Exhibit

Jim Kleckner, President and Chief Executive Officer, commented, “I am pleased with our Company's execution and performance through the first half of the year, with our DC&E costs down significantly from 2018. We continue to be intently focused on creating additional value through further reductions of these DC&E costs and preserving our high operating margins. Leveraging these efficiency gains will remain an important part of our business as we move to development projects in 2019 and 2020. During the quarter, we started operations on the six-well Coriander pad. The wells have been drilled and the completions are progressing on schedule to deliver first production in the next few weeks. Also during the quarter, we turned online two wells in the Big Tex area and have seen encouraging initial results. While it’s too early to make a full assessment of these results, we remain cautiously optimistic on the future optionality of our Big Tex area."

During the second quarter of 2019, the Company turned online 11 gross operated wells and reported average daily oil production for the quarter of 29.1 MBbls per day, at the upper end of the Company's previously announced guidance range of 27.8 – 29.2 MBbls per day. Total equivalent production averaged 38.3 MBoe per day for the second quarter, slightly above the upper end of the Company's previously announced guidance range of 36.6 – 38.0 MBoe per day. Second quarter production mix was comprised of 76% oil, 13% NGLs, and 11% natural gas, and is essentially unchanged from the prior quarter.

For the second quarter of 2019, the Company reported net income of $41.9 million, or $0.20 per diluted common share. Net income for the second quarter of 2018 was $45.1 million, or $0.21 per diluted common share. Adjusted net income (a non-GAAP measure) for the second quarter of 2019, was $21.3 million, or $0.10 per diluted common share, compared to $43.3 million, or $0.20 per diluted common share for the same period in 2018. Adjusted net income (a non-GAAP measure) eliminates certain non-cash and non-recurring items such as certain equity-based compensation, non-cash mark-to-market gains or losses on derivatives and impairment expense, further adjusted for any associated changes in estimated income tax expense. Adjusted EBITDAX (a non-GAAP measure) for the second quarter of 2019 was $101.7 million, a decrease of $16.9 million from the second quarter of 2018.

due to a 16% decrease in unhedged realized pricing on a per Boe basis. Natural gas pricing during the quarter was weak as daily spot pricing at Waha, the Company's primary pricing point, averaged approximately $0.01/Mcf for the quarter. After differentials, processing, and transportation fees were applied, the net realized price for natural gas sales for the quarter was negative $0.87 per Mcf. Despite negative realized pricing for natural gas, the Company continued to gather and process its gas to capture economics from NGL volumes and minimize flare volumes. Average realized prices for the second quarter of 2019 are included in the table below.



	Three Months Ended June 30, 2019
	Actual	Guidance ⁽¹⁾
Production
Average daily equivalent production (MBoe/d)	38.3	36.6 – 38.0
Average daily oil production (MBbl/d)	29.1	27.8 – 29.2

	Six Months Ended June 30, 2019	Full-Year 2019
	Actual	Guidance⁽¹⁾
Production
Average daily equivalent production (MBoe/d)	37.5	38.3 – 41.3
Average daily oil production (MBbl/d)	28.6	29.2 – 31.2

Income Statement
Lease operating expense ($/Boe)	$4.31	$3.65 – $4.15
General and administrative (before equity-based compensation) ($MM) (Non-GAAP)	$19.5	$46 – $50
Production and ad valorem taxes (% of revenue)	7.5%	6.0% – 7.0%

Capital Expenditures
Drilling and completion ($MM)	$288.7	$580 – $630
Infrastructure and other ($MM)	$21.2	$25 – $35
Total development capital ($MM)	$309.8	$605 – $665

Operated Activity
Gross horizontal wells brought online	23	52 – 56

The Company's lease operating expense ("LOE") per Boe for the quarter trended above the upper end of the annual guided range, primarily due to increased costs associated with artificial lift, including additional workover expenses and electric power. The Company now expects many of these increased costs to persist throughout the remainder of the year and has revised its guidance range, which are reflected in the "Updated 2019 Capital, Production, and Operating Guidance" section below.

Capital expenditures for DC&E activities were $152.0 million for the three months ended June 30, 2019. Activity during the quarter included drilling 13 and completing 11 gross (10.4 net) operated wells. A portion of the capital spent during the second quarter relates to 17 gross (16.2 net) operated wells that were in various stages of being drilled or completed at June 30, 2019, three of which were turned online during the first week of July. Including capital expenditures for infrastructure of $15.5 million, which account for approximately two thirds of the expected annual investment and activity, and leasehold acquisition costs of $3.2 million, total capital expenditures for the quarter were $170.7 million.

