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HighPoint Resources Reports Second Quarter 2018 Financial and Operating Results

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HighPoint Resources Reports Second Quarter 2018 Financial and Operating Results

- Hereford Field ("Hereford") drilling and completion operations commenced on schedule

- Drilling completed on first Hereford drilling and spacing unit ("DSU") and flowback commenced from nine previously drilled, but not completed ("DUC"), extended reach lateral ("XRL") wells

- Encouraging early production data from Hereford as initial DUCs are performing consistent with base type-curve after the initial 60 days of production

- Oil production sales volume of 1.51 million barrels of oil ("MMBbls") for the second quarter of 2018 was above the mid-point of guidance and represent a 67% year-over-year increase

- Production sales volume of 2.41 MMBoe (63% oil) for the second quarter of 2018 represent an increase of 58% from the second quarter of 2017

PR Newswire

DENVER, Aug. 8, 2018 /PRNewswire/ -- HighPoint Resources Corporation (the "Company" or "HighPoint") (NYSE:HPR) today reported second quarter of 2018 financial and operating results, highlighted by oil volumes above the mid-point of guidance and early positive results from Hereford development activity.

For the second quarter of 2018, the Company reported a net loss of $46.9 million, or $0.22 per diluted share. Adjusted net income for the second quarter of 2018 was a net loss of $3.2 million, or $0.02 per diluted share. EBITDAX for the second quarter of 2018 was $63.1 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, "Our second quarter results demonstrate our continued operating excellence as we reported total equivalent production sales volumes within our guidance range, including oil volumes that were above the mid-point of guidance.  During the second quarter, we generated EBITDAX of $63.1 million, an increase of 35% over the first quarter of 2018 and 72% over the second quarter last year. We are well positioned for continued growth with a dominant acreage position, a low cost structure, and ample liquidity of $381 million at the end of the second quarter. Combined with disciplined capital allocation across an extensive and attractive inventory of XRL drilling locations we remain well positioned for value creation.

"Operationally, our development program is on track as Hereford activity began as planned in April. Drilling of the first DSU was recently completed and we initiated production from nine DUCs. Three of the DUCs were placed on flowback in May and we are seeing positive early production data as the wells are performing consistent with our base type-curve assumptions. The early results highlight the significant resource potential of the Hereford asset. The pace of development at Hereford will increase during the second half of the year as we are currently operating two drilling rigs. NE Wattenberg also continues to see very consistent results and produced an average of 23,900 Boe/d in the second quarter of 2018, representing a 65% increase over the second quarter of 2017.

"Midstream constraints in NE Wattenberg resulted in curtailed natural gas and liquids production during the second quarter. While we had anticipated these issues, the impact was greater than forecast due to a period of unseasonably warm weather in June and July, which resulted in an increase in processing facility outages. We are adjusting our 2018 natural gas and NGL guidance to account for these temporary issues, but expect that full-year oil volumes will be relatively unchanged from previous expectations.

"I am pleased with HighPoint's ability to create long-term shareholder value through development of our extensive and favorable asset base targeting the oil-weighted and rural core of the DJ Basin. We remain positioned to deliver significant growth in production, cash flow and EBITDAX and reiterate our 2019 outlook."

OPERATING AND FINANCIAL RESULTS

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


Three Months Ended
June 30,


Three Months Ended
March 31,


2018


2017


Change


2018


Change

Combined production sales volumes (MBoe)

2,409



1,526



58

%


1,914



26

%

Net cash provided by (used in) operating activities ($ millions)

$

14.6



$

0.1



*nm



$

54.3



(73)

%

Discretionary cash flow ($ millions) (1)

$

51.3



$

21.6



138

%


$

34.9



47

%

Combined realized prices with hedging (per Boe)

$

39.29



$

37.42



5

%


$

37.86



4

%

Net income (loss) ($ millions)

$

(46.9)



$

(18.4)



(155)

%


$

(24.9)



(88)

