PERMIAN RESOURCES CORPORATION
The following discussion and analysis of our financial condition and results of
operation should be read in conjunction with the accompanying consolidated
financial statements and related notes. The following discussion and analysis
contains forward-looking statements that reflect our future plans, estimates,
beliefs and expected performance. The 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, market prices for oil, natural gas and NGLs, production
volumes, estimates of proved reserves, capital expenditures, economic and
competitive conditions, regulatory changes, continued and future impacts of
Coronavirus Disease 2019 ("COVID-19") and other uncertainties, as well as those
factors discussed above in "Cautionary Statement Regarding Forward-Looking
Statements" and under the heading "Item 1A. Risk Factors" in this Quarterly
Report and our 2019 Annual Report, all of which are difficult to predict. In
light of these risks, uncertainties and assumptions, the forward-looking events
discussed may not occur. We do not undertake any obligation to publicly update
any forward-looking statements except as otherwise required by applicable law.
Overview
Centennial Resource Development, Inc. ("Centennial," "we," "us," or "our") is an
independent oil and natural gas company focused on the development of
unconventional oil and associated liquids-rich natural gas reserves in the
Permian Basin . Our assets are primarily in the Delaware Basin , a sub-basin of
the Permian Basin . Our capital programs are specifically focused on projects
that we believe provide the highest return on capital. Unless otherwise
specified or the context otherwise requires, all references in these discussions
to "Centennial," "we," "us," or "our" are to Centennial Resource Development,
Inc. and its consolidated subsidiary, Centennial Resource Production, LLC
("CRP").
Market Conditions
The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact
of COVID-19 and various governmental actions taken to mitigate the impact of
COVID-19, have resulted in an unprecedented decline in demand for oil and
natural gas. At the same time, the decision by Saudi Arabia in March 2020 to
drastically reduce export prices and increase oil production followed by
curtailment agreements among OPEC and other countries such as Russia further
increased uncertainty and volatility around global oil supply-demand dynamics.
As a result, there has been a significant decline in commodity prices starting
in the first quarter of 2020. However, during the second quarter of 2020, OPEC
and other oil producing countries agreed to reduce their crude oil production
and then extend such production cuts through at least August of 2020, while U.S.
producers substantially reduced or suspended drilling activity, and in most
cases curtailed production, due to low oil prices and poor economics. These
actions have aided in a partial recovery of global commodity prices.
Specifically, WTI spot prices for crude oil fell to a low of negative ($37.63 )
on April 20, 2020 (due to depressed demand and insufficient storage capacity,
particularly at the WTI physical settlement location in Cushing, Oklahoma ) and
have since partially recovered to a high of $40.46 on June 22, 2020 .
The oil and natural gas industry is cyclical, and it is likely that commodity
prices, as well as commodity price differentials, will continue to be volatile
and fluctuate due to global supply and demand, inventory levels, the continued
effects from COVID-19, geopolitical events, weather conditions and other
factors. The following table highlights the quarterly average NYMEX price trends
for crude oil and natural gas since the first quarter of 2018:
2018 2019 2020
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Crude oil (per Bbl)
$ 62.91 $ 68.07 $ 69.50 $ 58.81 $ 54.90
A sustained drop in oil, natural gas and NGL prices, such as those we have
experienced in the first half of 2020, will not only decrease our revenues on a
per unit basis but can also reduce the amount of oil, natural gas and NGLs that
we can produce economically and therefore potentially lower our oil, natural gas
and NGL reserve quantities.
Lower commodity prices (including realized differentials) and lower futures
curves for oil and gas prices, can also result in further impairments of our
proved oil and natural gas properties or undeveloped acreage (such as the
impairments discussed below under "Results of Operations") and may materially
and adversely affect our future business, financial condition, results of
operations, operating cash flows, liquidity and/or ability to finance planned
capital expenditures. Lower realized prices may also reduce the borrowing base
under CRP's credit agreement (such as the reduction discussed below under
"Financing Highlights"), which is determined at the discretion of the lenders
and is based on the collateral value of our proved reserves that have been
mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of
the revised borrowing capacity were outstanding, we could be forced to
immediately repay a portion of the debt outstanding under the credit agreement.
