EX-99.1 2 hpr-9302018xex991.htm EXHIBIT 99.1 Exhibit

hplogo3.jpg

Press Release

For immediate release

Company contact: Larry C. Busnardo, Vice President, Investor Relations, 303-312-8514

HighPoint Resources Reports Third Quarter 2018 Financial and Operating Results

•
Early DUC and development well performance validates the productivity and extent of the Hereford Field and the Company's economic model for full field development
•
Positive early production data from initial Hereford drilling and spacing unit ("DSU") as the wells are currently producing at a rate of 480 Boe/d (~90% oil) per well after approximately three weeks utilizing modified controlled flowback and continue to increase
•
Reported production sales volume of 2.74 million barrels of oil equivalent ("MMBoe") (63% oil) for the third quarter of 2018, represents an increase of 43% from the third quarter of 2017
•
Oil production sales volume of 1.72 million barrels of oil ("MMBbls") for the third quarter of 2018, represents an increase of 43% from the third quarter of 2017
•
Delivered basin operating margin1 of $40.69 per Boe, an increase of 44% over the third quarter of 2017 and driven by high oil weighting, an attractive oil price differential of $2.51 per barrel and low operating costs
•
Lease operating expense of $2.65 per Boe, a 14% decrease from the third quarter of 2017
•
Entered into a new amended and restated credit agreement that increased the borrowing base and commitments by 67% to $500 million, providing strong liquidity

DENVER - October 31, 2018 - HighPoint Resources Corporation (the "Company" or "HighPoint") (NYSE: HPR) today reported third quarter of 2018 financial and operating results highlighted by strong growth in oil volumes and EBITDAX and lower lease operating expense.

For the third quarter of 2018, the Company reported a net loss of $29.4 million, or $0.14 per diluted share. Adjusted net income for the third quarter of 2018 was $2.3 million, or $0.01 per diluted share. EBITDAX for the third quarter of 2018 was $78.0 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, "I am pleased with our execution and initial results of the Hereford program in the two full quarters since acquisition. The development program has confirmed our acquisition and economic model for this large, oil-weighted and rural acreage block. We are seeing positive early indications of performance from our initial DSU as the wells have been online for three weeks and are producing at a current average per well rate of approximately 480 Boe/d, of which approximately 90% is oil, and continue to increase. In addition, the early well performance from the DUCs validates the productivity of the Hereford Field and the Company's economic model for full field development. Two of the best performing wells are located six miles apart and have established strong indications of productive deliverability from east to west across our acreage position.


1 Basin operating margin is defined as the average realized price per Boe before hedging less lease operating expense, gathering, transportation and process expense and production tax expense

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"We successfully managed through mid-stream constraints that persisted into the third quarter and delivered financial results that were highlighted by a 14% sequential increase in both equivalent production and oil volumes, strong growth in EBITDAX, and lower lease operating expense. Oil represented 63% of total equivalent production and we anticipate that the percentage of oil volumes will continue to grow in future quarters as the Hereford development program is expanded. DCP's commissioning of the Mewbourn 3 gas processing facility was completed during the quarter and reached design capacity of 200 MMcf/d in mid-September. We have strategically diversified our gas processing exposure in Northeast ("NE") Wattenberg to other outlets, which will approximately double our first half of 2018 processing capacity by year-end. We believe this flexibility will limit our exposure to any future mid-stream constraints in NE Wattenberg and mitigates our reliance on DCP.

"Our favorable oil weighting, low cost structure and attractive oil differential allows us to deliver a peer leading basin operating margin of $40.69 per Boe for the third quarter. We are well positioned to generate a strong growth profile with a dominant acreage position in the oily and rural areas of the DJ Basin. We will continue our disciplined capital approach and maintain ample liquidity of $567 million that supports our development program going forward."

