DENVER, Nov. 8, 2018 /PRNewswire/ — Jagged Peak Energy Inc. (NYSE: JAG) (“Jagged Peak” or the “Company”) today announced financial and operating results for the third quarter ended September 30, 2018.

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

Jim Kleckner, President and Chief Executive Officer, commented, “The first three quarters of 2018 have been laser focused on operational execution and the Jagged Peak team has delivered on that execution, with three consecutive quarters meeting or beating expectations. As we develop this top-tier acreage position in the southern Delaware, well performance continues to exceed expectations and our operational teams continue to enhance our drilling and completion efficiencies, resulting in better program returns and return on capital employed. Our 2019 planning cycle is underway and we plan to announce our 2019 budget in our fourth quarter earnings release. In that planning process, we are focused on creating a program that provides strong economic returns and capital efficiency, all while providing robust cash flow growth and maintaining a strong balance sheet. To help achieve these goals, we are actively seeking partners to develop a portion of our Big Tex acreage, which will allow for a greater portion of our capital to be allocated to the full-field development of our Whiskey River and Cochise project areas.”

Operations Update

The Company reported record production for the third quarter of 2018, with average daily production rates exceeding the top-end of the Company’s guidance range. Production outperformance for the quarter was attributed to better than expected production from the wells brought online in 2018. The Company continues to see improvements in its well results with its 2018 program exceeding its 2017 program and its 1.2 MMBOE type curve, on average.

The Company recently entered into a firm transportation and sales agreement with Trafigura Trading LLC, that will link a portion of its future production to a waterborne pricing hub, MEH. By diversifying the pricing points to which its produced oil is linked, the Company will further mitigate its risk to pricing differentials. The new firm transportation and sales agreement will link 30.0 MBbls per day of gross production to MEH pricing over a five-year period starting at the commencement of the Cactus II pipeline, which is expected to be in operation in the second half of 2019. The Company has also extended its current oil sales agreement through 2020. The extension of this agreement along with the firm transportation and sales agreement provides flow assurance for all the Company’s piped oil production through 2020.

The Company has received fully processed 3D seismic data for both its Cochise and Whiskey River drilling programs, where it is assisting in geosteering, resulting in more optimally placed laterals, more efficient completions, and ultimately better well results. In its Big Tex area, the Company recently received fast-track 3D seismic data, and is expected to receive the fully processed data by year-end.

The Company continues to focus its efforts on increasing operational efficiencies through increased lateral footage drilled and completed per day. During the quarter, the Company increased its average completed footage per crew per day to 623 feet, an increase of approximately 30% from the 2017 average, and achieved a Company record of over 1,000 lateral feet completed per day on a two-well zipper pad. The Company’s drilling efficiencies continue to increase, with the average drilled footage per day increasing by approximately 10% from 2017. Beginning in the fourth quarter of 2018, the Company began to upgrade its rig fleet to higher spec rigs, which are expected to further improve drilling efficiencies.

Third Quarter Results

During the third quarter, the Company reported average daily production of 36.1 MBoe per day, 6% above the midpoint of the Company’s guidance range of 33.0 – 35.0 MBoe/d. Oil production for the quarter averaged 27.5 MBbls per day. The better than expected production growth in the quarter is primarily attributed to the continued strong well performance from wells brought online, many of which are showing lower decline rates than expected. Average daily production in the third quarter of 2018, grew sequentially by 5% from the second quarter, and by 88% from the third quarter of 2017. Third quarter production mix was comprised of 76% oil, 11% natural gas, and 13% NGLs. Changes to the Company’s product mix were largely driven by increased ethane recovery in the field, which resulted in increased NGL volumes for the quarter.

Reported revenue for the third quarter of 2018 was $155.4 million, compared to $70.5 million in the third quarter of 2017. The increase in revenue in the third quarter of 2018 compared to the same period in 2017 was a result of increased production volumes and commodity prices. Realized prices for the third quarter of 2018 are included in the table below.