Additionally,
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the lower price environment and its impact to our operations could impact our ability to comply with the covenants under our credit agreement and senior notes. COVID-19 Outbreak The COVID-19 outbreak and its development into a pandemic inMarch 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, contractors, suppliers and the communities in which we operate. Our operational employees have been and are currently able to work on site, while the vast majority of our non-operational employees worked remotely during the months of March and April but have started to report back to our offices on a limited basis starting in mid-May. We have taken various precautionary measures with respect to our operational employees and employees who return to our offices such as (i) requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site or office, (ii) self-quarantining any employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and (iii) imposing social distancing requirements on work sites and at our offices, that are in accordance with the guidelines released by theCenter for Disease Control as well as local and state authorities. We have not experienced any operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak. 2020 Highlights and Future Considerations The changes in the macro environment and related volatility in commodity prices that occurred during the first half of 2020 discussed above have significantly impacted our results of operations for the three and six months endedJune 30, 2020 , and we believe that our future operating results and near-term financial condition will continue to be impacted, until such time that oil supply and demand dynamics stabilize. Further, our results of operations for the three and six months endedJune 30, 2020 discussed within this Quarterly Report will likely not be indicative of our operating results for the remainder of 2020 due to the timing of operational changes and continued volatility of commodity prices. Operational Highlights We operated a five-rig drilling program during the majority of the first quarter of 2020, which enabled us to complete and bring online 26 gross operated wells with an average effective lateral length of approximately 7,200 feet during the first half of 2020. Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we suspended all drilling and completion activities in order to preserve capital. Specifically, we reduced our operated drilling rig program to zero rigs starting in April of 2020 and continued with no rigs in operation for the remainder of the second quarter. In addition, given the weakness in realized oil prices, we voluntarily curtailed or shut-in a portion of our production volumes. Specifically, we curtailed approximately 20% of our production during the month of May, but were able to bring the majority of our production back online in June, with minimal incremental cost as crude oil prices recovered. Additionally, the Company filled its on-site tank batteries with crude oil during May in order to minimize the amount of shut-in volumes, ultimately selling these barrels in June at higher prices. The potential for any future curtailment decisions will continue to be evaluated and made on a month-to-month basis subject to market conditions, storage or transportation constraints, and contractual obligations. As substantially all of our revenues are generated by the production and sale of hydrocarbons, the curtailment or shut-in of our production could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. Financing Highlights OnMay 22, 2020 , we completed an opportunistic private exchange of our debt pursuant to which$110.6 million aggregate principal amount of CRP's 5.375% senior notes due 2026 (the "2026 Senior Notes") and$143.7 million aggregate principal amount of CRP's 6.875% senior notes due 2027 (the "2027 Senior Notes" and, together with the 2026 Senior Notes, the "Senior Unsecured Notes") were validly tendered and exchanged by certain eligible bondholders for consideration consisting of$127.1 million aggregate principal amount (the "Debt Exchange") of newly issued 8.00% second lien senior secured notes due 2025 (the "Senior Secured Notes"). This transaction resulted in the removal of$127.1 million in principal amount of Senior Unsecured Notes from the long-term debt balance in our Consolidated Balance Sheets. OnMay 1, 2020 , we entered into amendments to CRP's amended and restated credit agreement (the "2020 Amendments") with the lenders to our existing credit agreement. Pursuant to the 2020 Amendments, the borrowing base and level of elected commitments were reduced to$700.0 million . The 2020 Amendments that the lenders approved permitted the issuance of the Senior Secured Notes in connection with the Debt Exchange, and they implemented an availability blocker of$31.8 million equal to 25% of the newly issued and outstanding Senior Secured Notes. Among other things, the Amendments also suspended the total funded debt to EBITDAX ratio (as specified in the existing credit agreement) through year-end 2021 and introduced a new financial covenant testing the ratio of first lien debt to EBITDAX. 32
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Results of Operations Three Months EndedJune 30, 2020 Compared to Three Months EndedJune 30, 2019 The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period's average prices and average daily production volumes: Three Months Ended June 30, Increase/(Decrease) 2020 2019 $ % Net revenues (in thousands): Oil sales$ 73,100 $ 214,305 $ (141,205 ) (66 )% Natural gas sales 8,787 8,088 699 9 % NGL sales 8,622 21,846 (13,224 ) (61 )% Oil and gas sales$ 90,509 $ 244,239 $ (153,730 ) (63 )% Average sales prices: Oil (per Bbl)$ 21.47 $ 54.63 $ (33.16 ) (61 )% Effect of derivative settlements on average price (per Bbl) (1.60 ) (0.18 ) (1.42 ) (789 )% Oil net of hedging (per Bbl)$ 19.87 $ 54.45 $ (34.58 ) (64 )% Average NYMEX price for oil (per Bbl)$ 28.00 $ 59.81 $ (31.81 ) (53 )% Oil differential from NYMEX (6.53 ) (5.18 ) (1.35 ) (26 )% Natural gas (per Mcf)$ 0.87 $ 0.81$ 0.06 7 % Effect of derivative settlements on average price (per Mcf) (0.14 ) 0.71 (0.85 ) (120 )% Natural gas net of hedging (per Mcf)$ 0.73 $ 1.52
Average NYMEX price for natural gas (per Mcf)$ 1.65 $ 2.51$ (0.86 ) (34 )% Natural gas differential from NYMEX (0.78 ) (1.70 ) 0.92 54 % NGL (per Bbl)$ 7.72 $ 16.24 $ (8.52 ) (52 )% Net production: Oil (MBbls) 3,404 3,922 (518 ) (13 )% Natural gas (MMcf) 10,140 9,954 186 2 % NGL (MBbls) 1,116 1,346 (230 ) (17 )% Total (MBoe)(1) 6,210 6,927 (717 ) (10 )% Average daily net production: Oil (Bbls/d) 37,411 43,105 (5,694 ) (13 )% Natural gas (Mcf/d) 111,419 109,392 2,027 2 % NGL (Bbls/d) 12,264 14,785 (2,521 ) (17 )% Total (Boe/d)(1) 68,245 76,122 (7,877 ) (10 )%
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of
six Mcf of natural gas to one Boe.
Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the three months endedJune 30, 2020 were$153.7 million (or 63%) lower than total net revenues for the three months endedJune 30, 2019 . Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized. 33
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Average realized sales prices for oil and NGLs decreased in the second quarter of 2020 compared to the same 2019 period. The average price for oil before the effects of hedging decreased 61% and the average price for NGLs decreased 52% between periods. The 61% decrease in the average realized oil price was the result of lower NYMEX crude prices between periods (average NYMEX prices decreased 53%) and wider oil differentials (an increase of$1.35 per Bbl). The 52% decrease in average realized NGL prices between periods was primarily attributable to lowerMont Belvieu spot prices for plant products in the second quarter of 2020 as compared to the second quarter of 2019. Conversely, the average price for natural gas before the effects of hedging increased 7% in the second quarter 2020 compared to the same 2019 period. This increase was mainly due to improved gas differentials (a decrease of$0.92 per Mcf), which was largely offset by lower average NYMEX gas prices between periods (average NYMEX prices decreased$0.86 per Mcf). The improvement in gas differentials is the result of higher natural gas prices realized inWest Texas as several producers shut-in wells and curtailed production in thePermian Basin during the second quarter and as new pipelines have been placed into service. These pipelines have provided relief from gas pipeline takeaway capacity constraints experienced in 2019. The market prices for oil, natural gas and NGLs were significantly impacted by lower demand globally for oil and gas as a result of COVID-19 as well as commodity supply disruptions, both of which combined resulted in significant price declines starting inMarch 2020 , as discussed in the market conditions section above. Net production volumes for oil and NGLs decreased 13% and 17%, respectively, while natural gas increased 2% between periods. The crude oil production volume decrease was the result of (i) the temporary suspension of our drilling and completion activity in the second quarter of 2020, which resulted in only four new wells completed and brought online during the period as compared to 20 wells completed and brought online in the second quarter of 2019; (ii) the curtailment of a portion of our production during the month of May in the second quarter of 2020; and (iii) normal field production declines across our existing wells. These production decreases were partially offset by 70 gross operated wells placed on production in theDelaware Basin since the second quarter of 2019, which added 1,604 MBbls of net oil production to the three months endedJune 30, 2020 . Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, during the second quarter of 2020, the main processor of our raw gas operated in partial ethane-rejection for two-thirds of the quarter, as compared to operating in full ethane-recovery during the entire 2019 period. As a result, we sold an increased amount of natural gas from our wet gas stream and recovered fewer NGLs during the 2020 period, resulting in an increase (2%) in natural gas volumes and a decrease (17%) in NGL volumes between periods. Operating Expenses. The following table sets forth selected operating expense data for the periods indicated: Three Months EndedJune 30 ,
Increase/(Decrease)
2020 2019 $ %
Operating costs (in thousands):
Lease operating expenses $ 25,839 $ 34,885 $ (9,046 ) (26 )%
Severance and ad valorem taxes 5,696 17,186 (11,490 ) (67 )%
Gathering, processing and
transportation expenses 17,284 16,243 1,041 6 %
Operating costs per Boe:
Lease operating expenses $ 4.16 $ 5.04 $ (0.88 ) (17 )%
Severance and ad valorem taxes 0.92 2.48 (1.56 ) (63 )%
Gathering, processing and 2.78 2.34
transportation expenses 0.44 19 %
Lease Operating Expenses. Lease operating expenses ("LOE") for the three months
ended June 30, 2020 decreased $9.0 million compared to the three months ended
June 30, 2019 . Lower LOE for the second quarter of 2020 was primarily related to
a $7.6 million decrease in workover expense between periods as a result of lower
workover activity and a $1.4 million decrease in variable and semi-variable
operating costs as a result of lower production activity between periods.
LOE on a per Boe basis decreased when comparing the second quarter of 2020 to
the same 2019 period. LOE per Boe was $4.16 for the second quarter of 2020,
which represents a decrease of $0.88 per Boe (or 17%) from the second quarter of
2019. This decrease in rate was mainly due to the lower level of workover
activity, discussed above, as well as cost reduction initiatives we have
undertaken such as lowering contract labor costs and decreasing monthly
equipment rentals, which were achieved by moving multiple wells off generators
to more efficient electrical line-power. These decreases were partially offset
by per BOE cost increases associated with fixed and semi-variable costs that
don't decrease at the same rate as declines in production such as (i) monthly
rental fees for compressors and electric submersible pumps ("ESPs"), and (ii)
wellhead chemical costs.
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Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months endedJune 30, 2020 decreased$11.5 million compared to the three months endedJune 30, 2019 . Severance taxes are primarily based on the market value of production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of proved developed oil and natural gas reserves and vary across the different counties in which we operate. Severance and ad valorem taxes as a percentage of total net revenues decreased to 6.3% for the second quarter of 2020 as compared to 7.0% for the same 2019 period. This decrease in rate between periods was mainly due to (i) lower severance paid on the taxable values of natural gas and (ii)$0.3 million in tax credits received on wells designated "high cost gas" by the state ofTexas . Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses ("GP&T") for the three months endedJune 30, 2020 increased$1.0 million as compared to the three months endedJune 30, 2019 primarily due to a$2.4 million decrease in reimbursements (net of related fees) received from third parties for their usage of our available firm transport ("FT") capacity. This was partially offset by a$1.3 million decrease in plant processing, transportation and gathering fees incurred between periods, which cost reductions were associated with lower NGL and oil production volumes between periods. On a per Boe basis, GP&T increased from$2.34 for the second quarter of 2019 to$2.78 per Boe for the second quarter of 2020. On a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) the Boe rate likewise increased between periods to$6.16 from$5.41 for the three months endedJune 30, 2020 and 2019, respectively. These rate increases were mainly attributable to the decrease in FT reimbursements (net of related fees) received from third parties as discussed above. Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization ("DD&A") for the periods indicated: Three Months EndedJune 30 , (in thousands, except per Boe data) 2020