OPERATING AND FINANCIAL RESULTS

The following table summarizes certain operating and financial results for the third quarter of 2018 and 2017 and for the second quarter of 2018:

 
Three Months Ended 
 September 30,
 
Three Months Ended 
 June 30,
 
2018
 
2017
 
Change
 
2018
 
Change
Combined production sales volumes (MBoe)
2,736

 
1,920

 
43
 %
 
2,409

 
14
%
Net cash provided by operating activities ($ millions)
$
91.3

 
$
57.2

 
60
 %
 
$
14.6

 
525
%
Discretionary cash flow ($ millions) (1)
$
65.9

 
$
34.8

 
89
 %
 
$
51.3

 
28
%
Combined realized prices with hedging (per Boe)
$
41.23

 
$
38.78

 
6
 %
 
$
39.29

 
5
%
Net income (loss) ($ millions)
$
(29.4
)
 
$
(28.8
)
 
(2
)%
 
$
(46.9
)
 
37
%
Per share, basic
$
(0.14
)
 
$
(0.39
)
 
64
 %
 
$
(0.22
)
 
36
%
Per share, diluted
$
(0.14
)
 
$
(0.39
)
 
64
 %
 
$
(0.22
)
 
36
%
Adjusted net income (loss) ($ millions) (1)
$
2.3

 
$
(5.9
)
 
*nm

 
$
(3.2
)
 
*nm

Per share, basic
$
0.01

 
$
(0.08
)
 
*nm

 
$
(0.02
)
 
*nm

Per share, diluted
$
0.01

 
$
(0.08
)
 
*nm

 
$
(0.02
)
 
*nm

Weighted average shares outstanding, basic (in thousands)
209,502

 
74,886

 
180
 %
 
209,393

 
—
%
Weighted average shares outstanding, diluted (in thousands) (1)
209,502

 
74,886

 
180
 %
 
209,393

 
—
%
EBITDAX ($ millions) (2)
$
78.0

 
$
47.9

 
63
 %
 
$
63.1

 
24
%

*
Not meaningful.

(1)
The three months ended September 30, 2018 adjusted net income per diluted share is calculated with 210,728,243 diluted weighted average shares outstanding.
(2)
Discretionary cash flow, adjusted net income (loss) and EBITDAX are non-GAAP measures. Please reference the reconciliations to GAAP financial statements at the end of this release.

The Company reported oil, natural gas and natural gas liquids ("NGL") production of 2.74 MMBoe for the third quarter of 2018, which was an increase of 43% over the third quarter of 2017. Oil volumes

2

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totaled 1.72 MMBbls or 63% of total equivalent volumes, which was an increase of 43% over the third quarter of 2017. Production sales volumes from NE Wattenberg totaled 2.3 MMBoe and Hereford volumes totaled 0.4 MMBoe.

Production sales volumes were comprised of approximately 63% oil, 20% natural gas and 17% NGLs.

Pro forma production for the first nine months of 2018 was 7.4 MMBoe (62% oil and includes approximately 0.3 MMBoe associated with Hereford for the first quarter of 2018) and it is estimated that 0.5 MMBoe of production has been adversely impacted due to mid-stream constraints. Despite DCP's addition of processing capacity, the Company continues to be impacted by high line pressures, which is having a modest impact on production.

For the third quarter of 2018, WTI oil prices averaged $69.50 per barrel, Northwest Pipeline ("NWPL") natural gas prices averaged $2.32 per MMBtu and NYMEX natural gas prices averaged $2.91 per MMBtu. Commodity price realizations to benchmark pricing were WTI less $2.51 per barrel of oil and NWPL less $0.73 per Mcf of gas. The NGL price averaged approximately 35% of the WTI price per barrel.

