliation of Adjusted EBITDA to Net Income Debt/Adjusted EBITDA 3.2x 2.3x
Asset Base - Post Arkoma Divestiture 6 Mid-Con East Texas Gulf Coast East Texas Gulf Coast Mid-Con 1Q15 Reserves 1Q15 PF Reserves 409 Bcfe 177 Bcfe 1Q15 Field Cash Flow 1Q15 PF Field Cash Flow East Texas Gulf Coast Mid-Con Mid-Con East Texas Gulf Coast $19.2 MM $11.7 MM 69 78 60 65 70 75 80 1Q15PF 3Q15E (2) (2) (1) PQ internal estimates (2) Prior to commencement of production at Thunder Bayou (3) Mid-point of 3Q15 production guidance Production (MMcfe/d) (3) (1) (1)
Strategic Rationale for Divestiture Attractive Valuation Metrics Proceeds of 9X cash flow are highly accretive to corporate multiple with sold assets embedded Significantly enhances liquidity and financial flexibility No bank borrowings outstanding post-sale ($70 million borrowing base) > 7X increase in liquidity (adjusted for working capital) Over $2.00/share of cash on hand provides additional deleveraging options Allows for operational focus on Company’s best asset: Cotton Valley Last 8 wells have added ~70 Bcfe of net proved reserves ~1 Tcfe (1) of net risked inventory in Cotton Valley Evaluating timing to resume drilling program second half of 2015 Strong Gulf Coast free cash flow (~$40MM in 2014) now directed to development of multi-year Cotton Valley inventory Thunder Bayou on-line shortly at 38,000 Mcfe/d enhancing Gulf Coast free cash flow 7 (1) PQ internal estimate
8 Appendix
Appendix 1 – Adjusted EBITDA Reconciliation Adjusted EBITDA represents net income (loss) available to common stockholders before income tax expense (benefit), interest expense (net), preferred stock dividends, depreciation, depletion, amortization, loss on early extinguishment of debt , share based compensation expense, non-cash gain on legal settlement , accretion of asset retirement obligation, derivative (income )expense, and ceiling test writedowns . We have reported Adjusted EBITDA because we believe Adjusted EBITDA is a measure commonly reported and widely used by investors as an indicator of a company’s operating performance. We believe Adjusted EBITDA assists such investors in comparing a company’s performance on a consistent basis without regard to depreciation, depletion and amortization, which can vary significantly depending upon accounting methods or nonoperating factors such as historical cost. Adjusted EBITDA is not a calculation based on generally accepted accounting principles, or GAAP, and should not be considered an alternative to net income in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions and other sources and uses of cash which are disclosed in our consolidated statements of cash flows. Investors should carefully consider the specific items included in our computation of Adjusted EBITDA. While Adjusted EBITDA has been disclosed herein to permit a more complete comparative analysis of our operating performance relative to other companies, investors should be cautioned that Adjusted EBITDA as reported by us may not be comparable in all instances to Adjusted EBITDA as reported by other companies. Adjusted EBITDA amounts may not be fully available for management’s discretionary use, due to certain requirements to conserve funds for capital expenditures, debt service and other commitments, and therefore management relies primarily on our GAAP results. Adjusted EBITDA is not intended to represent net income as defined by GAAP and such information should not be considered as an alternative to net income, cash flow from operations or any other measure of performance prescribed by GAAP in the United States. The above table reconciles net income (loss) available to common stockholders to Adjusted EBITDA for the periods presented. 9 ($ in thousands) 2010 2011 2012 2013 2014 1Q15 LTM 1Q15 Net Income (Loss) available to common stockholders $41,987 $5,409 ($137,218) $8,943 $26,051 ($122,240) ($106,232) Income tax expense (benefit) 1,630 (1,810) 1,636 320 (2,941) (927) (3,868) Interest expense & preferred dividends 15,091 14,787 14,947 27,025 34,420 9,154 34,658 Depreciation, depletion, and amortization 59,326 58,243 60,689 71,445 87,818 20,654 88,044 Loss on early extinguishment of debt 5,973 - - - - - - Share based compensation expense 7,137 4,833 6,910 4,216 5,248 1,478 5,337 Non-cash gain on legal settlement (4,164) - - - - - - Accretion of asset retirement obligation 1,306 2,049 2,078 1,753 2,958 859 3,026 Derivative (income) expense - - 233 (233) - - - Ceiling test writedown - 18,907 137,100 - - 108,911 108,911 Adjusted EBITDA $128,286 $102,418 $86,375 $113,469 $153,554 $17,889 $129,876 Arkoma Divested Assets Field Level Cash Flow ($41,119) Pro Forma Adjusted EBITDA $88,769