HIGHPOINT RESOURCES CORPORATION This Quarterly Report on Form 10-Q contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements as to future plans, estimates, beliefs and expected performance ofHighPoint Resources Corporation . Forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, risks and uncertainties relating to: •outbreaks of communicable diseases like COVID-19 and resulting regulatory and economic consequences; •the ability and willingness of members of theOrganization of Petroleum Exporting Countries ("OPEC") along with non-OPEC oil-producing countries (collectively known as "OPEC+"), to agree to and maintain oil price and production controls; •ability to regain compliance with the minimum share price requirement under theNew York Stock Exchange (the "NYSE") continued listing requirements and avert delisting of our common stock; •debt and equity market conditions and availability of capital; •reductions in the borrowing base under our amended revolving credit facility (the "Amended Credit Facility"); •any failure to comply with the financial or other covenants under our Amended Credit Facility, which could result in an event of default that could raise substantial doubt about our ability to continue as a going concern; •downstream shut-ins due to oversupply and shortage of storage capacity; •legislative, judicial or regulatory changes including initiatives to impose increased setbacks from occupied structures and other sensitive areas, initiatives to give local governmental authorities the ability to further regulate or to ban oil and gas development activities within their boundaries, and initiatives related to drilling and completion techniques such as hydraulic fracturing; •potential failure to achieve expected production from existing and future exploration or development projects or acquisitions; •volatility of market prices received for oil, natural gas and natural gas liquids ("NGLs"), and the risk of a prolonged period of depressed prices; •declines in the values of our oil and natural gas properties resulting in impairments; •reduction of proved undeveloped reserves due to failure to develop within the five-year development window defined by theSecurities and Exchange Commission ; •derivative and hedging activities; •the concentration of our properties in theRocky Mountain region; •compliance with environmental and other regulations; •economic and competitive conditions; •occurrence of property divestitures or acquisitions; •costs and availability of third party facilities for gathering, processing, refining and transportation; •future processing volumes and pipeline throughput; •impact of health and safety issues on operations; •operational risks, including the risk of industrial accidents and natural disasters; •ability to receive drilling and other permits, regulatory approvals and required surface access and rights of way; •higher than expected costs and expenses including production, drilling and well equipment costs; •changes in estimates of proved reserves; •the potential for production decline rates from our wells, and/or drilling and related costs, to be greater than we expect; •ability to replace natural production declines with acquisitions, new drilling or recompletion activities; •exploration risks such as the risk of drilling unsuccessful wells; •capital expenditures and contractual obligations; •liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance; •midstream capacity issues; •changes in tax laws and statutory tax rates; and •other uncertainties, including those factors discussed below and in our Annual Report on Form 10-K for the year endedDecember 31, 2019 under the headings "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" and in Part II, Item 1A, "Risk Factors" of this Quarterly Report on Form 10-Q, all of which are difficult to predict. 24 -------------------------------------------------------------------------------- Table of Contents In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management's views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise. Overview We develop oil and natural gas in theRocky Mountain region ofthe United States . We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.
We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders' expectations and regulatory requirements.
In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus. As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil demand. In response, OPEC+ initiated discussions to lower production to support energy prices. With OPEC+ unable to agree on cuts, crude oil prices declined to an average of$30.45 per barrel for the month ofMarch 2020 and$16.70 per barrel for the month ofApril 2020 before increasing to an average of$38.31 per barrel for the month ofJune 2020 , compared to$59.80 for the month ofDecember 2019 . These declines in prices have adversely affected the economics of our existing wells and planned future development, which led to impairments of both proved and unproved oil and gas properties during the three months endedMarch 31, 2020 . Aside from the impairment of our proved and unproved oil and gas properties, impacts to our results of operations for the three and six months endedJune 30, 2020 from price declines were mitigated by hedges in place on 78% and 86%, respectively, of our oil production. As ofJuly 20, 2020 , we have hedged 2,760,000 barrels, or approximately 92%, of our expected remaining 2020 oil production and 3,098,000 barrels of our expected 2021 oil production, at price levels that provide some economic certainty to our cash flows. In addition, we have hedged 3,680,000 MMbtu, or approximately 56%, of our expected remaining 2020 natural gas production, and 5,790,000 MMbtu of our expected 2021 natural gas production. As the duration of the COVID-19 pandemic is uncertain, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. The degree to which the COVID-19 pandemic will adversely impact our future operations and results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration of the spread of the outbreak, its severity, the actions to contain the virus and treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. The substantial decline in oil price has increased the volatility and amplitude of risks we face as described in this report and in our Annual Report on Form 10-K for the year endedDecember 31, 2019 . If oil prices do not improve, capital availability, our liquidity and profitability will be adversely affected, particularly after our current hedges are realized in 2020 and 2021. There is uncertainty around the timing and recovery of the global economy from COVID-19 and its effects on the supply and demand for crude oil. Therefore, we expect continued volatility and uncertainty in the outlook for near to medium term oil prices. As of the date of this filing,August 3, 2020 , we believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility to meet our obligations and commitments for the next twelve months. We deferred drilling and completion activity starting inMay 2020 and will continue to defer until oil prices improve to a level that allows us to meet our target return threshold. In addition, we are currently in compliance with all financial covenants under our Amended Credit Facility and have$71.2 million available for future borrowing. However, if current market conditions continue, we may not be able to maintain compliance with our financial covenants. In particular, we may breach the debt-to-EBITDAX ratio and the current ratio covenants in the Amended Credit Facility in the latter part of 2021. Further, if our independent auditor were to include an explanatory paragraph