Three Months Ended September 30, 2018

Before the Effects of
Derivatives

After the Effects of
Derivatives

Oil ($/Bbl)

$

55.95

$

53.45

NGL ($/Bbl) (1)

$

24.81

$

24.81

Gas ($/Mcf) (1)

$

1.19

$

1.19

Boe ($/Boe)

$

46.64

$

44.73

(1) Due to the adoption of ASC 606 (Revenue Recognition) as of January 1, 2018, the average sales prices include gathering and processing expenses (“G&P”) of $0.52 per Mcf of natural gas and $8.27 per Bbl of NGLs.

The table below provides a summary of the Company’s third quarter and year-to-date actuals in comparison to its previously provided guidance ranges.

Three Months Ended September 30, 2018

Actual

Previous Guidance (1)

Production

Average daily equivalent production (MBoe/d)

36.1

33.0 – 35.0

Average daily oil production (MBbls/d)

27.5

25.5 – 27.5

Nine Months Ended
September 30, 2018

Previous Full-Year

Actuals

2018 Guidance (1)

Production

Average daily production (MBoe/d)

32.8

32.0 – 34.0

Average daily oil production (MBbls/d)

25.4

25.0 – 27.0

Income Statement

Lease operating expense ($/Boe)

$3.51

$3.25 – $4.00

General and administrative (before equity-based compensation)

$28.8

$44 – $46

Production and ad valorem taxes (% of revenue)

6.0%

6.5% – 7.5%

Capital Expenditures

Drilling and completion ($MM)

$535.6

$650 – $680

Infrastructure and other ($MM)

$14.5

$18 – $22

Total development capital ($MM)

$550.1

$668 – $702

Operated Activity

 Gross horizontal wells brought online

36

45 – 47

(1) Guidance as provided in the Company’s second quarter earnings and operational update press release on August 9, 2018.

For the third quarter of 2018, the Company reported a net loss of $26.6 million, or $0.12 per diluted common share. Net loss for the third quarter of 2017 was $15.2 million, or $0.07 per diluted common share. Adjusted net income, (a non-GAAP measure) for the third quarter of 2018, was $39.3 million or $0.18 per diluted common share, compared to $15.4 million, or $0.07 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 third quarter of 2018 was $118.6 million, an increase of $62.1 million from the third 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.

Capital expenditures for drilling and completion activities were $151.8 million for the three months ended September 30, 2018. Activity during the quarter included drilling and completing 11 gross (9.9 net) wells, of which, 10 gross (9.8 net) wells were operated by Jagged Peak. Additionally, a portion of the capital spent during the third quarter relates to 11 gross (10.9 net) operated wells that were in various stages of being drilled or completed at September 30, 2018. Including capital expenditures for infrastructure of $6.7 million and leasehold acquisition costs of $6.3 million, total capital expenditures for the quarter were $164.8 million. The Company’s leasehold acquisition costs for the quarter represent the addition or extension of approximately 5,700 net acres to its leasehold position, primarily in its Whiskey River area. As of September 30, 2018, the Company had approximately 78,900 net acres.

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

Three Months Ended September 30,

Nine Months Ended September 30,

2018

2017

2018

2017

(in thousands)

Capital Expenditures for Oil and Gas Activities

Acquisitions

Proved properties

$

$

$

$

Unproved properties

6,321

7,845

17,647

56,364

Drilling and completion costs

151,797

158,870

535,590

399,057

Infrastructure costs

6,693

3,613

14,463

21,805

Exploration costs

23

6

24

14

Total oil and gas capital expenditures

$

164,834

$

170,334

$

567,724

$

477,240

Updated 2018 Production, and Operating Guidance

The Company is providing updated guidance for fourth quarter and full-year 2018. Changes from the previously provided guidance include, increasing its fourth quarter and full-year production guidance, and reducing its full-year operating cost metrics. The Company is reiterating its full-year capital program and activity counts, indicating improved capital efficiency over the originally provided guidance. The table below provides a summary of the Company’s updated guidance.

