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Jagged Peak Energy Inc. Announces Fourth Quarter and Full-Year 2018 Financial and Operating Results; Provides 2019 Capital, Production, and Cost Guidance

- Production volumes for the fourth quarter of 2018 grew 6% sequentially from the third quarter and averaged 38.4 MBoe per day (29.1 MBbls/d oil); full-year 2018 production averaged 34.2 MBoe per day, a 102% increase from 2017

- Year-end 2018 proved reserves increased by 44% to 118.9 MMBoe (60% proved developed), representing reserve replacement of 393%

- Organic proved developed finding and development costs(1), decreased by 23% from 2017 to $15.55 per Boe in 2018

- 2019 program focuses on Whiskey River and Cochise areas; reduces capital expenditures, retains balance sheet strength, and provides double-digit debt-adjusted production growth in the current price environment

(1) Organic proved developed finding and development costs is a non-GAAP financial measure. Please see the "Non-GAAP Financial Measures" section at the end of this release for a discussion of this metric.

DENVER, Feb. 28, 2019 /PRNewswire/ -- Jagged Peak Energy Inc. (JAG) ("Jagged Peak" or the "Company") today announced financial and operating results for the fourth quarter and full-year ended December 31, 2018.

Jagged Peak Energy Inc. (PRNewsfoto/Jagged Peak Energy Inc.)

Jim Kleckner, President and Chief Executive Officer, commented, "2018 marked another successful year for Jagged Peak, as we firmly delivered on our objective of operational execution. We ended the year with top-tier operating margins, improved average well performance year-over-year, and reduced proved developed finding and development costs, which have resulted in peer-leading return on capital employed. The entire Jagged Peak team was instrumental in achieving each of our 2018 strategic goals, setting the stage for a strong 2019. As we begin the year, the team remains focused on driving additional efficiencies by executing on a 2019 program that contemplates an activity level similar to 2018 with approximately $75 million less in capital expenditures. As we continue to grow our early stage Company, we will strive to consistently provide capital efficient growth, while keeping the balance sheet strong at under two times leverage in a $50/Bbl commodity price environment. By executing on these goals, we believe that we can efficiently get to the size and scale where we can provide organic, sustainable free cash flow to our investors. By continually pressing on capital efficiency, we remain confident in our ability to create shareholder value on our contiguous acreage blocks in the core oil window of the southern Delaware Basin."

Fourth Quarter Results

During the fourth quarter, the Company turned online 9 gross operated wells and reported average daily production of 38.4 MBoe per day, above the high-end of the Company's previously announced guidance range of 36.0 – 38.0 MBoe per day. Oil production for the quarter averaged 29.1 MBbls per day, above the midpoint of the Company's previously announced guidance range of 28.0 – 30.0 MBbls per day. Average daily production in the fourth quarter of 2018, grew sequentially by 6% from the third quarter of 2018, and by 60% from the fourth quarter of 2017. Fourth quarter production mix was comprised of 76% oil, 15% NGLs, and 9% natural gas. Similar to the third quarter of 2018, the Company had increased ethane recovery, which resulted in increased NGL and oil equivalent volumes for the fourth quarter of 2018.

Reported revenue for the fourth quarter of 2018 was $138.5 million, compared to $104.4 million in the fourth quarter of 2017. The increase in revenue in the fourth quarter of 2018 compared to the same period in 2017 was a result of the 60% increase in production volumes, as fourth quarter 2018 average realized prices, before the effects of derivative settlements, were 17% below the fourth quarter of 2017 on a per Boe basis. Average realized prices for the fourth quarter of 2018 are included in the table below.


Three Months Ended December 31, 2018


Before the Effects of
Derivative Settlements


After the Effects of
Derivatives Settlements

Oil ($/Bbl)

$

48.22



$

48.06


NGL ($/Bbl) (1)

$

15.44



$

15.44


Gas ($/Mcf) (1)

$

0.70



$

0.70


Boe ($/Boe)

$

39.18



$

40.06



(1) Due to the adoption of ASC 606 (Revenue Recognition) as of January 1, 2018, the average sales prices are net of gathering and processing expenses ("G&P") of $0.25 per Mcf of natural gas and $5.69 per Bbl of NGLs.

