DENVER, Nov. 07, 2016 (GLOBE NEWSWIRE) -- Extraction Oil & Gas, Inc. (NASDAQ:XOG), an oil and gas exploration and production company with primary assets in the Wattenberg Field in the Denver-Julesburg Basin of Colorado, today reported financial and operational results for the third quarter ended September 30, 2016.
Unless indicated otherwise or the context otherwise requires, references in this report to the "Company," “XOG,” "us," "we," "our," or "ours" or like terms refer to Extraction Oil & Gas, Inc. following the completion of our initial public offering on October 17, 2016. When used in the historical context, the "Company," “Holdings,” "us," "we," "our" and "ours" or like terms refer to Extraction Oil & Gas Holdings, LLC and its subsidiaries. Holdings is our accounting predecessor, for which we present the financial information in this release.
Third-Quarter 2016 Highlights
- Average net sales of 28,948 barrels of oil equivalent per day (“BOE/d”), a 45% increase from the same period in 2015, with closing of the acquisition of certain assets from Bayswater Exploration & Production, LLC (the “Bayswater Acquisition”) on October 3, 2016, increasing estimated pro forma average net sales to approximately 37,000 BOE/d;
- Oil, natural gas and natural gas liquids (“NGL”) sales totaled $72.9 million, a 49% increase from the same period in 2015;
- For the third quarter 2016, the Company reported net loss of $37.3 million, or $(0.11) per basic and diluted share, compared to net income of $18.7 million, or $0.07 per basic and diluted share, for the same period in 2015; and
- Adjusted EBITDAX prior to the impact of commodity derivatives of $43.5 million, a 51% increase from the same period in 2015 and including the impact of commodity derivatives of $48.2 million, a 12% increase from the same period in 2015. Adjusted EBITDAX and Adjusted EBITDAX, Unhedged are non-GAAP financial measures. For a definition of Adjusted EBITDAX and Adjusted EBITDAX, Unhedged and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, read “—Adjusted EBITDAX and Adjusted EBITDAX, Unhedged.”
Commenting on third quarter 2016 results, Extraction's Chairman and CEO Mark Erickson said: "We are very pleased with our third quarter financial and operating results. Year-over-year, we have substantially increased organic production while lowering our Capex cost structure. With the close of our recent initial public offering, we have substantially improved the balance sheet which currently reflects less than 1x Net Debt to LTM EBITDAX. Extraction’s debt and equity holders are well-positioned to benefit from our top-tier balance sheet strength which should allow us to continue our robust growth trajectory while maintaining financial flexibility and ample liquidity.”
“Our recent pads in our Southern acreage brought on at the end of the third quarter are exceeding our type-curve expectations which we believe validates our conviction in the value of our highly targeted acreage position strategy. Extraction’s operational efficiencies continue to progress as our top five fastest two-mile lateral wells were all drilled in the third quarter, with the fastest at 2.27 days spud to total depth, resulting in leading cost structures through efficiency gains. Simultaneously, our operations team is intently focused on increasing ultimate resource recovery through enhanced completion designs, leading to improved well economics.”
“Lastly, through both our internal production growth and the Bayswater asset acquisition of operated working interest and leasehold in October, we believe we are demonstrating the ability to both grow organically and through selective acquisition opportunities, all while showing balance sheet strength and value creation for our investors. Looking forward, this month we commenced completion activities on a 68-well program in the Windsor area and additionally we have 18 drilled uncompleted wells associated with the Bayswater Acquisition, which positions Extraction for substantial 2017 growth in both production and reserves. This production growth should also decrease our average cost structure per BOE, such as LOE and G&A."
Financial Results
For the third quarter ended September 30, 2016, the Company reported oil, natural gas and NGL sales of $72.9 million, as compared to $48.8 million during the same period in 2015, representing an increase of 49%. The Company reported an overall 45% increase in equivalent sales volumes with 2.7 million barrels of oil equivalent (MMBOE) sold, or an average of 28,948 BOE per day (BOE/d) during the third quarter 2016, as compared to 1.8 MMBOE, or an average of 20,026 BOE/d during the third quarter of 2015. Crude oil revenue accounted for approximately 71% of our total revenues recorded during the third quarter 2016.