%

Per share, basic

$

(0.22)



$

(0.25)



12

%


$

(0.20)



(10)

%

Per share, diluted

$

(0.22)



$

(0.25)



12

%


$

(0.20)



(10)

%

Adjusted net income (loss) ($ millions) (1)

$

(3.2)



$

(12.9)



75

%


$

(5.9)



46

%

Per share, basic

$

(0.02)



$

(0.17)



88

%


$

(0.05)



(60)

%

Per share, diluted

$

(0.02)



$

(0.17)



88

%


$

(0.05)



(60)

%

Weighted average shares outstanding, basic (in thousands)

209,393



74,794



180

%


123,596



69

%

Weighted average shares outstanding, diluted (in thousands)

209,393



74,794



180

%


123,596



69

%

EBITDAX ($ millions) (1)

$

63.1



$

36.7



72

%


$

46.7



35

%



*

Not meaningful



(1)

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 2.41 MMBoe for the second quarter of 2018, which was an increase of 58% over the second quarter of 2017. Oil volumes totaled 1.51 MMBbls, which was an increase of 67% over the second quarter of 2017. Production sales volumes from NE Wattenberg totaled 2.2 MMBoe and Hereford volumes totaled 0.2 MMBoe. Second quarter natural gas and NGL production was impacted by midstream constraints in NE Wattenberg, including high line pressures, unplanned processing facility outages due to unseasonably warm weather and lower product recoveries associated with interim processing facilities.

Production sales volumes were comprised of approximately 63% oil, 21% natural gas and 16% NGLs.

For the second quarter of 2018, WTI oil prices averaged $67.88 per barrel, NWPL natural gas prices averaged $1.95 per MMBtu and NYMEX natural gas prices averaged $2.80 per MMBtu. Commodity price realizations to benchmark pricing were oil less $2.76 per barrel versus WTI and natural gas less $0.66 per Mcf compared to NWPL. The NGL price averaged approximately 31% of the WTI price per barrel.

For the second quarter of 2018, the Company had derivative commodity swaps in place for 11,637 barrels of oil per day tied to WTI pricing at $52.98 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
June 30,


Three Months Ended
March 31,


2018


2017


Change


2018


Change

Average Realized Prices before Hedging:










Oil (per Bbl)

$

65.07



$

45.83



42

%


$

60.45



8

%

Natural gas (per Mcf)

1.29



2.43



(47)

%


1.95



(34)

%

NGLs (per Bbl)

20.84



16.20



29

%


20.31



3

%

Combined (per Boe)

45.71



33.38



37

%


42.24



8

%











Average Realized Prices with Hedging:










Oil (per Bbl)

$

54.59



$

52.39



4

%


$

53.00



3

%

Natural gas (per Mcf)

1.40



2.56



(45)

%


1.98



(29)

%

NGLs (per Bbl)

20.84



16.20



29

%


20.31



3

%

Combined (per Boe)

39.29



37.42



5

%


37.86



4

%

LOE averaged $3.15 per Boe in the second quarter of 2018 compared to $3.61 per Boe in the second quarter of 2017. The year-over-year reduction in LOE is a result of improved operating efficiencies on the legacy NE Wattenberg asset and disposition of higher LOE wells in Utah.

Production tax expense averaged $4.02 per Boe in the second quarter of 2018 compared to $2.25 per Boe in the second quarter of 2017. Production tax expense averaged approximately 9% of revenues in the second quarter of 2018 compared to 7% of revenues in the second quarter of 2017. The increase was due to a higher estimated effective tax rate for Colorado severance taxes and is currently expected to approximate this level for the remainder of the year.

Depreciation, depletion and amortization ("DD&A") averaged $21.66 per Boe in the second quarter of 2018 compared to $25.78 per Boe in the second quarter of 2017. Lower DD&A on a per unit basis compared to the second quarter of 2017 was primarily the result of proved reserves added at lower costs.


