- Production sales volumes of 10.2 million barrels of oil
equivalent ("MMBoe") in 2018 represents 45% growth over 2017; oil
sales volumes of 6.3 million barrels of oil ("MMBbls") grew 51%
over 2017 and represent 62% of total production
- Production sales volumes of 3.11 MMBoe in the fourth quarter of
2018 represents 47% growth over the fourth quarter of 2017; oil
sales volumes of 1.97 MMBbls grew 55% over the fourth quarter of
2017 and represent 63% of total production
- Lease operating expense ("LOE") of $2.74 per Boe in 2018
represents 21% improvement over 2017
- Delivered a 2018 basin operating margin1 of $37.69 per Boe, an
increase of 27% over 2017, driven by high oil weighting, an
attractive oil price differential of $2.73 per barrel and low
operating costs
- Entered 2019 with $33 million of cash on hand and an undrawn
credit facility of $500 million providing strong liquidity
- 2019 capital budget of $350-$380 million designed to be cash
flow positive in the second half of 2019 with 25% production growth
over 2018
- 2019 drilling program is fully permitted and given the
exclusively rural nature of acreage is resilient to potential
Colorado regulatory developments
1 Basin operating margin is defined as the
average realized price per Boe before hedging less lease operating
expense, gathering, transportation and processing expense and
production tax expense
HighPoint Resources Corporation (the "Company") (NYSE: HPR) today
reported fourth quarter and full year 2018 financial and operating
results, 2019 operating and financial guidance and year-end 2018
proved reserves.
For the fourth quarter of 2018, the Company
reported earnings of $222.4 million, or $1.06 per diluted share.
Adjusted net income for the fourth quarter of 2018 was $1.2
million, or $0.01 per diluted share. EBITDAX for the fourth quarter
of 2018 was $92.1 million. For 2018, the Company reported net
income of $121.2 million, or $0.64 per diluted share. Adjusted net
income for 2018 was a net loss of $5.5 million, or $0.03 per
diluted share. EBITDAX for 2018 was $279.9 million. Adjusted net
income (loss) and EBITDAX are non-GAAP (Generally Accepted
Accounting Principles) measures. Please reference the
reconciliations to GAAP financial statements at the end of this
release.
Chief Executive Officer and President Scot
Woodall commented, "2018 was a transformational year as we
completed our strategic combination with Fifth Creek Energy,
integrated both organizations in a timely fashion, rebranded as
HighPoint Resources and initiated the Hereford development program.
We delivered solid year-over-year operating and financial results
that were highlighted by production growth of 45%, strong EBITDAX
growth of 57%, a 21% reduction in per unit operating costs and a
strong operating margin of $37.69 per Boe. We also successfully
managed through mid-stream constraints in Northeast ("NE")
Wattenberg that were largely out of our control and persisted
throughout much of the year. I commend our production and marketing
groups for their efforts in strategically diversifying our gas
processing to other outlets. We are utilizing multiple mid-stream
providers and have approximately 40% of our total gas processing
volumes going to alternative outlets, which should mitigate any
disruptions going forward."
"2018 was also a good year operationally. We
brought our best wells to date on line in NE Wattenberg as we
implemented higher fluid intensity completions and we have seen
early performance across Hereford that confirms high margin
investment opportunities that are driven by the highest oil
percentages being developed in the Denver-Julesburg ("DJ") Basin.
Our initial wells at Hereford utilized our proven drilling,
completion and controlled flowback designs from NE Wattenberg.
These designs delivered a reduction in well cost of over 30%
compared to previous wells. We continue to optimize production
through an enhanced completion design that is leveraging
microseismic and fiber optic technology with work already in
progress for an early development cycle determination of the
optimal stimulation design and well spacing to be utilized for
future development. We remain confident with respect to the
productive capacity and resource potential of the Hereford asset as
both the Niobrara and Codell formations have exhibited pressures,
oil cuts, and initial productivity consistent with our expectations
and which support a highly economic investment program."
"Looking at 2019, our design enhancements are
expected to deliver optimum value from the NE Wattenberg and
Hereford assets as we align capital spending with anticipated cash
flow. In that respect, we have set a 2019 capital budget that is
approximately 28% lower than 2018, but maintain the flexibility to
adjust the development plan as conditions warrant. We are
projecting well costs to be approximately 5-10% lower than 2018 as
a result of execution efficiencies and design change improvements.
We expect production growth that is 25% greater than 2018 at the
mid-point of guidance and to be cash flow positive in the second
half of 2019. We can execute our 2019 program without a need for
further drilling permits. Given the exclusively rural nature of our
assets, we expect our capital program to be extremely resilient to
potential regulatory developments in Colorado."
OPERATING AND FINANCIAL
RESULTS
Proved Reserves
Total estimated proved reserves at year-end 2018
were 104.6 MMBoe (56% oil, 49% proved developed) compared to 85.8
MMBoe (46% oil, 48% proved developed) at year-end 2017, which is a
22% year-over-year increase. The Company maintains a conservative
approach to proved reserve bookings and only included approximately
220 gross proved undeveloped ("PUD") locations at year-end 2018, of
which approximately 60 gross PUD locations represent wells that are
in various stages of drilling and completion activity. This amounts
to approximately 1.5 years of future development activity at the
current planned development pace.