Adjusted EBITDAX, Unhedged was $43.5 million for the third quarter ended September 30, 2016, as compared to $28.7 million in the same period in 2015, reflecting a 51% increase, including the impact of commodity derivative settlements of $4.7 million for the quarter ended September 30, 2016 and $14.1 million for the quarter ended September 30, 2015. Adjusted EBITDAX, after the impact of commodity derivatives, increased to $48.2 million from $42.9 million, respectively, or a 12% increase. Adjusted EBITDAX and Adjusted EBITDAX, Unhedged are non-GAAP financial measures. For additional information please refer to the reconciliation of these measures at the end of this news release.
The Company reported quarterly net loss of $37.3 million, or $(0.11) per basic and diluted share, compared to net income of $18.7 million, or $0.07 per basic and diluted share, for the same period in 2015. The decrease in net income of $55.9 million is largely attributable to (i) a decline in commodity derivative gains in the amount of $30.7 million as a result of the settlement of our 2015 hedge positions entered into during the higher commodity price environment of 2014 and (ii) the amortization of our remaining unamortized debt issuance costs and debt discount of $15.1 million upon the repayment of our term loan facility (the “Second Lien Notes”) in July 2016.
Lease operating expenses (“LOE”) for the third quarter ended September 30, 2016 totaled $9.5 million or $3.57 per BOE, a 25% increase as compared to the same period in 2015. This increase is primarily related to an acquisition that included a number of vertical wells holding leases by production, which began impacting LOE per BOE in the fourth quarter of 2015. Transportation and gathering expenses for the third quarter ended September 30, 2016 totaled $6.0 million or $2.24 per BOE, an 85% increase as compared to the same period in 2015. The increase is primarily the result of an increase in transportation and gathering fees of $3.7 million on gas sales as a result of the Company entering into fee-type gas contracts on the southern pads recently brought on versus percent of proceeds contracts in the northern part of its acreage.
Cash general and administrative expenses (“G&A”) for the third quarter ended September 30, 2016 totaled $7.8 million, or $2.91 per BOE, as compared to $7.1 million, or $3.83 per BOE, in the same period in 2015. This increase in G&A is primarily due to the Company expanding operations and its preparedness for operating as a public company but this effect was more than offset by an increase in production volumes over the same time period, resulting in a decrease in per unit G&A cost.
During the third quarter ended September 30, 2016, the Company recognized total interest expense related to its outstanding 7.875% Senior Notes due 2021 (the “Senior Notes”), Second Lien Notes and revolving credit facility of approximately $31.2 million, of which $15.1 million was associated with the amortization of our remaining unamortized debt issuance costs and debt discount upon the repayment of our Second Lien Notes in July 2016. The Company capitalized interest costs of $1.2 million for the third quarter 2016.
The following table provides a summary of our sales volumes, average prices and certain operating expenses on a per BOE basis for the three and nine months ended September 30, 2016 and 2015 (unaudited):
| Three Months Ended | Nine Months Ended | ||||||||||||
| September 30, | September 30, | ||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||
| Sales (BOE/d)(1): | 28,948 | 20,026 | 27,114 | 17,779 | |||||||||
| Sales (MBoe)(1): | 2,663 | 1,842 | 7,429 | 4,854 | |||||||||
| Oil sales (MBbl) | 1,290 | 1,015 | 3,808 | 2,792 | |||||||||
| Natural gas sales (MMcf) | 4,792 | 2,753 | 12,851 | 7,225 | |||||||||
| NGL sales (MBbl) | 574 | 369 | 1,479 | 857 | |||||||||
| Average sales prices(2): | |||||||||||||
| Oil sales (per Bbl) | $ | 40.11 | $ | 36.76 | $ | 35.68 | $ | 41.10 | |||||
| Oil sales with derivative settlements (per Bbl) | 42.73 | 49.89 | 41.93 | 55.09 | |||||||||
| Natural gas sales (per Mcf) | 2.67 | 2.71 | 2.16 | 2.45 | |||||||||
| Natural gas sales with derivative settlements (per Mcf) | 2.94 | 3.01 | 2.84 | 2.77 | |||||||||
| NGL sales (per Bbl) | 14.54 | 11.04 | 13.37 | 10.68 | |||||||||
| Average price per BOE | 27.38 | 26.51 | 24.69 | 29.18 | |||||||||
| Average price per BOE with derivative settlements | 29.12 | 34.18 | 29.06 | 37.71 | |||||||||
| Expense per BOE: | |||||||||||||
| Lease operating expenses | $ | 3.57 | $ | 2.86 | $ | 3.47 | $ | 3.09 | |||||
| Transportation and gathering expenses | 2.24 | 1.21 | 2.03 | 0.78 | |||||||||
| Production taxes | 2.32 | 2.65 | 2.28 | 2.64 | |||||||||
| Other operating expenses | — | 0.38 | 0.12 | 0.48 | |||||||||
| Acquisition transaction expenses | 0.13 | — | 0.05 | 1.24 | |||||||||
| Cash general and administrative expenses | 2.91 | 3.83 | 2.73 | 4.21 | |||||||||
| Non-cash unit-based compensation | 4.62 | 0.82 | 2.01 | 0.94 | |||||||||
| (1 | ) | One BOE is equal to six thousand cubic feet (“Mcf”) of natural gas or one barrel (“Bbl”) of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. | |
| (2 | ) | Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains and losses on cash settlements for commodity derivatives and premiums paid or received on options that settled during the period. |
Operational Results
During the third quarter of 2016, our aggregate drilling, completion and leasehold capital expenditures were approximately $65.3 million, excluding acquisitions. During the third quarter 2016, we have and continue to operate two rigs in the Wattenberg Field.
