Extraction Oil & Gas, Inc. Announces Third-Quarter 2018 Results
DENVER, Nov. 06, 2018 (GLOBE NEWSWIRE) -- Extraction Oil & Gas, Inc. (NASDAQ: XOG) (“Extraction” or the “Company”) today reported financial and operational results for the third quarter of 2018.
Third-Quarter 2018 Highlights
Third quarter average net sales volumes of 75,680 barrels of oil equivalent per day (BOE/d) including 39,323 barrels per day (Bbl/d) of crude oil;
For the third quarter, Extraction reported net income of $65.2 million, or $0.33 per basic and diluted share, compared to net loss of $29.8 million, or $0.20 per basic and diluted share1, for the same period in 2017. Adjusted EBITDAX, Unhedged2 was $212.4 million for the third quarter, up 69% year-over-year and up 12% sequentially. Adjusted EBITDAX was $169.4 million for the third quarter, up 32% year-over-year and up 11% sequentially;
Drilling and completion (D&C) capital expenditures for the third quarter 2018 were $161 million; and
First operated pad in Extraction's Broomfield Development Area produced crude oil at a peak 60-day average daily rate of 1,179 BOE/d, 68% of which was crude oil, exceeding internal estimates.
"After DCP's Plant 10 became operational in August, we were achieving sustained production in excess of 90 MBOE/d, reaching almost 93 MBOE/d at one point," said Extraction Oil & Gas Chairman and CEO Mark Erickson. "After DCP imposed production allocations later in August, we were forced to choke our wells back considerably, and since that time, we have not realized the full, sustained production potential of our outstanding DJ Basin wells. Despite these midstream headwinds that are outside of our control, we continue to produce some of the best wells in our company's history."
"As stated previously on October 18, we initially expected that DCP's Plant 10 would provide much more relief than what we have seen to date. We estimate that DCP negatively impacted our production by approximately 18 MBOE/d during the third quarter. Once Plant 10 came online, we did not expect that DCP would be basing allocations on production data from August 2017, and as a result, our gas production on DCP's system is currently curtailed by over 35%."
_______________________ 1 For further information on the earnings per share, refer to the Condensed Consolidated Statement of Operations, included herein. 2 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 “-Reconciliation of Adjusted EBITDAX and Adjusted EBITDAX, Unhedged” included herein.
"Despite the midstream headwinds, we still expect to generate positive free cash flow for the fourth quarter of 2018 when you exclude the impact of our initial Elevation Midstream investment, which is non-recourse to and does not require capital outlays by the upstream Company."
Financial Results
For the third quarter, Extraction reported oil, natural gas and NGL sales revenue of $282.2 million, as compared to $180.9 million during the same period in 2017, representing an increase of 56%. Revenue increased 8% sequentially, primarily driven by higher production and an improvement in crude oil prices.
Extraction reported net income of $65.2 million, or $0.33 per basic and diluted share for the third quarter, compared to net loss of $29.8 million for the same period in 2017. This increase in net income was driven predominately by an $83.6 million gain from the previously announced sale of Extraction's ownership in Discovery Midstream that closed in August. Adjusted EBITDAX, Unhedged was $212.4 million for the third quarter, up 69% year-over-year and up 12% sequentially. Adjusted EBITDAX was $169.4 million for the third quarter, up 32% year-over-year and up 11% sequentially. Please read “Reconciliation of Adjusted EBITDAX and Adjusted EBITDAX, Unhedged”, included herein.