regarding our ability to continue as a "going concern" in the auditors' report on our financial statements for the year endingDecember 31, 2020 , this would also cause a default under the Amended Credit Facility. If a covenant breach occurs or is likely, we may attempt to obtain a waiver from the lenders under the Amended Credit Facility, seek to amend the terms of the Amended Credit Facility to prevent the breach or seek to obtain alternative financing to repay the Amended Credit Facility balance outstanding. If these efforts are unsuccessful, 25 -------------------------------------------------------------------------------- Table of Contents all or a portion of the amount borrowed under the Amended Credit Facility could become due, and cross-defaults could occur under our senior notes and we may not have other sources of capital to repay the amounts due. We may from time to time seek to retire, purchase or otherwise refinance our outstanding debt securities through cash purchases and/or exchanges, in open market purchases, privately negotiated transactions, exchange offers or otherwise. Any such transactions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. We operate in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of our operations are conducted in theRocky Mountain region ofthe United States . Consequently, we currently report a single reportable segment. 26
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Results of OperationsThe following table sets forth selected operating data for the periods indicated:
Three Months EndedJune 30, 2020 Compared with Three Months EndedJune 30, 2019 Three Months Ended June 30, Increase (Decrease) 2020 2019 Amount Percent ($ in thousands, except per unit data) Operating Results: Operating Revenues Oil, gas and NGL production$ 43,300 $ 107,486 $ (64,186) (60) % Other operating revenues - 98 (98) (100) % Total operating revenues 43,300 107,584 (64,284) (60) % Operating Expenses Lease operating expense 9,074 10,772 (1,698) (16) % Gathering, transportation and processing expense 4,254 1,742 2,512 144 % Production tax expense 1,449 8,905 (7,456) (84) % Exploration expense 21 12 9 75 % Impairment, dry hole costs and abandonment expense 810 995 (185) (19) % (Gain) loss on sale of properties 4,779 2,906 1,873 64 % Depreciation, depletion and amortization 24,908 72,612 (47,704) (66) % Unused commitments 4,378 4,352 26 1 % General and administrative expense (1) 12,890 12,401 489 4 % Other operating expense, net (557) 4 (561) *nm Total operating expenses$ 62,006 $ 114,701 $ (52,695) (46) % Production Data: Oil (MBbls) 1,638 1,748 (110) (6) % Natural gas (MMcf) 3,948 3,558 390 11 % NGLs (MBbls) 575 500 75 15 % Combined volumes (MBoe) 2,871 2,841 30 1 % Daily combined volumes (Boe/d) 31,549 31,220 329 1 % Average Realized Prices before Hedging: Oil (per Bbl)$ 22.74 $ 55.46 $ (32.72) (59) % Natural gas (per Mcf) 0.80 1.58 (0.78) (49) % NGLs (per Bbl) 5.07 9.81 (4.74) (48) % Combined (per Boe) 15.08 37.83 (22.75) (60) % Average Realized Prices with Hedging: Oil (per Bbl)$ 47.33 $ 54.88 $ (7.55) (14) % Natural gas (per Mcf) 0.88 1.59 (0.71) (45) % NGLs (per Bbl) 5.07 9.81 (4.74) (48) % Combined (per Boe) 29.23 37.48 (8.25) (22) % Average Costs (per Boe): Lease operating expense$ 3.16 $ 3.79 $ (0.63) (17) % Gathering, transportation and processing expense 1.48 0.61 0.87 143 % Production tax expense 0.50 3.13 (2.63) (84) % Depreciation, depletion and amortization 8.68 25.56 (16.88) (66) % General and administrative expense (1) 4.49 4.37 0.12 3 % *Not meaningful. (1)Included in general and administrative expense is long-term cash and equity incentive compensation of$1.6 million (or$0.54 per Boe) and$2.3 million (or$0.81 per Boe) for the three months endedJune 30, 2020 and 2019, respectively. 27 -------------------------------------------------------------------------------- Table of Contents Production Revenues and Volumes. Production revenues decreased to$43.3 million for the three months endedJune 30, 2020 from$107.5 million for the three months endedJune 30, 2019 . The decrease in production revenues was due to a 60% decrease in average realized prices before hedging, offset by a 1% increase in production volumes. The decrease in average realized prices before hedging decreased production revenues by approximately$64.6 million , while the increase in production volumes increased production revenues by approximately$0.4 million . Lease Operating Expense ("LOE"). LOE was$9.1 million for the three months endedJune 30, 2020 and$10.8 million for the three months endedJune 30, 2019 . LOE decreased to$3.16 per Boe for the three months endedJune 30, 2020 from$3.79 per Boe for the three months endedJune 30, 2019 . We started seeing a decrease in service industry costs during the three months endedJune 30, 2020 . Gathering, Transportation and Processing Expense ("GTP"). GTP expense increased to$1.48 per Boe for the three months endedJune 30, 2020 from$0.61 per Boe for the three months endedJune 30, 2019 . Costs incurred to gather, transport and/or process our oil, gas and NGLs prior to the transfer of control to the customer are included in GTP expense. Costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues. In general, based on specific contract arrangements, costs incurred associated with gas and NGLs in the Hereford Field in theDJ Basin , which was acquired in the Merger, are included in GTP expense and costs incurred associated with gas and NGLs in the Northeast Wattenberg Field in theDJ Basin are included in production revenues. Costs incurred associated with oil are included in production revenues for both areas. See the "Revenue Recognition" section in Note 2 for additional information. The increase in GTP per Boe for the three months endedJune 30, 2020 compared to the three months endedJune 30, 2019 was due to an increase in our production mix from the Hereford Field under the existing contractual arrangement, which has a primary term throughApril 2027 . Production Tax Expense. Total production taxes decreased to$1.4 million for the three months endedJune 30, 2020 from$8.9 million for the three months endedJune 30, 2019 . Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes for the three months endedJune 30, 2020 includedColorado severance tax refunds of$1.8 million based on an audit of tax years 2015 to 2017. Excluding the severance tax refunds associated with tax years 2015 to 2017, production taxes as a percentage of oil, natural gas and NGL sales were 7.5% and 8.3% for the three months endedJune 30, 2020 andJune 30, 2019 , respectively. The decrease in the rate for the three months endedJune 30, 2020 was due to a decrease in our ad valorem effective tax rate. Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to$24.9 million for the three months endedJune 30, 2020 compared with$72.6 million for the three months endedJune 30, 2019 . The decrease of$47.7 million was a result of a 1% increase in production volumes and a 66% decrease in the DD&A rate for the three months endedJune 30, 2020 compared with the three months endedJune 30, 2019 . The increase in production accounted for a$0.8 million increase in DD&A expense, while the decrease in the DD&A rate accounted for a$48.5 million decrease in DD&A expense. Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months endedJune 30, 2020 , the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of$8.68 per Boe compared with$25.56 per Boe for the three months endedJune 30, 2019 . The decrease in the depletion rate of 66% was a result of recognizing a$1.2 billion impairment associated with our proved oil and gas properties during the three months endedMarch 31, 2020 . Unused Commitments. Unused commitments expense was$4.4 million for both the three months endedJune 30, 2020 andJune 30, 2019 related to gas transportation contracts. DuringMarch 2010 , we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of theUinta Basin and the Gibson Gulch area of thePiceance Basin . These transportation contracts were not included in the sales of these assets inDecember 2013 andSeptember 2014 , respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expireJuly 31, 2021 . General and Administrative Expense. General and administrative expense increased to$12.9 million for the three months endedJune 30, 2020 from$12.4 million for the three months endedJune 30, 2019 . General and administrative expense on a 28 -------------------------------------------------------------------------------- Table of Contents Boe basis increased to$4.49 for the three months endedJune 30, 2020 from$4.37 for the three months endedJune 30, 2019 . The increase in general and administrative expense for the three months endedJune 30, 2020 was a result of severance and other employee-related non-recurring costs of which were associated with a reduction in force inMay 2020 implemented in order to align our cost structure to the current operating environment. Included in general and administrative expense is long-term cash and equity incentive compensation of$1.6 million and$2.3 million for the three months endedJune 30, 2020 and 2019, respectively. The components of long-term cash and equity incentive compensation for the three months endedJune 30, 2020 and 2019 are shown in the following table: Three Months Ended June 30, 2020 2019 (in thousands) Nonvested common stock$ 1,150 $ 1,533 Nonvested common stock units 202 318 Nonvested performance cash units (1) 198 445 Total$ 1,550 $ 2,296 (1)The nonvested performance cash units are accounted for as liability awards and will be settled in cash for the performance metrics that are met. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date. Interest Expense. Interest expense increased to$15.4 million for the three months endedJune 30, 2020 from$14.4 million for the three months endedJune 30, 2019 . The increase for the three months endedJune 30, 2020 was due to increased borrowings under the Amended Credit Facility during the three months endedJune 30, 2020 . See Note 4 for additional information. Commodity Derivative Gain (Loss). Commodity derivative loss was$33.8 million for the three months endedJune 30, 2020 compared with a gain of$19.5 million for the three months endedJune 30, 2019 . The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as ofJune 30, 2020 and 2019 or during the periods then ended. The fair value of our open, but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility during the three months endedJune 30, 2020 due to the COVID-19 pandemic and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher wellhead revenues in the future.
The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:
Three Months Ended June 30,
2020 2019
(in thousands)
Realized gain (loss) on derivatives (1) $ 40,611 $ (993) Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
(225) (20,933)
Unrealized gain (loss) on derivatives (1) (74,179) 41,470
Total commodity derivative gain (loss) $ (33,793)
(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 Unaudited Consolidated Statements of Operations.
This separate presentation is a non-GAAP measure. Management believes the
separate presentation of the realized and
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unrealized commodity derivative gains and losses is useful because the realized
cash settlement portion provides a better understanding of our hedge
position. We also believe that this disclosure allows for a more meaningful
comparison to our peers.
During the three months ended June 30, 2020 , approximately 78% of our oil
volumes and 26% of our natural gas volumes were subject to financial hedges,
which resulted in an increase in oil income of $40.2 million and natural gas
income of $0.4 million after settlements. During the three months ended June 30,
2019 , approximately 90% of our oil volumes and 17% of our natural gas volumes
were subject to financial hedges, which resulted in a decrease in oil income of
$1.0 million and no change to natural gas income after settlements.
The COVID-19 pandemic caused a severe decline in current and estimated future
oil and gas prices during the three months ended June 30, 2020 . As the duration
of the COVID-19 pandemic is uncertain, we may be unable to obtain additional
hedges at favorable price levels in the near or foreseeable future.
Income Tax (Expense) Benefit. For the three months ended June 30, 2020 and 2019,
income tax expense of zero and $0.1 million was recognized, respectively. For
the three months ended June 30, 2020 , we determined that it was more likely than
not that we would not be able to realize a portion of our deferred tax assets.
This determination was made by considering all available evidence in assessing
the need for a valuation allowance. Such evidence included the scheduled
reversal of deferred tax assets and liabilities, current and projected future
taxable income and tax planning strategies. In making this assessment, judgment
is required in considering the relative weight of positive and negative
evidence. As a result of the analysis conducted, we recorded a valuation
allowance on the net deferred tax asset in excess of deferred tax liabilities.
We continue to consider all available evidence in assessing the need for a
valuation allowance on our deferred tax assets.
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Six Months Ended June 30, 2020 Compared with Six Months Ended June 30, 2019
Six Months Ended June 30, Increase (Decrease)
2020 2019 Amount Percent
($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production $ 122,866 $ 209,191 $ (86,325) (41) %
Other operating revenues - 373 (373) (100) %
Total operating revenues 122,866 209,564 (86,698) (41) %
Operating Expenses
Lease operating expense 20,155 22,049 (1,894) (9) %
Gathering, transportation and processing
expense 8,666 3,465 5,201 150 %
Production tax expense (1,059) 12,798 (13,857) *nm
Exploration expense 52 37 15 41 %
Impairment and abandonment expense 1,266,236 1,317 1,264,919 *nm
(Gain) loss on sale of properties 4,779 2,901 1,878 65 %
Depreciation, depletion and amortization 99,833 145,222 (45,389) (31) %
Unused commitment 8,836 8,821 15 - %
General and administrative expense (1) 23,105 25,061 (1,956) (8) %
Merger transaction expense - 2,414 (2,414) (100) %
Other operating expense, net (502) (20) (482) *nm
Total operating expenses $ 1,430,101 $ 224,065 $ 1,206,036 538 %
Production Data:
Oil (MBbls) 3,224 3,468 (244) (7) %
Natural gas (MMcf) 8,304 7,308 996 14 %
NGLs (MBbls) 1,170 953 217 23 %
Combined volumes (MBoe) 5,778 5,639 139 2 %
Daily combined volumes (Boe/d) 31,747 31,155 592 2 %
Average Realized Prices before Hedging:
Oil (per Bbl) $ 32.56 $ 53.16 $ (20.60) (39) %
Natural gas (per Mcf) 1.06 1.90 (0.84) (44) %
NGLs (per Bbl) 7.74 11.47 (3.73) (33) %
Combined (per Boe) 21.26 37.10 (15.84) (43) %
Average Realized Prices with Hedging:
Oil (per Bbl) $ 53.99 $ 54.45 $ (0.46) (1) %
Natural gas (per Mcf) 1.11 1.79 (0.68) (38) %
NGLs (per Bbl) 7.74 11.47 (3.73) (33) %
Combined (per Boe) 33.28 37.75 (4.47) (12) %
Average Costs (per Boe):
Lease operating expense $ 3.49 $ 3.91 $ (0.42) (11) %
Gathering, transportation and processing
expense 1.50 0.61 0.89 146 %
Production tax expense (0.18) 2.27 (2.45) *nm
Depreciation, depletion and amortization 17.28 25.75 (8.47) (33) %
General and administrative expense (1) 4.00 4.44 (0.44) (10) %
*Not meaningful.