The standardized measure of discounted future
net cash flows at December 31, 2018 was $1.3 billion, which was a
54% increase over year-end 2017.
|
Changes in Proved Reserves (MMBoe) |
Proved reserves as of December 31, 2017 |
85.8 |
|
Extensions, discoveries, purchases and revisions |
29.0 |
|
Production sales volumes |
(10.2 |
) |
Proved
reserves as of December 31, 2018 |
104.6 |
|
|
|
|
2018 Production and Financial
Results
Reported oil, natural gas and natural gas
liquids production totaled 10.2 MMBoe for 2018, which is an
increase of 45% over 2017. Pro forma for the merger with Fifth
Creek, 2018 production totaled 10.5 MMBoe, including approximately
0.3 MMBoe associated with Hereford for the first quarter of 2018
(prior to the merger date of March 19, 2018), which is an increase
of 50% over 2017. Reported oil volumes totaled 6.3 MMBbls, which is
an increase of 51% over 2017; and pro forma oil volumes totaled 6.6
MMBbls, which is an increase of 56% over 2017. Production sales
volumes from NE Wattenberg totaled 8.9 MMBoe and pro forma Hereford
volumes totaled 1.5 MMBoe.
Production sales volumes for 2018 were weighted
62% oil, 21% natural gas and 17% natural gas liquids.
Production sales volumes for the fourth quarter
of 2018 totaled 3.11 MMBoe, which was an increase of 47% over the
fourth quarter of 2017. Oil volumes totaled 2.0 MMBbls, which was
an increase of 55% over the fourth quarter of 2017. Production
sales volumes from NE Wattenberg totaled 2.6 MMBoe and Hereford
volumes totaled 0.5 MMBoe.
Production sales volumes for the fourth quarter
of 2018 were weighted 63% oil, 21% natural gas and 16% NGLs.
|
|
|
|
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
Production Data
(1) |
|
|
|
|
|
|
|
Oil
(MBbls) |
1,970 |
|
1,274 |
|
6,330 |
|
4,203 |
Natural
gas (MMcf) |
3,912 |
|
2,868 |
|
12,864 |
|
8,952 |
NGLs
(MBbls) |
490 |
|
371 |
|
1,697 |
|
1,307 |
Combined
volumes (MBoe) |
3,112 |
|
2,123 |
|
10,171 |
|
7,002 |
Daily
combined volumes (Boe/d) |
33,826 |
|
23,076 |
|
27,866 |
|
19,184 |
(1) 2017 includes legacy DJ Basin and Uinta Basin
production only.
For 2018, West Texas Intermediate ("WTI") oil
prices averaged $64.77 per barrel, NWPL natural gas prices averaged
$2.63 per MMBtu and NYMEX natural gas prices averaged $3.10 per
MMBtu. Commodity price differentials to benchmark pricing for 2018
were oil less $2.73 per barrel versus WTI; and natural gas less
$0.88 per Mcf compared to NWPL. The NGL price averaged
approximately 34% of the WTI price per barrel.
For the fourth quarter of 2018, WTI oil prices
averaged $58.81 per barrel, NWPL natural gas prices averaged $3.75
per MMBtu and NYMEX natural gas prices averaged $3.65 per MMBtu.
Fourth quarter 2018 commodity price differentials to benchmark
pricing were oil less $2.61 per barrel versus WTI and natural gas
less $1.62 per Mcf compared to NWPL. The NGL price averaged
approximately 38% of the WTI price per barrel.
For the fourth quarter of 2018, the Company had
derivative commodity swaps in place for 13,806 barrels of oil per
day tied to WTI pricing at $54.63 per barrel, derivative collars in
place for 2,000 barrels of oil per day with a ceiling price of
$77.27 per barrel and a floor price of $60.00 per barrel, 5,000
MMBtu of natural gas per day tied to NWPL regional pricing at $2.68
per MMBtu and no hedges in place for NGLs.
|
|
|
|
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
Average
Sales Prices (before the effects of realized hedges): |
Oil (per
Bbl) |
$ |
56.35 |
|
$ |
52.63 |
|
$ |
62.04 |
|
$ |
48.37 |
Natural
gas (per Mcf) |
2.13 |
|
2.32 |
|
1.75 |
|
2.43 |
NGLs (per
Bbl) |
22.54 |
|
24.09 |
|
22.18 |
|
20.01 |
Combined
(per Boe) |
41.88 |
|
38.94 |
|
44.53 |
|
35.88 |
|
|
|
|
|
|
|
|
Average
Realized Sales Prices (after the effects of realized hedges): |
Oil (per
Bbl) |
$ |
54.08 |
|
$ |
53.98 |
|
$ |
54.51 |
|
$ |
52.72 |
Natural
gas (per Mcf) |
2.01 |
|
2.43 |
|
1.76 |
|
2.52 |
NGLs (per
Bbl) |
22.54 |
|
24.09 |
|
22.18 |
|
20.01 |
Combined
(per Boe) |
40.29 |
|
39.90 |
|
39.85 |
|
38.60 |
|
|
|
|
|
|
|
|
Cash operating costs (LOE, gathering,
transportation and processing costs, and production tax expense)
averaged $6.81 per Boe in 2018 compared to $5.90 per Boe in 2017.
The increase in cash operating costs is primarily a result of
higher commodity prices and higher production taxes due to a higher
concentration of revenues from Colorado following the sale of Utah
properties in December 2017.
Cash operating costs totaled $6.09 per Boe in
the fourth quarter of 2018 compared to $6.24 per Boe in the fourth
quarter of 2017.