The following table provides a summary of our sales volumes, average sales prices and certain operating expenses on a per BOE basis for the three and nine months ended September 30, 2018 and 2017, respectively:
For the Three Months Ended
For the Nine Months Ended
September 30,
September 30,
2018
2017
2018
2017
Sales (MBoe)(1):
6,963
5,785
19,855
12,809
Oil sales (MBbl)
3,618
3,184
10,394
6,496
Natural gas sales (MMcf)
11,838
8,953
33,612
21,713
NGL sales (MBbl)
1,372
1,109
3,860
2,695
Sales (BOE/d)(1):
75,680
62,884
72,731
46,921
Oil sales (Bbl/d)
39,323
34,607
38,072
23,794
Natural gas sales (Mcf/d)
128,679
97,311
123,122
79,536
NGL sales (Bbl/d)
14,910
12,059
14,138
9,871
Average sales prices(2):
Oil sales (per Bbl)
$
62.32
$
41.48
$
59.58
$
41.50
Oil sales with derivative settlements (per Bbl)
50.02
42.14
48.23
40.61
Differential ($/Bbl) to Average NYMEX WTI
(7.11
)
(6.72
)
(7.21
)
(7.86
)
Natural gas sales (per Mcf)
1.95
2.76
1.99
2.91
Natural gas sales with derivative settlements (per Mcf)
2.08
2.84
2.37
2.90
Differential ($/Mcf) to Average NYMEX Henry Hub(3)
(1.20
)
(0.49
)
(1.15
)
(0.45
)
NGL sales (per Bbl)(3)
24.49
21.74
22.38
21.36
Average price per BOE
40.53
31.26
38.91
30.47
Average price per BOE with derivative settlements
34.35
31.76
33.62
30.00
Expense per BOE:
Lease operating expenses
$
2.91
$
2.67
$
3.11
$
3.25
Transportation and gathering(3)
1.69
2.39
1.47
2.66
General and administrative expenses
5.08
4.97
5.06
6.08
Cash general and administrative expenses
2.58
1.84
2.50
2.43
Stock-based compensation
2.50
3.13
2.56
3.65
Production taxes as a % of Revenue
7.7
%
9.0
%
8.6
%
8.5
%
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.
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 settlements for commodity derivatives and amortization of premiums paid or received on options that settled during the period.
As a result of the adoption of ASC 606 - Revenue from Contracts with Customers ("ASC 606") on January 1, 2018, certain costs previously classified as transportation and gathering expenses are presented on a net basis for proceeds expected to be received. For further information, see Note 2 - Adoption of ASC 606 of our Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2018.
Operational Results
Extraction turned its first pad in its Broomfield Development Area to sales starting in early August 2018. This pad consists of ten two-mile laterals with seven of the wells producing from the Niobrara formation and three producing from the Codell formation. The Codell wells produced at a peak 60-day average daily rate of approximately 1,197 BOE/d, 68% of which was crude oil. The Niobrara wells produced at a peak 60-day average daily rate of approximately 1,173 BOE/d, 69% of which was crude oil.
"We had very high expectations for our Broomfield area, and these results exceed even our high expectations," Erickson said. "They came on very strong and are exhibiting a relatively shallow decline profile, which is very encouraging for the long-term deliverability of these wells. With over 12,000 developable acres in this area, all of which will be served by our own Elevation Midstream, this area provides us with a lot of running room along with greater control over the midstream situation. We plan to put one rig in Broomfield drilling full-time starting in early 2019. We've already begun construction on the midstream side and expect to begin construction for the well pads before the end of this year."
Third quarter crude oil volumes of 39,323 Bbl/d increased 14% year-over-year and increased 1% sequentially. Crude oil accounted for approximately 80% of the Company’s total revenues and over 52% of the Company’s total equivalent volumes recorded during the third quarter. Third quarter average net sales volumes were 75,680 BOE/d, an increase of 20% year-over-year and 3% sequentially.
Extraction estimates the limited allocation it received on DCP's midstream system negatively impacted its production by approximately 18 MBOE/d during the third quarter and expects DCP's constraints to impact its full-year 2018 production by over approximately 17 MBOE/d, which is incorporated into its guidance announced on October 18, 2018. The Company expects these constraints on DCP's system to persist with limited relief after DCP's Plant 11 is placed into service during the second quarter of 2019.
For the third-quarter 2018, Extraction’s aggregate drilling, completion, and leasehold capital expenditures totaled $186.7 million, of which $161.0 million was drilling and completion additions and $25.7 million was leasehold and surface acreage additions. This excludes the impact of the decrease in outstanding elections of $16.1 million. In addition, Elevation Midstream, LLC, our wholly owned midstream subsidiary, incurred $37.5 million of capital expenditures. Elevation's capital budget results in no capital outlay from Extraction and the financing is non-recourse to Extraction's balance sheet.