The table below provides a summary of the Company's fourth quarter and full-year 2018 actuals in comparison to its previously provided guidance ranges.


Three Months Ended December 31, 2018


Actual


Guidance (1)

Production




Average daily equivalent production (MBoe/d)

38.4


36.0 – 38.0

Average daily oil production (MBbl/d)

29.1


28.0 – 30.0






Twelve Months Ended December 31, 2018


Actuals


Guidance (1)

Production




Average daily production (MBoe/d)

34.2


33.6 – 34.1

Average daily oil production (MBbl/d)

26.4


26.1 – 26.6





Income Statement




Lease operating expense ($/Boe)

$3.40


$3.25 – $3.75

General and administrative (before equity-based compensation) ($MM)

$39.1


$42 – $44

Production and ad valorem taxes (% of revenue)

6.0%


6.0% – 7.0%





Capital Expenditures




Drilling and completion ($MM)

$690.8


$650 – $680

Infrastructure and other ($MM)

$20.2


$18 – $22

Total development capital ($MM)

$711.0


$668 – $702





Operated Activity




 Gross horizontal wells brought online

45


45 – 47


(1) Guidance as provided in the Company's third quarter earnings and operational update press release on November 8, 2018.

For the fourth quarter of 2018, the Company reported net income of $186.3 million, or $0.87 per diluted common share. Net income for the fourth quarter of 2017 was $12.8 million, or $0.06 per diluted common share. Adjusted net income (a non-GAAP measure) for the fourth quarter of 2018, was $28.2 million, or $0.13 per diluted common share, compared to $20.2 million, or $0.09 per diluted common share for the same period in 2017. 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 fourth quarter of 2018 was $108.6 million, an increase of $30.2 million from the fourth quarter of 2017.

Please reference the reconciliations of these non-GAAP measures to the most directly comparable GAAP measures at the end of this release.

During the fourth quarter, the Company identified a portion of its Big Tex acreage that it does not currently intend to develop before the expiration of its leases. As a result, a non-cash impairment expense of unproved properties was recorded in the amount of $28.1 million.

Capital expenditures for drilling and completion activities were $155.3 million for the three months ended December 31, 2018. Activity during the quarter included drilling and completing 10 gross (9.4 net) wells, of which, 9 gross (8.9 net) wells were operated by Jagged Peak. Additionally, a portion of the capital spent during the fourth quarter relates to 19 gross (18.4 net) operated wells that were in various stages of being drilled or completed at December 31, 2018. Including capital expenditures for infrastructure of $5.7 million and leasehold acquisition costs of $12.1 million, total capital expenditures for the quarter were $173.1 million. The Company's leasehold acquisition costs for the quarter represent additions or extensions of approximately 1,500 net acres, primarily in Whiskey River.  During 2018, the Company added approximately 4,100 net acres to its position.  As of December 31, 2018, the Company had approximately 79,500 net acres, including Big Tex acres that were impaired, but are still leased by the Company, and approximately 5,100 net surface acres.

The table below provides a comparative breakout of the Company's capital expenditures for the periods indicated:

Capital Expenditures for Oil and Gas Activities


Three Months Ended December 31,


Twelve Months Ended December 31,

(in thousands)