For the third quarter of 2018, the Company had derivative commodity swaps in place for 13,843 barrels of oil per day tied to WTI pricing at $54.62 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 
 September 30,
 
Three Months Ended 
 June 30,
 
2018
 
2017
 
Change
 
2018
 
Change
Average Realized Prices before Hedging:
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
66.96

 
$
46.08

 
45
 %
 
$
65.07

 
3
%
Natural gas (per Mcf)
1.59

 
2.37

 
(33
)%
 
1.29

 
23
%
NGLs (per Bbl)
24.31

 
18.93

 
28
 %
 
20.84

 
17
%
Combined (per Boe)
48.10

 
34.99

 
37
 %
 
45.71

 
5
%
 
 
 
 
 
 
 
 
 
 
Average Realized Prices with Hedging:
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
55.92

 
$
51.86

 
8
 %
 
$
54.59

 
2
%
Natural gas (per Mcf)
1.64

 
2.51

 
(35
)%
 
1.40

 
17
%
NGLs (per Bbl)
24.31

 
18.93

 
28
 %
 
20.84

 
17
%
Combined (per Boe)
41.23

 
38.78

 
6
 %
 
39.29

 
5
%

Lease operating expense ("LOE") averaged $2.65 per Boe in the third quarter of 2018 compared to $3.08 per Boe in the third quarter of 2017. The year-over-year reduction in LOE is primarily a result of improved operating efficiencies, higher production sales volumes, and disposition of higher LOE wells in Utah.

Production tax expense averaged $4.20 per Boe in the third quarter of 2018 compared to $2.80 per Boe in the third quarter of 2017. Higher production tax expense was primarily the result of higher oil prices. Production tax expense averaged approximately 9% of revenues in the third quarter of 2018 compared to 8% of revenues in the third quarter of 2017.


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Depreciation, depletion and amortization averaged $21.54 per Boe in the third quarter of 2018 compared to $22.52 per Boe in the third quarter of 2017.

 
Three Months Ended 
 September 30,
 
Three Months Ended 
 June 30,
 
2018
 
2017
 
Change
 
2018
 
Change
Average Costs (per Boe):
 
 
 
 
 
 
 
 
 
Lease operating expenses
$
2.65

 
$
3.08

 
(14
)%
 
$
3.15

 
(16
)%
Gathering, transportation and processing expense
0.51

 
0.32

 
59
 %
 
0.42

 
21
 %
Production tax expenses
4.20

 
2.80

 
50
 %
 
4.02

 
4
 %
Depreciation, depletion and amortization
21.54

 
22.52

 
(4
)%
 
21.66

 
(1
)%
General and administrative expense
4.64

 
6.51

 
(29
)%
 
4.83

 
(4
)%

Debt and Liquidity

At September 30, 2018, the principal debt balance was $627.0 million, while cash and cash equivalents were $93.0 million, resulting in net debt of $534.0 million. Cash and cash equivalents were primarily used during the quarter to execute on the third quarter development program.

On September 17, 2018, the Company announced that it had entered into a new amended and restated credit agreement for its revolving credit facility (“Facility”). The agreement extended the maturity date of the Facility by over three years to 2023 and increased the borrowing base and commitments by 67% to $500 million. The increase in the borrowing base is a result of the greater value of the NE Wattenberg assets due to ongoing development and reflects contribution from the Hereford assets. The Company currently has no amounts drawn on the facility and has $474 million in available borrowing capacity on the Facility after taking into account a $26 million letter of credit.

Capital Expenditures

Capital expenditures for the third quarter of 2018 totaled $124.0 million. The Company operated three drilling rigs and capital projects included spudding 21 extended reach lateral ("XRL") wells and placing 27 XRL wells on initial flowback. Capital expenditures were lower than anticipated as greater than expected rig and service-related downtime resulted in the deferral of certain planned spuds and completions during the quarter.

Capital expenditures included $109.3 million for drilling and completion operations, $5.8 million for leasehold, and $8.9 million for infrastructure and corporate assets.

OPERATIONAL UPDATE

Hereford Field

Production sales volumes for the third quarter of 2018 in the Hereford Field averaged 4,255 Boe/d (75% oil), which is a 68% increase over the second quarter of 2018. During the third quarter, 14 wells were spud and 8 wells were placed on flowback, including the initial 5 wells that were drilled and completed by the Company. Drilling operations commenced in April on DSU 11-63-14, which included 10 XRL wells (6 Niobrara and 4 Codell). Drilling was completed in June and flowback began on the initial four wells at the end of September (one well had mechanical issues and is being used as an observation well). The four wells were completed utilizing the Company's standard completion

4

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design and modified controlled flowback methodology. Drilling and completion costs for the four wells averaged $5.1 million, which is consistent with cost expectations for the Hereford Field. The Company is seeing positive early indications of performance as the wells have been on flowback for approximately three weeks and are currently producing at an average rate of 480 Boe/d per well, of which approximately 90% is oil, and continue to increase.