During the third quarter of 2016, we reached total depth on 22 gross (20 net) horizontal wells with an average lateral length of two miles, completed 22 gross (18 net) horizontal wells with an average lateral length of one mile, and turned-in-line 32 gross (27 net) horizontal wells in the Wattenberg Field with an average lateral length of 1.2 miles. During the fourth quarter of 2016, we had expected to bring on 16 gross (15 net) horizontal wells with an average lateral length of one mile but we brought those wells online early, in mid-September 2016. Completion work has now begun on approximately 68 wells in our Windsor area which will be completed together to maximize well performance. As such, while we will have strong production contribution in the fourth quarter from the wells brought online early, we do not expect to bring online any additional wells for the remainder of the year.
Debt and Liquidity
On October 17, 2016, we closed our initial public offering (the “IPO”) of our common stock. We received $683.7 million of estimated net proceeds from the IPO. We used $291.6 million of the net proceeds from our IPO to repay borrowings under our revolving credit facility and $90.0 million of proceeds to redeem certain preferred units of Holdings (the “Series A Preferred Units”). The remaining net proceeds will be used for general corporate purposes, including to fund our 2016 and 2017 capital expenditures. September 30, 2016 liquidity pro forma for the closing of our IPO was approximately $828.3 million, consisting of $378.5 million in cash and cash equivalents and $450.0 million of availability under our revolving credit facility. At September 30, 2016, the Company had $550.0 million aggregate amount outstanding of the Senior Notes. As of the date of this filing we had no balance outstanding under the revolving credit facility.
Commodity Derivative Instruments
The Company uses various derivative instruments to manage fluctuations in crude oil and natural gas prices. The Company has in place a series of collars and fixed price and basis swaps on a portion of its expected crude oil and natural gas production. The Company recognized a net gain on commodity derivatives of $16.2 million for the three months ended September 30, 2016. The Company recognized a net gain of $46.9 million for the three months ended September 30, 2015.
Third-Quarter 2016 Earnings Conference Call Information
Those who would like to participate can dial into the number listed below approximately 15 minutes before the scheduled conference call time, and enter confirmation number 7606470 when prompted.
| Date: | Tuesday, November 8, 2016 |
| Time: | 8:00 AM MST / 10:00 AM EST |
| Dial - In Numbers: | 1-844-229-9561 (Domestic toll-free) |
| Conference ID: | 7606470 |
To access the audio webcast and related presentation materials, please visit the investor relations section of the Company’s website at www.extractionog.com. A replay of the conference call will be available on the website for approximately 30 days following the call.
About Extraction Oil & Gas, Inc.
Denver-based Extraction Oil & Gas, Inc. is an independent energy exploration and development company focused on exploring, developing and producing crude oil, natural gas and NGLs primarily in the Wattenberg Field in the Denver-Julesburg Basin of Colorado. For further information, please visit www.extractionog.com. The Company's common shares are listed for trading on the NASDAQ under the symbol: “XOG.”