2018


2017


2018


2017

Acquisitions








Proved properties

$

2,401



$



$

2,401



$


Unproved properties

9,707



13,120



27,354



70,693


Drilling and completion costs

155,258



168,498



690,848



567,555


Infrastructure costs

5,699



7,703



20,162



28,299


Exploration costs

5



17



29



31


Total oil and gas capital expenditures

$

173,070



$

189,338



$

740,794



$

666,578


Proved Reserves

Proved oil and gas reserves at December 31, 2018 were estimated at 118.9 MMBoe, an increase of 44% from 82.4 MMBoe at December 31, 2017. The composition of the reserves at the end of 2018 were 77% oil, 12% NGL, and 11% natural gas. Proved developed reserves at year-end 2018 increased 89% from year-end 2017 to 71.4 MMBoe, and represent 60% of total proved reserves compared to 40% at year-end 2017. The Company expects its 2019 exit-to-exit aggregate decline for these PDP wells to be approximately 45%, compared to a 49% aggregate decline rate in 2018. All-in proved reserve replacement for 2018 was 393%. As of December 31, 2018, the Company's PV-10 value for proved reserves (a non-GAAP measure) was $1.8 billion, an increase of 100% from the prior year. For 2018, the Company's organic proved developed finding and development ("F&D") costs were $15.55 per Boe, a decrease of 23% from 2017. Organic proved developed F&D costs are defined as the sum of drilling and completion, infrastructure, and exploration costs included in the above table, divided by the sum of proved developed reserves added through extensions, discoveries and other, including infill reserves in an existing proved field, converted to proved developed, and revisions of previous estimates, included in the proved reserve roll-forward table below.

Please reference the reconciliation of the non-GAAP measure, PV-10 to the most directly comparable GAAP measure, Standardized Measure of Discounted Future Net Cash Flows, at the end of this release.

Proved Reserve Roll-Forward


Proved Developed
(MBoe)


Proved Undeveloped
(MBoe)


Total Proved
(MBoe)

Balance December 31, 2017

37,739



44,619



82,358


Acquisitions of reserves

442



187



629


Extensions, discoveries and other, including infill reserves in an existing proved field

6,441



29,255



35,696


Converted to proved developed

26,585



(26,585)




Revisions of previous estimates

12,711



(18)



12,693


Production

(12,486)





(12,486)


Balance December 31, 2018

71,432



47,458



118,890


Jagged Peak's proved reserve estimates as of December 31, 2018, and 2017 were prepared by Ryder Scott Company, L.P. in accordance with the applicable rules of the Securities and Exchange Commission. The reference prices used to determine the reserve quantities and future cash flows were $65.56 per barrel of oil and $3.10 per MMBtu of natural gas. After considering applicable differentials and pricing adjustments, the realized prices were $58.35 per barrel of oil, $34.21 per barrel of NGLs, and $2.23 per Mcf of natural gas.

2019 Capital, Production, and Operating Guidance

The Company's 2019 capital expenditure program is primarily focused on the continued development of the Wolfcamp A formation in Whiskey River and Cochise to further improve F&D cost efficiency and cash flow, resulting in enhanced full-cycle returns on its capital investments. The program contemplates approximately 54 gross (51 net) operated wells and 2 net non-operated wells turned online at a drilling, completion, and equipment ("DC&E") capital cost of approximately $605 million, a significant improvement when compared to the Company's 2018 program, which included 48.0 net wells turned online at a DC&E capital cost of $690.8 million. When planning for 2019, the Company is focusing its efforts on delivering increased capital efficiency to minimize capital outspend and keeping its balance sheet strong. The 2019 program is expected to keep balance sheet leverage under 2.0x debt to EBITDAX in a $50 per barrel WTI environment, while providing ample growth on a year-over-year basis and exit-to-exit basis.

Of the allocated capital for 2019, most of the activity will occur in the Company's Whiskey River and Cochise areas, where it expects to bring online 42 and 7 wells, respectively. In its Big Tex acreage, the Company plans to bring online 5 wells during 2019. Apart from one follow-up Woodford test in Big Tex during the year, the remaining Big Tex program will target the Wolfcamp A formation, and is primarily concentrated in a high-graded fairway of acreage that was identified through recently acquired 3D seismic data. Based on results from these 5 Big Tex wells, the Company will remain flexible in reallocating capital for up to an additional 7 Big Tex wells during the year. The Company is still pursuing various commercial options to assist with Big Tex development, and has recently entered into an agreement to farm-out a portion of its Big Tex area covering 3,200 gross/net acres. The farm-out allows the Company to receive a 25% carried working interest in up to 7 wells, 2 or more of which will be drilled in 2019, in exchange for approximately 2,200 net acres of the Company's western Big Tex acreage.