LOE totaled $2.74 per Boe for 2018 compared to
$3.46 per Boe for 2017 or a reduction of 21%. The year-over-year
improvement was primarily a result of increased operational
efficiencies and lease operating cost reductions.
|
|
|
|
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
Average Costs (per
Boe): |
|
|
|
|
|
|
|
Lease
operating expenses |
$ |
2.17 |
|
|
$ |
3.27 |
|
|
$ |
2.74 |
|
|
$ |
3.46 |
|
Gathering, transportation and processing expense |
0.58 |
|
|
0.46 |
|
|
0.46 |
|
|
0.37 |
|
Production tax expenses |
3.34 |
|
|
2.51 |
|
|
3.61 |
|
|
2.07 |
|
Depreciation, depletion and amortization |
24.53 |
|
|
19.10 |
|
|
22.46 |
|
|
22.85 |
|
General
and administrative expense |
3.44 |
|
|
5.51 |
|
|
4.44 |
|
|
6.07 |
|
The following table summarizes certain operating
and financial results for the fourth quarter of 2018 and 2017 and
the full years 2018 and 2017:
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
Production sales
volumes (MBoe) |
3,112 |
|
|
2,123 |
|
|
10,171 |
|
|
7,002 |
|
Net cash provided by
(used in) operating activities ($ millions) |
$ |
71.3 |
|
|
$ |
26.6 |
|
|
$ |
231.4 |
|
|
$ |
122.0 |
|
Discretionary cash flow
($ millions) (1) |
$ |
79.3 |
|
|
$ |
45.9 |
|
|
$ |
231.4 |
|
|
$ |
125.3 |
|
Net income (loss) ($
millions) |
$ |
222.4 |
|
|
$ |
(77.8 |
) |
|
$ |
121.2 |
|
|
$ |
(138.2 |
) |
Per
share, basic |
$ |
1.06 |
|
|
$ |
(0.94 |
) |
|
$ |
0.64 |
|
|
$ |
(1.80 |
) |
Per
share, diluted |
$ |
1.06 |
|
|
$ |
(0.94 |
) |
|
$ |
0.64 |
|
|
$ |
(1.80 |
) |
Adjusted net income
(loss) ($ millions) (1) |
$ |
1.2 |
|
|
$ |
(39.9 |
) |
|
$ |
(5.5 |
) |
|
$ |
(29.2 |
) |
Per
share, basic |
$ |
0.01 |
|
|
$ |
(0.48 |
) |
|
$ |
(0.03 |
) |
|
$ |
(0.38 |
) |
Per
share, diluted |
$ |
0.01 |
|
|
$ |
(0.48 |
) |
|
$ |
(0.03 |
) |
|
$ |
(0.38 |
) |
Weighted average shares
outstanding, basic (in thousands) |
209,529 |
|
|
83,138 |
|
|
188,299 |
|
|
76,859 |
|
Weighted average shares
outstanding, diluted (in thousands) |
209,645 |
|
|
83,138 |
|
|
189,241 |
|
|
76,859 |
|
EBITDAX ($ millions)
(1) |
$ |
92.1 |
|
|
$ |
57.3 |
|
|
$ |
279.9 |
|
|
$ |
178.0 |
|
(1) Discretionary cash flow, adjusted net income (loss) and
EBITDAX are non-GAAP (Generally Accepted Accounting Principles)
measures. Please reference the reconciliations to GAAP financial
statements at the end of this release.
At December 31, 2018, the Company’s $500 million
revolving credit facility had zero drawn and $474.0 million in
available capacity, after taking into account a $26.0 million
letter of credit. The principal balance of long-term debt was
$626.9 million and cash and cash equivalents were $32.8 million,
resulting in net debt (principal balance of debt outstanding less
the cash and cash equivalents balance) of $594.1 million.
Capital Expenditures
Capital expenditures of $508.9 million for 2018
included spudding 103 gross operated wells and placing 87 gross
operated wells on initial flowback. Capital expenditures were at
the low end of the Company's guidance range of $500-$550 million
and included $448.9 million for drilling and completion operations,
$19.9 million for leasehold and minerals, and $40.1 million for
infrastructure and corporate purposes. XRL well costs averaged
approximately $5.1 million for Hereford and $4.85 million for NE
Wattenberg.
Capital expenditures for the fourth quarter of
2018 totaled $127.8 million, which compares to the Company's
guidance range of $120-$130 million. Capital expenditures included
spudding 33 gross operated wells and placing 11 gross operated
wells on initial flowback. Capital expenditures included $106.1
million for drilling and completion operations, $11.6 million for
leaseholds, and $10.1 million for infrastructure and corporate
assets.
OPERATIONAL HIGHLIGHTS
Hereford Field
Production sales volumes for the fourth quarter
of 2018 averaged 5,977 Boe/d (76% oil), which is a 40% increase
over the fourth quarter of 2017. During the fourth quarter, 24
wells were spud and 7 wells were placed on flowback. During the
early development stage, the Company has utilized the same
drilling, completion and controlled flowback methodology used in NE
Wattenberg. This has yielded encouraging early program results,
including high oil cuts in excess of 90% in the initial months of
production. Positive indications of economic performance have been
demonstrated by the best performing well located in DSU 11-63-14
which has reached cumulative production of approximately 50,000
barrels of oil equivalent (88% oil) after 130 days of production
utilizing modified controlled flowback. This early performance
validates the Company's assessment of the resource potential of the
field and reflects the quality and productivity of the
reservoir.
As part of a continuous improvement of the
Company's optimized completions and controlled flowback
methodology, an extensive reservoir and geologic technical study of
early well performance was initiated. Microseismic and fiber optic
technology is being utilized with work already in progress to
determine the optimal stimulation design and well spacing to be
utilized for future development. In addition, a methodical
sequencing of drilling and completion operations is being
implemented to mitigate interference from offset activity as
development progresses across multiple DSUs. This real-time
collection of data and performance monitoring will provide
immediate feedback with respect to future completions, facilitate
the application of completion technology and validate well spacing
assumptions.
Drilling and completion costs averaged
approximately $5.1 million in 2018 and based on execution
efficiencies and design changes are expected to average
approximately $4.9 million in 2019.