Cautionary Note Regarding Forward-Looking Statements
Certain statements contained in this press release constitute “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 facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could," and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. These forward-looking statements represent our expectations or beliefs concerning future events, and it is possible that the results described in this press release will not be achieved. These forward-looking statements are subject to risks, uncertainties and other factors, many of which are outside of our control that could cause actual results to differ materially from the results discussed in the forward-looking statements.
Any forward-looking statement speaks only as of the date on which it is made, and, except as required by law, we do not undertake any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. New factors emerge from time to time, and it is not possible for us to predict all such factors. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in the prospectus filed with the SEC in connection with our initial public offering and in subsequent public filings with the SEC. These and other factors could cause our actual results to differ materially from those contained in any forward-looking statement.
| EXTRACTION OIL & GAS HOLDINGS, LLC. | |||||||||||
| CONDENSED CONSOLIDATED BALANCE SHEETS | |||||||||||
| (In thousands, except share data) | |||||||||||
| (Unaudited) | |||||||||||
| September 30, | December 31, | ||||||||||
| 2016 | 2015 | ||||||||||
| ASSETS | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 1,386 | $ | 97,106 | |||||||
| Accounts receivable | |||||||||||
| Trade | 19,011 | 27,927 | |||||||||
| Oil, natural gas and NGL sales | 24,444 | 15,938 | |||||||||
| Inventory and prepaid expenses | 5,695 | 7,938 | |||||||||
| Commodity derivative asset | 532 | 68,885 | |||||||||
| Total Current Assets | 51,068 | 217,794 | |||||||||
| Property and Equipment (successful efforts method), at cost: | |||||||||||
| Proved oil and gas properties | 1,405,817 | 1,128,022 | |||||||||
| Unproved oil and gas properties | 318,267 | 374,194 | |||||||||
| Wells in progress | 61,064 | 59,416 | |||||||||
| Less: accumulated depletion, depreciation and amortization | (341,050 | ) | (181,382 | ) | |||||||
| Net oil and gas properties | 1,444,098 | 1,380,250 | |||||||||
| Other property and equipment, net of accumulated depreciation (Note 2) | 29,346 | 30,402 | |||||||||
| Net Property and Equipment | 1,473,444 | 1,410,652 | |||||||||
| Non-Current Assets: | |||||||||||
| Cash held in escrow | 42,000 | — | |||||||||
| Deferred equity issuance costs | 5,126 | 942 | |||||||||
| Commodity derivative asset | — | 2,906 | |||||||||
| Other non-current assets | 1,767 | 1,846 | |||||||||
| Total Non-Current Assets | 48,893 | 5,694 | |||||||||
| Total Assets | $ | 1,573,405 | $ | 1,634,140 | |||||||
| LIABILITIES AND MEMBERS' EQUITY | |||||||||||
| Current Liabilities: | |||||||||||
| Accounts payable and accrued liabilities | $ | 76,982 | $ | 111,127 | |||||||
| Revenue payable | 48,980 | 38,752 | |||||||||
| Production taxes payable | 27,149 | 19,061 | |||||||||
| Commodity derivative liability | 21,776 | — | |||||||||
| Accrued interest payable | 8,792 | 450 | |||||||||
| Asset retirement obligations | 3,742 | 952 | |||||||||
| Total Current Liabilities | 187,421 | 170,342 | |||||||||
| Non-Current Liabilities: | |||||||||||
| Credit facility | 89,000 | 225,000 | |||||||||
| Second Lien Notes, net of unamortized debt discount and debt issuance costs (Note 4) | — | 412,790 | |||||||||
| Senior Notes, net of unamortized debt issuance costs (Note 4) | 537,601 | — | |||||||||
| Production taxes payable | 23,406 | 25,275 | |||||||||
| Commodity derivative liability | 6,727 | — | |||||||||