2019
Depreciation, depletion and amortization$ 93,020
Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. For the three months endedJune 30, 2020 , DD&A expense amounted to$93.0 million , a decrease of$19.1 million over the same 2019 period. The primary factor contributing to lower DD&A expense in 2020 was the decrease in our overall production volumes between periods, which decreased DD&A expense by$11.5 million during the first half of 2020, while lower DD&A rates between periods lowered DD&A expense by$7.6 million . DD&A per Boe was$14.98 for the second quarter of 2020 compared to$16.18 for the same period in 2019. The decrease in the DD&A rate was primarily due to the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base by$591.8 million . The effect of this impairment, however, was partially offset by downward revisions in our proved reserves during the second quarter, mainly due to lowerSEC pricing and a higher level of infrastructure costs incurred in the trailing twelve months, which have no associated proved reserve adds. Impairment and Abandonment Expense. During the three months endedJune 30, 2020 ,$19.4 million of impairment and abandonment expense was incurred related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties. During the three months endedJune 30, 2019 ,$4.4 million of abandonment expense was incurred related to undeveloped leasehold acreage that expired after efforts to extend, sell or trade these leases were unsuccessful. Exploration Expense. The following table summarizes our exploration expense for the periods indicated: Three Months Ended June 30, (in thousands) 2020 2019 Geological and geophysical costs $ 1,081$ 3,179 Rig termination fees 1,547 - Severance payments 722 - Stock-based compensation 457 682 Other expenses 244 - Exploration expense $ 4,051$ 3,861 35
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Exploration expense was$4.1 million for the three months endedJune 30, 2020 compared to$3.9 million for the three months endedJune 30, 2019 . Exploration expense mainly consists of topographical studies, geographical and geophysical ("G&G") projects, and salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was primarily related to the$1.5 million in rig termination fees incurred in the second quarter of 2020 as a result of reducing our operated drilling activity in April of 2020 and$0.7 million in nonrecurring severance payments to G&G personnel, resulting from our workforce reduction that was announced in the second quarter of 2020 (as further described below under General and Administrative Expenses). These increases were partially offset by$1.5 million in higher costs incurred on G&G projects and seismic studies in the 2019 period and$0.6 million in lower ongoing G&G personnel costs in the 2020 period associated with the workforce reduction referred to above. General and Administrative Expenses. The following table summarizes our general and administrative ("G&A") expenses for the periods indicated: Three Months EndedJune 30 , (in thousands) 2020
2019
Cash general and administrative expenses$ 10,840 $ 12,359 Stock-based compensation 4,270 6,076 Severance payments 2,884 - General and administrative expenses$ 17,994 $
18,435
G&A expenses for the three months endedJune 30, 2020 were$18.0 million compared to$18.4 million for the three months endedJune 30, 2019 . The lower G&A expenses incurred in the second quarter of 2020 was primarily the result of a reduction to our workforce and reduced salaries for the employees that remained, effective onMay 1, 2020 . These two factors combined resulted in (i) a$2.0 million decrease in employee payroll costs between periods, and (ii) a$1.8 million decrease in stock compensation expense, primarily related to reduced values of share awards modified and credits for shares forfeited, both in the workforce reduction (refer to Note 6-Stock-Based Compensation for additional information regarding the stock modification). These decreases were partially offset by nonrecurring charges incurred during the three months endedJune 30, 2020 related to (i)$2.9 million in severance payments to G&A employees included in the workforce reduction, and (ii)$0.5 million of transaction costs that were expensed when the water disposal asset sale was terminated, which is included in cash G&A (see Note 2-Property Divestiture for additional information). Other Income and Expenses. Interest Expense. The following table summarizes our interest expense for the periods indicated: Three Months Ended June 30, (in thousands) 2020 2019 Credit facility$ 3,159 $ 879 8.00% Senior Secured Notes due 2025 1,129
-
5.375% Senior Unsecured Notes due 2026 4,732
5,375
6.875% Senior Unsecured Notes due 2027 7,524
8,594
Amortization of debt issuance costs and discount 1,535 775 Interest capitalized (708 ) (1,186 ) Total$ 17,371 $ 14,437 Interest expense was$2.9 million higher for the three months endedJune 30, 2020 as compared to the three months endedJune 30, 2019 primarily due to$2.3 million in increased interest expense incurred on our credit facility due to increased borrowings outstanding under the facility and$0.8 million in higher amortization related to debt issuance costs and debt discount recognized in connection with the Debt Exchange. Our weighted average borrowings outstanding under our credit facility were$344.7 million versus$13.2 million for the three months endedJune 30, 2020 and 2019, respectively. Our credit facility's weighted average effective interest rate (which is a LIBOR-based rate) was 3.1% and 4.0% for the three months endedJune 30, 2020 and 2019, respectively, as a result of lower LIBOR in the second quarter of 2020 versus the prior year quarter. 36
