Quarterly / Earnings Reports | Third Quarter (3Q) Update

HighPoint Resources Reports Q3 2019 Results

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HighPoint Resources Corp. reported its Q3 2019 results.

Highlights:

• Reported production sales volume of 3.4 million barrels of oil equivalent ("MMBoe") for the third quarter of 2019, represents an increase of 20% over the second quarter of 2019 and a 24% increase over the third quarter of 2018
• Oil production sales volume of 2.18 million barrels of oil ("MMBbls") for the third quarter of 2019 or 64% of total equivalent production sales volume, represents an increase of 25% over the second quarter of 2019 and a 27% increase over the third quarter of 2018
• Reported net income of $11.1 million or $0.05 per diluted share and adjusted net income (non-GAAP) of a loss of $7.4 million or $0.03 per diluted share
• EBITDAX (non-GAAP) of $94.3 million increased 33% over the second quarter of 2019 driven by a significant per unit reduction in controllable cash operating costs¹ of 29% and 30% compared to both the second quarter of 2019 and third quarter of 2018, respectively
• Continued positive results from DSU 11-63-16 (east pad) as wells are exhibiting a dramatic 120% increase in current daily production rate through 130 days with a shallower decline compared to previously completed wells, demonstrating economic development of both the Niobrara and Codell formations in Hereford
• Encouraging early performance from upspaced DSU 11-63-16 (west pad) that is exhibiting a meaningful increase of 55% in current daily production rate through 85 days compared to previously completed wells and continues ramping to peak production
• Became cash flow positive in the third quarter of 2019
• Semi-annual borrowing base review recently completed with $500 million credit facility reaffirmed

For the third quarter of 2019, the Company reported net income of $11.1 million, or $0.05 per diluted share. Adjusted net income for the third quarter of 2019 was a net loss of $7.4 million, or $0.03 per diluted share. EBITDAX for the third quarter of 2019 was $94.3 million.

Chief Executive Officer and President Scot Woodall commented, "Our third quarter results are reflective of strong operational execution and were highlighted by robust growth in oil volumes and a significant reduction in cash operating costs that underpinned a 33% increase in EBITDAX to $94 million compared to the second quarter of 2019. We also became cash flow positive during the third quarter, which will enhance liquidity. Following up on our recent positive operational update, we continue to demonstrate a dramatic improvement in Hereford well performance with results showing a substantial and continuous increase in productivity. Today, we are providing a further positive update to the initial seven wells in DSU 11-63-16 that are now showing a 120% increase in current daily production with a shallower decline profile compared to previously completed wells, demonstrating a viable, economic development template for the Hereford field. Similarly, the performance of the four wells on the western side of DSU 11-63-16 continues to improve since our last update, showing a 55% increase in current daily production and are trending to peak production. This continues to build upon the early success of the Hereford optimization program as we assess performance opportunities of upspacing and increased completion intensity."

Ops Update

Hereford Field

Production sales volumes for the third quarter of 2019 in Hereford averaged a Company record of 10,101 Boe/d (80% oil) or a 41% increase over the second quarter of 2019. During the third quarter of 2019, 6 gross wells were spud and 16 gross wells were placed on flowback.

The following provides an update of current DSU activity:

• DSU 11-63-16 (east pad) - was placed on flowback in June and includes seven wells drilled at a density of 16 wells per section. The wells were completed with a Gen 2 completion that used approximately 30 barrels of fluid per lateral foot and approximately 1,500 pounds of sand per lateral foot. Through 130 days of flowback, the average per well daily production rate is currently 120% greater than previously completed wells, demonstrating an economic development template for the Hereford field. This rate continues to improve compared to the previously disclosed daily production rate indicating a 75% per well increase following 105 days.
• DSU 11-63-16 (west pad) - was placed on flowback in July and includes four wells drilled at a density of 8 wells per section. The wells were completed with a Gen 3 completion that utilized greater fluid of up to 40 barrels per lateral foot and approximately 1,500 pounds of sand per lateral foot and assessed performance improvement opportunities of upspacing and increased completion intensity. Through 85 days of production, the average per well daily production rate is presently 55% greater than the previously completed wells and continues trending higher.
• DSU 11-63-17 - was placed on flowback in July and includes twelve wells drilled at a density of 12 wells per section. The wells are assessing the performance impact of Gen 4 completions that utilized greater fluid of up to 52 barrels per lateral foot and an average of approximately 1,500 pounds of sand per lateral foot. These wells were stimulated with larger fluid completions than all previous wells and continue to ramp to peak production.

The Company continues to recognize well cost efficiencies that have resulted in lower completed well costs. Based on the current price outlook, future wells are anticipated to average approximately $4.9 million for an XRL well completed with high-fluid intensity completion. This compares to $5.1 million for XRL wells drilled during the first half of 2019 and utilized lower fluid.