| Other non-current liabilities | 3,523 | 3,086 | |||||||||
| Asset retirement obligations | 49,492 | 43,415 | |||||||||
| Total Non-Current Liabilities | 709,749 | 709,566 | |||||||||
| Commitments and Contingencies—Note 11 | |||||||||||
| Total Liabilities | 897,170 | 879,908 | |||||||||
| Members' Equity: | |||||||||||
| Preferred tranche C units; unlimited units authorized; 115,706,938 units issued and outstanding | 370,418 | 250,338 | |||||||||
| Tranche A units; unlimited units authorized; 237,434,889 units issued and outstanding | 513,451 | 501,128 | |||||||||
| Retained earnings (deficit) | (207,634 | ) | 2,766 | ||||||||
| Total Members' Equity | 676,235 | 754,232 | |||||||||
| Total Liabilities and Members' Equity | $ | 1,573,405 | $ | 1,634,140 | |||||||
| EXTRACTION OIL & GAS HOLDINGS, LLC. | |||||||||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||||||||
| (In thousands, except share data) | |||||||||||||||||||||
| (Unaudited) | |||||||||||||||||||||
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||
| Revenues: | |||||||||||||||||||||
| Oil sales | $ | 51,760 | $ | 37,304 | $ | 135,896 | $ | 114,768 | |||||||||||||
| Natural gas sales | 12,792 | 7,472 | 27,730 | 17,707 | |||||||||||||||||
| NGL sales | 8,350 | 4,070 | 19,773 | 9,153 | |||||||||||||||||
| Total Revenues | 72,902 | 48,846 | 183,399 | 141,628 | |||||||||||||||||
| Operating Expenses: | |||||||||||||||||||||
| Lease operating expenses | 15,480 | 7,493 | 40,819 | 18,806 | |||||||||||||||||
| Production taxes | 6,186 | 4,874 | 16,935 | 12,798 | |||||||||||||||||
| Exploration expenses | 5,985 | 1,911 | 14,735 | 6,763 | |||||||||||||||||
| Depletion, depreciation, amortization and accretion | 46,680 | 40,880 | 141,317 | 100,170 | |||||||||||||||||
| Impairment of long lived assets | 467 | — | 23,350 | 9,525 | |||||||||||||||||
| Other operating expenses | — | 696 | 891 | 2,353 | |||||||||||||||||
| Acquisition transaction expenses | 345 | — | 345 | 6,000 | |||||||||||||||||
| General and administrative expenses | 20,071 | 8,568 | 35,189 | 25,437 | |||||||||||||||||
| Total Operating Expenses | 95,214 | 64,422 | 273,581 | 181,852 | |||||||||||||||||
| Operating Loss | (22,312 | ) | (15,576 | ) | (90,182 | ) | (40,224 | ) | |||||||||||||
| Other Income (Expense): | |||||||||||||||||||||
| Commodity derivatives gain (loss) | 16,225 | 46,886 | (62,424 | ) | 38,478 | ||||||||||||||||
| Interest expense | (31,216 | ) | (12,682 | ) | (57,914 | ) | (36,350 | ) | |||||||||||||
| Other income | 36 | 22 | 120 | 36 | |||||||||||||||||
| Other Income (Expense) | (14,955 | ) | 34,226 | (120,218 | ) | 2,164 | |||||||||||||||
| Net Income (Loss) | (37,267 | ) | 18,650 | (210,400 | ) | $ | (38,060 | ) | |||||||||||||
| Income (Loss) per Unit | |||||||||||||||||||||
| Basic | $ | (0.11 | ) | $ | 0.07 | $ | (0.63 | ) | $ | (0.14 | ) | ||||||||||
| Diluted | $ | (0.11 | ) | $ | 0.07 | $ | (0.63 | ) | $ | (0.14 | ) | ||||||||||
| Weighted Average Units Outstanding | |||||||||||||||||||||
| Basic | 349,014 | 279,896 | 332,377 | 266,844 | |||||||||||||||||
| Diluted | 349,014 | 286,891 | 332,377 | 266,844 | |||||||||||||||||
| Pro Forma Information (unaudited): | |||||||||||||||||||||
| Pro forma income (loss) | $ | (37,267 | ) | $ | 18,650 | $ | (210,400 | ) | $ | (38,060 | ) | ||||||||||
| Pro forma provision for income tax (expense) benefit | 14,161 | (7,087 | ) | 79,952 | 14,463 | ||||||||||||||||
| Pro forma net income (loss) | $ | (23,106 | ) | $ | 11,563 | $ | (130,448 | ) | $ | (23,597 | ) | ||||||||||
| Pro forma net income (loss) per unit | |||||||||||||||||||||
| Basic | $ | (0.07 | ) | $ | 0.04 | $ | (0.39 | ) | $ | (0.09 | ) | ||||||||||
| Diluted | $ | (0.07 | ) | $ | 0.04 | $ | (0.39 | ) | $ | (0.09 | ) | ||||||||||
| Weighted average pro forma units outstanding | |||||||||||||||||||||
