Jagged Peak Energy Inc. Announces Second Quarter 2019 Financial and Operating Results

- 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

DENVER, Aug. 8, 2019 /PRNewswire/ -- Jagged Peak Energy Inc. (NYSE: JAG) ("Jagged Peak" or the "Company") today announced financial and operating results for the second quarter ended June 30, 2019.

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

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."

Second Quarter Results

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.

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

Revenue for the second quarter of 2019 was $146.8 million, compared to $158.7 million in the second quarter of 2018. The decrease in revenue for the second quarter of 2019 compared to the same period in 2018 was primarily 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

 

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

 

The table below provides a summary of the Company's second quarter and first half 2019 actual results in comparison to its previously provided guidance ranges.

 

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

 

Note: Totals may not add due to rounding.

(1) Guidance as provided in the Company's first quarter earnings and operational update press release on May 9, 2019.

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

 

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

 

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.

Operational Updates

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.

Updated 2019 Capital, Production, and Operating Guidance

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

Financial Update

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.

Since the hedging update on May 9, 2019, the Company has added to its 2020 WTI swaps, which are now at 17,000 Bbls per day of oil for 2020. These additions are included in the commodity hedges schedule at the end of this release.

Conference Call

Jagged Peak will host a conference call and webcast to discuss its second quarter 2019 financial and operating results on August 9, 2019 at 9:00 am MT (11:00 am ET). The call will be webcast and accessible via the Investor Relations section of the Company's website at www.jaggedpeakenergy.com. Dial-in information for this call is included below:

 

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

Upcoming Investor Events

The Company will be participating in the following upcoming investor events:

Event

 

Date

 

Location

 

Management Attendees

Enercom

 

August 12,

 

Denver, CO

 

Jim Kleckner, President and CEO;

The Oil and Gas Conference

 

2019

     

Bob Howard, EVP and CFO;

           

Craig Walters, EVP and COO;

Seaport Global

 

August 27,

 

Chicago, IL

 

Craig Walters, EVP and COO

2019 Energy & Industrials
Conference

 

2019

       

Barclays

 

September

 

New York, NY

 

Jim Kleckner, President and CEO;

CEO Energy-Power
Conference

 

3-5, 2019

     

Bob Howard, EVP and CFO

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 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.

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, 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

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.

Net Debt to LTM Adjusted EBITDAX

Net debt to LTM 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 last twelve month 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

 

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

 
   

(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.

 

 

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SOURCE Jagged Peak Energy Inc.

James Edwards, Director, Investor Relations, jedwards@jaggedpeakenergy.com, 720-215-3754