Three Months Ended
June 30,


Three Months Ended
March 31,


2018


2017


Change


2018


Change

Average Costs (per Boe):










Lease operating expenses

$

3.15



$

3.61



(13)

%


$

3.27



(4)

%

Gathering, transportation and processing expense

0.42



0.35



20

%


0.22



91

%

Production tax expenses

4.02



2.25



79

%


2.70



49

%

Depreciation, depletion and amortization

21.66



25.78



(16)

%


21.41



1

%

General and administrative expense

4.83



5.86



(18)

%


5.28



(9)

%

Debt and Liquidity

At June 30, 2018, the principal debt balance was $627.1 million, while cash and cash equivalents were $107.4 million, resulting in net debt of $519.7 million. Cash and cash equivalents were primarily used during the quarter to execute on the second quarter development program.

The Company currently has $274 million in available borrowing capacity on its $300 million credit facility, after taking into account a $26 million letter of credit.

Capital Expenditures

Capital expenditures for the second quarter of 2018 totaled $145.0 million. The Company operated three drilling rigs and capital projects included spudding 28 XRL wells and placing 27 XRL wells on initial flowback, including six DUCs in Hereford.

Capital expenditures included $135.4 million for drilling and completion operations, $2.0 million for leasehold, and $7.6 million for infrastructure and corporate assets.

OPERATIONAL UPDATE

The Company is operating three drilling rigs in the DJ Basin with one rig in NE Wattenberg and two rigs in Hereford. The Company currently anticipates maintaining this pace of development and plans to drill approximately 120-125 gross XRL wells in 2018. Two completion crews will be utilized in 2018 and the Company has the ability to add a third completion crew, as necessary, based on the timing of well completions.

NE Wattenberg

The Company produced an average of 23,900 Boe/d (61% oil) in the second quarter of 2018, representing a 65% increase over the second quarter of 2017. For the second quarter of 2018, the Company drilled 20 XRL wells and placed 21 XRL wells on initial flowback. The Company is currently operating a one-rig drilling program and expects to maintain this level of development activity for the remainder of the year.

Recent activity was highlighted by DSU 5-61-27, which includes 10 XRL wells and is located in the east-central portion of NE Wattenberg. Initial flowback began in the second quarter and the wells have performed consistent with the type-curve expectations. This is a step-out to DSU 5-61-20, which was placed on flowback in the fourth quarter of 2017 and continues to perform in line with the base type-curve after 260 days of production.

In addition, DSUs 4-62-28 and 4-62-33 are located in the southern portion of NE Wattenberg and were also placed on initial flowback during the second quarter. The DSUs include 10 XRL and 9 XRL wells, respectively, and continue to trend towards peak production.

The Company continues to mitigate the impact of inflationary pressure on well costs as wells drilled during the first half of 2018 averaged approximately $4.85 million, which is in line with internal expectations. In addition, total drilling and completion cycle times averaged approximately 16.5 days for the first half of 2018, which is a 6% improvement over the 2017 average and was driven by a reduction in the number of frac and drill out days.

Hereford Field

Production sales volumes for the second quarter of 2018 averaged approximately 2,550 Boe/d (79% oil). Drilling operations commenced in April on DSU 11-63-14, which includes 10 XRL wells (6 Niobrara, 4 Codell). Drilling was completed in June and it is anticipated that the wells will be placed on initial flowback during the third quarter of 2018. A full-time completion crew began operating in April and completion operations commenced on three pads (three wells each) of DUCs, which incorporated optimized completions, including controlled flowback methods. The first three wells were placed on flowback in May and continue to trend towards peak production. Early production data is encouraging as the wells are performing consistent with the base type-curve of 550 MBoe for the 60 days of production following initial oil sales. It is anticipated that peak production will be achieved after approximately 90 days of production. The remaining six DUCs were placed on production in June and July and are in the initial flowback stage.