Like 2018, the Company's 2019 program in Whiskey River will consist of mostly 2-well pads, which provide significant cost efficiencies over single well development. In the second half of the year, the Company plans to begin transitioning to larger scale development of multiple horizons by executing on a 9-well pilot from three adjacent pads in its Cochise area, which are expected to come online in 2020. By moving to these larger development pads, the Company expects to provide optimal development of its acreage from both a capital efficiency and reservoir productivity standpoint.

During 2018, the Company successfully reduced its well costs and improved its average well performance to increase its capital efficiency. The Company expects its 2019 drilling, completion, and equipment costs will show a further increase to capital efficiency by reducing average cost per lateral foot by approximately 15% year over year, to approximately $1,250 per lateral foot. This decrease is driven by a combination of increased operational efficiencies, decreased service costs, and optimized well design.

Due to the timing of pad completions in the fourth quarter of 2018 and the development schedule in 2019, the Company expects its first quarter 2019 production to decline slightly from its fourth quarter levels, pushing most of the Company's expected 2019 production growth into the second and fourth quarters. The Company expects to exit 2019 with fourth quarter production averaging 32.5 - 36.5 Bbls per day per day of oil (43 - 47 MBoe per day), providing oil production growth of approximately 19% from fourth quarter 2018 to fourth quarter 2019.

The table below provides a summary of the Company's production, capital expenditure and operating guidance for 2019.


Guidance for the Three Months Ended
March 31, 2019

Production


Average daily equivalent production (MBoe/d)

36.5 – 37.9

Average daily oil production (MBbl/d)

27.5 – 28.9




Guidance for the Twelve Months Ended
December 31, 2019

Production


Average daily equivalent production (MBoe/d)

38.3 – 41.3

Average daily oil production (MBbl/d)

29.2 – 31.2



Income Statement


Lease operating expense ($/Boe)

$3.65 – $4.15

General and administrative (before equity-based compensation) ($MM)

$46 – $50

Production and ad valorem taxes (% of revenue)

6.0% – 7.0%



Capital Expenditures


Drilling and completion ($MM) (1)

$580 – $630

Infrastructure and other ($MM)

$25 – $35

Total development capital ($MM)

$605 – $665



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

2.0


(1) Includes pad-level infrastructure and equipment

Financial Update

At the end of the fourth quarter, the Company had an undrawn revolving credit facility with elected commitments of $540 million, and $35.2 million of cash on the balance sheet, resulting in total liquidity of $575.2 million. The Company's borrowing base at December 31, 2018 was $900 million. Net debt to adjusted EBITDAX (a non-GAAP measure) was 1.1x on an annualized basis. Please reference the reconciliation of this non-GAAP measure to the most directly comparable GAAP measures at the end of this release.

Conference Call

Jagged Peak will host a conference call and webcast to discuss its fourth quarter and full-year 2018 financial and operating results, and 2019 guidance on March 1, 2019 at 9:00 am MST (11:00 am EST). The call will be webcast and accessible via the Investor Relations section of the Company's website at www.jaggedpeakenergy.com. To join the live, interactive call, please dial 1-877-823-8605 (international callers, dial 1-647-689-5644) with the conference ID 8268275. A telephone replay will be available from 12:00 noon MST (2:00 pm EST) on March 1, 2019 through March 15, 2019 at 10:00 pm MST (12:00 midnight EST). To access the replay, dial 1-800-585-8367 (international callers dial, 1-416-621-4642) and enter conference ID 8268275. A live broadcast of the earnings conference call will also be available via the Company's website at www.jaggedpeakenergy.com under the "Investor Relations" section of the site. A replay will also be available on the website approximately two hours after the conference call. The presentation material for this conference call will also be available on the Company's website.