During the third quarter, Extraction reached total depth on 41 gross (30 net) wells with an average lateral length of approximately 9,700 feet and completed 31 gross (26 net) wells with an average lateral length of approximately 6,500 feet. We turned to sales 71 gross (61 net) wells with an average lateral length of approximately 9,600 feet. Of these 71 wells, 57 are on DCP's midstream system. The Company completed 1,091 total stages during the quarter while pumping approximately 340 million pounds of proppant.
Updated Investor Presentation
Extraction has posted an updated investor presentation to its website. The investor presentation may be viewed on the Company’s website (www.extractionog.com) by selecting “Investors,” then “News and Events,” then “Presentations.”
Third-Quarter 2018 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 6475178 when prompted.
Date:
Tuesday, November 6, 2018
Time:
4:30 PM EST / 2:30 PM MST
Dial - In Numbers:
1-844-229-9561 (Domestic toll-free)
Conference ID:
6475178
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.”
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 “Risk Factors” section of our most recent Form 10-K and Forms 10-Q filed with the Securities and Exchange Commission and in our other public filings and press releases. These and other factors could cause our actual results to differ materially from those contained in any forward-looking statement.
EXTRACTION OIL & GAS, INC. CONDENSED CONSOLIDATED BALANCE SHEETS (In thousands, except share data) (Unaudited)
September 30, 2018
December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents
$
274,065
$
6,768
Accounts receivable
151,731
139,348
Inventory and prepaid expenses
26,676
13,017
Commodity derivative asset
13,226
4,132
Total Current Assets
465,698
163,265
Property and Equipment (successful efforts method), at cost:
Oil and gas properties
4,544,761
3,825,912
Less: accumulated depletion, depreciation and amortization
(1,029,539
)
(709,662
)
Net oil and gas properties
3,515,222
3,116,250
Gathering systems and facilities
63,998
4,889
Other property and equipment, net of accumulated depreciation
37,829
32,429
Net Property and Equipment
3,617,049
3,153,568
Non-Current Assets:
Goodwill and other intangible assets, net of accumulated amortization
56,446
55,453
Other non-current assets
19,132
12,383
Total Non-Current Assets
75,578
67,836
Total Assets
$
4,158,325
$
3,384,669
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities
$
200,137
$
211,581
Revenue and production taxes payable
175,248
90,249
Commodity derivative liability
143,576
67,428
Accrued interest payable
18,792
23,807
Asset retirement obligations
12,928
6,873
Total Current Liabilities
550,681
399,938
Non-Current Liabilities:
Credit facility
290,000
90,000
Senior Notes, net of unamortized debt issuance costs
1,132,115
933,361
Deferred tax liability
54,626
42,326
Commodity derivative liability
8,786
17,274
Other non-current liabilities
148,975
126,622
Total Non-Current Liabilities
1,634,502
1,209,583
Total Liabilities
2,185,183
1,609,521
Commitments and Contingencies
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding
162,813
158,383
Total Stockholders' Equity
1,810,329
1,616,765
Total Liabilities and Stockholders' Equity
$
4,158,325
$
3,384,669
EXTRACTION OIL & GAS INC. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share data) (Unaudited)
For the Three Months Ended September 30,
For the Nine Months Ended September 30,
2018
2017
2018
2017
Revenues:
Oil sales
$
225,467
$
132,075
$
619,211
$
269,597
Natural gas sales
23,103
24,672
66,991
63,095
NGL sales
33,590
24,114
86,369
57,574
Total Revenues
282,160
180,861
772,571
390,266
Operating Expenses:
Lease operating expenses
20,283
15,465
61,760
41,626
Transportation and gathering
11,786
13,802
29,284
34,129
Production taxes
21,605
16,290
66,317
33,254
Exploration expenses
11,038
7,181
21,326
24,431
Depletion, depreciation, amortization and accretion
107,315
94,220
310,296
213,483
Impairment of long lived assets
16,166
—
16,294
675
(Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary
(83,559
)
—
(143,461
)
451
Acquisition transaction expenses
—
—
—
68
General and administrative expenses
35,365
28,741
100,565
77,916
Total Operating Expenses
139,999
175,699
462,381
426,033
Operating Income (Loss)
142,161
5,162
310,190
(35,767
)
Other Income (Expense):
Commodity derivatives gain (loss)
(35,913
)
(37,875
)
(175,752
)
46,423
Interest expense
(20,725
)
(15,080
)
(103,229
)
(33,761
)
Other income
1,827
891
3,094
1,709
Total Other Income (Expense)
(54,811
)
(52,064
)
(275,887
)
14,371
Income (Loss) Before Income Taxes
87,350
(46,902
)
34,303
(21,396
)
Income tax (expense) benefit
(22,200
)
17,106
(12,300
)
7,556
Net Income (Loss)
$
65,150
$
(29,796
)
$
22,003
$
(13,840
)
Income (Loss) Per Common Share(1)
Basic and diluted
$
0.33
$
(0.20
)
$
0.03
$
(0.15
)
Weighted Average Common Shares Outstanding
Basic and diluted
175,814
171,845
175,269
171,838
For further information, see the reconciliation of Net Income (Loss) to Net Income (Loss) available to common shareholders in Note 10 of our Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2018 and 2017.