Guidance for the Three
Months Ended

December 31, 2018

Production

Average daily equivalent production (MBoe/d)

36.0 – 38.0

Average daily oil production (MBbls/d)

28.0 – 30.0

Revised Guidance for the
Twelve Months Ended
December 31, 2018

Previous Guidance(1) for the
Twelve Months Ended

 December 31, 2018

Production

Average daily equivalent production (MBoe/d)

33.6 – 34.1

32.0 – 34.0

Average daily oil production (MBbls/d)

26.1 – 26.6

25.0 – 27.0

Income Statement

Lease operating expense ($/Boe)

$3.25 – $3.75

$3.25 – $4.00

General and administrative (before equity-based compensation)

$42 – $44

$44 – $46

Production and ad valorem taxes (% of revenue)

6.0% – 7.0%

6.5% – 7.5%

Capital Expenditures

Drilling and completion ($MM) (2)

$650 – $680

$650 – $680

Infrastructure and other ($MM)

$18 – $22

$18 – $22

Total development capital ($MM)

$668 – $702

$668 – $702

Operated Activity

Gross horizontal wells brought online

45 – 47

45 – 47

Average working interest

~95%

~95%

Average lateral length per well

~9,000′

~9,000′

Non-operated Activity

Gross horizontal wells brought online

13 – 14

13 – 14

Average working interest

~35%

~35%

(1) Guidance as provided in the Company’s second quarter earnings and operational update press release on August 9, 2018.

(2) Includes ~$7 million of geological and geophysical costs.

Financial Update

At the end of the third quarter, the Company had an undrawn revolving credit facility with elected commitments of $540.0 million, and $93.9 million of cash on the balance sheet, resulting in total liquidity of $633.9 million. Net debt to adjusted EBITDAX (a non-GAAP measure) was 0.9x 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.

On November 7, 2018, the Company completed a borrowing base redetermination for its revolving credit facility. The Company’s borrowing base was increased to $900.0 million, up from the previous redetermination of $825.0 million, on August 9, 2018. As part of the November redetermination, the Company elected to keep its current commitments at $540.0 million.

Conference Call

Jagged Peak will host a conference call and webcast to discuss its third quarter 2018 financial and operating results on Friday, November 9, 2018 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 1-855-327-6838 ten minutes before the scheduled start time (international callers, dial 1-604-235-2082). A telephone replay will be available from 12:00 noon MST (2:00 pm EST) on November 9, 2018 through November 9, 2019 at 10:00 pm MST (12:00 midnight EST). To access the replay, dial 1-844-512-2921 (international callers dial, 1-412-317-6671) and enter confirmation code 10005776. 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 Capital One Securities 13th Annual Energy Conference on December 6, 2018 in New Orleans, LA. The Company’s EVP and COO, Craig Walters 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 “Updated 2018 Production, and Operating Guidance”; the expected commencement of the Cactus II pipeline; securing partners to develop Big Tex acreage; the decrease in cycle times resulting from the Company upgrading its rig fleet to higher spec rigs; planned 3D seismic program, 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 2017 Annual Report on Form 10-K and in “Item 8.01, Other Events” of Jagged Peak’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 23, 2018, 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.

Reconciliation of 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.

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

Nine Months Ended

September 30,

September 30,

2018

2017

2018

2017

Production volumes:

Oil (MBbls)

2,531

1,383

6,947

3,208

Natural gas (MMcf)

2,139

1,136

6,025

2,224

NGLs (MBbls)

436

192

1,001

406

Total (MBoe)

3,323

1,765

8,952

3,984

Average daily production volumes:

Oil (Bbls/d)

27,507

15,036

25,447

11,750

Natural gas (Mcf/d)

23,245

12,346

22,069

8,147

NGLs (Bbls/d)

4,738

2,087

3,665

1,486

Total (Boe/d)

36,118

19,180

32,790

14,594

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

Oil (per Bbl)

$

55.95

$

45.24

$

59.15

$

46.06

Natural gas (per Mcf)

$

1.19

$

2.59

$

1.29

$

2.56

NGLs (per Bbl)

$

24.81

$

25.31

$

23.71

$

22.28

Combined (per Boe)

$

46.64

$

39.89

$

49.42

$

40.78

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

Oil (per Bbl)

$

53.45

$

47.55

$

54.30

$

47.21

Natural gas (per Mcf)

$

1.19

$

2.59

$

1.29

$

2.56

NGLs (per Bbl)

$

24.81

$

25.31

$

23.71

$

22.28

Combined (per Boe)

$

44.73

$

41.70

$

45.66

$

41.71

Average Operating Costs (per Boe):