NE Wattenberg
During 2018, production sales volumes from NE
Wattenberg averaged 24,497 Boe/d (60% oil), which represents a 43%
increase over 2017. In the fourth quarter of 2018, production sales
volumes averaged 27,849 Boe/d (61% oil), which represents a 32%
increase over the fourth quarter of 2017. For the fourth quarter of
2018, the Company spud 9 XRL wells and placed 4 XRL wells on
initial flowback. A high fluid intensity completion pilot program
was initiated in DSU 5-62-26 (6 XRL wells) and DSU 5-62-35 (5 XRL
wells) during 2018. Early well results are encouraging as the
average cumulative production is tracking above wells utilizing the
previous completion design. Based on the early positive results
from these high-intensity stimulations, the Company is utilizing
this modified completion design as the new standard for the NE
Wattenberg development program.
Drilling and completion costs averaged
approximately $4.85 million in 2018 and based on execution
efficiencies and design changes expected to average approximately
$4.5 million in 2019.
2019 OPERATING GUIDANCE
The Company enters 2019 having ample liquidity,
a strong underlying hedge position, nominal drilling commitments
and no long-term drilling or completion contracts. The 2019 capital
expenditure budget is expected to be in a range of $350-$380
million and includes spudding approximately 100 gross wells. The
capital program is predicated on pricing of $50.00 per barrel WTI
oil and $3.00 per Mcf natural gas. Based on the expected timing and
sequencing of development, the capital program is weighted to the
first half of 2019. The Company will remain flexible with its 2019
capital spending plans and has the ability to adjust spending as
warranted. Based on this level of development activity, production
sales volumes are expected to grow approximately 25% at the
mid-point of guidance year-over-year.
The Company is providing the following guidance
for its 2019 activities. See "Forward-Looking Statements"
below.
• Capital expenditures of approximately $350-$380
million
- Designed to be cash flow positive in the second half of
2019.
- Expect to spud approximately 100 gross wells and place
approximately 85 gross wells on flowback; one continuous completion
crew will be utilized.
- Based on expected timing and sequencing of the development
program capital expenditures are weighted toward the first half of
2019.
- Drilling and completion costs are anticipated to be
approximately 10% lower per well than 2018 based on execution
efficiencies and design changes.
- First quarter of 2019 capital expenditures are expected to be
approximately $125-$135 million.
• Production of 12.5-13.0 MMBoe
- Represents a production level that is approximately 25% higher
at the mid-point than 2018.
- Production is estimated to be approximately 62%-64% oil.
- First quarter of 2019 production is expected to approximate
2.7-2.9 MMBoe (approximately 62% oil), which represents lower
sequential production from the fourth quarter of 2018 and reflects
lower aggregate spending during 2018 and the timing of certain well
completions.
• Oil price differential of approximately $4.00 per
barrel
- Incorporates an increase in DJ Basin trucking costs that have
increased approximately 30% since mid-2018.
• Lease operating expense of $35-$39
million• Cash general and administrative expense of
$41-$45 million• Gathering, transportation and
processing costs of $10-$12 million• Unused commitment
for firm natural gas transportation charges of $18-$19 million
COMMODITY HEDGES UPDATE
As of February 26, 2019, the Company had the following commodity
hedge positions in place for 2019 and 2020:
|
|
Oil (WTI) |
|
Oil (WTI) Collars |
|
Natural Gas (NWPL) |
|
Natural Gas (NWPL) Collars |
Period |
|
Volume Bbls/d |
|
Price $/Bbl |
|
Volume Bbls/d |
|
Floor $/Bbl |
|
Ceiling $/Bbl |
|
Volume MMBtu/d |
|
Price $/MMBtu |
|
Volume MMBtu/d |
|
Floor $/MMBtu |
|
Ceiling $/MMBtu |
1Q19 |
|
17,085 |
|
|
$ |
58.33 |
|
|
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
12,500 |
|
|
$ |
3.06 |
|
|
2,500 |
|
|
$ |
3.25 |
|
|
$ |
4.45 |
|
2Q19 |
|
17,250 |
|
|
59.18 |
|
|
— |
|
|
— |
|
|
— |
|
|
7,000 |
|
|
2.11 |
|
|
— |
|
|
— |
|
|
— |
|
3Q19 |
|
16,731 |
|
|
59.00 |
|
|
3,000 |
|
|
55.00 |
|
|
77.56 |
|
|
7,000 |
|
|
2.11 |
|
|
— |
|
|
— |
|
|
— |
|
4Q19 |
|
16,712 |
|
|
59.01 |
|
|
3,000 |
|
|
55.00 |
|
|
77.56 |
|
|
7,000 |
|
|
2.11 |
|
|
— |
|
|
— |
|
|
— |
|
1Q20 |
|
10,000 |
|
|
60.26 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
2Q20 |
|
10,000 |
|
|
60.26 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
3Q20 |
|
8,000 |
|
|
59.16 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
4Q20 |
|
8,000 |
|
|
59.16 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Realized sales prices will reflect basis
differentials from the index prices to the sales location.
UPCOMING EVENTS
Teleconference Call and
Webcast
The Company plans to host a conference call on
Wednesday, February 27, 2019, to discuss the results and other
items presented in this press release. The call is scheduled at
10:00 a.m. Eastern time (8:00 a.m. Mountain time). Please join the
webcast conference call live or for replay via the Internet at
www.hpres.com, accessible from the home page. To join by telephone,
call 855-760-8152 (631-485-4979 international callers) with
passcode 2991479. The webcast will remain on the Company's website
for approximately 30 days and a replay of the call will be
available through Wednesday, March 6, 2019 at 855-859-2056
(404-537-3406 international) with passcode 2991479.
An updated corporate slide presentation that
will be referenced on the conference call will be available on the
“Investor Relations” section of the Company’s website prior to the
start of the call.