NE Wattenberg

The Company produced an average of 26,845 Boe/d (58% oil) in the third quarter of 2019 in NE Wattenberg and spud 9 gross wells and placed 5 gross XRL and 4 gross SRL wells on flowback in the area. Recent activity includes placing five XRL wells located in DSU 5-61-35 on flowback in September. Subsequent to the end of the quarter two additional XRL wells located in DSU 5-61-35 were placed on flowback. These wells continue to ramp to peak production and were completed with high-fluid intensity completions.

The Company is also recognizing well cost efficiencies in NE Wattenberg as future wells are anticipated to cost an average of approximately $4.3 million for XRL wells completed with high-fluid intensity completions. This compares to $4.5 million for wells drilled during the first half of 2019.

2019 Guidance

The Company is providing capital expenditure and production guidance for the fourth quarter of 2019 as discussed below and reiterates full-year 2019 guidance.

See "Forward-Looking Statements" below.

• Production of 3.6-3.7 MMBoe
• Oil volumes to approximate 2.3 MMBbls or approximately 63% of total production volumes
• Capital expenditures of $30-$40 million
• Lease operating expense is expected to average $2.50-$3.00 per Boe
• Cash general and administrative expense of $2.50-$3.00 per Boe
• Gathering, transportation and processing costs of $0.75-$0.95 per Boe

Operating & Financial Results

The following table summarizes certain operating and financial results for the third quarter of 2019 and 2018 and for the second quarter of 2019:

The Company reported oil, natural gas and natural gas liquids ("NGL") production of 3.4 MMBoe for the third quarter of 2019, which was a 20% increase over the second quarter of 2019 and a 24% increase over the third quarter of 2018. Oil volumes totaled 2.18 MMBbls, which was a 25% increase over the second quarter of 2019 and a 27% increase over the third quarter of 2018. Third quarter of 2019 volumes were negatively impacted by depressed processing yields, including basin-wide ethane rejections.

Production sales volumes for the third quarter were comprised of approximately 64% oil, 21% natural gas and 15% NGLs.

For the third quarter of 2019, West Texas Intermediate ("WTI") oil prices averaged $56.45 per barrel, Northwest Pipeline ("NWPL") natural gas prices averaged $1.91 per MMBtu and NYMEX natural gas prices averaged $2.23 per MMBtu. Commodity price realizations to benchmark pricing were WTI less $4.11 per barrel of oil and NWPL less $0.88 per Mcf of gas. The NGL price averaged approximately 10% of the WTI price per barrel as unprecedented weakness in broader markets resulted in a 76% decline in NGL prices compared to the third quarter of 2018.

For the third quarter of 2019, the Company had derivative commodity swaps in place for 19,730 barrels of oil per day tied to WTI pricing at $56.45 per barrel, 7,000 MMBtu of natural gas per day tied to NWPL regional pricing at $1.91 per MMBtu, and no hedges in place for NGLs.

Lease operating expense ("LOE") averaged $2.47 per Boe in the third quarter of 2019 compared to $2.65 per Boe in the third quarter of 2018 and $3.79 per Boe in the second quarter of 2019. The 35% reduction from the second quarter of 2019 was due to higher production volumes and a decrease in compressor maintenance and workover activity.

Production tax expense averaged $2.31 per Boe in the third quarter of 2019 compared to $4.20 per Boe in the third quarter of 2018. The decrease in the rate for the three months ended September 30, 2019 was due to a lower projected effective 2019 Colorado severance tax rate. Production tax expense averaged 6.5% of revenues in the third quarter of 2019 and is expected to average approximately 6%-7% of revenues for the remainder of 2019.

Debt and Liquidity

At September 30, 2019, the Company had cash and cash equivalents of $20 million and $299 million available under its $500 million credit facility, after taking into account a $26 million letter of credit, resulting in total liquidity of $319 million. Net debt totaled $780 million at September 30, 2019.

The Company completed its semiannual redetermination in October 2019 with the borrowing base under the credit facility reaffirmed at $500 million, despite lower price assumptions being used by lenders in the fall redetermination process. The reaffirmation of the borrowing base reflects the lenders' confidence in the Company's underlying reserve base.

Capital Expenditures

Capital expenditures for the third quarter of 2019 totaled $76.2 million, including $64.8 million for drilling and completion operations. Capital projects included spudding 15 gross extended reach lateral ("XRL") wells and placing 25 gross wells (21 XRL wells and 4 standard reach lateral ("SRL") wells) on initial flowback.

Hedging Update

The following table summarizes the Company's current hedge position as of November 4, 2019:

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