The Company expects to maintain two drilling rigs for the remainder of the year and the focus of the 2018 program will be on full DSU development to maximize drilling and completion efficiencies. The Company has already begun to realize significant savings due to synergies generated as completion costs for the 9 DUCs were 29% below legacy completion costs. In addition, drilling costs for the initial DSU were 17% below legacy wells with drilling days to rig release averaging approximately 8.5 days per well, including a best-in-class well that was drilled in 6.9 days.

MARKETING UPDATE

The Company experienced midstream curtailments in the first half of 2018 due to high line pressures in the DJ Basin that led to minor production impacts in NE Wattenberg, but expects that line pressures and gas processing capacity will improve in the second half of 2018. Natural gas processing capacity has improved as DCP's Mewbourn 3 plant recently became operational, which increased the Company's allocated gas volumes by approximately 25%. In addition, the Company has worked diligently to diversify its gas processing capacity and has signed agreements with several third-party midstream providers that will increase the Company's available gas processing capacity by over 70% by the end of 2018. This provides the flexibility to direct approximately 35% of expected fourth quarter NE Wattenberg volumes to processing facilities outside of the legacy DCP system.

Hereford natural gas volumes are processed by Summit midstream, which is in the process of expanding its gas processing capacity to 60 MMcf/d by the end of 2018.

The Company continues to maintain no oil marketing or oil pipeline delivery commitments and expects that oil price differentials to benchmark pricing will be less than $3.00 per barrel versus WTI for the foreseeable future.

2018 OPERATING GUIDANCE

The Company is updating its 2018 operating guidance and providing third quarter of 2018 guidance for capital expenditures and production as discussed below. The Company is reiterating its previously announced outlook for 2019.

See "Forward-Looking Statements" below.

  • Capital expenditures of $500-$550 million, unchanged
    • Third quarter capital expenditures are expected to total $140-$150 million
  • Pro forma production of 10.5-11.0 MMBoe, revised from a previous guidance range of 11.0-11.5 MMBoe
    • Updated to reflect actual production volumes for the first half of 2018 and the anticipated impact of midstream constraints in NE Wattenberg in the third quarter, including high line pressures, a greater amount of processing facility outages due to unseasonably warm weather and lower processing plant product recoveries associated with interim processing facilities
    • Includes production volumes of approximately 0.3 MMBoe associated with Hereford for the first quarter of 2018
  • Pro forma oil volumes are expected to be in a range of 6.6-6.9 MMBbls or approximately 63% of total production volumes, an increase from previous oil weighting guidance of 60-62% of total production volumes
    • Includes oil volumes of approximately 0.2 MMBbls associated with Hereford for the first quarter of 2018
  • Third quarter production sales volumes are expected to approximate 2.65-2.95 MMBoe (approximately 63% oil)
  • Lease operating expense of $28-$32 million, unchanged
  • General and administrative expenses of $36-$40 million, unchanged
  • Gathering, transportation and processing costs of $5-$10 million, unchanged
  • Unused commitment for firm natural gas transportation charges of $18-$19 million, unchanged

COMMODITY HEDGES UPDATE

The following table summarizes our current hedge position as of August 8, 2018:



Oil (WTI)


Natural Gas (NWPL)

Period


Volume
Bbls/d


Price
$/Bbl


Volume
MMBtu/d


Price
$/MMBtu

3Q18


13,843



54.62



5,000



2.68


4Q18


13,806



54.63



5,000



2.68


1Q19


17,774



58.33



5,000



2.05


2Q19


17,750



58.34



5,000



2.05


3Q19


17,231



58.64



5,000



2.05


4Q19


17,212



58.65



5,000



2.05


FY2020


3,500



59.71






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

UPCOMING EVENTS

Second Quarter Conference Call and Webcast

The Company plans to host a conference call on Thursday, August 9, 2018, to discuss second quarter of 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 8494357. The webcast will remain on the Company's website for approximately 7 days and a replay of the call will be available through August 16, 2018 at (855) 859-2056 ((404) 537-3406 international) with passcode 8494357.