(1)Included in general and administrative expense is long-term cash and equity
incentive compensation of $2.0 million (or $0.35 per Boe) and $5.0 million (or
$0.89 per Boe) for the six months ended June 30, 2020 and 2019, respectively.
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Production Revenues and Volumes. Production revenues decreased to $122.9 million
for the six months ended June 30, 2020 from $209.2 million for the six months
ended June 30, 2019 . The decrease in production revenues was due to a 43%
decrease in average realized prices before hedging, offset by a 2% increase in
production volumes. The decrease in average realized prices before hedging
decreased production revenues by approximately $89.3 million , while the increase
in production volumes increased production revenues by approximately $3.0
million .
Lease Operating Expense. LOE was $20.2 million for the six months ended June 30,
2020 and $22.0 million for the six months ended June 30, 2019 . LOE decreased to
$3.49 per Boe for the six months ended June 30, 2020 from $3.91 per Boe for the
six months ended June 30, 2019 . We started seeing a decrease in service industry
costs during the six months ended June 30, 2020 .
Gathering, Transportation and Processing Expense. GTP expense increased to $1.50
per Boe for the six months ended June 30, 2020 from $0.61 per Boe for the six
months ended June 30, 2019 .
Costs incurred to gather, transport and/or process our oil, gas and NGLs prior
to the transfer of control to the customer are included in GTP expense. Costs
incurred to gather, transport and/or process our oil, gas and NGLs after control
has transferred to the customer are considered components of the consideration
received from the customer and thus recorded in oil, gas and NGL production
revenues. In general, based on specific contract arrangements, costs incurred
associated with gas and NGLs in the Hereford Field in the DJ Basin are included
in GTP expense and costs incurred associated with gas and NGLs in the Northeast
Wattenberg Field in the DJ Basin are included in production revenues. Costs
incurred associated with oil are included in production revenues for both areas.
See the "Revenue Recognition" section in Note 2 for additional information.
The increase in GTP per Boe for the six months ended June 30, 2020 compared to
the six months ended June 30, 2019 was due to an increase in our production mix
from the Hereford Field under the existing contractual arrangement, which has a
primary term through April 2027 .
Production Tax Expense. Total production taxes decreased to negative $1.1
million for the six months ended June 30, 2020 from $12.8 million for the six
months ended June 30, 2019 . Production taxes are primarily based on the wellhead
values of production, which exclude gains and losses associated with hedging
activities. Production tax expense for both periods included an annual true up
of Colorado ad valorem tax based on actual assessments. Production taxes for the
six months ended June 30, 2020 also included Colorado severance tax refunds of
$1.8 million based on an audit of tax years 2015 to 2017. Excluding the ad
valorem and severance tax adjustments and the severance tax refunds associated
with tax years 2015 to 2017, production taxes as a percentage of oil, natural
gas and NGL sales were 6.6% and 8.4% for the six months ended June 30, 2020 and
2019, respectively. The decrease in the rate for the six months ended June 30,
2020 was due to a decrease in our ad valorem effective tax rate.
Impairment and Abandonment Expense. We review our proved oil and natural gas
properties for impairment on a quarterly basis or whenever events and
circumstances indicate that a decline in the recoverability of their carrying
value may have occurred. Whenever we conclude the carrying value may not be
recoverable, we estimate the expected undiscounted future net cash flows of our
oil and gas properties using proved and risked probable and possible reserves
based on our development plans and best estimate of future production, commodity
pricing, reserve risking, gathering and transportation deductions, production
tax rates, lease operating expenses and future development costs. We compare
such undiscounted future net cash flows to the carrying amount of the oil and
gas properties to determine if the carrying amount is recoverable. If the
undiscounted future net cash flows exceed the carrying amount of the oil and gas
properties, no impairment is taken. If the carrying amount of a property exceeds
the undiscounted future net cash flows, we will impair the carrying value to
fair value based on an analysis of quantitative and qualitative factors existing
as of the balance sheet date. The factors used to determine fair value may
include, but are not limited to, recent sales prices of comparable properties,
indications from marketing activities, the present value of future revenues, net
of estimated operating and development costs using estimates of reserves, future
commodity pricing, future production estimates, anticipated capital expenditures
and various discount rates commensurate with the risk and current market
conditions associated with realizing the projected cash flows.
Unproved oil and gas properties are assessed periodically for impairment based
on remaining lease terms, drilling results, reservoir performance, commodity
price outlooks, future plans to develop acreage, recent sales prices of
comparable properties and other relevant matters. We generally expect
impairments of unproved properties to be more likely to occur in periods of low
commodity prices because we will be less likely to devote capital to exploration
activities.