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Gain on exchange of debt. A gain of$143.4 million was recognized for the three months endedJune 30, 2020 related to our opportunistic Debt Exchange that was executed in the second quarter of 2020. This gain was determined based on the difference between the carrying value of the Senior Unsecured Notes extinguished less the fair value at the date of issuance of our newly issued Senior Secured Notes. Refer to Note 4-Long-Term Debt for additional information regarding the gain on exchange of debt.Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) fluctuations in mark-to-market derivative fair values associated with changes in the forward price curves for the commodities underlying our hedge contracts entered into and (ii) monthly settlements on our hedged derivative positions. The following table presents gains and losses on our derivative instruments for the periods indicated: Three Months Ended June 30, (in thousands) 2020 2019 Settlement gains (losses)$ (6,894 ) $ 6,388 Non-cash mark-to-market derivative gain (loss) (22,963 ) (4,260 ) Total$ (29,857 ) $ 2,128 Income Tax Expense. We recognized income tax benefit of$1.9 million and income tax expense of$5.9 million for the three months endedJune 30, 2020 and 2019, respectively. The income tax benefit recognized in the second quarter of 2020 was primarily due to the release of a portion of our deferred tax asset valuation allowance during the period relating to our conversion of Class C to Class A shares during the quarter. Refer to Note 1-Basis of Presentation and Summary of Significant Accounting Policies for additional information on the conversion. The income tax expense recognized in the second quarter of 2019 was a result of pre-tax book income of$24.9 million during the period. Our provisions for income taxes for the three months ended 2020 and 2019 differed from the amounts that would be provided by applying the statutoryU.S. federal income tax rate of 21% to pre-tax book loss or income primarily due to (i) state income taxes; (ii) estimated permanent differences; and (iii) any changes during the period in our deferred tax asset valuation allowance, such as the$5.9 million reduction in the second quarter of 2020 that was mainly due to a discreet item recognized during the period for the decrease in deductions associated with stock award forfeitures and the conversion of Class C shares discussed above. 37
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Six Months EndedJune 30, 2020 Compared to Six Months EndedJune 30, 2019 The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period's average prices and average daily production volumes: Six Months Ended June 30, Increase/(Decrease) 2020 2019 $ % Net revenues (in thousands): Oil sales$ 243,605 $ 389,859 $ (146,254 ) (38 )% Natural gas sales 17,145 20,585 (3,440 ) (17 )% NGL sales 22,528 48,364 (25,836 ) (53 )% Oil and gas sales$ 283,278 $ 458,808 $ (175,530 ) (38 )% Average sales prices: Oil (per Bbl)$ 33.92 $ 51.51 $ (17.59 ) (34 )% Effect of derivative settlements on average price (per Bbl) (0.76 ) (0.20 ) (0.56 ) (280 )% Oil net of hedging (per Bbl)$ 33.16 $ 51.31 $ (18.15 ) (35 )% Average NYMEX price for oil (per Bbl)$ 37.09 $ 57.36 $ (20.27 ) (35 )% Oil differential from NYMEX (3.17 ) (5.85 ) 2.68 46 % Natural gas (per Mcf)$ 0.82 $ 1.09 $ (0.27 ) (25 )% Effect of derivative settlements on average price (per Mcf) (0.07 ) 0.40 (0.47 ) (118 )% Natural gas net of hedging (per Mcf)$ 0.75 $ 1.49 $
(0.74 ) (50 )%
Average NYMEX price for natural gas (per Mcf)$ 1.76 $ 2.69 $ (0.93 ) (35 )% Natural gas differential from NYMEX (0.94 ) (1.60 ) 0.66 41 % NGL (per Bbl)$ 10.79 $ 17.99 $ (7.20 ) (40 )% Net production: Oil (MBbls) 7,182 7,568 (386 ) (5 )% Natural gas (MMcf) 20,855 18,918 1,937 10 % NGL (MBbls) 2,088 2,689 (601 ) (22 )% Total (MBoe)(1) 12,746 13,410 (664 ) (5 )% Average daily net production: Oil (Bbls/d) 39,461 41,814 (2,353 ) (6 )% Natural gas (Mcf/d) 114,585 104,521 10,064 10 % NGLs (Bbls/d) 11,474 14,856 (3,382 ) (23 )% Total (Boe/d)(1) 70,333 74,089 (3,756 ) (5 )%
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of
six Mcf of natural gas to one Boe.
Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the six months endedJune 30, 2020 were$175.5 million , or 38%, lower than total net revenues for the six months endedJune 30, 2019 . Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized. 38
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Average realized sales prices for oil, natural gas and NGLs decreased in the first half of 2020 compared to the same 2019 period. The average price for oil before the effects of hedging decreased 34%, the average price for natural gas before the effects of hedging decreased 25% and the average price for NGLs decreased 40% between periods. The 34% decrease in the average realized oil price was mainly the result of lower NYMEX crude prices between periods (average NYMEX prices decreased 35%), which was minimally offset by improved oil differentials (a decrease of$2.68 per Bbl). The average realized sales price of natural gas decreased 25% due to lower average NYMEX gas prices between periods (average NYMEX prices decreased 35%), but this decrease was partially offset by improved gas differentials (a decrease of$0.66 per Mcf). The 40% decrease in average realized NGL prices between periods was primarily attributable to lowerMont Belvieu spot prices for plant products in the first half of 2020 compared to the first half of 2019. The market prices for oil, natural gas and NGLs were all significantly impacted by lower demand globally for oil and gas as a result of COVID-19 as well as commodity supply disruptions, both of which combined resulted in significant price declines starting inMarch 2020 as discussed in the market conditions section above. Net production volumes for oil and NGLs decreased 5% and 22%, respectively, while natural gas production volumes increased 10% between periods. The oil production volume decrease was the result of (i) the temporary suspension of our drilling and completion activity in the second quarter of 2020, which resulted in only 26 new wells completed and brought online during the first half of 2020 as compared to 40 wells completed and brought online during the same 2019 period, (ii) the curtailment of a portion of our production during the month of May in the second quarter of 2020, and (iii) normal field production declines across our existing wells. These production decreases were partially offset by 70 operated wells placed on production in theDelaware Basin since the second quarter of 2020, which added 3,207 MBbls of net oil production to the six months endedJune 30, 2020 . Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, except for one month during the first half of 2020, the main processor of our raw gas operated in ethane-rejection as compared to operating in full ethane-recovery during the entire 2019 comparable period. As a result, we sold an increased amount of natural gas from our wet gas stream and recovered fewer NGLs during the 2020 period, resulting in an increase (10%) in natural gas volumes and a decrease (22%) in NGL volumes between periods. Operating Expenses. The following table summarizes our operating expenses for the periods indicated: Six Months Ended June 30, Increase/(Decrease) 2020 2019 $ % Operating costs (in thousands): Lease operating expenses$ 58,478 $ 64,747 $ (6,269 ) (10 )% Severance and ad valorem taxes 22,269 33,306 (11,037 ) (33 )% Gathering, processing and transportation expenses 34,223 31,267 2,956 9 % Operating costs per Boe: Lease operating expenses $ 4.59$ 4.83 $ (0.24 ) (5 )% Severance and ad valorem taxes 1.75 2.48 (0.73 ) (29 )% Gathering, processing and transportation expenses 2.68 2.33 0.35 15 % Lease Operating Expenses. LOE for the six months endedJune 30, 2020 decreased$6.3 million as compared to the six months endedJune 30, 2019 . Lower LOE for the first half of 2020 was primarily related to a$10.4 million decrease in workover expense between periods as a result of less workover activity. This decrease was offset by a$4.1 million increase in LOE costs associated with our higher well count. We had 381 gross operated horizontal wells as ofJune 30, 2020 compared to 302 gross operated horizontal wells as ofJune 30, 2019 . The net increase in well count was mainly the result of our drilling activity adding 70 gross operated wells since the second quarter of 2019, which was further adjusted for acquisitions and divestitures. LOE on a per Boe basis decreased when comparing the first half of 2020 to the same 2019 period. LOE per Boe was$4.59 for the six months endedJune 30, 2020 , which represents a decrease of$0.24 per Boe (or 5%) from the comparable 2019 period. This decrease in rate was mainly due to the lower level of workover activity, discussed above, as well as cost reduction initiatives we have undertaken such as (i) lowering contract labor costs, (ii) switching wells away from ESP lift to more reliable gas lift, and (iii) decreasing monthly equipment rentals, which were achieved by moving multiple wells off generators to more efficient electrical line-power. These decreases were partially offset by per BOE cost increases in the first half of 2020 compared to the same 2019 period associated with fixed and semi-variable costs that don't decrease at the same rate as declines in production such as (i) wellhead chemical costs, (ii) electricity, (iii) water handling costs, and (iv) monthly rental fees for compressors. 39
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Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the six months endedJune 30, 2020 decreased$11.0 million compared to the six months endedJune 30, 2019 . Severance taxes are primarily based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and natural gas reserves and vary across the different counties in which we operate. Severance taxes for the first half of 2020 decreased$9.1 million compared to the same 2019 period primarily due to lower oil, natural gas and NGL revenues between periods. Ad valorem taxes also decreased$1.9 million between periods due to lower tax assessments on our oil and gas reserve values. Severance and ad valorem taxes as a percentage of total net revenues increased to 7.9% for the first half of 2020 as compared to 7.3% for the same 2019 period. This increase in rate was due to the ad valorem tax assessment, which while lower between periods (down 20%), declined less than our oil and gas sales which decreased 38% between periods. Gathering, Processing and Transportation Expenses. GP&T for the six months endedJune 30, 2020 increased$3.0 million compared to the six months endedJune 30, 2019 primarily due to a$5.4 million decrease in reimbursements (net of related fees) received from third parties for their usage of our available FT capacity. This was partially offset by a$2.0 million decrease in plant processing, transportation and gathering fees incurred between periods. On a per Boe basis, GP&T increased from$2.33 for the first half of 2019 to$2.68 per Boe for the same 2020 period. On a natural gas and NGL volume basis (i.e. excluding crude oil barrels) the Boe rate likewise increased between periods to$6.15 from$5.35 for the six months endedJune 30, 2020 and 2019, respectively. These rate increases were mainly attributable to a lower amount of FT reimbursements (net of related fees) received from third parties for their usage of our available capacity as referenced above. Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated: Six Months Ended June
30,
(in thousands, except per Boe data) 2020
2019
Depreciation, depletion and amortization$ 194,278 $ 208,672 Depreciation, depletion and amortization per Boe$ 15.24
Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. For the six months endedJune 30, 2020 , DD&A expense amounted to$194.3 million , a decrease of$14.4 million over the same 2019 period. The primary factor contributing to lower DD&A expense in 2020 was the decrease in our overall production volumes between periods, which decreased DD&A expense by$10.2 million during the first half of 2020, while lower DD&A rates between periods lowered DD&A expense by$4.2 million . DD&A per Boe was$15.24 for the first half of 2020 compared to$15.56 for the same period in 2019. This decrease in DD&A rate was primarily due to the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base by$591.8 million . The effect of this impairment, however, was partially offset by downward revisions in our proved reserves during the first half of 2020, mainly due to lowerSEC pricing and a higher level of infrastructure costs incurred in the trailing twelve months, which have no associated proved reserve adds. Impairment and Abandonment Expense. During the six months endedJune 30, 2020 ,$630.7 million of impairment and abandonment expense was incurred related to certain of our oil and natural gas properties. This expense consisted of (i) a$591.8 million non-cash impairment of our proved oil and gas properties as a result of depressed oil, natural gas and NGL commodity prices, and (ii)$38.9 million related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties. We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that the fair value of these assets may be below their carrying value. Fair values of our oil and natural gas properties are estimated using an income approach that is based on the discounted expected future net cash flows from these assets. These valuations are based on inputs which require significant judgment and include estimates of: (i) reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted average cost of capital rate. We performed an impairment assessment of all our proved oil and gas properties as ofMarch 31, 2020 . Two of our fields were subject to impairment write-downs as quantified above, but the remaining five fields were not impaired due to their undiscounted cash flows exceeding their carrying values by 30% to over 100%. This impairment assessment was performed using commodity price futures curves as ofMarch 31, 2020 . If future oil, natural gas and NGL prices continue to decline to lower levels, or other estimates impacting future net cash flows deteriorate (e.g. reserves, price differentials, future operating and/or development costs), our proved oil and gas properties could be subject to additional impairment write-downs in future periods. We did not recognize any additional impairment write-downs with respect to our proved oil and gas properties for the three months endedJune 30, 2020 . 40