Investor Events

Members of the Company's management are currently scheduled to participate in the following investor events:

  • August 20-22, 2018 - EnerCom's The Oil & Gas Conference in Denver, CO
  • August 28, 2018 - Seaport Global Energy & Industrials Conference in Chicago, IL
  • September 25-26, 2018 - Johnson Rice & Co. Energy Conference in New Orleans, LA

Presentation materials will be posted to the investor relations section of the Company's website prior to the start of each event.

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 "2018 Operating Guidance," which contains projections for certain 2018 full-year and third 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. 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
June 30,


Six Months Ended
June 30,


2018


2017


2018


2017

Production Data:








Oil (MBbls)

1,507



902



2,644



1,727


Natural gas (MMcf)

3,096



1,920



5,652



3,810


NGLs (MBbls)

386



304



737



597


Combined volumes (MBoe)

2,409



1,526



4,323



2,959


Daily combined volumes (Boe/d)

26,473



16,769



23,884



16,348










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

Oil (per Bbl)

$

65.07



$

45.83



$

63.09



$

46.83


Natural gas (per Mcf)

1.29



2.43



1.59



2.54


NGLs (per Bbl)

20.84



16.20



20.59



18.09


Combined (per Boe)

45.71



33.38



44.18



34.25










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

Oil (per Bbl)

$

54.59



$

52.39



$

53.91



$

52.40


Natural gas (per Mcf)

1.40



2.56



1.66



2.59


NGLs (per Bbl)

20.84



16.20



20.59



18.09


Combined (per Boe)

39.29



37.42



38.66



37.56










Average Costs (per Boe):








Lease operating expenses

$

3.15



$

3.61



$

3.20



$

3.84


Gathering, transportation and processing expense

0.42



0.35



0.33



0.35


Production tax expenses

4.02



2.25



3.44



1.27


Depreciation, depletion and amortization

21.66



25.78



21.55



26.25


General and administrative expense (1)

4.83



5.86



5.03



6.18




(1)

Includes long-term cash and equity incentive compensation of $0.93 per Boe and $1.10 per Boe for the three months ended June 30, 2018 and 2017, respectively, and $0.85 per Boe and $0.95 per Boe for the six months ended June 30, 2018 and 2017, respectively.

 

HIGHPOINT RESOURCES CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)



As of
June 30,


As of
December 31,


2018


2017


(in thousands)

Assets:




Cash and cash equivalents

$

107,379



$

314,466


Other current assets

66,140



53,197


Property and equipment, net

1,905,620



1,018,880


Other noncurrent assets

3,814



4,163


Total assets

$

2,082,953



$

1,390,706






Liabilities and Stockholders' Equity:




Current liabilities (1)

$

264,247



$

148,934


Long-term debt, net of debt issuance costs

616,625



617,744


Other long-term liabilities (1)

186,878



25,474


Stockholders' equity

1,015,203



598,554


Total liabilities and stockholders' equity

$

2,082,953



$

1,390,706




(1)

At June 30, 2018, the estimated fair value of all of the Company's commodity derivative instruments was a liability of $85.3 million, comprised of $66.4 million of current liabilities and $18.9 million of non-current liabilities. 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
June 30,


Six Months Ended
June 30,


2018


2017


2018


2017


(in thousands, except per share amounts)

Operating Revenues:








Oil, gas and NGL production

$

110,118



$

50,941



$

190,949



$

101,366


Other operating revenues, net

280



125



259



236


Total operating revenues

110,398



51,066



191,208



101,602


Operating Expenses:








Lease operating

7,594



5,506



13,845



11,368


Gathering, transportation and processing

1,012



535



1,431



1,024


Production tax

9,684



3,434



14,859



3,756


Exploration

7



3



20



30


Impairment, dry hole costs and abandonment

108



1



425



8,075


(Gain) Loss on sale of properties

564





972



(92)


Depreciation, depletion and amortization

52,175



39,337



93,160



77,677


Unused commitments

4,572



4,558



9,110



9,130


General and administrative (1)