Lease operating expenses

$

3.37

$

2.94

$

3.51

$

2.68

Gathering and processing expenses

$

$

0.77

$

$

0.60

Production and ad valorem tax expenses

$

2.86

$

2.69

$

2.95

$

2.74

Depletion, depreciation, amortization and accretion

$

17.35

$

17.48

$

17.93

$

16.87

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

$

2.92

$

3.30

$

3.22

$

4.48

(1) Due to the adoption of ASC 606 (Revenue Recognition) as of January 1, 2018, the average sales prices for the three and nine months ended September 30, 2018 include gathering and processing expenses (“G&P”) of $0.52 and $0.49 per Mcf of natural gas and $8.27 and $8.20 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)

September 30, 2018

December 31, 2017

(in thousands)

Assets:

Cash and cash equivalents

$

93,939

$

9,523

Other current assets

101,385

51,540

Property and equipment, net

1,445,380

1,038,947

Other noncurrent assets

4,681

3,418

Total assets

$

1,645,385

$

1,103,428

Liabilities and Stockholders’ Equity:

Current liabilities

$

273,063

$

174,475

Long-term debt

488,972

155,000

Deferred income taxes

72,680

57,943

Other long-term liabilities

51,741

16,665

Stockholders’ equity

758,929

699,345

Total liabilities and stockholders’ equity

$

1,645,385

$

1,103,428

 

Jagged Peak Energy Inc.

Condensed Consolidated and Combined Statements of Operations

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2018

2017

2018

2017

(in thousands, except per share amounts)

Revenues

Oil, natural gas and NGL sales

$

154,964

$

70,384

$

442,421

$

162,476

Other operating revenues

414

67

686

414

Total revenues

155,378

70,451

443,107

162,890

Operating Expenses

Lease operating expenses

11,184

5,184

31,390

10,684

Gathering and processing expenses

1,357

2,404

Production and ad valorem taxes

9,517

4,739

26,437

10,916

Exploration

23

6

24

14

Depletion, depreciation, amortization and accretion

57,660

30,851

160,552

67,224

Impairment of unproved oil and natural gas properties

257

53

365

Other operating expenses

19

41

65

223

General and administrative (before equity-based compensation)

9,707

5,830

28,800

17,862

General and administrative, equity-based compensation

2,614

11,903

80,671

431,642

Total operating expenses

90,724

60,168

327,992

541,334

Income (Loss) from Operations

64,654

10,283

115,115

(378,444)

Other Income and Expense

Gain (loss) on commodity derivatives

(96,516)

(27,693)

(110,426)

15,922

Gain on sale of assets

6,225

6,225

Interest expense and other

(8,244)

(407)

(17,065)

(1,136)

Total other income (loss)

(98,535)

(28,100)

(121,266)

14,786

Income (Loss) before Income Taxes

(33,881)

(17,817)

(6,151)

(363,658)

Income tax expense (benefit)

(7,315)

(2,598)

14,737

101,039

Net Income (Loss)

$

(26,566)

$

(15,219)

$

(20,888)

$

(464,697)

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

$

$

$

$

(375,476)

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

(26,566)

(15,219)

(20,888)

(89,221)

Net Income (Loss)

$

(26,566)

$

(15,219)

$

(20,888)

$

(464,697)

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

Basic

$

(0.12)

$

(0.07)

$

(0.10)

$

(0.42)

Diluted

$

(0.12)

$

(0.07)

$

(0.10)

$

(0.42)

Weighted-average common shares outstanding:

Basic

213,180

212,931

213,109

212,933

Diluted

213,180

212,931

213,109

212,933

 

Jagged Peak Energy Inc.

Consolidated and Combined Statements of Cash Flows

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2018

2017

2018

2017

(in thousands)

Cash Flows from Operating Activities

Net income (loss)

$

(26,566)

$

(15,219)

$

(20,888)

$

(464,697)

Adjustments to reconcile to net cash provided by operating activities:

Depletion, depreciation, amortization and accretion

57,660

30,851

160,552

67,224

Impairment of unproved oil and natural gas properties

257

53

365

Amortization of debt issuance costs

732

147

1,753

407

Deferred income taxes

(7,315)

(2,598)

14,737

101,039

Equity-based compensation

2,614

11,903

80,671

431,642

(Gain) Loss on commodity derivatives

96,516

27,693

110,426

(15,922)

