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.