Market conditions led to a decline in the recoverability of the carrying value
of our oil and gas properties during the six months ended June 30, 2020 . Since
the carrying amount of our oil and gas properties was no longer recoverable, we
impaired the carrying value to fair value. Therefore, we recognized non-cash
impairment charges associated with our proved and
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unproved oil and gas properties during the six months ended June 30, 2020 . Our
impairment and abandonment expense for the six months ended June 30, 2020 and
2019 is summarized below:
Six Months Ended June 30,
2020 2019
Impairment of proved oil and gas properties
-
Impairment of unproved oil and gas properties 76,298
-
Abandonment expense 1,372
1,317
Total impairment and abandonment expense
Given the decline in current and estimated future commodity prices, we will continue to review our acreage position and future drilling plans as well as assess the carrying value of our properties relative to their estimated fair values. Lower sustained commodity prices or additional commodity price declines may lead to additional property impairment in future periods. Depreciation, Depletion and Amortization. DD&A decreased to$99.8 million for the six months endedJune 30, 2020 compared with$145.2 million for the six months endedJune 30, 2019 . The decrease of$45.4 million was a result of a 2% increase in production and a 33% decrease in the DD&A rate for the six months endedJune 30, 2020 compared with the six months endedJune 30, 2019 . The increase in production accounted for a$3.6 million increase in DD&A expense while the decrease in the DD&A rate accounted for a$49.0 million decrease in DD&A expense. Under successful efforts accounting, depletion expense is calculated using the units-of-production method on the basis of some reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the six months endedJune 30, 2020 , the relationship of historical capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of$17.28 per Boe compared with$25.75 per Boe for the six months endedJune 30, 2019 . The decrease in the depletion rate of 33% was a result of recognizing a$1.2 billion impairment associated with our proved oil and gas properties during the six months endedJune 30, 2020 . Unused Commitments. Unused commitments expense of$8.8 million for both the six months endedJune 30, 2020 and 2019 related to gas transportation contracts. DuringMarch 2010 , we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of theUinta Basin and the Gibson Gulch area of thePiceance Basin . These transportation contracts were not included in the sales of these assets inDecember 2013 andSeptember 2014 , respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expireJuly 31, 2021 . General and Administrative Expense. General and administrative expense decreased to$23.1 million for the six months endedJune 30, 2020 from$25.1 million for the six months endedJune 30, 2019 . General and administrative expense on a Boe basis decreased to$4.00 for the six months endedJune 30, 2020 from$4.44 for the six months endedJune 30, 2019 . Included in general and administrative expense is long-term cash and equity incentive compensation of$2.0 million and$5.0 million for the six months endedJune 30, 2020 and 2019, respectively. The components of long-term cash and equity incentive compensation for the six months endedJune 30, 2020 and 2019 are shown in the following table: Six Months Ended June 30, 2020 2019 (in thousands) Nonvested common stock$ 2,300 $ 3,329 Nonvested common stock units 482 612 Nonvested performance cash units (1) (776) 1,077 Total$ 2,006 $ 5,018 (1)The nonvested performance cash units are accounted for as liability awards and will be settled in cash for the performance metrics that are met. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date. 33
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Merger Transaction Expense. Merger transaction expense of$2.4 million for the six months endedJune 30, 2019 included severance, consulting, advisory, legal and other merger-related fees that were not capitalized as part of the Merger. Interest Expense. Interest expense increased to$29.8 million for the six months endedJune 30, 2020 from$28.1 million for the six months endedJune 30, 2019 . The increase for the six months endedJune 30, 2020 was due to increased borrowings under the Amended Credit Facility during the six months endedJune 30, 2020 . See Note 4 for additional information. Commodity Derivative Gain (Loss). Commodity derivative gain was$158.4 million for the six months endedJune 30, 2020 compared with a loss of$85.6 million for the six months endedJune 30, 2019 . The gain for the six months endedJune 30, 2020 compared to the loss for the six months endedJune 30, 2019 was related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as ofJune 30, 2020 and 2019 or during the periods then ended. The fair value of our open, but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility during the six months endedJune 30, 2020 due to the COVID-19 pandemic and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher wellhead revenues in the future.
The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:
Six Months Ended June 30,
2020 2019
(in thousands)
Realized gain (loss) on derivatives (1) $ 69,447 $ 3,656 Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
1,104 (57,073)
Unrealized gain (loss) on derivatives (1) 87,844 (32,230)
Total commodity derivative gain (loss) $ 158,395 $ (85,647)
(1)Realized and unrealized gains and losses on commodity derivatives are
presented in the table as separate line items but are combined for a total
commodity derivative gain (loss) in the Unaudited 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 our hedge position. We also believe
that this disclosure allows for a more meaningful comparison to our peers.
During the six months ended June 30, 2020 , approximately 86% of our oil volumes
and 12% of our natural gas volumes were subject to financial hedges, which
resulted in an increase in oil income of $60.7 million and natural gas income of
$0.4 million . We also amended certain oil hedge contracts to terminate future
hedged volumes, which resulted in additional oil income of $8.3 million during
the six months ended June 30, 2020 . During the six months ended June 30, 2019 ,
approximately 90% of our oil volumes and 26% of our natural gas volumes were
subject to financial hedges, which resulted in an increase in oil income of $4.5
million and a decrease in natural gas income of $0.8 million after settlements.
The COVID-19 pandemic caused a severe decline in current and estimated future
oil and gas prices during the six months ended June 30, 2020 . As the duration of
the COVID-19 pandemic is uncertain, we may be unable to obtain additional hedges
at favorable price levels in the near or foreseeable future.
Income Tax (Expense) Benefit. For the six months ended June 30, 2020 and 2019,
income tax benefits of $95.3 million and $29.6 million were recognized,
respectively. For the six months ended June 30, 2020 , we determined that it was
more likely than not that we would not be able to realize a portion of our
deferred tax assets. This determination was made by considering all available
evidence in assessing the need for a valuation allowance. Such evidence included
the scheduled reversal of
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deferred tax assets and liabilities, current and projected future taxable income
and tax planning strategies. In making this assessment, judgment is required in
considering the relative weight of positive and negative evidence. As a result
of the analysis conducted, we recorded a valuation allowance on the net deferred
tax asset in excess of deferred tax liabilities. For the six months ended
June 30, 2020 , we have recorded a deferred tax liability of $2.1 million for
projected taxable income in future periods in which only 80% of taxable income
can be offset by net operating losses. We continue to consider all available
evidence in assessing the need for a valuation allowance on our deferred tax
assets.