Completion operations continue on DSU 11-63-15 (10 XRL wells) and DSU 11-64-23 (3 XRL wells) and it is anticipated that the wells will be placed on flowback during the fourth quarter of 2018. Drilling operations have commenced on DSU 11-63-16 (15 XRL wells).

Flowback commenced from the nine XRL wells drilled, but not completed, by the previous operator in June and July, respectively. After completing two full quarters since acquisition, early production data has confirmed the Company's acquisition and initial development model, including high oil content, productive deliverability across the acreage position and expectations of completion costs. The wells have exhibited some production variations due to a combination of tighter effective spacing of 18 wells per DSU, mechanical issues, and certain Codell wells being drilled as vertical offsets to Niobrara wells compared to a standard "wine rack" development pattern. The best performing well is located in DSU 11-63-13 on the eastern portion of the field and has shown strong indications of performance as it reached a peak initial rate of approximately 700 Boe/d (84% oil) from a lateral of 8,377 feet utilizing modified controlled flowback. The well is located adjacent to the initial development wells located in DSU 11-63-14. The Company has also seen solid production from the western portion of the field as one of the DUCs in DSU 11-63-18 reached a peak initial rate of approximately 620 Boe/d (90% oil) utilizing modified controlled flowback. This early well performance, which is located across a six mile section of the Hereford Field, supports the Company's model for the full scale Hereford development program.

NE Wattenberg

The Company produced an average of 25,477 Boe/d (61% oil) in the third quarter of 2018 in NE Wattenberg, representing a 38% increase over the third quarter of 2017. For the third quarter of 2018, the Company drilled 7 XRL wells and placed 19 XRL wells on initial flowback. The Company continues to see strong performance from DSU 5-61-27 (10 XRL wells), which is located in the east-central portion of NE Wattenberg. Initial flowback began in the second quarter and after six months of production the wells are currently producing approximately 615 Boe/d (80% oil) per well, highlighting the resource opportunity of the remaining 15 undeveloped DSUs in this area of the field.

MARKETING UPDATE

The Company’s NE Wattenberg gas volume allocated to DCP progressively increased during the third quarter as a result of DCP's Mewbourn 3 gas processing facility being commissioned in August and reaching design capacity in September. The Company has diversified its gas processing exposure in NE Wattenberg to other outlets and has approximately doubled its first half 2018 capacity, with a further increase expected in the first half of 2019. This added flexibility mitigates the Company's reliance on DCP and limits any local mid-stream issues in NE Wattenberg for the foreseeable future.

FOURTH QUARTER OPERATING GUIDANCE

The Company is providing capital expenditure and production guidance for the fourth quarter of 2018 as discussed below.

See "Forward-Looking Statements" below.

5

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•
Capital expenditures of $120-$130 million
◦
Incorporates the impact of recent third-party rig and service-related downtime, which resulted in the deferral of certain drilling and completion activity to the first quarter of 2019

•
Production sales volumes of 3.1-3.3 MMBoe
 
•
Oil volumes of 2.0-2.1 MMBbls or approximately 64% of total production volumes

•
Lease operating expense of $8-$9 million

•
General and administrative expenses of $10-$11 million

•
Gathering, transportation and processing costs of $2-$3 million

COMMODITY HEDGES UPDATE

The following table summarizes our current hedge position as of October 31, 2018:

 
Oil (WTI) Swaps
 
Oil (WTI) Collars
 
Natural Gas (NWPL) Swaps
Period
Volume
Bbls/d
 
Price
$/Bbl
 
Volume
Bbls/d
 
Floor
$Bbl
 
Ceiling
$/Bbl
 
Volume
MMBtu/d
 
Price
$/MMBtu
4Q18
13,806

 
$
54.63

 
2,000

 
$
60.00

 
$
77.27

 
5,000

 
$
2.68

1Q19
17,774

 
$
58.33

 
—

 
$
—

 
$
—

 
5,000

 
$
2.05

2Q19
19,250

 
$
59.09

 
—

 
$
—

 
$
—

 
5,000

 
$
2.05

3Q19
18,231

 
$
58.96

 
3,000

 
$
55.00

 
$
77.56

 
5,000

 
$
2.05

4Q19
18,212

 
$
58.97

 
3,000

 
$
55.00

 
$
77.56

 
5,000

 
$
2.05

1Q20
7,000

 
$
61.92

 
—

 
$
—

 
$
—

 
—

 
$
—

2Q20
7,000

 
$
61.92

 
—

 
$
—

 
$
—

 
—

 
$
—

3Q20
5,500

 
$
60.57

 
—

 
$
—

 
$
—

 
—

 
$
—

4Q20
5,500

 
$
60.57

 
—

 
$
—

 
$
—

 
—

 
$
—


Realized sales prices will reflect basis differentials from the index prices to the sales location.

UPCOMING EVENTS

Third Quarter Conference Call and Webcast

The Company plans to host a conference call on Thursday, November 1, 2018, to discuss third quarter 2018 results. 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 1459015. The webcast will remain on the Company's website for approximately 7 days and a replay of the call will be available through November 8, 2018 at (855) 859-2056 ((404) 537-3406 international) with passcode 1459015.

DISCLOSURE STATEMENTS

Forward-Looking Statements

6

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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 "Fourth Quarter Operating Guidance", which contains projections for certain fourth quarter operational and financial metrics. Additional forward-looking statements in this release relate to, among other things, future capital expenditures, costs, projects and opportunities; and the availability of adequate natural gas processing capacity, future line pressures and the timing and effect of new midstream facilities, and future diversification of gas processing capacity.

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 the Bill Barrett Corporation's Annual Report on Form 10-K for the year ended December 31, 2017 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. In addition, actual results could differ from those indicated by the forward-looking statements due to future regulatory developments, including Proposition 112. See our Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 for additional information. 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.

7

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HIGHPOINT RESOURCES CORPORATION
Selected Operating Highlights
(Unaudited)

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
1,716

 
1,202

 
4,360

 
2,929

Natural gas (MMcf)
3,294

 
2,274

 
8,946

 
6,084

NGLs (MBbls)
471

 
339

 
1,207

 
936

Combined volumes (MBoe)
2,736

 
1,920

 
7,058

 
4,879

Daily combined volumes (Boe/d)
29,739

 
20,870

 
25,853

 
17,872

 
 
 
 
 
 
 
 
Average Sales Prices (before the effects of realized hedges):
Oil (per Bbl)
$
66.96

 
$
46.08

 
$
64.61

 
$
46.52

Natural gas (per Mcf)
1.59

 
2.37

 
1.59

 
2.48

NGLs (per Bbl)
24.31

 
18.93

 
22.04

 
18.40

Combined (per Boe)
48.10

 
34.99

 
45.70

 
34.54

 
 
 
 
 
 
 
 
Average Realized Sales Prices (after the effects of realized hedges):
Oil (per Bbl)
$
55.92

 
$
51.86

 
$
54.70

 
$
52.18

Natural gas (per Mcf)
1.64

 
2.51

 
1.65

 
2.56

NGLs (per Bbl)
24.31

 
18.93

 
22.04

 
18.40

Combined (per Boe)
41.23

 
38.78

 
39.66

 
38.04

 
 
 
 
 
 
 
 
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expenses
$
2.65

 
$
3.08

 
$
2.99

 
$
3.54

Gathering, transportation and processing expense
0.51

 
0.32

 
0.40

 
0.34

Production tax expenses
4.20

 
2.80

 
3.74

 
1.87

Depreciation, depletion and amortization
21.54

 
22.52

 
21.55

 
24.81

General and administrative expense (1)
4.64

 
6.51

 
4.88

 
6.31


(1)
Includes long-term cash and equity incentive compensation of $0.82 per Boe and $1.40 per Boe for the three months ended September 30, 2018 and 2017, respectively, and $0.84 per Boe and $1.12 per Boe for the nine months ended September 30, 2018 and 2017, respectively.