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During the six months endedJune 30, 2019 ,$35.7 million of impairment and abandonment expense was incurred related to undeveloped leasehold acreage. This expense consisted of (i)$19.1 million related to non-core acreage that expired during the first half of 2019 after efforts to extend, sell or trade these leases were unsuccessful, and (ii)$16.6 million for impaired acreage following an acreage sale initiated in the first quarter of 2019. Exploration Expense. The following table summarizes our exploration expense for the periods indicated: Six Months Ended June 30, (in thousands) 2020 2019 Geological and geophysical costs$ 3,074 $ 4,812 Rig termination fees 3,046 283 Stock-based compensation 974 1,282 Severance payments 722 - Other expenses 244 - Exploration expense$ 8,060 $ 6,377 Exploration was$8.1 million for the six months endedJune 30, 2020 compared to$6.4 million for the same prior year period. Exploration expense mainly consists of topographical studies, G&G projects, and salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was primarily due to (i) rig termination fees that were$2.8 million higher in the first half of 2020, as a result of reducing our operated drilling activity in 2020 and (ii)$0.7 million in nonrecurring severance payments to G&G personnel, resulting from our workforce reduction that was announced in the second quarter of 2020. These increases were partially offset by a$0.9 million decrease in G&G project and seismic study costs between periods and$0.8 million in lower ongoing G&G personnel costs in the 2020 period associated with the workforce reduction. General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated: Six Months Ended June 30, (in thousands) 2020 2019 Cash general and administrative expenses$ 23,818 $ 24,594 Stock-based compensation 10,162 11,959 Severance payments 2,884 - General and administrative expenses$ 36,864 $
36,553
G&A expenses for the six months endedJune 30, 2020 were$36.9 million compared to$36.6 million for the six months endedJune 30, 2019 . The higher G&A expenses incurred in the first half of 2020 were primarily due to nonrecurring charges for (i)$2.9 million of severance payments to G&A employees included in the reduction to our workforce (which was discussed above in the results for the three months endedJune 30, 2020 ) and (ii)$0.5 million in transaction costs that were expensed when the water disposal asset sale was terminated and are included in cash G&A (see Note 2-Property Divestiture for additional information). In addition, cash G&A expenses increased by$0.7 million between periods due to higher software costs, corporate insurance premiums and professional fees. These increases were partially offset by (i) a$1.8 million decrease in stock compensation expense between periods primarily related to modifications and forfeitures of stock awards included in the workforce reduction (refer to Note 6-Stock-Based Compensation for additional information) and (ii) a$1.9 million decrease in employee payroll costs, which was attributable to our workforce reduction as well as compensation decreases taken by employees that remained. 41
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Other Income and Expenses.
Interest Expense. The following table summarizes our interest expense for the
periods indicated:
Six Months Ended June 30,
(in thousands) 2020 2019
Credit facility $ 5,326 $ 4,611
8.00% Senior Secured Notes due 2025 1,129 -
5.375% Senior Unsecured Notes due 2026 10,106
10,750
6.875% Senior Unsecured Notes due 2027 16,118
10,122
Amortization of debt issuance costs and discount 2,334 1,287 Interest capitalized (1,221 ) (2,173 ) Total$ 33,792 $ 24,597 Interest expense was$9.2 million higher for the six months endedJune 30, 2020 compared to the same 2019 period. The higher interest expense incurred in the first half of 2020 was mainly due to (i)$6.0 million in increased interest expense related to our 2027 Senior Notes, that were issued inMarch 2019 and only outstanding for three and half months during the prior year period, (ii)$1.1 million in interest incurred on our Senior Secured Notes issued in May of 2020 in connection with the Debt Exchange, (iii)$1.0 million in higher amortization related to debt issuance costs and debt discount recognized in connection with the Debt Exchange, and (iv)$0.7 million in increased interest expense incurred on our credit facility borrowings. These increases were partially offset by lower interest expense incurred on our Senior Unsecured Notes during the second quarter of 2020, as a result of the Debt Exchange discussed in Note 4-Long-Term Debt under Part I, Item I of this Quarterly Report. Our weighted average borrowings outstanding under our credit facility were$311.6 million and$158.0 million for the first half of 2020 and 2019, respectively. Our credit facility's weighted average effective interest rate (which is a LIBOR-based rate) was 3.0% and 4.2% for the six months endedJune 30, 2020 and 2019, respectively. LIBOR was lower in the first half of 2020 versus the same prior year period. Gain on exchange of debt. A gain of$143.4 million was recognized for the six months endedJune 30, 2020 related to our opportunistic Debt Exchange that was executed in the second quarter of 2020. This gain was determined based on the difference between the carrying value of the Senior Unsecured Notes extinguished less the fair value at the date of issuance of our newly issued Senior Secured Notes. Refer to Note 4-Long-Term Debt for additional information regarding the gain on exchange of debt.Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) fluctuations in mark-to-market derivative fair values associated with changes in the forward price curves for the commodities underlying our hedge contracts entered into and (ii) monthly settlements of our hedged derivative positions. The following table presents gains and losses for derivative instruments for the periods indicated: Six Months Ended June 30, (in thousands) 2020 2019 Settlement gains (losses)$ (6,947 ) $ 6,011 Non-cash mark-to-market derivative gain (loss) (31,415 ) (9,754 ) Total$ (38,362 ) $ (3,743 ) Income Tax Expense. We recognized income tax benefit of$85.1 million and income tax expense of$3.7 million for the six months endedJune 30, 2020 and 2019, respectively. The income tax benefit recognized in the first half of 2020 was primarily due to a pre-tax book loss incurred of$630.1 million , whereas the income tax expense recognized in the first half of 2019 was a result of pre-tax book income of$14.1 million during the period. Our provisions for income taxes for the first half of 2020 and 2019 differed from the amounts that would be provided by applying the statutoryU.S. federal income tax rate of 21% to pre-tax book income (loss) primarily due to (i) state income taxes; (ii) estimated permanent differences; and (iii) any changes during the period in our deferred tax asset valuation allowance, such as the recognition of a$49.7 million valuation allowance in the first half of 2020 against net operating loss carryforwards that are not expected to be realized. 42