Capital Resources and Liquidity
Our primary sources of liquidity since our formation have been net cash provided
by operating activities, including commodity hedges, sales and other issuances
of equity and debt securities, bank credit facilities, proceeds from
sale-leasebacks, joint exploration agreements and sales of interests in
properties. Our primary use of capital has been for the development, exploration
and acquisition of oil and natural gas properties. As we pursue profitable
reserves and production growth, we continually monitor the capital resources
available to us to meet our future financial obligations, fund planned capital
expenditure activities and ensure adequate liquidity.
We may from time to time seek to retire, purchase or otherwise refinance our
outstanding debt securities through cash purchases and/or exchanges, in open
market purchases, privately negotiated transactions, exchange offers or
otherwise. Any such transactions will depend on prevailing market conditions,
our liquidity requirements, contractual restrictions and other factors. The
amounts involved may be material.
Our future success in growing proved reserves and production will be highly
dependent on capital resources being available to us. Given the levels of market
volatility and disruption due to the COVID-19 pandemic, the availability of
funds from those markets has diminished substantially. Further, arising from
concerns about the stability of financial markets generally and the solvency of
borrowers specifically, the cost of accessing the credit markets has increased
as many lenders have raised interest rates, enacted tighter lending standards,
or altogether ceased to provide funding to borrowers.
At December 31, 2019 , we had cash and cash equivalents of $16.4 million and
$140.0 million outstanding under the Amended Credit Facility. At June 30, 2020 ,
we had cash and cash equivalents of $2.7 million and $175.0 million outstanding
under the Amended Credit Facility. On May 21, 2020 , the Amended Credit Facility
borrowing base was reduced from $500.0 million to $300.0 million and the
applicable margins for interest and commitment fee rates were increased. In
addition, provisions were added requiring the availability under the Amended
Credit Facility to be at least $50.0 million and our weekly cash balance
(subject to certain exceptions) to not exceed $35.0 million . Our available
borrowing capacity under the Amended Credit Facility as of June 30, 2020 was
$53.3 million , after taking into account the $50.0 million minimum availability
requirement and outstanding irrevocable letter of credit of $21.7 million
related to a firm transportation agreement.
As of the date of this filing, August 3, 2020 , we believe that we have
sufficient liquidity available to us from cash on hand, cash flows from
operations and under our Amended Credit Facility to meet our obligations and
commitments for the next twelve months. We deferred drilling and completion
activity starting in May 2020 and will continue to defer until oil prices
improve to a level that allows us to meet our target return threshold. In
addition, we are currently in compliance with all financial covenants under our
Amended Credit Facility and have $71.2 million available for future borrowing,
after taking into consideration payments on the Amended Credit Facility of $20
million made in July 2020 and letter of credit balances of $23.8 million .
Cash Flow from Operating Activities
Net cash provided by operating activities for the six months endedJune 30, 2020 and 2019 was$60.3 million and$98.5 million , respectively. The decrease in net cash provided by operating activities was due to a decrease in production revenues and a decrease in working capital changes due to the timing of cash receipts and disbursements. These were partially offset by an increase in cash settlements of derivatives. Commodity Hedging Activities Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors, which include the COVID-19 pandemic, are beyond our control and are difficult to predict. 35 -------------------------------------------------------------------------------- Table of Contents To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap and swaption contracts to receive fixed prices for a portion of our production. AtJune 30, 2020 , we had in place crude oil and natural gas swaps covering portions of our 2020 and 2021 production and crude oil swaptions covering portions of our 2022 production. In addition, we had oil roll swaps covering portions of our 2020 production. Due to the uncertainty surrounding the COVID-19 pandemic, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. The following table includes all hedges entered into throughJuly 20, 2020 . Weighted Total Average Hedged Quantity Fixed Index Contract Volumes Type Price Price (1) Swaps 2020 Oil 2,760,000 Bbls$ 56.59 WTI Natural gas 3,680,000 MMBtu$ 1.83 NWPL 2021 Oil 3,098,000 Bbls$ 54.30 WTI Natural gas 5,790,000 MMBtu$ 2.13 NWPL Oil Roll Swaps (2) 2020 Oil 276,500 Bbls$ (1.47) WTI Swaptions 2022 Oil 1,092,000 Bbls$ 55.08 WTI (1)WTI refers to West Texas Intermediate price as quoted on theNew York Mercantile Exchange . NWPL refers to theNorthwest Pipeline Corporation price as quoted in Platt's Inside FERC on the first business day of each month. (2)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.
By removing the price volatility from a portion of our oil and natural gas revenue, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for the relevant period. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.
It is our policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. Our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement andInternational Swaps and Derivative Association, Inc. ("ISDA") Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to us under the derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. Capital Expenditures
Our capital expenditures are summarized in the following tables for the periods indicated:
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Six Months Ended June 30,
Basin/Area 2020 2019
(in millions)
DJ Basin $ 93.4 $ 246.9
Other 1.8 3.6
Total $ 95.2 $ 250.5
Six Months Ended June 30,
2020 2019
(in millions) Acquisitions of proved and unproved properties and other real estate
$ - $ 0.7 Drilling, development, exploration and exploitation of oil and natural gas properties
92.4 230.1
Gathering and compression facilities 2.1 9.3
Geologic and geophysical costs 0.4 6.8
Furniture, fixtures and equipment 0.3 3.6
Total $ 95.2 $ 250.5
For the three months ending September 30, 2020 , capital expenditures are
anticipated to be approximately $10.0 million . As oil prices declined
significantly due to the COVID-19 pandemic, we deferred drilling and completion
activity starting in May 2020 and will continue deferring until oil prices
improve to a level that allows us to meet our target return threshold. We may
continue to adjust capital expenditures as business conditions and operating
results warrant. The amount, timing and allocation of capital expenditures is
generally discretionary and within our control.
