Extraction Oil & Gas, Inc. Announces Third-Quarter 2017 Results

Third-Quarter 2017 Highlights

• Average net sales volumes of 62,884 barrels of oil equivalent per day (BOE/d) including 34,607 barrels per day (Bbl/d) of oil. Production volumes exceeded the high end of the Company’s crude oil and total equivalent volume ranges;
• Net loss of $29.8 million, or $0.20 per basic and diluted share¹, compared to a net loss of $37.3 million for the same period in 2016 and net income of $7.2 million for the second quarter of 2017. Adjusted EBITDAX, Unhedged² was $125.6 million for the third quarter, up 189% year-over-year and up 68% sequentially. Adjusted EBITDAX was $128.4 million, up 167% year-over-year and up 72% sequentially;
• Turned to sales 30 gross (27 net) operated wells with an average lateral length of approximately 7,900 feet, and completed 51 gross (34 net) wells with an average lateral length of approximately 10,300 feet;
• The Company expects fourth-quarter 2017 average net sales volumes to be 65-67 MBoe/d with 32-34 MBbl/d of crude oil and increases its full year crude oil production guidance to 25.5-26.5 MBbl/d and total equivalent volumes to 51.5-52.0 MBoe/d; and
• Expected total investment in its New Acquisition Area (Hawkeye Area) in Arapahoe and Adams Counties to be approximately $450 million for roughly 60,000 net acres.

Commenting on third-quarter 2017 results, Extraction's Chairman and CEO Mark Erickson said: “We have now had two quarters in a row where our growth has exceeded our forecast, and as a result, we have effectively doubled the Company’s production since the first quarter."

"We expect to exit the year with a large amount of flush production coming online, which will set us up nicely for hitting our plan to fund our corporate expenditures inside of cash flow during the second half of 2018 while still being able to maintain our previously disclosed production guidance.”

Financial Results

Third quarter average net sales volumes were 62,884 BOE/d, an increase of 117% year-over-year and 42% sequentially. Crude oil volumes of 34,607 Bbl/d increased 147% year-over-year and 50% sequentially. Both crude oil and total equivalent volumes exceeded the high end of the Company’s previously disclosed guidance ranges while crude oil accounted for approximately 73% of the Company’s total revenues recorded during the third quarter of 2017.

For the third quarter, Extraction reported oil, natural gas and NGL sales revenue of $180.9 million, as compared to $72.9 million during the same period in 2016, representing an increase of 148%. Revenue increased 51% sequentially driven by an increase in average daily production and higher realized oil and NGL prices.

Extraction reported a net loss of $29.8 million, or $0.20 per basic and diluted share, compared to net loss of $37.3 million for the same period in 2016 and net income of $7.2 million for the second quarter. This net loss was driven predominately by a $40.7 million unrealized loss on commodity derivatives. Adjusted EBITDAX, Unhedged was $125.6 million for the third quarter, up 189% year-over-year and up 68% sequentially. Adjusted EBITDAX was $128.4 million, up 167% year-over-year and up 72% sequentially.

Lease operating expenses (LOE) excluding transportation and gathering expenses for the third quarter were in-line with the Company’s guidance range and totaled $15.5 million, or $2.67 per BOE. Cash general and administrative expense (G&A) of $10.6 million, or $1.84 per BOE came in below the low end of the company’s previous guidance range as Extraction maintains its low overhead cost structure while rapidly growing its production. Transportation and gathering expense related to natural gas and NGL sales for the third quarter was $13.8 million, or $2.39 per BOE.

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, 2017 and 2016 respectively:

Update on New Acquisition Area in the Southern DJ Basin (Hawkeye Area)

To date Extraction has invested approximately $333 million to acquire acreage in its New Acquisition Area, now referred to as the Hawkeye Area, located predominately in Arapahoe and Adams Counties in the Southern DJ Basin. Of this $333 million, $255 million was previously announced and paid across several transactions to acquire approximately 30,000 net acres while the additional $78 million represents a deposit as part of a contemplated November 2017 transaction expected to result in an incremental 30,000 net acres for approximately $195 million, inclusive of the previously paid down payment. The $255 million total previously announced includes $160 million paid during 2016. This brings Extraction’s expected total investment in its Hawkeye Area to approximately $450 million for roughly 60,000 net acres with approximately 77 percent working interest.

To date, over 30 wells have been drilled in this area, and many of which have exhibited some of the highest oil production rates in the DJ Basin. Extraction believes this acreage is very comparable with core Wattenberg in terms of Niobrara thickness and expects to develop 12-16 wells per section.

The Hawkeye Area is some of Extraction's most rural acreage, and as such, has allowed the Company to quickly secure permits. Extraction currently has over 100 permits approved and over 110 more in process. The Company is currently negotiating with multiple third parties for gas gathering & processing and oil gathering solutions and expects competitive rates similar to our other operating areas.

Commenting on the Company’s new acquisition area, Matt Owens said, “We have assembled a large, high-quality, majority operated drilling inventory of over 1,000 gross locations with an average lateral length of 8,800 feet. This is an oil prone area, and we expect it to be a significant contributor to Extraction’s future growth. Our first operated well in the area continues to perform above expectations, and we look forward to providing additional results as we complete our next well towards the end of this year and continue activity in this area as part of our 2018 development program.”

With the inclusion of the Hawkeye Area, Extraction now has approximately 160,000 net acres in the core of the DJ Basin and 155,000 net acres in the Northern Extension. The Company is currently performing a strategic review of its entire portfolio with the goal of high-grading its acreage position and monetizing non-strategic assets.