8

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HIGHPOINT RESOURCES CORPORATION
Consolidated Condensed Balance Sheets
(Unaudited)

 
As of
September 30,
 
As of
December 31,
 
2018
 
2017
 
(in thousands)
Assets:
 
 
 
Cash and cash equivalents
$
92,980

 
$
314,466

Other current assets
71,002

 
53,197

Property and equipment, net
1,973,869

 
1,018,880

Other noncurrent assets
6,795

 
4,163

Total assets
$
2,144,646

 
$
1,390,706

 
 
 
 
Liabilities and Stockholders' Equity:
 
 
 
Current liabilities (1)
$
338,832

 
$
148,934

Long-term debt, net of debt issuance costs
617,006

 
617,744

Other long-term liabilities (1)
201,011

 
25,474

Stockholders' equity
987,797

 
598,554

Total liabilities and stockholders' equity
$
2,144,646

 
$
1,390,706


(1)
At September 30, 2018, the estimated fair value of all of the Company's commodity derivative instruments was a liability of $118.0 million, comprised of $87.5 million of current liabilities and $30.5 million of non-current liabilities. This amount will fluctuate based on estimated future commodity prices and the current hedge position.


9

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HIGHPOINT RESOURCES CORPORATION
Consolidated Statements of Operations
(Unaudited)

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per share amounts)
Operating Revenues:
 
 
 
 
 
 
 
Oil, gas and NGL production
$
131,585

 
$
67,175

 
$
322,534

 
$
168,541

Other operating revenues, net
(459
)
 
690

 
(200
)
 
926

Total operating revenues
131,126

 
67,865

 
322,334

 
169,467

Operating Expenses:
 
 
 
 
 
 
 
Lease operating
7,237

 
5,919

 
21,082

 
17,287

Gathering, transportation and processing
1,398

 
620

 
2,829

 
1,644

Production tax
11,504

 
5,384

 
26,363

 
9,140

Exploration
19

 
18

 
39

 
48

Impairment, dry hole costs and abandonment
184

 
261

 
609

 
8,336

(Gain) Loss on sale of properties
74

 
—

 
1,046

 
(92
)
Depreciation, depletion and amortization
58,946

 
41,732

 
152,106

 
119,409

Unused commitments
4,574

 
4,557

 
13,684

 
13,687

General and administrative (1)
12,696

 
12,496

 
34,427

 
30,788

Merger transaction expense
100

 
—

 
6,140

 
—

Other operating expenses, net
(764
)
 
(282
)
 
(716
)
 
(1,610
)
Total operating expenses
95,968

 
70,705

 
257,609

 
198,637

Operating Income (Loss)
35,158

 
(2,840
)
 
64,725

 
(29,170
)
Other Income and Expense:
 
 
 
 
 
 
 
Interest and other income
451

 
332

 
1,843

 
1,030

Interest expense
(13,165
)
 
(13,926
)
 
(39,348
)
 
(44,014
)
Commodity derivative gain (loss) (2)
(51,547
)
 
(12,408
)
 
(128,166
)
 
19,654

Gain (loss) on extinguishment of debt
(257
)
 
—

 
(257
)
 
(7,904
)
Total other income and expense
(64,518
)
 
(26,002
)
 
(165,928
)
 
(31,234
)
Income (Loss) before Income Taxes
(29,360
)
 
(28,842
)
 
(101,203
)
 
(60,404
)
(Provision for) Benefit from Income Taxes
—

 
—

 
—

 
—

Net Income (Loss)
$
(29,360
)
 
$
(28,842
)
 
$
(101,203
)
 
$
(60,404
)
 
 
 
 
 
 
 
 
Net Income (Loss) per Common Share
 
 
 
 
 
 
 