Upcoming Investor Events

The Company will be participating in the Scotia Howard Weil 47th Annual Energy Conference in New Orleans, LA on March 25 - 27, 2019. The Company's President and CEO, Jim Kleckner, will be presenting and hosting 1-on-1 meetings.

Forward Looking Statements

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 "2019 Capital, Production, and Operating Guidance"; securing partners to develop Big Tex acreage; the decrease in well costs and increased capital efficiency, the timing of the program, and its ultimate impact on well performance; expected capital expenditures and expected production. 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.

Non-GAAP Financial Measures

Adjusted EBITDAX

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, gains or losses on sales of assets, and net gains or losses on derivatives less net cash from 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

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 items, such as certain equity-based compensation 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.

Net Debt to Adjusted EBITDAX

Net debt to adjusted EBITDAX is a non-GAAP measure, which is defined as the face value of the Company's long-term debt, including its senior unsecured notes and amounts drawn on its credit facility, less cash and cash equivalents at quarter end, divided by the Company's quarterly annualized adjusted EBITDAX, as defined above.

PV-10

PV-10 is a non-GAAP metric, which is derived from the Standardized Measure of Discounted Future Net Cash Flows, the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of Jagged Peak's reserves to other companies. Management uses this measure along with other measures when assessing the potential return on investment related to oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. PV-10 and the Standardized Measure of oil and gas do not purport to present the fair value of the Company's proved oil and natural gas reserves.

Organic Proved Developed Finding and Development Costs

Organic proved developed finding and development ("F&D") costs is a financial measure that is used by management to assess the relative amount of development capital needed to develop one barrel of oil equivalent reserves. This measure is defined as the sum of drilling and completion, infrastructure, and exploration costs included in the Company's "Capital Expenditures for Oil and Gas Activities" table contained in this release, divided by the sum of proved developed reserves added through extensions, discoveries and other, including infill reserves in an existing proved field, converted to proved developed, and revisions of previous estimates, included in the "Proved Reserve Roll-Forward" table contained in this release. The method the Company uses to calculate its organic proved developed F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, the Company's organic proved developed F&D costs may not be comparable to similar measures provided by other companies.

This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP in the Company's 2018 10-K. Due to various factors, including timing differences in the addition of proved reserves and the related costs to develop those reserves, organic proved developed F&D costs does not precisely reflect the costs associated with particular proved reserves. As a result of various factors that could materially affect the timing and amounts of future increases in proved developed reserves and the timing and amounts of future costs, we cannot assure you that our future organic proved developed F&D costs will not differ materially from those presented.

About Jagged Peak Energy Inc.

Jagged Peak Energy Inc. is an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves in the southern Delaware Basin, a sub-basin of the Permian Basin of West Texas.

Jagged Peak Energy Inc.

Selected Operating Highlights

(Unaudited)










Three Months Ended


Twelve Months Ended


December 31,


December 31,


2018


2017


2018


2017









Production volumes:








Oil (MBbls)

2,673



1,771



9,620



4,979


Natural gas (MMcf)

1,968



1,377



7,992



3,601


NGLs (MBbls)

533



211



1,534



617


Total (MBoe)

3,534



2,211



12,486



6,196


Average daily production volumes:








Oil (Bbls/d)

29,050



19,250



26,355



13,640


Natural gas (Mcf/d)

21,387



14,964



21,897



9,865


NGLs (Bbls/d)

5,799



2,293



4,203



1,690


Total (Boe/d)

38,413



24,037



34,207



16,974










Average Sales Prices (excluding realized hedge settlements and including G&P Deduction):(1)

Oil (per Bbl)

$

48.22



$

53.10



$

56.12



$

48.56


Natural gas (per Mcf)

$

0.70



$

2.45



$

1.14



$

2.52


NGLs (per Bbl)

$

15.44



$

30.96



$

20.83



$

25.25


Combined (per Boe)

$

39.18



$

47.00



$

46.52



$

43.00










Average Sales Prices (including realized hedge settlements and G&P Deduction):(1)

Oil (per Bbl)

$

48.06



$

49.54



$

52.57



$

48.04


Natural gas (per Mcf)