The Company continues to drive down its DC&E costs through continued efficiency gains and improvements to its supply chain and strategic sourcing of materials including sand, tubular goods, and cement. These improvements have resulted in a further reduction of the Company's total DC&E costs, which averaged $1,250 per lateral foot in the second quarter of 2019 and approximately $1,270 per lateral foot year-to-date. The Company remains on track to meet its full-year 2019 goal of $1,250 per lateral foot. The Company is tightly focused on further enhancing operational efficiencies and reducing total well costs.

In the Company's Whiskey River asset, the Company finished drilling its Coriander project. This project is the Company's first six-well co-development project spaced at 1,320 feet, and has recently commenced completions operations. Drilling operations for Coriander averaged approximately 860 feet per day, compared to the 2019 average of approximately 830 feet per day. Completion operations for Coriander started in mid-July and are currently on schedule with two frac crews completing the six wells. The Company expects the project to finish completions and be turned online in late-August, at which point the Company plans to finish drilling and begin completions activity on its Venom project, an eight-well multi-horizon development in the northern portion of Whiskey River.

During the quarter, the Company turned online its first Wolfcamp A well in the central fairway of its Big Tex acreage. Early results from this well, the State Big Tex South 7673-8 11-H, are encouraging, with a two-stream peak IP30 of 104 Boe per 1,000 lateral feet and 90-day cumulative production of approximately 7,500 Boe per 1,000 feet. This compares favorably to the average of the Company's Big Tex wells, which have had average two-stream peak IP30 of approximately 88 Boe per day and 90-day cumulative production of 6,300 Boe per 1,000 feet. The well is currently on artificial lift and continues to show a robust production profile after 130 days of production, with the most recent seven-day average oil production of 1,077 Bbls per day. The Company is drilling and completing two additional Wolfcamp A wells in this fairway in 2019, the first of which is in the early stages of flowing back and the second is currently completing.

The Company also turned online a successful well in its Southeastern Big Tex position during the quarter, that targeted the Woodford formation. This well, the Chimera 3601-142 61H, has an approximate 6,400 foot lateral and was placed entirely in-zone. The early time data of this well has been encouraging, with a two-stream peak IP30 of 294 Boe per 1,000 lateral feet (50% oil). As the production data of this well is preliminary, the Company will continue to monitor and evaluate the performance of this well, and its other 2019 Big Tex wells to inform capital allocation decisions for Big Tex in 2020.

For the remainder of the year, the Company plans to continue running five drilling rigs and between one and two completion crews, which are expected to complete between 13-15 wells in each of the remaining quarters of 2019. Development capital guidance is being affirmed at a midpoint of $635 million. For production, the Company is affirming its fourth quarter and full-year guidance ranges and providing guidance for the third quarter. The Company is expecting its oil production to grow sequentially in the third quarter by approximately 3% and then grow by approximately 15% in the fourth quarter as volumes from the Coriander and Venom projects are expected to be turned online in the second half of the third quarter and the beginning of the fourth quarter, respectively. From a cost perspective, the Company is raising the midpoint of its LOE guidance by $0.25 per Boe to account for additional artificial lift costs, and is decreasing its annual G&A guidance by $7.5 million, at the midpoint. The Company has also increased the production and ad valorem tax guidance by 0.5% as a percentage of revenue, due in part to decreased per unit revenues from natural gas and NGLs. As these three changes are netting, they are expected to have a neutral to slightly positive impact to the Company's top-tier adjusted EBITDAX margin. Adjusted EBITDAX margin is a non-GAAP metric. Please reference the reconciliations of this non-GAAP measures to the most directly comparable GAAP measure, Net Income, at the end of this release. The table below provides an updated summary of the Company's capital, production, and operating guidance for the third quarter and full-year 2019.



