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Jagged Peak Energy Inc. Announces Third Quarter 2017 Financial and Operating Results

DENVER, Nov. 8, 2017 /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, 2017. The financial and operating results discussed in this news release include the results for Jagged Peak Energy LLC (the "Predecessor") which became a wholly owned subsidiary of Jagged Peak Energy Inc. as the result of transactions associated with the Company's initial public offering ("IPO") in January 2017.

Third Quarter 2017 Highlights

  • Production volumes were 19,180 Boe/d (78% oil) for the quarter, an increase of 201% compared to the third quarter of 2016 and an increase of 30% compared to the second quarter 2017.
  • Net loss for the quarter was $15.2 million, or $(0.07) per common share. Eliminating certain non-cash charges and the non-cash loss on commodity derivative contracts, adjusted net income (a non-GAAP measure)(1) was $15.4 million, or $0.07 per diluted common share.
  • Adjusted EBITDAX (a non-GAAP measure)(1) was $56.6 million, with an adjusted EBITDAX margin (a non-GAAP measure)(1) of $32.04 per Boe.
  • Capital expenditures for drilling and completion activities were $158.9 million. Additionally, $3.6 million was spent on infrastructure and $7.8 million was spent to add over 2,200 net acres to the Company's leasehold position during the third quarter 2017.
  • On October 26, 2017, the borrowing base and lender commitments under the Company's credit facility were increased by 70% to $425 million, of which $35 million was drawn as of September 30, 2017.
  • The Company spud 15 gross operated horizontal wells and completed and put online 11 gross operated horizontal wells during the third quarter 2017. For the first nine months of 2017, the Company has spud 39 gross operated horizontal wells and completed and put online 32 gross operated horizontal wells.
  • Lower Wolfcamp A development wells continue to exceed expectations with the average of all wells with at least 30 days of production since February 2017 performing approximately 18% above type curve. Five Whiskey River wells with optimized completions are outperforming the type curve by 35% based on EUR / 1,000'.
  • Total leasehold position increased to approximately 72,600 net acres as of September 30, 2017, with over 1,400 future well locations identified in the 3rd Bone Spring, Wolfcamp A and Wolfcamp B formations.
  • Encouraging well results achieved in two new target formations, the Wolfcamp C and the Woodford Shale. These provide for the potential to add over 300 locations to the Company's undrilled inventory. Including the 2nd Bone Spring and these new formations, the Company is now producing from seven distinct benches across its acreage position.

Commenting on the third quarter results, Joe Jaggers, Chairman, Chief Executive Officer and President of Jagged Peak said, "In the third quarter, the Company saw adjusted EBITDAX climb 44% over the second quarter 2017 and 271% over the third quarter 2016. This continues to represent extraordinary and highly economic growth as we move towards our goal of more than tripling 2016 production this year. Over the last three months, our drilling performance has continued to improve, but we have been impacted by completion delays primarily related to fracing operations. Our drilling performance during the third quarter improved with overall cost per foot declining 17% versus performance over the first half of 2017. One remarkable drilling achievement is a Whiskey River Wolfcamp well with a 9,900' foot lateral that was drilled with a single lateral drilling assembly in a total of 141 hours. This well was drilled in 22 days from spud to rig release. However, we have experienced completion delays related to frac fleet equipment reliability from our service providers and the learning curve of less experienced crews. We have communicated these issues to our service providers, and they are being actively addressed within their individual organizations. These delays have increased our completed well costs and will reduce our total number of well completions in both the third and fourth quarters of 2017. Although we would be able to offset the impact of these delays by deploying additional spot frac fleets, we are unwilling to continue incurring the additional costs associated with these fleets. We have seen the additional costs of spot fleets approach $1 million per well, so we have chosen to be efficient with our capital and to preserve the strongest economic returns possible from our wells. In fact, our individual well results continue to meet or exceed our type curves. Any delayed wells will be completed in early 2018. We now expect to complete 15 to 17 operated wells this quarter and expect that our production will range from 26,000 to 27,000 Boe/d during the fourth quarter 2017."