$

0.70



$

2.45



$

1.14



$

2.52


NGLs (per Bbl)

$

15.44



$

30.96



$

20.83



$

25.25


Combined (per Boe)

$

40.06



$

44.15



$

43.79



$

42.58










Average Operating Costs (per Boe):








Lease operating expenses

$

3.12



$

3.25



$

3.40



$

2.88


Gathering and processing expenses

$



$

0.91



$



$

0.71


Production and ad valorem tax expenses

$

2.32



$

2.35



$

2.77



$

2.60


Depletion, depreciation, amortization and accretion

$

17.49



$

19.82



$

17.81



$

17.92


General and administrative expense (before equity-based compensation expense)

$

2.92



$

2.36



$

3.13



$

3.73



(1) Due to the adoption of ASC 606 (Revenue Recognition) as of January 1, 2018, the average sales prices for the three and twelve months ended December 31, 2018 are net of gathering and processing expenses ("G&P") of $0.25 and $0.44 per Mcf of natural gas and $5.69 and $7.33 per Bbl of NGLs, respectively. This standard affects comparability between 2017 and 2018 for revenues, average sales prices and G&P expenses but does not impact net income.

 

Jagged Peak Energy Inc.

Condensed Consolidated and Combined Balance Sheets

(Unaudited)













December 31, 2018


December 31, 2017






(in thousands)

Assets:





Cash and cash equivalents

$

35,229



$

9,523



Other current assets

165,905



51,540



Property and equipment, net

1,530,285



1,038,947



Other noncurrent assets

35,722



3,418



Total assets

$

1,767,141



$

1,103,428







Liabilities and Stockholders' Equity:





Current liabilities

$

187,982



$

174,475



Long-term debt

489,239



155,000



Deferred income taxes

124,418



57,943



Other long-term liabilities

17,552



16,665



Stockholders' equity

947,950



699,345



Total liabilities and stockholders' equity

$

1,767,141



$

1,103,428


 

Jagged Peak Energy Inc.

Condensed Consolidated and Combined Statements of Operations

(Unaudited)










Three Months Ended


Twelve Months Ended


December 31,


December 31,


2018


2017


2018


2017










(in thousands, except per share amounts)

Revenues








Oil, natural gas and NGL sales

$

138,473



$

103,948



$

580,894



$

266,424


Other operating revenues

64



474



750



888


Total revenues

138,537



104,422



581,644



267,312


Operating Expenses








Lease operating expenses

11,016



7,190



42,406



17,874


Gathering and processing expenses



2,020





4,424


Production and ad valorem taxes

8,205



5,204



34,642



16,120


Exploration

5



17



29



31


Depletion, depreciation, amortization and accretion

61,803



43,825



222,355



111,049


Impairment of unproved oil and natural gas properties

28,145



8



28,198



373


Other operating expenses

(2)



24



63



247


General and administrative (before equity-based compensation)

10,326



5,229



39,126



23,091


General and administrative, equity-based compensation

2,675



11,334



83,346



442,976


Total operating expenses

122,173



74,851



450,165



616,185


Income (Loss) from Operations

16,364



29,571



131,479



(348,873)


Other Income and Expense








Gain (loss) on commodity derivatives

229,764



(58,537)



119,338



(42,615)


Gain on sale of assets





6,225




Interest expense and other

(8,044)



(1,367)



(25,109)



(2,503)


Total other income (loss)

221,720



(59,904)



100,454



(45,118)


Income (Loss) before Income Taxes

238,084



(30,333)



231,933



(393,991)


Income tax expense (benefit)

51,738



(43,096)



66,475



57,943


Net Income (Loss)

$

186,346



$

12,763



$

165,458



$

(451,934)










Net Income (Loss) attributable to Jagged Peak Energy LLC (predecessor)

$



$



$



$

(375,476)


Net Income (Loss) attributable to Jagged Peak Energy Inc. Stockholders

186,346



12,763



165,458



(76,458)


Net Income (Loss)

$

186,346



$

12,763



$

165,458



$

(451,934)










Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share:








Basic

$

0.87



$

0.06



$

0.78



$

(0.36)


Diluted

$

0.87



$

0.06



$

0.78



$

(0.36)










Weighted-average common shares outstanding:








Basic

213,186



212,931



213,128



212,932


Diluted

213,464



213,553



213,203



212,932


 

Jagged Peak Energy Inc.

