• 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

DENVER, Feb. 26, 2019 (GLOBE NEWSWIRE) -- 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 of December 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