	Updated Guidance for the Three Months Ended September 30, 2019
Production
Average daily equivalent production (MBoe/d)	38.6 – 40.2
Average daily oil production (MBbl/d)	29.4 – 30.6

	Updated Guidance for the Full-Year 2019
Production
Average daily equivalent production (MBoe/d)	38.6 – 41.0
Average daily oil production (MBbl/d)	29.3 – 31.1

Income Statement
Lease operating expense ($/Boe)	$4.00 – $4.30
General and administrative (before equity-based compensation) ($MM) (Non-GAAP)	$39 - $42
Production and ad valorem taxes (% of revenue)	6.5% – 7.5%

Capital Expenditures
Drilling and completion ($MM) ⁽¹⁾	$590 – $620
Infrastructure and other ($MM)	$27 – $33
Total development capital ($MM)	$617 – $653

Operated Activity
Gross horizontal wells brought online	52 – 56
Average working interest	~95%
Average lateral length per well	8,900'

Non-operated Activity
Net horizontal wells brought online	2

⁽¹⁾Includes pad-level infrastructure and equipment

At the end of the second quarter of 2019, the Company had $150.0 million drawn on its revolving credit facility and $24.8 million of cash on the balance sheet, resulting in total liquidity of $414.8 million. Net debt to LTM adjusted EBITDAX (a non-GAAP measure) was 1.5x as of the end of the second quarter. The Company's current capital program is expected to keep the Company's leverage ratio, as measured by net debt to LTM adjusted EBITDAX, under 2.0x in a $50 per Bbl WTI environment. Please reference the reconciliation of this non-GAAP measure to the most directly comparable GAAP measure at the end of this release.

This news release contains forward-looking statements within the meaning of the federal securities laws. All statements, other than historical facts, that address activities that Jagged Peak assumes, plans, expects, believes, intends or anticipates (and other similar expressions), will, should or may occur in the future are forward-looking statements. Forward-looking statements are based on management's current beliefs, based on currently available information, as to the outcome and timing of future events. Forward-looking statements in this release include, among other things, guidance estimates including all statements under the heading “Updated 2019 Capital, Production, and Operating Guidance”; the Company’s ability to enhance operational efficiencies and reduce total well costs; the Company’s expected allocation of capital expenditures; the Company’s expected completion of certain wells and the timing of such completions; the Company’s expected number of drilling rigs, completions crews, and number of well completions for the remainder of 2019, early results of Big Tex delineation wells, and the Company's expectation that it will continue to keep its leverage ratio under 2.0x in a $50 per Bbl WTI environment during 2019. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of Jagged Peak. General risk factors include the availability, proximity and capacity of gathering, processing and transportation facilities; the volatility and level of oil, natural gas, and NGL prices, including any impact on the Company’s asset carrying values or reserves arising from price declines; uncertainties inherent in projecting future rates of production or other results from drilling and completion activities; the imprecise nature of estimating oil and gas reserves; uncertainties inherent in projecting future drilling and completion activities, costs or results; the availability of drilling, completion, and operating equipment and services; the risks associated with the Company’s commodity price risk management strategy; impact of environmental events, governmental and other third-party responses to such events and Jagged Peak’s

ability to adequately insure against such events; and other such matters discussed in the “Risk Factors” section of Jagged Peak’s 2018 Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 28, 2019, as such risk factors may be updated from time to time in the Company’s other periodic reports filed with the Securities and Exchange Commission, which can be obtained free of charge on the Securities and Exchange Commission's web site at http://www.sec.gov. The forward-looking statements contained in this release speak as of the date of this announcement. Although Jagged Peak may from time to time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so except as required by applicable securities laws.

Adjusted EBITDAX is a non-GAAP financial measure that is 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) before interest expense, net of capitalized interest, depletion, depreciation, amortization and accretion expense, impairment of oil and natural gas properties, exploration expenses, equity-based compensation expense, income taxes, contract termination fees, gains or losses on sales of assets, and net gains or losses on derivatives less net cash from/for derivative settlements. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historical costs of depreciable assets and exploration expenses, none of which are components of Adjusted EBITDAX. Our computation of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

Management believes Adjusted EBITDAX is useful because it allows investors to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book value of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance.

Adjusted net income is a non-GAAP performance measure used by management to evaluate financial performance, prior to non-cash market-to-market gains or losses on derivatives, impairment expense, exploratory dry hole costs, gain or loss on the sale of property, certain one-time or unusual items, such as certain equity-based compensation, contract termination fees, and the associated changes in estimated income tax. Management believes adjusted net income is useful because it may enhance investors’ ability to assess historical and future financial performance. Adjusted net income should not be considered an alternative to net income, operating income, or any other measure of financial performance presented in accordance with GAAP or as an indicator of our operating performance.