Consolidated and Combined Statements of Cash Flows

(Unaudited)










Three Months Ended


Twelve Months Ended


December 31,


December 31,


2018


2017


2018


2017










(in thousands)

Cash Flows from Operating Activities








Net income (loss)

$

186,346



$

12,763



$

165,458



$

(451,934)


Adjustments to reconcile to net cash provided by operating activities:








Depletion, depreciation, amortization and accretion

61,803



43,825



222,355



111,049


Impairment of unproved oil and natural gas properties

28,145



8



28,198



373


Amortization of debt issuance costs

587



199



2,340



606


Deferred income taxes

51,738



(43,096)



66,475



57,943


Equity-based compensation

2,675



11,334



83,346



442,976


(Gain) Loss on commodity derivatives

(229,764)



58,537



(119,338)



42,615


Net cash receipts (payments) on settled derivatives

(429)



(6,309)



(34,134)



(2,618)


(Gain) on sale of oil and natural gas properties





(6,225)




Other

(80)



1,005



(314)



882


Change in operating assets and liabilities:








Accounts receivable and other current assets

18,581



(13,150)



(11,273)



(40,442)


Other assets







(3)


Accounts payable and accrued liabilities

(9,693)



8,327



30,768



17,424


Net cash provided by operating activities

109,909



73,443



427,656



178,871


Cash Flows from Investing Activities








Leasehold and acquisitions costs

(10,817)



(12,865)



(29,671)



(73,492)


Development of oil and natural gas properties

(155,630)



(174,383)



(706,689)



(523,559)


Other capital expenditures

(1,991)



349



(5,236)



(2,983)


Proceeds from sale of oil and natural gas properties





8,377




Net cash used in investing activities

(168,438)



(186,899)



(733,219)



(600,034)


Cash Flows from Financing Activities








Proceeds from senior notes





500,000




Proceeds from senior secured revolving credit facility



120,000



165,000



165,000


Repayment of senior secured revolving credit facility





(320,000)



(142,000)


Debt issuance costs

(181)



(921)



(13,531)



(2,362)


Proceeds from issuance of common stock in IPO, net of underwriting fees







401,625


Costs related to initial public offering







(3,216)


Employee tax withholding for settlement of equity compensation awards





(200)



(88)


Net cash provided by financing activities

(181)



119,079



331,269



418,959


Net Change in Cash and Cash Equivalents

(58,710)



5,623



25,706



(2,204)


Cash and Cash Equivalents, Beginning of Period

93,939



3,900



9,523



11,727


Cash and Cash Equivalents, End of Period

$

35,229



$

9,523



$

35,229



$

9,523


 

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 February 28, 2019, the Company had the following commodity hedges in place for future production:





Production Period

Volumes


Weighted Average
Price


(Bbls)


($/Bbl)

Oil Swaps:




First Quarter 2019

1,890,000



$

59.95


Second Quarter 2019

1,911,000



$

59.95


Third Quarter 2019

1,932,000



$

59.95


Fourth Quarter 2019

1,932,000



$

59.95


Full Year 2019

7,665,000



$

59.95


Full Year 2020

2,928,000



$

60.82






Oil Basis Swaps:




First Quarter 2019

2,070,000



$

(7.17)


Second Quarter 2019

2,093,000



$

(7.17)


Third Quarter 2019

2,300,000



$

(4.79)


Fourth Quarter 2019

2,300,000



$

(4.79)


Full Year 2019

8,763,000



$

(5.92)


Full Year 2020

9,516,000



$

(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


Twelve Months Ended


December 31,


December 31,


2018


2017


2018


2017










(in thousands, except for per share and Boe metrics)