Financing Activities
Amended Credit Facility. OnMay 21, 2020 , the Amended Credit Facility aggregate elected commitment amount and borrowing base were reduced from$500.0 million to$300.0 million and the applicable margins for interest and commitment fee rates were increased. In addition, provisions were added requiring the availability under the Amended Credit Facility to be at least$50.0 million and our weekly cash balance (subject to certain exceptions) to not exceed$35.0 million . We had$175.0 million and$140.0 million outstanding under the Amended Credit Facility as ofJune 30, 2020 andDecember 31, 2019 , respectively. Our available borrowing capacity was$53.3 million as ofJune 30, 2020 after taking into account the$50.0 million minimum availability requirement as well as a$21.7 million letter of credit, which was issued as credit support for future payments under a contractual obligation. As of the date of this filing,August 3, 2020 , our available borrowing capacity is at$71.2 million after taking into consideration payments on the Amended Credit Facility of$20 million made inJuly 2020 and letter of credit balances of$23.8 million . The current maturity date of the Amended Credit Facility isJuly 16, 2022 . While the stated maturity date in the Amended Credit Facility isSeptember 14, 2023 , the maturity date is accelerated if we have more than$100.0 million of "Permitted Debt" or "Permitted Refinancing Debt" (as those terms are defined in the Amended Credit Facility) that matures prior toDecember 14, 2023 . If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature onOctober 15, 2022 , the aggregate amount of those notes exceeds$100.0 million and the notes represent "Permitted Debt", the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, orJuly 16, 2022 . The borrowing base is determined at the discretion of the lenders and is subject to regular re-determination on or aboutApril 1 andOctober 1 of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. If the borrowing base is reduced below the then-outstanding amount under the amended Credit Facility, we will be required to repay the excess of the outstanding amount over the borrowing base over a period of four months. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt. We have financial covenants associated with our Amended Credit Facility that are measured each fiscal quarter. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. However, if current market conditions continue, we may not be able to maintain compliance with these financial covenants. In particular, we may breach the debt-to-EBITDAX ratio and the current ratio covenants in the Amended Credit Facility in the latter part of 37 -------------------------------------------------------------------------------- Table of Contents 2021. Further, if our independent auditor were to include an explanatory paragraph regarding our ability to continue as a "going concern" in the auditors' report on our financial statements for the year endingDecember 31, 2020 , this would also cause a default under the Amended Credit Facility. If a covenant breach occurs or is likely, we may attempt to obtain a waiver from the lenders under the Amended Credit Facility, seek to amend the terms of the Amended Credit Facility to prevent the breach or seek to obtain alternative financing to repay the Amended Credit Facility balance outstanding. If these efforts are unsuccessful, all or a portion of the amount borrowed under the Amended Credit Facility could become due, and cross-defaults could occur under our senior notes and we may not have other sources of capital to repay the amounts due.
Our outstanding debt is summarized below:
As of June 30, 2020 As of December 31, 2019
Unamortized Carrying Unamortized Carrying
Maturity Date Principal Discount Amount Principal Discount Amount
(in thousands)
Amended Credit Facility September 14, 2023 $ 175,000 $ - $ 175,000 $ 140,000 $ - $ 140,000
7.0% Senior Notes October 15, 2022 350,000 (1,954) 348,046 350,000 (2,372) 347,628
8.75% Senior Notes June 15, 2025 275,000 (3,373) 271,627 275,000 (3,717) 271,283
Total Long-Term Debt (1) $ 800,000 $ (5,327) $ 794,673 $ 765,000 $ (6,089) $ 758,911 (1)See Note 4 for additional information.
Guarantor Structure. The issuer of our 7.0% Senior Notes and 8.75% Senior Notes isHighPoint Operating Corporation (f/k/aBill Barrett ), or Subsidiary Issuer. Pursuant to supplemental indentures entered into in connection with the Merger,HighPoint Resources Corporation , or the Parent Guarantor, became a guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes inMarch 2018 . In addition,Fifth Pocket Production, LLC , or the Subsidiary Guarantor, became a subsidiary of Subsidiary Issuer onAugust 1, 2019 and also guarantees the 7.0% Senior Notes and the 8.75% Senior Notes. The Parent Guarantor and the Subsidiary Guarantor, on a joint and several basis, fully and unconditionally guarantee the debt securities of the Subsidiary Issuer. We have no other subsidiaries. All covenants in the indentures governing the notes limit the activities of the Subsidiary Issuer and the Subsidiary Guarantor, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to the Parent Guarantor, but in most cases the covenants in the indentures are not applicable to the Parent Guarantor. InMarch 2020 , theSecurities and Exchange Commission ("SEC") issued a final rule, Financial Disclosures About Guarantors and Issuers ofGuaranteed Securities and Affiliates Whose Securities Collateralize a Registrant's Securities, which amends the disclosure requirements related to certain registered securities which currently require separate financial statements for subsidiary issuers and guarantors of registered debt securities unless certain exceptions are met. Alternative disclosures are available for each subsidiary issuer/guarantor when they are consolidated and the parent company either issues or guarantees, on a full and unconditional basis, the guaranteed securities. If a registrant qualifies for alternative disclosure, the registrant may omit summarized financial information when not material and instead provide narrative disclosure of the guarantor structure, including terms and conditions of the guarantees. We qualify for alternative disclosure, therefore, as ofMarch 2020 , we are no longer presenting condensed consolidating financial information for our parent guarantor, subsidiary issuer, or subsidiary guarantor of our debt securities. The assets, liabilities and results of operations of the issuer and guarantors of the guaranteed securities on a combined basis are not materially different than corresponding amounts presented in the consolidated financial statements of the parent company as all of the material operating assets and liabilities, and all of our material operations reside within the subsidiary issuer. Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies.Moody's Investor Services andStandard & Poor's Rating Services currently rate our 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, 7.0% Senior Notes or 8.75% Senior Notes. However, our ability to raise funds and the costs of any financing activities could be affected by our credit rating at the time any such financing activities are conducted.