Investor Events
Members of management are scheduled to
participate in the Scotia Howard Weil Energy Conference in New
Orleans, Louisiana, March 25-26, 2019. Chief Executive Officer and
President, Scot Woodall is scheduled to present on Monday, March
25, 2019, at 2:30 pm Central time. Presentation materials will be
posted to the investor relations section of the Company's website
at www.hpres.com prior to the start of the conference.
The Company’s annual meeting of shareholders
will be held on May 1, 2019 at 8:30 a.m. Mountain time at the
Company’s offices in Denver, Colorado.
DISCLOSURE STATEMENTS
Forward-Looking Statements
All statements in this press release, other than
statements of historical fact, are forward-looking statements
within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934.
Words such as expects, forecast, guidance, anticipates, intends,
plans, believes, seeks, estimates and similar expressions or
variations of such words are intended to identify forward-looking
statements herein; however, these are not the exclusive means of
identifying forward-looking statements. In particular, the Company
is providing "2019 Operating Guidance", which contains projections
for certain operational and financial metrics. Additional
forward-looking statements in this release relate to, among other
things, future production, cash flows, capital expenditures, costs,
projects and opportunities and the effect of future regulatory
developments.
These and other forward-looking statements in
this press release are based on management's judgment as of the
date of this release and are subject to numerous risks and
uncertainties. Actual results may vary significantly from those
indicated in the forward-looking statements. Please refer to
HighPoint Resource's Annual Report on Form 10-K for the year ended
December 31, 2018 filed with the SEC, and other filings,
including our Current Reports on Form 8-K and Quarterly Reports on
Form 10-Q, all of which are incorporated by reference herein, for
further discussion of risk factors that may affect the
forward-looking statements. The Company encourages you to consider
the risks and uncertainties associated with projections and other
forward-looking statements and to not place undue reliance on any
such statements. In addition, the Company assumes no obligation to
publicly revise or update any forward-looking statements based on
future events or circumstances.
ABOUT HIGHPOINT RESOURCES
CORPORATION
HighPoint Resources Corporation (NYSE: HPR) is a
Denver, Colorado based company focused on the development of oil
and natural gas assets located in the Denver-Julesburg Basin of
Colorado. Additional information about the Company may be found on
its website at www.hpres.com.
|
HIGHPOINT RESOURCES CORPORATION |
Selected Operating Highlights |
(Unaudited) |
|
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
Production Data: |
|
|
|
|
|
|
|
Oil
(MBbls) |
1,970 |
|
|
1,274 |
|
|
6,330 |
|
|
4,203 |
|
Natural
gas (MMcf) |
3,912 |
|
|
2,868 |
|
|
12,864 |
|
|
8,952 |
|
NGLs
(MBbls) |
490 |
|
|
371 |
|
|
1,697 |
|
|
1,307 |
|
Combined
volumes (MBoe) |
3,112 |
|
|
2,123 |
|
|
10,171 |
|
|
7,002 |
|
Daily
combined volumes (Boe/d) |
33,826 |
|
|
23,076 |
|
|
27,866 |
|
|
19,184 |
|
|
|
|
|
|
|
|
|
Average
Sales Prices (before the effects of realized hedges): |
Oil (per
Bbl) |
$ |
56.35 |
|
|
$ |
52.63 |
|
|
$ |
62.04 |
|
|
$ |
48.37 |
|
Natural
gas (per Mcf) |
2.13 |
|
|
2.32 |
|
|
1.75 |
|
|
2.43 |
|
NGLs (per
Bbl) |
22.54 |
|
|
24.09 |
|
|
22.18 |
|
|
20.01 |
|
Combined
(per Boe) |
41.88 |
|
|
38.94 |
|
|
44.53 |
|
|
35.88 |
|
|
|
|
|
|
|
|
|
Average
Realized Sales Prices (after the effects of realized hedges): |
Oil (per
Bbl) |
$ |
54.08 |
|
|
$ |
53.98 |
|
|
$ |
54.51 |
|
|
$ |
52.72 |
|
Natural
gas (per Mcf) |
2.01 |
|
|
2.43 |
|
|
1.76 |
|
|
2.52 |
|
NGLs (per
Bbl) |
22.54 |
|
|
24.09 |
|
|
22.18 |
|
|
20.01 |
|
Combined
(per Boe) |
40.29 |
|
|
39.90 |
|
|
39.85 |
|
|
38.60 |
|
|
|
|
|
|
|
|
|
Average Costs (per
Boe): |
|
|
|
|
|
|
|
Lease
operating expenses |
$ |
2.17 |
|
|
$ |
3.27 |
|
|
$ |
2.74 |
|
|
$ |
3.46 |
|
Gathering, transportation and processing expense |
0.58 |
|
|
0.46 |
|
|
0.46 |
|
|
0.37 |
|
Production tax expenses |
3.34 |
|
|
2.51 |
|
|
3.61 |
|
|
2.07 |
|
Depreciation, depletion and amortization |
24.53 |
|
|
19.10 |
|
|
22.46 |
|
|
22.85 |
|
General
and administrative expense (1) |
3.44 |
|
|
5.51 |
|
|
4.44 |
|
|
6.07 |
|
(1) Includes long-term cash and equity incentive compensation of
$0.42 per Boe and $1.32 per Boe for the three months ended December
31, 2018 and 2017, respectively, and $0.71 per Boe and $1.18 per
Boe for the twelve months ended December 31, 2018 and 2017,
respectively.