Jagged Peak Energy Inc.
Selected Operating Highlights
(Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2019			2018		2019		2018

Production volumes:
Oil (MBbls)	2,649			2,450		5,179		4,416
Natural gas (MMcf)	2,334			2,220		4,503		3,886
NGLs (MBbls)	444			325		851		565
Total (MBoe)	3,482			3,145		6,781		5,629
Average daily production volumes:
Oil (Bbls/d)	29,106			26,921		28,612		24,400
Natural gas (Mcf/d)	25,644			24,399		24,878		21,471
NGLs (Bbls/d)	4,879			3,575		4,703		3,120
Total (Boe/d)	38,259			34,562		37,462		31,098

Average Sales Prices Excluding Realized Hedge Settlements:
Oil (per Bbl)	$	54.98		$	60.66	$	51.96	$	60.99
Natural gas (per Mcf)	$	(0.87	)	$	1.05	$	0.04	$	1.34
NGLs (per Bbl)	$	7.15		$	23.36	$	8.28	$	22.86
Combined (per Boe)	$	42.15		$	50.41	$	40.75	$	51.07

Average Sales Prices Including Realized Hedge Settlements:
Oil (per Bbl)	$	51.70		$	55.82	$	49.81	$	54.79
Natural gas (per Mcf)	$	(0.87	)	$	1.05	$	0.04	$	1.34
NGLs (per Bbl)	$	7.15		$	23.36	$	8.28	$	22.86
Combined (per Boe)	$	39.65		$	46.63	$	39.11	$	46.21

Average Operating Costs (per Boe):
Lease operating expenses	$	4.47		$	3.33	$	4.31	$	3.59
Production and ad valorem tax expenses	$	3.31		$	2.94	$	3.07	$	3.01
Depletion, depreciation, amortization and accretion	$	17.58		$	17.46	$	17.74	$	18.28
General and administrative expense (before equity-based compensation expense)	$	2.61		$	2.69	$	2.88	$	3.39



Jagged Peak Energy Inc.
Condensed Consolidated Balance Sheets
(Unaudited)


		June 30, 2019		December 31, 2018

		(in thousands)
Assets:
	Cash and cash equivalents	$	24,796	$	35,229
	Other current assets	85,480		165,905
	Property and equipment, net	1,734,131		1,530,285
	Other noncurrent assets	69,962		35,722
	Total assets	$	1,914,369	$	1,767,141

Liabilities and Stockholders' Equity:
	Current liabilities	$	226,786	$	187,982
	Long-term debt	639,904		489,239
	Deferred income taxes	109,835		124,418
	Other long-term liabilities	36,603		17,552
	Stockholders' equity	901,241		947,950
	Total liabilities and stockholders' equity	$	1,914,369	$	1,767,141



Jagged Peak Energy Inc.
Condensed Consolidated Statements of Operations
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018

	(in thousands, except per share amounts)
Revenues
Oil, natural gas and NGL sales	$	146,757		$	158,551		$	276,343		$	287,457
Other operating revenues	—			125			9			272
Total revenues	146,757			158,676			276,352			287,729
Operating Expenses
Lease operating expenses	15,554			10,486			29,204			20,206
Production and ad valorem taxes	11,535			9,246			20,837			16,920
Exploration	—			1			—			1
Depletion, depreciation, amortization and accretion	61,222			54,915			120,296			102,892
Impairment of unproved oil and natural gas properties	862			—			946			53
Other operating expenses	6			24			3,206			46
General and administrative (before equity-based compensation)	9,085			8,454			19,545			19,093
General and administrative, equity-based compensation	3,993			2,379			6,927			78,057
Total operating expenses	102,257			85,505			200,961			237,268
Income (Loss) from Operations	44,500			73,171			75,391			50,461
Other Income and Expense
Gain (loss) on commodity derivatives	18,469			(9,584		)	(125,123		)	(13,910		)
Interest expense and other	(9,400		)	(6,098		)	(17,832		)	(8,821		)
Total other income (loss)	9,069			(15,682		)	(142,955		)	(22,731		)
Income (Loss) before Income Taxes	53,569			57,489			(67,564		)	27,730
Income tax expense (benefit)	11,662			12,408			(14,583		)	22,052
Net Income (Loss)	$	41,907		$	45,081		$	(52,981	)	$	5,678

Net income (loss) per common share:
Basic	$	0.20		$	0.21		$	(0.25	)	$	0.03
Diluted	$	0.20		$	0.21		$	(0.25	)	$	0.03

Weighted-average common shares outstanding:
Basic	213,371			213,142			213,321			213,073
Diluted	213,519			213,262			213,321			213,169



Jagged Peak Energy Inc.
Consolidated Statements of Cash Flows
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018