Regarding Jagged Peak's delineation efforts, Mr. Jaggers continued, "We continue to successfully test new landing zones and formations in order to delineate additional resources, add reserves and gather information for full field development. In this quarterly release, we are announcing two exciting new wells - one targeting the Wolfcamp C and another targeting the Woodford Shale. This highlights our team's continued work towards derisking the very thick oil column across our leasehold position, and we are very encouraged with the initial results of these wells. These two wells mark our second and third announcements establishing new development targets this year, with the previous announcement of a successful 2nd Bone Spring well in August 2017. While some of these targets are characterized by a naturally higher gas-to-oil ratio, such as the 2nd Bone Spring and the Woodford Shale, than our traditional lower Wolfcamp A landing zone, these targets are highly economic and still produce an attractive oil cut. Additionally, our Wolfcamp A production is still greater than 80% oil, and represents 55% of our current inventory and approximately 80% of our current production. The Wolfcamp A drives our year to date oil cut of 81%, which is the best among our peer group's publicly announced results. This oil cut allowed us to generate a peer leading EBITDAX margin of $32.04 per Boe in the third quarter 2017."

Regarding Jagged Peak's plan going forward, Mr. Jaggers continued, "Our plans for fourth quarter 2017 include an average of six drilling rigs and three completion crews throughout the quarter. As evidenced by our third quarter results and our current estimated net production rate of 23,500 Boe/d, I have confidence in our team's ability to continue to execute our development plan. Following our successful fall borrowing base redetermination, we remain well capitalized with the liquidity to continue to fund our operations into the foreseeable future."

Operating Update

The Company spud 15 gross operated horizontal wells and completed 11 gross operated horizontal wells during the third quarter. Additionally, during the quarter, the Company participated in 7 gross non-operated horizontal spuds and 3 gross non-operated horizontal completions. At the end of the third quarter, the Company had 4 wells that were being completed and 5 wells that were awaiting completion. Since the end of the third quarter, the Company has brought online 5 gross operated wells and is in the process of completing 8 additional gross operated horizontal wells.

Notable recent individual well results, production activity and upcoming catalysts include the following:

  • The Company continues to achieve outstanding results with the performance of wells with optimized completions exceeding the type curve by 35% in the core lower Wolfcamp A development program while maintaining a high oil cut of greater than 80%:
    • In the central Whiskey River project area, the Eiland 1112-GG 1H (completed lateral length 7,657'), the most recent lower Wolfcamp A well with at least 30 days of production achieved an IP30 of 230 Boe/d / 1,000'. The Eiland 0812A-GG Houston 1H (completed lateral length 6,703') completed in the second quarter 2017 has produced a cumulative 192,577 Boe in its first 180 days online.
    • Extraordinary performance in the Whiskey River lower Wolfcamp A target continues from the State Skinwalker 2-8 1H (completed lateral length 8,101') with cumulative production of 273,488 Boe in its first 265 days online.
    • In the central Whiskey River project area, the State Ronald 4-J McDonald 1H (completed lateral length 8,310') has produced a cumulative 188,100 Boe in its first 205 days online.
  • The Company continues to be encouraged by the results achieved from the Wolfcamp B formation. A recent well completed in the Wolfcamp B, the Eiland 1806A-33 1H (completed lateral length 5,965'), was brought online during the quarter in the Whiskey River project area. The well has achieved a peak 24-hour rate of 244 Boe/d / 1,000' (85% oil).
  • The Company's first Wolfcamp C well, State 5913A GG Houston 2H (completed lateral length 6,662'), was put on production during the quarter and has achieved a peak 24-hour rate of 1,179 Boe/d (83% oil). The Company estimates the Wolfcamp C is prospective on approximately 70% of the Company's current leasehold and has the potential to add over 200 locations to its undrilled inventory, the majority of which would be 1.5 and 2.0 section locations.
  • The Company's first 2nd Bone Spring well, the County Line 18A-C2 1H (completed lateral length 4,843'), continues to perform strongly, with 100,186 Boe produced over the first 150 days online. Based on 2-stream production volumes, the well is currently producing an oil cut of 66%. The Company estimates the 2nd Bone Spring formation has the potential to add over 200 locations to its undrilled inventory, the majority of which would be 1.5 and 2.0 section locations.
  • The Company is announcing the results of a successful Woodford Shale exploration well drilled in the Company's Big Tex project area in Pecos County, Texas. The State Neal Lethco 3427-142 2H (completed lateral length 1,665') well was drilled into the Woodford Shale formation and produced an IP30 of 227 Boe/d / 1,000' (40 degree API gravity). Based on 2-stream production volumes, the well is currently producing an oil cut of 63%. The Woodford Shale formation is a prolific source rock that is characterized by high total organic content and has been a development target across the southern Midcontinent and the western Delaware Basin. The Devonian-aged Woodford formation lies below the Permian-aged Wolfcamp formation in the Delaware Basin and is 210 to 380 feet thick throughout the Company's acreage that is prospective for Woodford oil development. Analysis of core data indicates that a significant portion of the Company's Woodford Shale acreage is in the peak oil generation window with high oil saturation. The Company has been actively leasing oil prospective acreage and, including new and existing leases, the Company's leasehold position includes approximately 27,000 net acres prospective for Woodford oil development. The Company's Woodford Shale discovery could add 120 locations to the Company's undrilled inventory. A 3D seismic program has been scheduled in the Big Tex area in order to establish the next steps in developing this resource.
  • Operational catalysts for the Company include testing additional reservoirs and increased well density. The Company is concluding completion operations on its first 3rd Bone Spring well and has drilled and cased its second 3rd Bone Spring well. Further, the Company is currently drilling a 2.0 section 2nd Bone Spring well to build on its successful 2nd Bone Spring appraisal announced in August 2017. To continue testing increased density, the Company has drilled and is completing two spacing tests in its Cochise project area. The first test is a 2-well pad that will test staggered spacing in the upper and lower Wolfcamp A. Second, the Company has also drilled and is currently completing a 3-well pad on 660' spacing within the same lower Wolfcamp A landing zone in its Cochise project area.
  • The Company has licensed state of the art, high quality 3D seismic covering the Cochise project area. Initial results have successfully identified high quality shale targets and assisted in geosteering laterals. The Company is participating in a 3D survey over its Whiskey River project area that is anticipated to be completed by year end 2017. Further, seismic permitting work has begun in the Big Tex project area with data acquisition planned in early 2018. The Company continues to add to its understanding of the reservoir system by collecting additional core data in order to validate the petrophysical model. Together, these efforts are leading to an integrated understanding of optimal reservoir development.
  • The Company's third quarter 2017 lease operating expense ("LOE") of $2.94 per Boe and YTD 2017 LOE of $2.68 per Boe remain the best of our peers. This peer leading LOE is driven by the Company's water infrastructure that provides for cost-efficient water sourcing and disposal.

From January 1 through October 31, the Company has ramped up production with 34 new operated wells coming online. The Company's current estimated net production for November month to date is 23,500 Boe/d.

Financial Results

For the third quarter 2017, the Company reported a net loss of $15.2 million, which includes non-cash equity based compensation expense of $11.9 million. Net income for the third quarter of 2016 was $5.4 million. Adjusted EBITDAX (a non-GAAP measure) for the third quarter 2017 was $56.6 million, an increase of $41.3 million from the third quarter of 2016 and $17.3 million from the second quarter 2017.

For the third quarter 2017, the Company reported adjusted net income (a non-GAAP measure) of $15.4 million. Adjusted net income (a non-GAAP measure) eliminates certain non-cash and non-recurring items such as equity-based compensation and income tax expense directly related to the IPO, non-cash mark-to-market gains or losses on derivatives, and impairment expense, further adjusted for the associated changes in estimated income tax expense. For the third quarter 2016, the Company reported adjusted net income (a non-GAAP measure) of $3.4 million.

Adjusted EBITDAX and adjusted net income (loss) are non-GAAP measures. Please reference the reconciliations to the most directly comparable GAAP measures at the end of this release.