EXTRACTION OIL & GAS, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited)
For the Three Months Ended September 30,
For the Nine Months Ended September 30,
2018
2017
2018
2017
Cash flows from operating activities:
Net income (loss)
$
65,150
$
(29,796
)
$
22,003
$
(13,840
)
Reconciliation of net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion
107,315
94,220
310,296
213,483
Abandonment and impairment of unproved properties
9,541
1,124
15,463
5,684
Impairment of long lived assets
16,166
—
16,294
675
(Gain) loss on sale of property and equipment
53
—
(59,849
)
451
Gain on sale of assets of unconsolidated subsidiary
(83,612
)
—
(83,612
)
—
Amortization of debt issuance costs
935
1,469
12,303
3,181
Deferred rent
162
(73
)
442
(229
)
(Gain) loss on commodity derivatives, including settlements and premiums paid
(3,290
)
42,222
64,999
(55,316
)
Earnings in unconsolidated subsidiaries
(843
)
(266
)
(1,886
)
(256
)
Distributions from unconsolidated subsidiaries
1,058
131
1,684
131
Make-whole premium expense on 2021 Senior Notes
—
—
35,600
—
Deferred income tax expense (benefit)
22,200
(17,106
)
12,300
(7,556
)
Stock-based compensation
17,419
18,110
50,883
46,707
Changes in current assets and liabilities:
Accounts receivable
(14,327
)
(53,863
)
(9,292
)
(65,458
)
Inventory and prepaid expenses
175
(77
)
(637
)
(180
)
Accounts payable and accrued liabilities
(4,532
)
4,839
(14,780
)
1,653
Revenue and production taxes payable
55,724
21,340
110,603
19,567
Accrued interest payable
(3,619
)
(5,909
)
(5,015
)
(5,553
)
Asset retirement expenditures
(4,403
)
(456
)
(9,437
)
(1,408
)
Net cash provided by operating activities
181,272
75,909
468,362
141,736
Cash flows from investing activities:
Oil and gas property additions
(255,633
)
(443,595
)
(774,787
)
(1,015,700
)
Acquired oil and gas properties
—
—
—
(17,225
)
Sale of property and equipment
—
3,155
72,345
5,155
Gathering systems and facilities additions
(25,304
)
(3,046
)
(41,359
)
(7,685
)
Other property and equipment additions
(9,232
)
(772
)
(11,944
)
(1,923
)
Investment in unconsolidated subsidiaries
(5,707
)
—
(6,000
)
—
Distributions from unconsolidated subsidiaries, return of capital
—
116
—
116
Sale of assets of unconsolidated subsidiary
83,612
—
83,612
—
Net cash used in investing activities
(212,264
)
(444,142
)
(678,133
)
(1,037,262
)
Cash flows from financing activities:
Borrowings under credit facility
160,000
250,000
590,000
250,000
Repayments under credit facility
(60,000
)
(250,000
)
(390,000
)
(250,000
)
Proceeds from the issuance of 2026 Senior Notes
—
394,000
739,664
394,000
Repayments of 2021 Senior Notes
—
—
(550,000
)
—
Make-whole premium paid on 2021 Senior Notes
—
—
(35,600
)
—
Proceeds from issuance of Preferred Units
148,500
—
148,500
—
Preferred Unit issuance costs
(6,933
)
—
(6,933
)
—
Repurchase of shares
(2,125
)
—
(4,434
)
—
Payment of employee payroll withholding taxes
(331
)
(2,832
)
(2,862
)
(2,832
)
Dividends on Series A Preferred Stock
(2,721
)
(2,722
)
(8,164
)
(7,680
)
Debt issuance costs
(48
)
(3,163
)
(3,103
)
(3,273
)
Equity issuance costs
466
—
—
(1,486
)
Net cash provided by financing activities
236,808
385,283
477,068
378,729
Increase (decrease) in cash, cash equivalents and restricted cash
205,816
17,050
267,297
(516,797
)
Cash, cash equivalents and restricted cash at beginning of period
68,249
97,089
6,768
630,936
Cash, cash equivalents and restricted cash at end of the period
$
274,065
$
114,139
$
274,065
$
114,139