	(in thousands)
Cash Flows from Operating Activities
Net income (loss)	$	41,907		$	45,081		$	(52,981	)	$	5,678
Adjustments to reconcile to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	61,222			54,915			120,296			102,892
Impairment of unproved oil and natural gas properties	862			—			946			53
Amortization of debt issuance costs	590			421			1,176			1,021
Deferred income taxes	11,662			12,408			(14,583		)	22,052
Equity-based compensation	3,993			2,379			6,927			78,057
(Gain) Loss on commodity derivatives	(18,469		)	9,584			125,123			13,910
Net cash receipts (payments) on settled derivatives	(8,697		)	(11,879		)	(11,167		)	(27,358		)
Other	71			(78		)	(7		)	(156		)
Change in operating assets and liabilities:
Accounts receivable and other current assets	6,238			(13,198		)	(719		)	(18,549		)
Accounts payable and accrued liabilities	(10,116		)	19,939			(6,764		)	22,214
Net cash provided by operating activities	89,263			119,572			168,247			199,814
Cash Flows from Investing Activities
Leasehold and acquisitions costs	(3,304		)	(3,468		)	(15,567		)	(11,053		)
Development of oil and natural gas properties	(162,417		)	(206,986		)	(311,865		)	(392,968		)
Other capital expenditures	237			(611		)	(452		)	(1,881		)
Net cash used in investing activities	(165,484		)	(211,065		)	(327,884		)	(405,902		)
Cash Flows from Financing Activities
Proceeds from senior notes	—			500,000			—			500,000
Proceeds from senior secured revolving credit facility	95,000			55,000			150,000			165,000
Repayment of senior secured revolving credit facility	—			(320,000		)	—			(320,000		)
Debt issuance costs	(65		)	(11,220		)	(141		)	(12,743		)
Employee tax withholding for settlement of equity compensation awards	(376		)	—			(655		)	(200		)
Net cash provided by financing activities	94,559			223,780			149,204			332,057
Net Change in Cash and Cash Equivalents	18,338			132,287			(10,433		)	125,969
Cash and Cash Equivalents, Beginning of Period	6,458			3,205			35,229			9,523
Cash and Cash Equivalents, End of Period	$	24,796		$	135,492		$	24,796		$	135,492



Jagged Peak Energy Inc.
Commodity Hedges

The Company hedges its oil production to reduce cash flow volatility and to support funding of its capital expenditure program. The schedule below summarizes the hedges the Company has in place to hedge the price of WTI and the differential between the Cushing and Midland oil prices.



As of August 8, 2019, the Company had the following commodity hedges in place for future production:

Production Period	Volumes	Weighted Average Price
	(MBbls)	($/Bbl)
Oil Swaps:
Third Quarter 2019	1,932	$	59.95
Fourth Quarter 2019	1,932	$	59.95
Full Year 2019	3,864	$	59.95
First Quarter 2020	1,547	$	58.75
Second Quarter 2020	1,547	$	58.75
Third Quarter 2020	1,564	$	58.75
Fourth Quarter 2020	1,564	$	58.75
Full Year 2020	6,222	$	58.75

Oil Basis Swaps:
Third Quarter 2019	2,300	$	(4.79	)
Fourth Quarter 2019	2,300	$	(4.79	)
Full Year 2019	4,600	$	(4.79	)
First Quarter 2020	2,366	$	(1.31	)
Second Quarter 2020	2,366	$	(1.31	)
Third Quarter 2020	2,392	$	(1.31	)
Fourth Quarter 2020	2,392	$	(1.31	)
Full Year 2020	9,516	$	(1.31	)



Jagged Peak Energy Inc.
Reconciliation of Adjusted Net Income, Adjusted EBITDAX and Adjusted EBITDAX Margin
(Unaudited)

The following tables provide reconciliations of the GAAP financial measure of Net Income (Loss) to the non-GAAP financial measures of Adjusted Net Income (Loss) and Adjusted EBITDAX. A description of the reconciliations is included in the section titled “Reconciliation of Non-GAAP Financial Measures.”