The Company's average realized sales prices for the third quarter 2017, including settlement of realized oil hedges, were $47.55 per barrel of oil, $2.59 per Mcf of natural gas and $25.31 per barrel of natural gas liquids. The total oil equivalent price for the quarter was $41.70 per Boe compared to the third quarter 2016 total equivalent price of $36.79 per Boe and the second quarter 2017 total equivalent price of $40.67 per Boe. Additionally, LOE, including workovers, of $2.94 per Boe was 25% lower than third quarter 2016 of $3.90 per Boe. During the first nine months of 2017, LOE averaged $2.68 per Boe compared to $3.59 per Boe during the same period in 2016.

On October 26, 2017, the borrowing base and lender commitments under the Company's credit facility were increased from $250 million to $425 million. Concurrently with the borrowing base redetermination, the pricing structure and unused commitment fee of the Company's credit facility were improved to reflect favorable, current market rates. The Company began borrowing against its credit facility in September 2017 and had an outstanding balance of $35 million as of September 30, 2017. As of November 3, 2017, the Company had $80 million of outstanding borrowings against its credit facility, leaving $345 million of undrawn capacity. At current commodity prices, this represents sufficient liquidity for the Company to continue to fund its ongoing capital expenditure program while maintaining leverage consistent with the Company's long-term target of approximately 1.0x net debt / adjusted EBITDAX (a non-GAAP measure).

Capital Expenditures

Capital expenditures for drilling and completion activities were $158.9 million for the three months ended September 30, 2017, which represents capital spent to drill and complete 14 gross (11.6 net) wells, of which 11 gross (10.2 net) wells were drilled and completed by Jagged Peak. Additionally, the Company had 16 gross (15.1 net) wells that were in various stages of being drilled or completed at the end of the quarter. Adding in capital expenditures for infrastructure of $3.6 million and leasehold capital of $7.8 million, total capital expenditures for the quarter were $170.3 million. Year to date, the Company has spent $1.2 million on the acquisition of surface acreage, which is included in the $21.8 million in infrastructure costs incurred in year to date 2017. The $7.8 million spent on leasehold acquisitions added over 2,200 net undeveloped acres, increasing the Company's leasehold position to approximately 72,600 net acres as of September 30, 2017.


Three Months Ended September 30,


Nine Months Ended September 30,


2017


2016


2017


2016


(in thousands)

Capital Expenditures for Oil and Gas Activities








Acquisitions








Proved properties

$



$

7,482



$



$

7,482


Unproved properties

7,845



8,661



56,364



32,312


Development costs

158,870



36,845



399,057



82,651


Infrastructure costs

3,613



3,956



21,805



7,311


Exploration costs

6



78



14



1,663


Total oil and gas capital expenditures

$

170,334



$

57,022



$

477,240



$

131,419


2017 Operating Guidance

The Company updates its full-year 2017 guidance as follows:

  • Capital expenditures for development of oil and gas properties and infrastructure of approximately $550 to $575 million, excluding leasehold and surface additions - compared to previous guidance of $525 to $570 million
    • Approximately $530 to $550 million budgeted for drilling and completion costs - compared to previous guidance of $510 to $550 million
    • Approximately $20 to $25 million budgeted for water infrastructure construction costs, excluding any potential additions for surface acreage - compared to previous guidance of $15 to $20 million
  • Production of 17,500 to 17,800 Boe/d - compared to previous guidance of 17,500 to 18,000 Boe/d
    • 47 to 49 gross operated horizontal completions with an approximate average lateral length of 7,800' and an approximate average working interest of 94% - compared to previous guidance of 50 to 55 gross operated horizontal completions
  • LOE per Boe of $2.50 to $3.00 - compared to previous guidance of $2.75 to $3.25 per Boe
  • General and administrative expense, excluding equity-based compensation, of $26.0 to $28.0 million - compared to previous guidance of $28.0 to $30.0 million
  • Production and ad valorem taxes at 6.5% to 7.5% of unhedged production revenue

The Company expects fourth quarter 2017 production to average 26,000 to 27,000 Boe/d, an increase of approximately 7,320 Boe/d, or 38%, at the mid-point compared to third quarter production. This is compared to previous guidance of 26,000 to 28,000 Boe/d.