Adjusted Net Income (Loss)





Net income (loss)

$

186,346



$

12,763



$

165,458



$

(451,934)


Adjustments to reconcile to adjusted net income








Impairment of unproved oil and natural gas properties

28,145



8



28,198



373


(Gain) loss on commodity derivatives, net, less net cash from derivative settlements

(230,193)



52,228



(153,472)



39,997


Equity-based compensation expense related to allocated management incentive units (1)



9,435



74,470



438,401


Gain on sale of assets





(6,225)




Deferred income tax expense recorded in connection with the Company's initial public offering



1,598





80,704


Income tax effect for the above items

43,907



(18,527)



28,529



(14,347)


Impact of reduction in Federal statutory rate



(37,282)





(37,282)


Adjusted net income

$

28,205



$

20,223



$

136,958



$

55,912










Adjusted net income per basic common share

$

0.13



$

0.09



$

0.64



$

0.26


Adjusted net income per diluted common share

$

0.13



$

0.09



$

0.64



$

0.26










Basic common shares

213,186



212,931



213,128



212,932


Diluted common shares

213,464



213,552



213,203



212,979










Adjusted EBITDAX








Net income (loss)

$

186,346



$

12,763



$

165,458



$

(451,934)


Adjustments to reconcile to adjusted EBITDAX








Interest expense, net of capitalized

8,057



1,251



25,152



2,861


Income tax expense (benefit)

51,738



(43,096)



66,475



57,943


Depletion, depreciation, amortization and accretion

61,803



43,825



222,355



111,049


Impairment of unproved oil and natural gas properties

28,145



8



28,198



373


Exploration expenses

5



17



29



31


(Gain) loss on commodity derivatives, net, less net cash from derivative settlements

(230,193)



52,228



(153,472)



39,997


Equity-based compensation expense (2)

2,675



11,334



83,346



442,976


Gain on sale of assets





(6,225)




Adjusted EBITDAX

$

108,576



$

78,330



$

431,316



$

203,296










Total production (MBoe)

3,534



2,211



12,486



6,196


Adjusted EBITDAX margin per Boe (3)

$

30.72



$

35.43



$

34.54



$

32.81



(1) In connection with the IPO, management incentive units were converted to common stock. A portion of this common stock was transferred to JPE Management Holdings LLC and became subject to the terms and conditions of the amended and restated JPE Management Holdings LLC limited liability company agreement (the "Holdco Agreement"). The compensation expense related to these shares was primarily recognized ratably as they vested according to the terms of the Holdco Agreement. However, in February 2018, the Company incurred $71.3 million in accelerated compensation expense related to the modification of service requirements. Only compensation expense related to management incentive units allocated at the time of the IPO is excluded from the calculation of adjusted net income.

(2) Equity-based compensation expense for the twelve months ended December 31, 2018 includes $74.5 million related to management incentive units that converted to common stock in connection with the IPO and $8.9 million related to equity awards issued under the Company's long-term incentive plan.

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

 

Jagged Peak Energy Inc.

Reconciliation of GAAP Standardized Measure of Discounted Future Net Cash Flows to non-GAAP PV-10

(Unaudited)



The following table provides a reconciliation of the GAAP financial measure of Standardized measure of discounted future net cash flows to the non-GAAP financial measure of PV-10. A description of the reconciliations is included in the section titled "Reconciliation of Non-GAAP Financial Measures."



Standardized measure of discounted future net cash flows

$

1,543,268


Present value of future income taxes discounted at 10%

288,867


PV-10

$

1,832,135



 Note: In accordance with the applicable rules of the Securities and Exchange Commission, the reference prices used to determine the reserve quantities and future cash flows were $65.56 per barrel of oil and $3.10 per MMBtu of natural gas. After considering applicable differentials and pricing adjustments, the realized prices were $58.35 per barrel of oil, $34.21 per barrel of NGLs, and $2.23 per Mcf of natural gas.

 

Cision

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