| Basic | 349,014 | 279,896 | 332,377 | 266,844 | |||||||||||||||||
| Diluted | 349,014 | 286,891 | 332,377 | 266,844 | |||||||||||||||||
| EXTRACTION OIL & GAS HOLDINGS, LLC. | |||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||
| (In thousands) | |||||||||||
| (Unaudited) | |||||||||||
| For the Nine Months Ended | |||||||||||
| September 30, | |||||||||||
| 2016 | 2015 | ||||||||||
| Cash flows from operating activities: | |||||||||||
| Net loss | $ | (210,400 | ) | $ | (38,060 | ) | |||||
| Reconciliation of net loss to net cash provided by operating activities: | |||||||||||
| Depletion, depreciation, amortization and accretion | 141,317 | 100,170 | |||||||||
| Abandonment and impairment of unproved properties | 3,331 | 6,214 | |||||||||
| Impairment of long lived assets | 23,350 | 9,525 | |||||||||
| Non-cash acquisition transaction expenses | — | 6,000 | |||||||||
| Amortization of debt issuance costs and debt discount | 18,330 | 3,081 | |||||||||
| Deferred rent | 600 | 212 | |||||||||
| Commodity derivatives (gain) loss | 62,424 | (38,478 | ) | ||||||||
| Settlements on commodity derivatives | 43,015 | 39,929 | |||||||||
| Premiums paid on commodity derivatives | (611 | ) | (2,350 | ) | |||||||
| Unit-based compensation | 14,922 | 4,583 | |||||||||
| Changes in current assets and liabilities: | |||||||||||
| Accounts receivable—trade | 3,889 | (2,813 | ) | ||||||||
| Accounts receivable—oil, natural gas and NGL sales | (8,506 | ) | (8,352 | ) | |||||||
| Prepaid expenses | (273 | ) | (281 | ) | |||||||
| Accounts payable and accrued liabilities | (18,242 | ) | 33,585 | ||||||||
| Revenue payable | 10,228 | 10,888 | |||||||||
| Production taxes payable | 6,219 | 11,774 | |||||||||
| Accrued interest payable | 8,342 | 11,704 | |||||||||
| Asset retirement expenditures | (372 | ) | (1,770 | ) | |||||||
| Net cash provided by operating activities | 97,563 | 145,561 | |||||||||
| Cash flows from investing activities: | |||||||||||
| Oil and gas property additions | (223,684 | ) | (288,060 | ) | |||||||
| Acquired oil and gas properties | (13,674 | ) | (120,524 | ) | |||||||
| Sale of property and equipment | 2,148 | — | |||||||||
| Other property and equipment additions | (3,336 | ) | (20,086 | ) | |||||||
| Cash held in escrow | (42,000 | ) | 10,071 | ||||||||
| Net cash used in investing activities | (280,546 | ) | (418,599 | ) | |||||||
| Cash flows from financing activities: | |||||||||||
| Borrowings under credit facility | 60,000 | 100,000 | |||||||||
| Repayments under credit facility | (196,000 | ) | — | ||||||||
| Proceeds from the issuance of Senior Notes | 550,000 | — | |||||||||
| Repayments of Second Lien Notes | (430,000 | ) | — | ||||||||
| Proceeds from the issuance of units | 121,370 | 223,350 | |||||||||
| Repurchase of units | (2,867 | ) | — | ||||||||
| Debt issuance costs | (13,189 | ) | (1,874 | ) | |||||||
| Unit and deferred equity issuance costs | (2,051 | ) | (4,524 | ) | |||||||
| Net cash provided by financing activities | 87,263 | 316,952 | |||||||||
| Increase (decrease) in cash and cash equivalents | (95,720 | ) | 43,914 | ||||||||
| Cash and cash equivalents at beginning of period | 97,106 | 79,025 | |||||||||
| Cash and cash equivalents at end of the period | $ | 1,386 | $ | 122,939 | |||||||
| Supplemental cash flow information: | |||||||||||
| Property and equipment included in accounts payable and accrued liabilities | $ | 53,371 | $ | 81,444 | |||||||
| Acquisition transaction expenses paid through oil and gas properties | $ | — | $ | 6,000 | |||||||
| Cash paid for interest | $ | 30,531 | $ | 25,677 | |||||||
| Cash paid for Second Lien Notes prepayment penalty | $ | 4,300 | $ | — | |||||||
| Noncash settlement of promissory notes issued to officers | $ | 5,562 | $ | — | |||||||