Conference Call

Jagged Peak will host a conference call and webcast to discuss its third quarter 2017 financial and operating results on Thursday, November 9, 2017 at 9:00 am MDT (11:00 am EDT). 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 1-631-891-4304). A telephone replay will be available from 12:00 noon MDT (2:00 pm EDT) on Thursday, November 9, 2017 through Friday, December 1, 2017 at 10:00 pm MDT (12:00 midnight). To access the replay, dial 1-844-512-2921 (international callers dial, 1-412-317-6671) and enter confirmation code 10003627. 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

Chairman, Chief Executive Officer and President, Joe Jaggers, and other members of management will participate in KLR's E&P Conference in Denver on November 14, 2017. The presentation used for this event will be available on the Company's website at www.jaggedpeakenergy.com.

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 "2017 Operating Guidance"; expected capital expenditures; drilling, completion and development expectations; expected inventory locations; sufficiency of the Company's liquidity position; ability to realize value of Jagged Peak's acreage position; ability to improve well results, increase cash flow and reduce costs; ability to execute on the Company's development plan and increase production; estimates of current net operated production; expected number of rigs and completion crews; planned seismic programs and the impact and execution of the Company's hedging strategies. 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 2016 Annual Report on Form 10-K and the Form 10-Q for the quarter ended September 30, 2017, 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 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 or 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 performance measure used by management to evaluate financial performance, prior to non-cash 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 equity-based compensation and income tax expense related to the IPO, 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.

Adjusted EBITDAX Margin

Adjusted EBITDAX margin is a performance measure used by management to evaluate financial performance and profitability. The Company defines adjusted EBITDAX margin as the relevant period's adjusted EBITDAX divided by the total oil equivalent production for that same period.

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.

(1) Adjusted net income (loss), adjusted EBITDAX and adjusted EBITDAX margin are non-GAAP measures. Please reference the reconciliations to the most directly comparable GAAP measures at the end of this release.

Jagged Peak Energy Inc.

Selected Operating Highlights

(Unaudited)










Three Months Ended


Nine Months Ended


September 30,


September 30,


2017


2016


2017


2016









Production Data:








Oil (MBbls)

1,383



484



3,208



1,210


Natural gas (MMcf)

1,136



282



2,224



669


NGLs (MBbls)

192



55



406



141


Combined volumes (MBoe)

1,765



586



3,984



1,462


Daily combined volumes (Boe/d)

19,180



6,366



14,594



5,336










Average Sales Prices (before the effects of realized hedges):







Oil (per Bbl)

$

45.24



$

42.03



$

46.06



$

39.03


Natural gas (per Mcf)

2.59



2.59



2.56



2.17


NGLs (per Bbl)

25.31



14.89



22.28



14.35


Combined (per Boe)

39.89



37.36



40.78



34.67










Average Sales Prices (after the effects of realized hedges):







Oil (per Bbl)

$

47.55



$

41.34



$

47.21



$

38.07


Natural gas (per Mcf)

2.59



2.59



2.56



2.17


NGLs (per Bbl)

25.31



14.89



22.28



14.35


Combined (per Boe)

41.70



36.79



41.71



33.87










Average Operating Costs (per Boe):








Lease operating expenses

$

2.94



$

3.90



$

2.68



$

3.59


Gathering, transportation and processing expense

0.77



0.50



0.60



0.45


Production and ad valorem tax expenses

2.69



2.29



2.74



2.17


Depreciation, depletion, amortization and accretion expense

17.48



19.04



16.87



20.13


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

3.30



4.06



4.48



5.39


Jagged Peak Energy Inc.

Condensed Consolidated and Combined Balance Sheets

(Unaudited)













September 30, 2017


December 31, 2016








(in thousands)

Assets:





Cash and cash equivalents

$

3,900



$

11,727



Other current assets

44,750



13,739



Property and equipment, net

889,798



476,593



Other noncurrent assets

7,828



16,333



Total assets

$

946,276



$

518,392







Liabilities and Stockholders' / Members' Equity:





Current liabilities

$

129,283



$

56,421



Long-term debt

35,000



132,000



Deferred income taxes

101,039





Other long-term liabilities

5,706



3,859



Stockholders' / Members' equity

675,248



326,112



Total liabilities and stockholders' / members' equity

$

946,276



$

518,392


Jagged Peak Energy Inc.