|
HIGHPOINT RESOURCES CORPORATION |
Consolidated Condensed Balance
Sheets |
(Unaudited) |
|
|
As of December 31, |
|
As ofDecember
31, |
|
2018 |
|
2017 |
|
|
|
(in thousands) |
Assets: |
|
|
|
Cash and
cash equivalents |
$ |
32,774 |
|
|
$ |
314,466 |
|
Other
current assets (1) |
157,007 |
|
|
53,197 |
|
Property
and equipment, net |
2,029,523 |
|
|
1,018,880 |
|
Other
noncurrent assets |
33,156 |
|
|
4,163 |
|
Total
assets |
$ |
2,252,460 |
|
|
$ |
1,390,706 |
|
|
|
|
|
Liabilities and
Stockholders' Equity: |
|
|
|
Current
liabilities (1) |
$ |
248,185 |
|
|
$ |
148,934 |
|
Long-term
debt, net of debt issuance costs |
617,387 |
|
|
617,744 |
|
Other
long-term liabilities (1) |
174,790 |
|
|
25,474 |
|
Stockholders' equity |
1,212,098 |
|
|
598,554 |
|
Total
liabilities and stockholders' equity |
$ |
2,252,460 |
|
|
$ |
1,390,706 |
|
(1) At December 31, 2018, the estimated fair value of all
of the Company's commodity derivative instruments was a net asset
of $108.5 million, comprised of $81.2 million of current assets and
$27.3 million of noncurrent assets. This amount will fluctuate
based on estimated future commodity prices and the current hedge
position.
|
HIGHPOINT RESOURCES CORPORATION |
Consolidated Statements of
Operations |
(Unaudited) |
|
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
(in thousands, except per share
amounts) |
Operating
Revenues: |
|
|
|
|
|
|
|
Oil, gas
and NGL production |
$ |
130,383 |
|
|
$ |
82,674 |
|
|
$ |
452,917 |
|
|
$ |
251,215 |
|
Other
operating revenues |
300 |
|
|
698 |
|
|
100 |
|
|
1,624 |
|
Total
operating revenues |
130,683 |
|
|
83,372 |
|
|
453,017 |
|
|
252,839 |
|
Operating
Expenses: |
|
|
|
|
|
|
|
Lease
operating expense |
6,768 |
|
|
6,936 |
|
|
27,850 |
|
|
24,223 |
|
Gathering, transportation and processing expense |
1,815 |
|
|
971 |
|
|
4,644 |
|
|
2,615 |
|
Production tax expense |
10,399 |
|
|
5,336 |
|
|
36,762 |
|
|
14,476 |
|
Exploration expense |
31 |
|
|
35 |
|
|
70 |
|
|
83 |
|
Impairment, dry hole costs and abandonment expense |
110 |
|
|
41,217 |
|
|
719 |
|
|
49,553 |
|
(Gain)
loss on sale of properties |
— |
|
|
— |
|
|
1,046 |
|
|
(92 |
) |
Depreciation, depletion and amortization |
76,374 |
|
|
40,555 |
|
|
228,480 |
|
|
159,964 |
|
Unused
commitments |
4,503 |
|
|
4,544 |
|
|
18,187 |
|
|
18,231 |
|
General
and administrative expense (1) |
10,703 |
|
|
11,688 |
|
|
45,130 |
|
|
42,476 |
|
Merger
transaction expense |
1,851 |
|
|
8,749 |
|
|
7,991 |
|
|
8,749 |
|
Other
operating expenses, net |
1,989 |
|
|
96 |
|
|
1,273 |
|
|
(1,514 |
) |
Total
operating expenses |
114,543 |
|
|
120,127 |
|
|
372,152 |
|
|
318,764 |
|
Operating Income
(Loss) |
16,140 |
|
|
(36,755 |
) |
|
80,865 |
|
|
(65,925 |
) |
Other Income and
Expense: |
|
|
|
|
|
|
|
Interest
and other income |
(50 |
) |
|
329 |
|
|
1,793 |
|
|
1,359 |
|
Interest
expense |
(13,355 |
) |
|
(13,696 |
) |
|
(52,703 |
) |
|
(57,710 |
) |
Commodity
derivative gain (loss) (2) |
221,515 |
|
|
(28,766 |
) |
|
93,349 |
|
|
(9,112 |
) |
Gain
(loss) on extinguishment of debt |
— |
|
|
(335 |
) |
|
(257 |
) |
|
(8,239 |
) |
Total
other income and expense |
208,110 |
|
|
(42,468 |
) |
|
42,182 |
|
|
(73,702 |
) |
Income (Loss) before
Income Taxes |
224,250 |
|
|
(79,223 |
) |
|
123,047 |
|
|
(139,627 |
) |
(Provision for) Benefit
from Income Taxes |
(1,827 |
) |
|
1,402 |
|
|
(1,827 |
) |
|
1,402 |
|
Net Income (Loss) |
$ |
222,423 |
|
|
$ |
(77,821 |
) |
|
$ |
121,220 |
|
|
$ |
(138,225 |
) |
|
|
|
|
|
|
|
|
Net Income (Loss) per
Common Share |
|
|
|
|
|
|
|
Basic |
$ |
1.06 |
|
|
$ |
(0.94 |
) |
|
$ |
0.64 |
|
|
$ |
(1.80 |
) |
Diluted |
$ |
1.06 |
|
|
$ |
(0.94 |
) |
|
$ |
0.64 |
|
|
$ |
(1.80 |
) |
Weighted Average Common
Shares Outstanding |
|
|
|
|
|
|
|
Basic |
209,529 |
|
|
83,138 |
|
|
188,299 |
|
|
76,859 |
|
Diluted |
209,645 |
|
|
83,138 |
|
|
189,241 |
|
|
76,859 |
|
(1) Includes long-term cash and equity incentive compensation of
$1.3 million and $2.8 million for the three months ended December
31, 2018 and 2017, respectively, and $7.2 million and $8.3 million
for the twelve months ended December 31, 2018 and 2017,
respectively.(2) The table below summarizes the realized and
unrealized gains and losses the Company recognized related to its
oil and natural gas derivative instruments for the periods