Contractual Obligations. A summary of our contractual obligations as of
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Payments Due by Year
Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total
Twelve Months Twelve Months Twelve Months Twelve Months Twelve Months
Ended June 30 , Ended June 30 , Ended June 30 , Ended June 30 , Ended June 30 , After June
2021 2022 2023 2024 2025 30, 2025
(in thousands)
Notes payable (1) $ 390 $ 12 $ - $ 175,000 $ - $ - $ 175,402
7.0% Senior Notes (2) 24,500 24,500 362,250 - - - 411,250
8.75% Senior Notes (3) 24,063 24,063 24,063 24,063 299,061 - 395,313
Firm transportation agreements (4) 25,973 12,240 14,600 14,640 12,160 - 79,613
Gas gathering and processing agreements (5) 2,092 4,265 - - - -
6,357
Asset retirement obligations (6) 2,619 2,004 2,006 2,150 2,127 15,663 26,569 Operating leases (7) 2,708 2,490 2,219 2,051 2,137 6,486 18,091 Other (8) 1,471 1,285 11,485 15,912 - - 30,153 Total$ 83,816 $ 70,859 $ 416,623 $ 233,816 $ 315,485 $ 22,149 $ 1,142,748 (1)Included in notes payable is the outstanding principal amount under our Amended Credit Facility dueSeptember 14, 2023 . This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. The current maturity date of the Amended Credit Facility isJuly 16, 2022 . While the stated maturity date in the Amended Credit Facility isSeptember 14, 2023 , the maturity date is accelerated if we have more than$100.0 million of "Permitted Debt" or "Permitted Refinancing Debt" (as those terms are defined in the Amended Credit Facility) that matures prior toDecember 14, 2023 . If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature onOctober 15, 2022 , the aggregate amount of those notes exceeds$100.0 million and the notes represent "Permitted Debt", the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, orJuly 16, 2022 . Also included in notes payable is interest on a$21.7 million letter of credit, which will continue to decrease ratably per month until it expires onAugust 31, 2021 . Interest accrues at 3.0% and 0.125% per annum for participation fees and fronting fees, respectively. (2)OnMarch 25, 2012 , we issued$400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make semi-annual interest payments through maturity onOctober 15, 2022 equal to$12.3 million . (3)OnApril 28, 2017 , we issued$275.0 million aggregate principal amount of 8.75% Senior Notes. We are obligated to make semi-annual interest payments through maturity onJune 15, 2025 equal to$12.0 million . (4)We have entered into contracts that provide firm transportation capacity on oil and gas pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount we deliver to the processing facility or pipeline. (5)Includes a gas gathering and processing contract which requires us to deliver a minimum volume of natural gas to a midstream entity for gathering and processing on a monthly basis. The contract requires us to pay a fee associated with the contracted volumes regardless of the amount delivered. (6)Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year endedDecember 31, 2019 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations. (7)Operating leases primarily includes office leases. Also included are leases of operations equipment which are shown as gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest, which will vary from property to property. (8)Includes$10.2 million for the twelve months endedJune 30, 2023 and$15.3 million for the twelve months endedJune 30, 2024 related to a drilling commitment with a joint interest partner which requires us to drill and complete two wells byJuly 2022 and three wells by 2023. If the drilling commitment is not met, the Company must return the associated leases that are not held by production to the joint interest partner, which cover approximately 13,000 acres. Also includes fresh water commitment contracts which require us to purchase a minimum volume of fresh water from a supplier. The contracts require us to pay a fee associated with the contracted volumes regardless of the amount delivered.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements as of
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Trends and Uncertainties
We refer you to the corresponding section in Part II, Item 7 of our Annual
Report on Form 10-K for the year ended December 31, 2019 for a discussion of
trends and uncertainties that may affect our financial condition or liquidity.
Also see "Risk Factors" in Part II of this report. The following trends and
uncertainties are related to the COVID-19 pandemic.
Declining Commodity Prices. The severe decline in oil prices that occurred in
the first quarter of 2020 due to the COVID-19 pandemic has adversely affected
the economics of our existing wells and planned future wells, which led to
impairments of both proved and unproved oil and gas properties during the three
months ended March 31, 2020 . In addition, we deferred drilling and completion
activity starting in May 2020 for the foreseeable future. Our results of
operations for the three and six months ended June 30, 2020 were mitigated from
price declines by hedges in place on 78% and 86%, respectively, of our oil
production. We currently have hedged approximately 92% and 56% of our expected
remaining 2020 oil and natural gas production, respectively, at price levels
that provide some economic certainty to our capital investments. As the duration
of the COVID-19 pandemic is uncertain, we may be unable to obtain additional
hedges at favorable price levels in the near or foreseeable future. The degree
to which the COVID-19 pandemic will adversely impact our future operations and
results will depend on future developments, which are highly uncertain and
cannot be predicted, including, but not limited to, the duration of the spread
of the outbreak, its severity, the actions to contain the virus and treat its
impact, its impact on the economy and market conditions, and how quickly and to
what extent normal economic and operating conditions can resume. Lower sustained
commodity prices or additional commodity price declines may lead to additional
property impairment in future periods.
Employee Health and Safety. The health and safety of our employees and the
community is our highest priority. We are also cognizant that supplying reliable
energy to our communities and the nation is an essential function. The federal
government, through the Cybersecurity and Infrastructure Security
Administration , as well as Colorado state and local "stay-at-home" orders, have
provided exemptions for oil and gas workers.
Under our business continuity plan, we were rapidly able to switch to remote
operations in response to the COVID-19 pandemic in early March. Beginning March
16th , we successfully transitioned to full remote access and operations, in both
the Denver headquarters office and at the field level. The successful transition
to remote operations was virtually seamless. In late May, we began to transition
back to increased office presence on a staggered schedule so that approximately
50% of the work force is in the office on a daily basis.
Supply Chain Issues . We have not experienced any recent challenges with respect
to obtaining oil field goods and services. However, as oil service and supply
companies cut work force and stack rigs and frac fleets, there is the potential
for challenges on this front when activity begins to ramp up, although the
related timing is highly uncertain.
Access to Downstream Markets. We are not currently experiencing constraints
associated with midstream gas processing or crude oil transportation. However,
crude storage facilities are operating close to maximum capacity, which could
result in the need for us to shut-in production. Accordingly, we have engaged in
contingency planning for that possibility.
Critical Accounting Policies and Estimates
We refer you to the corresponding section in Part II, Item 7 of our Annual
Report on Form 10-K for the year ended December 31, 2019 and the notes to the
Unaudited Consolidated Financial Statements included in Item 1 of this Quarterly
Report on Form 10-Q for a description of critical accounting policies and
estimates.
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