11,624



8,943



21,731



18,292


Merger transaction expense

1,277





6,040




Other operating expenses, net

9



(755)



48



(1,328)


Total operating expenses

88,626



61,562



161,641



127,932


Operating Income (Loss)

21,772



(10,496)



29,567



(26,330)


Other Income and Expense:








Interest and other income

701



492



1,392



698


Interest expense

(13,093)



(16,137)



(26,183)



(30,088)


Commodity derivative gain (loss) (2)

(56,286)



15,598



(76,619)



32,062


Gain (loss) on extinguishment of debt



(7,904)





(7,904)


Total other income and expense

(68,678)



(7,951)



(101,410)



(5,232)


Income (Loss) before Income Taxes

(46,906)



(18,447)



(71,843)



(31,562)


(Provision for) Benefit from Income Taxes








Net Income (Loss)

$

(46,906)



$

(18,447)



$

(71,843)



$

(31,562)










Net Income (Loss) per Common Share








Basic

$

(0.22)



$

(0.25)



$

(0.43)



$

(0.42)


Diluted

$

(0.22)



$

(0.25)



$

(0.43)



$

(0.42)


Weighted Average Common Shares Outstanding








Basic

209,393



74,794



166,731



74,670


Diluted

209,393



74,794



166,731



74,670




(1)

Includes long-term cash and equity incentive compensation of $2.2 million and $1.7 million for the three months ended June 30, 2018 and 2017, respectively, and $3.7 million and $2.8 million for the six months ended June 30, 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
June 30,


Six Months Ended
June 30,


2018


2017


2018


2017


(in thousands)

Included in commodity derivative gain (loss):








Realized gain (loss) on derivatives (1)

$

(15,460)



$

6,167



$

(23,848)



$

9,799


Prior year unrealized (gain) loss transferred to realized (gain) loss (1)

5,788



(737)



20,940



(2,114)


Unrealized gain (loss) on derivatives (1)

(46,614)



10,168



(73,711)



24,377


Total commodity derivative gain (loss)

$

(56,286)



$

15,598



$

(76,619)



$

32,062




(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.

 

HIGHPOINT RESOURCES CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)



Three Months Ended
June 30,


Six Months Ended
June 30,


2018


2017


2018


2017


(in thousands)

Operating Activities:








Net income (loss)

$

(46,906)



$

(18,447)



$

(71,843)



$

(31,562)


Adjustments to reconcile to net cash provided by operations:








Depreciation, depletion and amortization

52,175



39,337



93,160



77,677


Impairment, dry hole costs and abandonment

108



1



425



8,075


Unrealized derivative (gain) loss

40,826



(9,432)



52,771



(22,264)


Incentive compensation and other non-cash charges

2,655



1,686



3,490



3,654


Amortization of deferred financing costs

568



597



1,131



1,155


(Gain) loss on sale of properties

564





972



(92)


(Gain) loss on extinguishment of debt



7,904





7,904


Change in operating assets and liabilities:








Accounts receivable

(13,363)



(1,160)



(4,197)



2,427


Prepayments and other assets

(978)



(330)



(1,089)



(1,377)


Accounts payable, accrued and other liabilities

(36,855)



(14,550)



(36,033)



(5,585)


Amounts payable to oil and gas property owners

15,923



1,583



25,532



2,673


Production taxes payable

(147)



(7,088)



4,568



(4,486)


Net cash provided by (used in) operating activities

$

14,570



$

101



$

68,887



$

38,199


Investing Activities:








Additions to oil and gas properties, including acquisitions

(131,962)



(46,273)



(220,816)



(104,236)


Additions of furniture, equipment and other

(348)



(190)



(470)



(201)


Repayment of debt associated with merger, net of cash acquired





(53,357)




Proceeds from sale of properties and other investing activities

687



(11,840)



530



(615)


Net cash provided by (used in) investing activities

$

(131,623)