| EXTRACTION OIL & GAS HOLDINGS, LLC. | |||||||||||||||||||||
| RECONCILIATION OF ADJUSTED EBITDAX AND ADJUSTED EBITDAX, UNHEDGED | |||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||
| (Unaudited) | |||||||||||||||||||||
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||
| Reconciliation of Adjusted EBITDAX: | |||||||||||||||||||||
| Net income (loss) | $ | (37,267 | ) | $ | 18,650 | $ | (210,400 | ) | $ | (38,060 | ) | ||||||||||
| Add back: | |||||||||||||||||||||
| Depreciation, depletion, amortization, and accretion | 46,680 | 40,880 | 141,317 | 100,170 | |||||||||||||||||
| Impairment of long lived assets | 467 | — | 23,350 | 9,525 | |||||||||||||||||
| Exploration expenses | 5,985 | 1,911 | 14,735 | 6,763 | |||||||||||||||||
| Rig termination fee | — | — | 891 | 1,657 | |||||||||||||||||
| Acquisition transaction expenses | 345 | — | 345 | 6,000 | |||||||||||||||||
| (Gain) loss on commodity derivatives | (16,225 | ) | (46,886 | ) | 62,424 | (38,478 | ) | ||||||||||||||
| Settlements on commodity derivative instruments | 4,787 | 15,067 | 37,947 | 42,441 | |||||||||||||||||
| Premiums paid for derivative that settled during the period | (132 | ) | (934 | ) | (5,470 | ) | (1,046 | ) | |||||||||||||
| Unit-based compensation expense | 12,315 | 1,510 | 14,922 | 4,583 | |||||||||||||||||
| Amortization of debt discount and debt issuance costs | 15,905 | 1,125 | 18,330 | 3,081 | |||||||||||||||||
| Interest expense | 15,311 | 11,557 | 39,584 | 33,269 | |||||||||||||||||
| Adjusted EBITDAX | $ | 48,171 | $ | 42,880 | $ | 137,975 | $ | 129,905 | |||||||||||||
| Deduct: | |||||||||||||||||||||
| Settlements on commodity derivative instruments | 4,787 | 15,067 | 37,947 | 42,441 | |||||||||||||||||
| Premiums paid for derivative that settled during the period | (132 | ) | (934 | ) | (5,470 | ) | (1,046 | ) | |||||||||||||
| Adjusted EBITDAX, Unhedged | $ | 43,516 | $ | 28,747 | $ | 105,498 | $ | 88,510 | |||||||||||||
Adjusted EBITDAX and Adjusted EBITDAX, Unhedged is not a measure of net income (loss) as determined by United States generally accepted accounting principles (‘‘GAAP’’). Adjusted EBITDAX and Adjusted EBITDAX, Unhedged is a supplemental non-GAAP financial measure that is used by management and external users of our Predecessor’s financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depreciation, depletion, amortization and accretion (‘‘DD&A’’), impairment of long lived assets, exploration expenses, rig termination fees, acquisition transaction expenses, commodity derivative (gain) loss, settlements on commodity derivatives, premiums paid for derivatives that settled during the period, unit-based compensation expense, amortization of debt discount and debt issuance costs, interest expense, income taxes and non-recurring charges. We define Adjusted EBITDAX, Unhedged as Adjusted EBITDAX adjusted for settlements on commodity derivative instruments and premiums paid for derivative that settled during the period.
Management believes Adjusted EBITDAX and Adjusted EBITDAX, Unhedged are useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX and Adjusted EBITDAX, Unhedged because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX and Adjusted EBITDAX, Unhedged should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX and Adjusted EBITDAX, Unhedged are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX and Adjusted EBITDAX, Unhedged. Our computations of Adjusted EBITDAX and Adjusted EBITDAX, Unhedged may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX and Adjusted EBITDAX, Unhedged is a widely followed measure of operating performance. A reconciliation of Adjusted EBITDAX and Adjusted EBITDAX, Unhedged and net income (loss) for the three and nine months ended September 30, 2016 and 2015 is provided in the table above.