Operational Results

During the third quarter, the Company’s aggregate drilling, completion, leasehold and midstream capital expenditures totaled approximately $302 million, $252 million of which was for drilling and completion, $47 million on leasehold and $3 million on midstream. Extraction’s total drilling and completion capital expenditures for the first three quarters of 2017 were approximately $701 million including $31 million for non-operated activity.

Commenting on the third quarter, Extraction’s Chairman and CEO Mark Erickson said, “Our drilling and completion capital expenditures increased relative to our initial expectations driven largely by our decision to utilize a fourth completion crew to reduce the cycle time on our 22-well, 2.5-mile lateral Triple Creek pad in Greeley. Increased efficiencies on the drilling side resulted in spudding an additional 14 net wells compared to our initial budget. While neither of these activities impacted our production during the third quarter, they will both contribute significantly to our 2018 growth.”

Extraction reached total depth on 53 gross (35 net) wells with an average lateral length of approximately 8,300 feet, completed 51 gross (34 net) wells with an average lateral length of approximately 10,300 feet and turned to sales 30 gross (27 net) wells with an average lateral length of approximately 7,900 feet during the third quarter. The Company completed 3,053 total stages during the third quarter while pumping approximately 965 million pounds of proppant.

Fourth Quarter and Full-Year 2017 Outlook

For the fourth quarter of 2017, Extraction expects its average net sales volumes to be 65-67 MBoe/d, which represents a five percent increase over its third-quarter 2017 volumes at the midpoint. The Company’s crude oil production in the fourth quarter of 2017 is expected to average 32-34 MBbl/d. For the full-year 2017, we are revising our expected crude oil production guidance to 25.5-26.5 MBbl/d from our previously revised guidance range of 24-27 MBbl/d. We now expect our full-year 2017 net sales to average between 51.5-52.0 MBoe/d.

The Company expects its fourth quarter LOE excluding transportation and gathering expense to be between $16 million and $17 million and its cash general and administrative expenses to be between $11.5 million and $12.5 million. Driven by better-than-expected well performance and continued efficiency gains, Extraction now expects its full-year 2017 per-unit LOE excluding transportation expense to be between $3.05 and $3.15 per BOE, down from its previous estimated range of $3.10 to $3.30 per BOE. Extraction now expects its cash G&A expense to be between $2.25 and $2.35 per BOE, down from its previous estimated range of $2.25-$2.50 per BOE.

Extraction now expects its full-year 2017 operated and non-operated drilling and completion forecast to be between $865 and $885 million, which represents an $80 million increase from the midpoint of its previous budget of $735-$855 million. Roughly half of the capital expenditure increase is due to incremental costs associated with appraisal wells we have drilled across our acreage position to delineate the effectiveness of enhanced completions. The other half is due to being slightly ahead of schedule with our drilling rigs as well as incremental completion costs associated with further testing and optimization utilizing even larger enhanced completion designs.

Driven by these additional wells turned to sales near the end of 2017 along with continued better-than-expected well performance, Extraction now expects its 2017 exit rate to be approximately 73 MBoe/d. This represents an eight percent increase from the midpoint of its previous 65-70 MBoe/d exit rate guidance range. As this incremental capital is going to impact 2018 production rather than 2017, Extraction continues to maintain its ability to meet its previously disclosed 2018 growth guidance target with less drilling and completion capital than in 2017. Extraction plans to issue official 2018 capital and production guidance sometime in December.

Commenting on the capital forecast, Mark Erickson, Extraction Chairman and CEO said, “While we utilized a fourth completion crew for about a month during the third quarter to improve the cycle time on our 22 well 2.5-mile lateral Triple Creek pad inside Greeley, we plan to reduce our activity during December, which makes us confident in our ability to hit our updated full-year 2017 capital forecast.”

“While navigating the high line pressures on DCP’s system in the northern portion of the Wattenberg field has been difficult, we are benefiting from plans made early in the year to proactively install pad sales compression enabling our older pads to produce against the higher line pressures and from our new pads which can more easily produce against the higher line pressures."

"We fortunately have a large acreage position in the southern portion of the field with access to Western Gas which has ample excess capacity. Extraction is focusing most of its completion activity on its southern acreage as we wait for DCP’s additional plant to come online next summer, in an effort to avoid the bottlenecks related to DCP,” said Erickson.

Debt and Liquidity

Extraction ended the third quarter with $114 million of cash on its balance sheet and a fully undrawn borrowing base. On October 11, 2017, Extraction’s borrowing base under its revolving credit facility was increased to $525 million from $375 million. This increase is primarily a result of wells turned to sales through June 30, 2017. The Company also bolstered its liquidity position with $394 million of proceeds from its senior notes offering that closed on August 1, 2017. Pro forma for this increased borrowing base and after giving effect to letters of credit, Extraction ended the third quarter with approximately $613 million of available liquidity. In addition, the Company has begun the next redetermination process which is expected to be completed prior to year end which will incorporate wells turned to sales through September 30, 2017.

Extraction continues to maintain its robust hedging program and currently has 18.4 million barrels of crude oil and 50.6 million MMBtu of natural gas hedged through the first half of 2019 as of October 31, 2017.

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 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 92226881when prompted.

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 “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.

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, rig termination fees, acquisition transaction expenses, commodity derivative (gain) loss, settlements on commodity derivatives, premiums paid for derivatives that settled during the period, unit and stock-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 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, 2017 and 2016 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