Basic
$
(0.14
)
 
$
(0.39
)
 
$
(0.56
)
 
$
(0.81
)
Diluted
$
(0.14
)
 
$
(0.39
)
 
$
(0.56
)
 
$
(0.81
)
Weighted Average Common Shares Outstanding
 
 
 
 
 
 
 
Basic
209,502

 
74,886

 
181,145

 
74,743

Diluted
209,502

 
74,886

 
181,145

 
74,743


(1)
Includes long-term cash and equity incentive compensation of $2.3 million and $2.7 million for the three months ended September 30, 2018 and 2017, respectively, and $5.9 million and $5.5 million for the nine months ended September 30, 2018 and 2017, respectively.




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(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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Included in commodity derivative gain (loss):
 
 
 
 
 
 
 
Realized gain (loss) on derivatives (1)
$
(18,780
)
 
$
7,263

 
$
(42,628
)
 
$
17,062

Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
4,920

 
(1,036
)
 
20,940

 
(2,114
)
Unrealized gain (loss) on derivatives (1)
(37,687
)
 
(18,635
)
 
(106,478
)
 
4,706

Total commodity derivative gain (loss)
$
(51,547
)
 
$
(12,408
)
 
$
(128,166
)
 
$
19,654


(1)
Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of the Company's hedge position. The Company also believes that this disclosure allows for a more accurate comparison to its peers.


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HIGHPOINT RESOURCES CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Operating Activities:
 
 
 
 
 
 
 
Net income (loss)
$
(29,360
)
 
$
(28,842
)
 
$
(101,203
)
 
$
(60,404
)
Adjustments to reconcile to net cash provided by operations:
 
 
 
 
 
 
 
Depreciation, depletion and amortization
58,946

 
41,732

 
152,106

 
119,409

Impairment, dry hole costs and abandonment
184

 
261

 
609

 
8,336

Unrealized derivative (gain) loss
32,767

 
19,672

 
85,538

 
(2,592
)
Incentive compensation and other non-cash charges
2,323

 
1,480

 
5,813

 
5,134

Amortization of deferred financing costs
598

 
510

 
1,729

 
1,665

(Gain) loss on sale of properties
74

 
—

 
1,046

 
(92
)
(Gain) loss on extinguishment of debt
257

 
—

 
257

 
7,904

Change in operating assets and liabilities:
 
 
 
 
 
 
 
Accounts receivable
(4,592
)
 
(11,679
)
 
(8,789
)
 
(9,252
)
Prepayments and other assets
(332
)
 
397

 
(1,421
)
 
(980
)
Accounts payable, accrued and other liabilities
10,746

 
25,656

 
(25,287
)
 
20,071

Amounts payable to oil and gas property owners
8,272

 
3,698

 
33,804

 
6,371

Production taxes payable
11,415

 
4,299

 
15,983

 
(187
)
Net cash provided by (used in) operating activities
$
91,298

 
$
57,184

 
$
160,185

 
$
95,383

Investing Activities:
 
 
 
 
 
 
 
Additions to oil and gas properties, including acquisitions
(101,798
)
 
(56,552
)
 
(322,614
)
 
(160,788
)
Additions of furniture, equipment and other
(146
)
 
(67
)
 
(616
)
 
(268
)
Repayment of debt associated with merger, net of cash acquired
—

 
—

 
(53,357
)
 
—

Proceeds from sale of properties and other investing activities
(519
)
 
(97
)
 
11

 
(712
)
Net cash provided by (used in) investing activities
$
(102,463
)
 
$
(56,716
)
 
$
(376,576
)
 
$
(161,768
)
Financing Activities:
 
 
 
 
 
 
 
Proceeds from debt
—

 
—

 
—

 
275,000

Principal payments on debt
(118
)
 
(115
)
 
(350
)
 
(322,228
)
Proceeds from sale of common stock, net of offering costs
1

 
—

 
1

 
(298
)
Deferred financing costs and other
(3,117
)
 
(33
)
 
(4,746
)
 
(6,045
)
Net cash provided by (used in) financing activities
$
(3,234
)
 