indicated:
|
|
|
|
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
(in thousands) |
Included in commodity
derivative gain (loss): |
|
|
|
|
|
|
|
Realized
gain (loss) on derivatives |
$ |
(4,959 |
) |
|
$ |
2,037 |
|
|
$ |
(47,587 |
) |
|
$ |
19,099 |
|
Reversal
of prior year unrealized gain transferred to realized gain |
4,138 |
|
|
(903 |
) |
|
20,940 |
|
|
(4,053 |
) |
Unrealized gain (loss) on derivatives |
222,336 |
|
|
(29,900 |
) |
|
119,996 |
|
|
(24,158 |
) |
Total
commodity derivative gain (loss) |
$ |
221,515 |
|
|
$ |
(28,766 |
) |
|
$ |
93,349 |
|
|
$ |
(9,112 |
) |
|
HIGHPOINT RESOURCES CORPORATION |
Consolidated Statements of Cash
Flows |
(Unaudited) |
|
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
(in thousands) |
Operating
Activities: |
|
|
|
|
|
|
|
Net
income (loss) |
$ |
222,423 |
|
|
$ |
(77,821 |
) |
|
$ |
121,220 |
|
|
$ |
(138,225 |
) |
Adjustments to reconcile to net cash provided by
operations: |
Depreciation, depletion and amortization |
76,374 |
|
|
40,555 |
|
|
228,480 |
|
|
159,964 |
|
Impairment, dry hole costs and abandonment expense |
110 |
|
|
41,217 |
|
|
719 |
|
|
49,553 |
|
Unrealized derivative (gain) loss |
(226,474 |
) |
|
30,803 |
|
|
(140,936 |
) |
|
28,211 |
|
Deferred
income tax benefit |
1,827 |
|
|
— |
|
|
1,827 |
|
|
— |
|
Incentive
compensation and other non-cash charges |
2,524 |
|
|
1,462 |
|
|
8,337 |
|
|
6,596 |
|
Amortization of debt discounts and deferred financing costs |
636 |
|
|
529 |
|
|
2,365 |
|
|
2,194 |
|
(Gain)
loss on sale of properties |
— |
|
|
— |
|
|
1,046 |
|
|
(92 |
) |
(Gain)
loss on extinguishment of debt |
— |
|
|
335 |
|
|
257 |
|
|
8,239 |
|
Change in
operating assets and liabilities: |
|
|
|
|
|
|
|
Accounts
receivable |
(4,908 |
) |
|
(9,326 |
) |
|
(13,697 |
) |
|
(18,578 |
) |
Prepayments and other assets |
628 |
|
|
(868 |
) |
|
(793 |
) |
|
(1,848 |
) |
Accounts
payable, accrued and other liabilities |
(15,037 |
) |
|
(8,381 |
) |
|
(40,324 |
) |
|
11,690 |
|
Amounts
payable to oil and gas property owners |
695 |
|
|
4,031 |
|
|
34,499 |
|
|
10,402 |
|
Production taxes payable |
12,458 |
|
|
4,071 |
|
|
28,441 |
|
|
3,884 |
|
Net cash
provided by (used in) operating activities |
$ |
71,256 |
|
|
$ |
26,607 |
|
|
$ |
231,441 |
|
|
$ |
121,990 |
|
Investing
Activities: |
|
|
|
|
|
|
|
Additions
to oil and gas properties, including acquisitions |
(131,002 |
) |
|
(78,843 |
) |
|
(453,616 |
) |
|
(239,631 |
) |
Additions
of furniture, equipment and other |
(237 |
) |
|
(658 |
) |
|
(853 |
) |
|
(926 |
) |
Repayment
of debt associated with merger, net of cash acquired |
— |
|
|
— |
|
|
(53,357 |
) |
|
— |
|
Proceeds
from sale of properties and other investing activities |
132 |
|
|
102,258 |
|
|
143 |
|
|
101,546 |
|
Net cash
provided by (used in) investing activities |
$ |
(131,107 |
) |
|
$ |
22,757 |
|
|
$ |
(507,683 |
) |
|
$ |
(139,011 |
) |
Financing
Activities: |
|
|
|
|
|
|
|
Proceeds
from debt |
— |
|
|
— |
|
|
— |
|
|
275,000 |
|
Principal
and redemption premium payments on debt |
(119 |
) |
|
(115 |
) |
|
(469 |
) |
|
(322,343 |
) |
Deferred
financing costs and other |
(236 |
) |
|
(1,676 |
) |
|
(4,982 |
) |
|
(7,721 |
) |
Proceeds
from sale of common stock, net of offering costs |
— |
|
|
111,008 |
|
|
1 |
|
|
110,710 |
|
Net cash
provided by (used in) financing activities |
$ |
(355 |
) |
|
$ |
109,217 |
|
|
$ |
(5,450 |
) |
|
$ |
55,646 |
|
Increase (Decrease) in
Cash and Cash Equivalents |
(60,206 |
) |
|
158,581 |
|
|
(281,692 |
) |
|
38,625 |
|
Beginning Cash and Cash
Equivalents |
92,980 |
|
|
155,885 |
|
|
314,466 |
|
|
275,841 |
|
Ending Cash and Cash
Equivalents |
$ |
32,774 |
|
|
$ |
314,466 |
|
|
$ |
32,774 |
|
|
$ |
314,466 |
|
|
HIGHPOINT RESOURCES CORPORATION |
Reconciliation of Discretionary Cash Flow,
Adjusted Net Income (Loss) and EBITDAX |
(Unaudited) |
|
Discretionary Cash Flow Reconciliation |
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
(in thousands) |
Net Cash Provided by
(Used in) Operating Activities |
$ |
71,256 |
|
|
$ |
26,607 |
|
|
$ |
231,441 |
|
|
$ |
121,990 |
|
Adjustments to
reconcile to discretionary cash flow: |
|
|
|
|
|
|
|
Exploration expense |
31 |
|
|
35 |
|
|
70 |
|
|
83 |
|
Merger
transaction expense |
1,851 |
|
|
8,749 |
|
|
7,991 |
|
|
8,749 |
|
Changes
in working capital |