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018

	(in thousands, except for per share and Boe metrics)
Adjusted Net Income (Loss)
Net income (loss)	$	41,907		$	45,081		$	(52,981	)	$	5,678
Adjustments to reconcile to adjusted net income
Impairment of unproved oil and natural gas properties	862			—			946			53
(Gain) loss on commodity derivatives, net, less net cash for/from derivative settlements	(27,166		)	(2,295		)	113,956			(13,448		)
Equity-based compensation expense related to allocated management incentive units	—			—			—			74,470
Contract termination fee ⁽¹⁾	—			—			3,200			—
Income tax effect for the above items	5,726			495			(25,491		)	2,890
Adjusted net income	$	21,329		$	43,281		$	39,630		$	69,643

Adjusted net income per basic common share	$	0.10		$	0.20		$	0.19		$	0.33
Adjusted net income per diluted common share	$	0.10		$	0.20		$	0.19		$	0.33

Basic common shares	213,371			213,142			213,321			213,073
Diluted common shares ⁽²⁾	213,519			213,262			213,458			213,169

Adjusted EBITDAX
Net income (loss)	$	41,907		$	45,081		$	(52,981	)	$	5,678
Adjustments to reconcile to adjusted EBITDAX
Interest expense, net of capitalized	9,263			6,108			17,709			8,839
Income tax expense (benefit)	11,662			12,408			(14,583		)	22,052
Depletion, depreciation, amortization and accretion	61,222			54,915			120,296			102,892
Impairment of unproved oil and natural gas properties	862			—			946			53
Contract termination fee ⁽¹⁾	—			—			3,200			—
Exploration expenses	—			1			—			1
(Gain) loss on commodity derivatives, net, less net cash from derivative settlements	(27,166		)	(2,295		)	113,956			(13,448		)
Equity-based compensation expense	3,993			2,379			6,927			78,057
Adjusted EBITDAX	$	101,743		$	118,597		$	195,470		$	204,124

Total production (MBoe)	3,482			3,145			6,781			5,629
Adjusted EBITDAX margin per Boe⁽³⁾	$	29.22		$	37.71		$	28.83		$	36.26



	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2019		2018		2019		2018
Acquisitions
Proved properties	$	584	$	—	$	7,407	$	—
Unproved properties	2,601		3,771		7,978		11,095
Drilling and completion costs	151,960		176,178		288,690		383,793
Infrastructure costs	15,523		4,065		21,158		8,001
Exploration costs	—		1		—		1
Total oil and gas capital expenditures	$	170,668	$	184,015	$	325,233	$	402,890



	Phone Number	Conference ID
Live Participant (Domestic)	1-877-823-8605	7790428
Live Participant (International)	1-647-689-5644	7790428
Replay⁽¹⁾ (Domestic)	1-800-585-8367	7790428
Replay⁽¹⁾ (International)	1-416-621-4642	7790428
⁽¹⁾ Replay available from 2:00 PM Eastern Time on August 9, 2019 through 12:00 midnight Eastern Time on August 16, 2019



Event	Date	Location	Management Attendees
Enercom The Oil and Gas Conference	August 12, 2019	Denver, CO	Jim Kleckner, President and CEO; Bob Howard, EVP and CFO; Craig Walters, EVP and COO;
Seaport Global 2019 Energy & Industrials Conference	August 27, 2019	Chicago, IL	Craig Walters, EVP and COO
Barclays CEO Energy-Power Conference	September 3-5, 2019	New York, NY	Jim Kleckner, President and CEO; Bob Howard, EVP and CFO


•	Second quarter capital expenditures of $171 million including leasehold acquisition costs; second quarter development capital expenditures of $167 million; in the first half of the year, the Company invested approximately 49% of its full-year guided capital midpoint of $635 million


•	Second quarter oil production averaged 29.1 MBbls per day, at the upper end of the Company's guidance


•	Reduced drill, complete and equip ("DC&E") costs to approximately $1,250 per lateral foot in the second quarter, which are on track to meet the Company's full-year 2019 goal of $1,250 per lateral foot


•	Recent Big Tex results from the Wolfcamp A and Woodford formations are showing encouraging initial results



	Three Months Ended June 30, 2019
	Before the Effects of Derivative Settlements			After the Effects of Derivatives Settlements
Oil ($/Bbl)	$	54.98		$	51.70
NGL ($/Bbl)	$	7.15		$	7.15
Gas ($/Mcf)	$	(0.87	)	$	(0.87	)
Boe ($/Boe)	$	42.15		$	39.65


(1)	Contract termination fee relates to the early termination of a frac fleet contract. These amounts are included as a part of Other operating expenses on the Condensed Consolidated Statements of Operations.


(2)	Reflects the weighted-average number of common shares outstanding during the period as adjusted for the dilutive effects of outstanding restricted stock unit and performance stock unit awards.


(3)	Adjusted EBITDAX margin is calculated as Adjusted EBITDAX divided by total production, expressed as adjusted EBITDAX per Boe.