Condensed Consolidated and Combined Statements of Operations

(Unaudited)










Three Months Ended


Nine Months Ended


September 30,


September 30,


2017


2016


2017


2016










(in thousands, except per share amounts)

Revenues








Oil, natural gas and NGL sales

$

70,384



$

21,882



$

162,476



$

50,688


Other operating revenues

67



182



414



957


Total revenues

70,451



22,064



162,890



51,645


Operating Expenses








Lease operating expenses

5,184



2,285



10,684



5,254


Gathering and transportation expenses

1,357



294



2,404



662


Production and ad valorem taxes

4,739



1,341



10,916



3,173


Exploration

6





14



2,474


Depletion, depreciation, amortization and accretion

30,851



11,152



67,224



29,430


Impairment of unproved oil and natural gas properties

257



7



365



317


Other operating expenses

41



169



223



567


General and administrative (before equity-based compensation)

5,830



2,375



17,862



7,878


General and administrative, equity-based compensation

11,903





431,642




Total operating expenses

60,168



17,623



541,334



49,755


Income (Loss) from Operations

10,283



4,441



(378,444)



1,890


Other Income and Expense








Gain (loss) on commodity derivatives

(27,693)



1,728



15,922



(8,208)


Interest expense and other

(407)



(759)



(1,136)



(1,471)


Total other income (loss)

(28,100)



969



14,786



(9,679)


Income (Loss) before Income Taxes

(17,817)



5,410



(363,658)



(7,789)


Income tax expense

(2,598)





101,039




Net Income (Loss)

$

(15,219)



$

5,410



$

(464,697)



$

(7,789)










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

$



$

5,410



$

(375,476)



$

(7,789)


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

(15,219)





(89,221)




Net Income (Loss)

$

(15,219)



$

5,410



$

(464,697)



$

(7,789)










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








Basic

$

(0.07)





$

(0.42)




Diluted

$

(0.07)





$

(0.42)












Weighted-average common shares outstanding:








Basic

212,931





212,933




Diluted

212,931





212,933




Jagged Peak Energy Inc.

Consolidated and Combined Statements of Cash Flows

(Unaudited)










Three Months Ended


Nine Months Ended


September 30,


September 30,


2017


2016


2017


2016










(in thousands)

Cash Flows from Operating Activities








Net income (loss)

$

(15,219)



$

5,410



$

(464,697)



$

(7,789)


Adjustments to reconcile to net cash provided by operating activities:








Depletion, depreciation, amortization and accretion expense

30,851



11,152



67,224



29,430


Management incentive unit advance







(14,712)


Impairment of unproved oil and natural gas properties

257



7



365



317


Exploratory dry hole costs







1,192


Amortization of debt issuance costs

147



77



407



164


Deferred income taxes

(2,598)





101,039




Equity-based compensation

11,903





431,642




(Gain) Loss on commodity derivatives

27,693



(1,728)



(15,922)



8,208


Net cash receipts (payments) on settled derivatives

3,195



(337)



3,691



(1,159)


Other

(40)



(42)



(123)



(120)


Change in operating assets and liabilities:








Accounts receivable and other current assets

(18,582)



265



(27,292)



(545)


Other assets

116





(3)



11


Accounts payable and accrued liabilities

7,700



714



9,097



1,825


Net cash provided by operating activities

45,423



15,518



105,428



16,822


Cash Flows from Investing Activities








Leasehold and acquisitions costs

(7,659)



(15,410)



(60,627)



(39,344)


Development of oil and natural gas properties

(153,964)



(30,654)



(349,176)



(84,809)


Other capital expenditures

(1,876)



(140)



(3,332)



(1,831)


Proceeds from sale of oil and natural gas properties








Net cash used in investing activities

(163,499)



(46,204)



(413,135)