Net cash receipts (payments) on settled derivatives

(6,347)

3,195

(33,705)

3,691

(Gain) on sale of assets

(6,225)

(6,225)

Other

(78)

(40)

(234)

(123)

Change in operating assets and liabilities:

Accounts receivable and other current assets

(11,305)

(18,582)

(29,854)

(27,292)

Other assets

116

(3)

Accounts payable and accrued liabilities

18,247

7,700

40,461

9,097

Net cash provided by operating activities

117,933

45,423

317,747

105,428

Cash Flows from Investing Activities

Leasehold and acquisitions costs

(7,801)

(7,659)

(18,854)

(60,627)

Development of oil and natural gas properties

(158,091)

(153,964)

(551,059)

(349,176)

Other capital expenditures

(1,364)

(1,876)

(3,245)

(3,332)

Proceeds from sale of oil and natural gas properties

8,377

8,377

Net cash used in investing activities

(158,879)

(163,499)

(564,781)

(413,135)

Cash Flows from Financing Activities

Proceeds from senior notes

500,000

Proceeds from senior secured revolving credit facility

35,000

165,000

45,000

Repayment of senior secured revolving credit facility

(320,000)

(142,000)

Debt issuance costs

(607)

(20)

(13,350)

(1,441)

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

(607)

34,980

331,450

299,880

Net Change in Cash and Cash Equivalents

(41,553)

(83,096)

84,416

(7,827)

Cash and Cash Equivalents, Beginning of Period

135,492

86,996

9,523

11,727

Cash and Cash Equivalents, End of Period

$

93,939

$

3,900

$

93,939

$

3,900

 

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 November 2, 2018, the Company had the following commodity hedges in place for future production:

Production Period

Volumes

Weighted Average
Price

(Bbls)

($/Bbl)

Oil Swaps:

Fourth Quarter 2018

1,789,400

$

55.66

Full Year 2019

7,665,000

$

59.95

Full Year 2020

2,928,000

$

60.82

Oil Basis Swaps:

Fourth Quarter 2018

1,610,000

$

(2.27)

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

Nine Months Ended

September 30,

September 30,

2018

2017

2018

2017

(in thousands)

Adjusted Net Income (Loss)

Net income (loss)

$

(26,566)

$

(15,219)

$

(20,888)

$

(464,697)

Adjustments to reconcile to adjusted net income

Impairment of unproved oil and natural gas properties

257

53

365

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

90,169

30,888

76,721

(12,231)

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

10,489

74,470

428,966

Gain on sale of assets

(6,225)

(6,225)

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

79,106

Income tax effect for the above items

(18,124)

(11,042)

(15,218)

4,214

Adjusted net income (loss)

$

39,254

$

15,373

$

108,913

$

35,723

Adjusted net income (loss) per basic common share

$

0.18

$

0.07

$

0.51

$

0.17

Adjusted net income (loss) per diluted common share

$

0.18

$

0.07

$

0.51

$

0.17

Basic common shares

213,180

212,931

213,109

212,931

Diluted common shares

213,675

213,258

213,192

213,042

Adjusted EBITDAX

Net income (loss)

$

(26,566)

$

(15,219)

$

(20,888)

$

(464,697)

Adjustments to reconcile to adjusted EBITDAX

Interest expense, net of capitalized

8,256

467

17,095

1,610

Income tax expense (benefit)

(7,315)

(2,598)

14,737

101,039

Depletion, depreciation, amortization and accretion

57,660

30,851

160,552

67,224

Impairment of unproved oil and natural gas properties

257

53

365

Exploration expenses

23

6

24

14

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

90,169

30,888

76,721

(12,231)

Equity-based compensation expense (2)

2,614

11,903

80,671

431,642

Gain on sale of assets

(6,225)

(6,225)

Adjusted EBITDAX

$

118,616

$

56,555

$

322,740

$

124,966

Total production (MBoe)

3,323

1,765

8,952

3,984

Adjusted EBITDAX margin (3)

$

35.70

$

32.04

$

36.05

$

31.37

(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 nine months ended September 30, 2018 includes $74.5 million related to management incentive units that converted to common stock in connection with the IPO and $6.2 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.

 

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SOURCE Jagged Peak Energy Inc.