6,164 |
|
|
10,473 |
|
|
(8,126 |
) |
|
(5,550 |
) |
Discretionary Cash
Flow |
$ |
79,302 |
|
|
$ |
45,864 |
|
|
$ |
231,376 |
|
|
$ |
125,272 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income (Loss) Reconciliation
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
(in thousands, except per share
amounts) |
Net Income (Loss) |
$ |
222,423 |
|
|
$ |
(77,821 |
) |
|
$ |
121,220 |
|
|
$ |
(138,225 |
) |
Provision for
(Benefit from) income taxes |
1,827 |
|
|
(1,402 |
) |
|
1,827 |
|
|
(1,402 |
) |
Income (Loss) before
Income Taxes |
224,250 |
|
|
(79,223 |
) |
|
123,047 |
|
|
(139,627 |
) |
Adjustments to Net
Income (Loss): |
|
|
|
|
|
|
|
Unrealized derivative (gain) loss |
(226,474 |
) |
|
30,803 |
|
|
(140,936 |
) |
|
28,211 |
|
Impairment expense |
— |
|
|
— |
|
|
— |
|
|
49,098 |
|
(Gain)
loss on sale of properties |
— |
|
|
— |
|
|
1,046 |
|
|
(92 |
) |
(Gain)
loss on extinguishment of debt |
— |
|
|
335 |
|
|
257 |
|
|
8,239 |
|
One-time
items: |
|
|
|
|
|
|
|
Merger
transaction expense |
1,851 |
|
|
8,749 |
|
|
7,991 |
|
|
8,749 |
|
(Income)
expense related to properties sold |
1,989 |
|
|
96 |
|
|
1,273 |
|
|
(1,514 |
) |
Adjusted
Income (Loss) before Income Taxes |
1,616 |
|
|
(39,240 |
) |
|
(7,322 |
) |
|
(46,936 |
) |
Adjusted
(provision for) benefit from income taxes (1) |
(399 |
) |
|
(700 |
) |
|
1,803 |
|
|
17,760 |
|
Adjusted Net Income
(Loss) |
$ |
1,217 |
|
|
$ |
(39,940 |
) |
|
$ |
(5,519 |
) |
|
$ |
(29,176 |
) |
Per
share, diluted |
$ |
0.01 |
|
|
$ |
(0.48 |
) |
|
$ |
(0.03 |
) |
|
$ |
(0.38 |
) |
(1) Adjusted (provision for) benefit from income taxes is
calculated using the Company's current effective tax rate prior to
applying the valuation allowance against deferred tax assets.
EBITDAX Reconciliation
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
(in thousands) |
Net Income (Loss) |
$ |
222,423 |
|
|
$ |
(77,821 |
) |
|
$ |
121,220 |
|
|
$ |
(138,225 |
) |
Adjustments to
reconcile to EBITDAX: |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
76,374 |
|
|
40,555 |
|
|
228,480 |
|
|
159,964 |
|
Impairment, dry hole and abandonment expense |
110 |
|
|
41,217 |
|
|
719 |
|
|
49,553 |
|
Exploration expense |
31 |
|
|
35 |
|
|
70 |
|
|
83 |
|
Unrealized derivative (gain) loss |
(226,474 |
) |
|
30,803 |
|
|
(140,936 |
) |
|
28,211 |
|
Incentive
compensation and other non-cash charges |
2,524 |
|
|
1,462 |
|
|
8,337 |
|
|
6,596 |
|
Merger
transaction expense |
1,851 |
|
|
8,749 |
|
|
7,991 |
|
|
8,749 |
|
(Gain)
loss on sale of properties |
— |
|
|
— |
|
|
1,046 |
|
|
(92 |
) |
(Gain)
loss on extinguishment of debt |
— |
|
|
335 |
|
|
257 |
|
|
8,239 |
|
Interest
and other income |
50 |
|
|
(329 |
) |
|
(1,793 |
) |
|
(1,359 |
) |
Interest
expense |
13,355 |
|
|
13,696 |
|
|
52,703 |
|
|
57,710 |
|
Provision
for (benefit from) income taxes |
1,827 |
|
|
(1,402 |
) |
|
1,827 |
|
|
(1,402 |
) |
EBITDAX |
$ |
92,071 |
|
|
$ |
57,300 |
|
|
$ |
279,921 |
|
|
$ |
178,027 |
|
Discretionary cash flow and adjusted net income
(loss) are non-GAAP measures. These measures are presented because
management believes that they provide useful additional information
to investors for analysis of the Company's ability to internally
generate funds for exploration, development and acquisitions as
well as adjusting net income (loss) for certain items to allow for
a more consistent comparison from period to period. In addition,
the Company believes that these measures are widely used by
professional research analysts and others in the valuation,
comparison and investment recommendations of companies in the oil
and gas exploration and production industry, and that many
investors use the published research of industry research analysts
in making investment decisions.
These measures should not be considered in
isolation or as a substitute for net income, income from
operations, net cash provided by operating activities or other
income, profitability, cash flow or liquidity measures prepared in
accordance with GAAP. The definition of these measures may vary
among companies, and, therefore, the amounts presented may not be
comparable to similarly titled measures of other companies.
Company contact: Larry C. Busnardo, Vice
President, Investor Relations, 303-312-8514
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