$

(58,303)



$

(274,113)



$

(105,052)


Financing Activities:








Proceeds from debt



275,000





275,000


Principal payments on debt

(116)



(322,001)



(232)



(322,113)


Proceeds from sale of common stock, net of offering costs



(74)





(298)


Deferred financing costs and other

(144)



(5,045)



(1,629)



(6,012)


Net cash provided by (used in) financing activities

$

(260)



$

(52,120)



$

(1,861)



$

(53,423)


Increase (Decrease) in Cash and Cash Equivalents

(117,313)



(110,322)



(207,087)



(120,276)


Beginning Cash and Cash Equivalents

224,692



265,887



314,466



275,841


Ending Cash and Cash Equivalents

$

107,379



$

155,565



$

107,379



$

155,565


 

HIGHPOINT RESOURCES CORPORATION

Reconciliation of Discretionary Cash Flow, Adjusted Net Income (Loss) and EBITDAX

(Unaudited)


Discretionary Cash Flow Reconciliation



Three Months Ended
June 30,


Six Months Ended
June 30,


2018


2017


2018


2017


(in thousands)

Net Cash Provided by (Used in) Operating Activities

$

14,570



$

101



$

68,887



$

38,199


Adjustments to reconcile to discretionary cash flow:








Exploration expense

7



3



20



30


Merger transaction expense

1,277





6,040




Changes in working capital

35,420



21,545



11,219



6,348


Discretionary Cash Flow

$

51,274



$

21,649



$

86,166



$

44,577



Adjusted Net Income (Loss) Reconciliation



Three Months Ended
June 30,


Six Months Ended
June 30,


2018


2017


2018


2017


(in thousands, except per share amounts)

Net Income (Loss)

$

(46,906)



$

(18,447)



$

(71,843)



$

(31,562)


Provision for (Benefit from) income taxes








Income (Loss) before income taxes

(46,906)



(18,447)



(71,843)



(31,562)










Adjustments to net income (loss):








Unrealized derivative (gain) loss

40,826



(9,432)



52,771



(22,264)


Impairment expense







8,010


(Gain) loss on sale of properties

564





972



(92)


(Gain) loss on extinguishment of debt



7,904





7,904


One-time item:








Merger transaction expense

1,277





6,040




(Income) expense related to properties sold

9



(755)



48



(1,328)


Adjusted Income (Loss) before income taxes

(4,230)



(20,730)



(12,012)



(39,332)


Adjusted (provision for) benefit from income taxes (1)

1,047



7,869



2,959



14,911


Adjusted Net Income (Loss)

$

(3,183)



$

(12,861)



$

(9,053)



$

(24,421)


Per share, diluted

$

(0.02)



$

(0.17)



$

(0.05)



$

(0.33)




(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
June 30,


Six Months Ended
June 30,


2018


2017


2018


2017


(in thousands)

Net Income (Loss)

$

(46,906)



$

(18,447)



$

(71,843)



$

(31,562)


Adjustments to reconcile to EBITDAX:








Depreciation, depletion and amortization

52,175



39,337



93,160



77,677


Impairment, dry hole and abandonment expense

108



1



425



8,075


Exploration expense

7



3



20



30


Unrealized derivative (gain) loss

40,826



(9,432)



52,771



(22,264)


Incentive compensation and other non-cash charges

2,655



1,686



3,490



3,654


Merger transaction expense

1,277





6,040




(Gain) loss on sale of properties

564





972



(92)


(Gain) loss on extinguishment of debt



7,904





7,904


Interest and other income

(701)



(492)



(1,392)



(698)


Interest expense

13,093



16,137



26,183



30,088


EBITDAX

$

63,098



$

36,697



$

109,826



$

72,812


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. If used as a liquidity measure, they should be reconciled to cash flow from operations 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.

HighPoint Resources Logo (PRNewsfoto/Bill Barrett Corporation)

 

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SOURCE HighPoint Resources Corporation

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