(125,984)


Cash Flows from Financing Activities








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





401,625




Proceeds from common units issued







31,542


Proceeds from senior secured revolving credit facility

35,000



30,000



45,000



70,000


Repayment of senior secured revolving credit facility





(142,000)




Debt issuance costs

(20)



(292)



(1,441)



(1,030)


Costs related to initial public offering



(95)



(3,216)



(95)


Employee tax withholding for settlement of equity compensation awards





(88)




Net cash provided by financing activities

34,980



29,613



299,880



100,417


Net Change in Cash and Cash Equivalents

(83,096)



(1,073)



(7,827)



(8,745)


Cash and Cash Equivalents, Beginning of Period

86,996



6,493



11,727



14,165


Cash and Cash Equivalents, End of Period

$

3,900



$

5,420



$

3,900



$

5,420


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. For the fourth quarter 2017, 15,138 Bbl/d of oil are hedged at an average WTI price of $51.34 per barrel. For 2018, 14,420 Bbl/d of oil are hedged at an average WTI price of $52.18 per barrel. In addition, for 2018, the Company has hedges in place for 5,110,000 barrels of oil to hedge the price differential between the Cushing and Midland oil prices at $(1.08) per barrel.











As of November 3, 2017, the Company had the following commodity hedges in place for future production:








Production Period


Volumes


Weighted Average
Price




(Bbls)


($/Bbl)


Oil Swaps:






Fourth quarter 2017


1,392,700



$

51.34



First quarter 2018


1,315,250



$

51.86



Second quarter 2018


1,275,500



$

51.82



Third quarter 2018


1,343,200



$

52.34



Fourth quarter 2018


1,329,400



$

52.67



Full-Year 2018


5,263,350



$

52.18



Full-Year 2019


2,372,500



$

51.89



Oil Basis Swaps:






Fourth quarter 2017


460,000



$

(1.00)



Full-Year 2018


5,110,000



$

(1.08)



Full-Year 2019


2,920,000



$

(1.10)



Jagged Peak Energy Inc.


Reconciliation of Adjusted Net Income and Adjusted EBITDAX


(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,



2017


2016


2017


2016












(in thousands)


Adjusted Net Income (Loss)






Net Income (Loss)

$

(15,219)



$

5,410



$

(464,697)



$

(7,789)



Adjustments to reconcile to Adjusted Net Income









Impairment of unproved oil and natural gas properties

257



7



365



317



Exploratory dry hole costs







1,192



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

30,888



(2,065)



(12,231)



7,049



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

10,489





428,966





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





79,106





Income tax effect for the above items

(11,042)





4,214





Adjusted Net Income (Loss)

$

15,373



$

3,352



$

35,723



$

769












Adjusted Net Income (Loss) per basic common share

$

0.07





$

0.17





Adjusted Net Income (Loss) per diluted common share

$

0.07





$

0.17














Basic common shares

212,931





212,931





Diluted common shares

213,258





213,042














Adjusted EBITDAX









Net Income (Loss)

$

(15,219)



$

5,410



$

(464,697)



$

(7,789)



Adjustments to reconcile to Adjusted EBITDAX









Interest expense, net of capitalized

467



759



1,610



1,471



Income tax expense (benefit)

(2,598)





101,039





Depletion, depreciation, amortization and accretion

30,851



11,152



67,224



29,430



Impairment of unproved oil and natural gas properties

257



7



365



317



Exploration expenses

6





14



2,474



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

30,888



(2,065)



(12,231)



7,049



Equity-based compensation expense (2)

11,903





431,642





Adjusted EBITDAX

$

56,555



$

15,263



$

124,966



$

32,952












Total Production (MBoe)

1,765



586



3,984



1,462



Adjusted EBITDAX Margin

$

32.04



$

26.05



$

31.37



$

22.54




(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 compensation expense related to these shares is recognized ratably as they vest. 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 third quarter 2017 includes $10.7 million related to management incentive units that converted to common stock in connection with the IPO and $1.2 million related to equity awards issued under the Company's long-term incentive plan.

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SOURCE Jagged Peak Energy Inc.