$
(148
)
 
$
(5,095
)
 
$
(53,571
)
Increase (Decrease) in Cash and Cash Equivalents
(14,399
)
 
320

 
(221,486
)
 
(119,956
)
Beginning Cash and Cash Equivalents
107,379

 
155,565

 
314,466

 
275,841

Ending Cash and Cash Equivalents
$
92,980

 
$
155,885

 
$
92,980

 
$
155,885



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HIGHPOINT RESOURCES CORPORATION
Reconciliation of Discretionary Cash Flow, Adjusted Net Income (Loss) and EBITDAX
(Unaudited)

Discretionary Cash Flow Reconciliation
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Net Cash Provided by (Used in) Operating Activities
$
91,298

 
$
57,184

 
$
160,185

 
$
95,383

Adjustments to reconcile to discretionary cash flow:

 

 

 

Exploration expense
19

 
18

 
39

 
48

Merger transaction expense
100

 
—

 
6,140

 
—

Changes in working capital
(25,509
)
 
(22,371
)
 
(14,290
)
 
(16,023
)
Discretionary Cash Flow
$
65,908

 
$
34,831

 
$
152,074

 
$
79,408


Adjusted Net Income (Loss) Reconciliation
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per share amounts)
Net Income (Loss)
$
(29,360
)
 
$
(28,842
)
 
$
(101,203
)
 
$
(60,404
)
Provision for (Benefit from) income taxes
—

 
—

 
—

 
—

Income (Loss) before income taxes
(29,360
)
 
(28,842
)
 
(101,203
)
 
(60,404
)
 
 
 
 
 
 
 
 
Adjustments to net income (loss):
 
 
 
 
 
 
 
Unrealized derivative (gain) loss
32,767

 
19,672

 
85,538

 
(2,592
)
Impairment expense
—

 
—

 
—

 
8,010

(Gain) loss on sale of properties
74

 
—

 
1,046

 
(92
)
(Gain) loss on extinguishment of debt
257

 
—

 
257

 
7,904

One-time item:
 
 
 
 
 
 
 
Merger transaction expense
100

 
—

 
6,140

 
—

(Income) expense related to properties sold
(764
)
 
(282
)
 
(716
)
 
(1,610
)
Adjusted Income (Loss) before income taxes
3,074

 
(9,452
)
 
(8,938
)
 
(48,784
)
Adjusted (provision for) benefit from income taxes (1)
(757
)
 
3,549

 
2,202

 
18,460

Adjusted Net Income (Loss)
$
2,317

 
$
(5,903
)
 
$
(6,736
)
 
$
(30,324
)
Per share, diluted
$
0.01

 
$
(0.08
)
 
$
(0.04
)
 
$
(0.41
)

(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.











13

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EBITDAX Reconciliation
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Net Income (Loss)
$
(29,360
)
 
$
(28,842
)
 
$
(101,203
)
 
$
(60,404
)
Adjustments to reconcile to EBITDAX:

 

 

 

Depreciation, depletion and amortization
58,946

 
41,732

 
152,106

 
119,409

Impairment, dry hole and abandonment expense
184

 
261

 
609

 
8,336

Exploration expense
19

 
18

 
39

 
48

Unrealized derivative (gain) loss
32,767

 
19,672

 
85,538

 
(2,592
)
Incentive compensation and other non-cash charges
2,323

 
1,480

 
5,813

 
5,134

Merger transaction expense
100

 
—

 
6,140

 
—

(Gain) loss on sale of properties
74

 
—

 
1,046

 
(92
)
(Gain) loss on extinguishment of debt
257

 
—

 
257

 
7,904

Interest and other income
(451
)
 
(332
)
 
(1,843
)
 
(1,030
)
Interest expense
13,165

 
13,926

 
39,348

 
44,014

EBITDAX
$
78,024

 
$
47,915

 
$
187,850

 
$
120,727


Discretionary cash flow, adjusted net income (loss) and EBITDAX 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 performance and, in the case of discretionary cash flow, liquidity. 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.


14