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities
$
148,156
$
130,022
$
148,156
$
130,022
Cash paid for interest
$
25,066
$
22,447
$
66,673
$
44,703
Accretion of beneficial conversion feature of Series A Preferred Stock
$
1,515
$
1,365
$
4,429
$
3,992
Preferred Units commitment fees and dividends paid-in-kind
$
3,305
$
—
$
3,305
$
—
EXTRACTION OIL & GAS, INC. RECONCILIATION OF ADJUSTED EBITDAX AND ADJUSTED EBITDAX, UNHEDGED (In thousands) (Unaudited)
For the Three Months Ended September 30,
For the Nine Months Ended September 30,
2018
2017
2018
2017
Reconciliation of Net Income (Loss) to Adjusted EBITDAX:
Net income (loss)
$
65,150
$
(29,796
)
$
22,003
$
(13,840
)
Add back:
Depletion, depreciation, amortization and accretion
107,315
94,220
310,296
213,483
Impairment of long lived assets
16,166
—
16,294
675
Exploration expenses
11,038
7,181
21,326
24,431
(Gain) loss on sale of property and equipment
—
—
(59,902
)
451
Gain on sale of assets of unconsolidated subsidiary
(83,559
)
—
(83,559
)
—
Acquisition transaction expenses
—
—
—
68
(Gain) loss on commodity derivatives
35,913
37,875
175,752
(46,423
)
Settlements on commodity derivative instruments
(41,009
)
3,162
(99,914
)
(6,022
)
Premiums paid for derivatives that settled during the period
(1,956
)
(293
)
(5,191
)
20
Stock-based compensation expense
17,420
18,110
50,883
46,707
Amortization of debt issuance costs
935
1,469
12,303
3,181
Make-whole premium on 2021 Senior Notes
—
—
35,600
—
Interest expense
19,790
13,611
55,326
30,580
Income tax expense (benefit)
22,200
(17,106
)
12,300
(7,556
)
Adjusted EBITDAX
$
169,403
$
128,433
$
463,517
$
245,755
Deduct:
Settlements on commodity derivative instruments
(41,009
)
3,162
(99,914
)
(6,022
)
Premiums paid for derivatives that settled during the period
(1,956
)
(293
)
(5,191
)
20
Adjusted EBITDAX, Unhedged
$
212,368
$
125,564
$
568,622
$
251,757
Adjusted EBITDAX and Adjusted EBITDAX, Unhedged are not measures of net income (loss) as determined by United States generally accepted accounting principles (“GAAP”). Adjusted EBITDAX and Adjusted EBITDAX, Unhedged are supplemental non-GAAP financial measures that are used by management and external users of our 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 depletion, depreciation, amortization and accretion, impairment of long lived assets, exploration expenses, (gain) loss on sale of property and equipment and assets of unconsolidated subsidiaries, acquisition transaction expenses, (gain) loss on commodity derivatives, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the period, stock-based compensation expense, amortization of debt issuance costs, make-whole premiums, 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 they allow 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 alternatives 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 are widely followed measures 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, 2018 and 2017 is provided in the table above. Additionally, our management team believes Adjusted EBITDAX and Adjusted EBITDAX, Unhedged are useful to an investor in evaluating our financial performance because these measures (i) are widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors; (ii) help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and (iii) are used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting.
Investor Contact: Louis Baltimore, ir@extractionog.com, 720-974-7773 Media Contact: Brian Cain, info@extractionog.com, 720-974-7782