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Liquidity and Capital Resources Overview Our drilling and completion and land acquisition activities require us to make significant capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under CRP's revolving credit facility, and proceeds from offerings of debt or equity securities. Future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly inMarch 2020 and continued to deteriorate and have remained volatile since. These lower commodity prices negatively impact our cash flows and availability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary use of capital has been for drilling and development capital expenditures and the acquisition of oil and natural gas properties. The following table summarizes our capital expenditures ("capex") incurred for the six months endedJune 30, 2020 : (in millions) Six Months EndedJune 30 ,
2020
Drilling and completion capital expenditures $
168.2
Facilities, infrastructure and other 31.7 Land 3.5 Total capital expenditures $ 203.4 We continually evaluate our capital needs and compare them to our capital resources. As a result of the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we temporarily suspended all drilling and completion activities at the end of the first quarter of 2020 in order to preserve capital. Specifically, we reduced our operated drilling rig program to zero rigs starting in April of 2020 and continued with no rigs in operation for the remainder of the second quarter, which is down from the four-rig program that we initially announced with our 2020 operational guidance at the beginning of the year. We plan to resume drilling activity in the fourth quarter of 2020 with a one-rig program and will begin to complete wells that were previously drilled but uncompleted in the third quarter of 2020. Consequently, we expect our total capex budget for 2020 will now be between$240.0 million to$270.0 million , which represents an approximate 60% reduction from the mid-point of our original estimated capex budget for 2020 of$590 million to$690 million . Because we are the operator of a high percentage of our acreage, we can control the amount and timing of our capital expenditures. We can choose to defer or accelerate a portion of our planned capex depending on a variety of factors, including but not limited to: prevailing and anticipated prices for oil and natural gas; oil storage or transportation constraints; the success of our drilling activities; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; seasonal conditions; property or land acquisition costs; and the level of participation by other working interest owners. Given the weakness in realized oil prices, we voluntarily curtailed or shut-in a portion of our second quarter 2020 production volumes. Specifically, we curtailed approximately 20% of our production during the month of May, but were able to bring the majority of our production back online in June as crude oil prices recovered. The potential for any future curtailment decisions will continue to be evaluated and made on a month-to-month basis subject to market conditions, storage and transportation constraints, and contractual obligations. Any decision in the future to further curtail or shut-in our production could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. We expect to fund the remainder of our 2020 capital expenditures with cash flows from operations and borrowings under our credit agreement. We cannot ensure that cash flows from operations will be available or other sources of needed capital on acceptable terms or at all. Further, our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control. Moreover, to manage our future financing cash outflows and liquidity position, we completed the Debt Exchange with respect to our Senior Unsecured Notes inMay 2020 which reduced the total principal amounts due of our aggregated secured and unsecured notes by$127.1 million and also reduced future interest payments. 43
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Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
Six Months Ended June 30,
(in thousands) 2020 2019
Net cash provided by operating activities
For the six months endedJune 30, 2020 , we generated$84.5 million of cash from operating activities, a decrease of$195.7 million from the same period in 2019. Cash provided by operating activities decreased primarily due to lower realized prices for all commodities, lower production volumes for crude oil and NGLs, higher GP&T costs, exploration expense, cash G&A expenses, interest payments, cash settlement losses from derivatives, and the timing of supplier payments during the six months endedJune 30, 2020 . These declining factors were partially offset by lower lease operating expenses, production taxes, and the timing of our receivable collections for the six months endedJune 30, 2020 as compared to the same 2019 period. Refer to "Results of Operations" for more information on the impact of volumes and prices on revenues and for more information on fluctuations in our operating expenses between periods. During the six months endedJune 30, 2020 , cash flows from operating activities, cash on hand, and net borrowings of$195.0 million under our credit facility were used to finance$271.4 million of drilling and development capex, to fund$6.1 million in oil and gas property acquisitions, and to finance$5.1 million of debt issuance and exchange costs. During the six months endedJune 30, 2019 , cash flows from operating activities, proceeds from sales of oil and gas properties and proceeds from the issuance of our 2027 Senior Notes were used to repay net borrowings of$300.0 million under our credit facility, to finance$437.9 million of drilling and development capex, to fund$42.3 million in oil and gas property acquisitions, and to purchase$4.3 million of other property and equipment. Credit Agreement CRP, our consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing onMay 4, 2023 (the "Credit Agreement"). OnMay 1, 2020 , CRP, as borrower, and we, as parent guarantor, entered into the 2020 Amendments, which, among other things, established a new borrowing base and level of elected commitments of$700.0 million . The 2020 Amendments that the lenders approved permitted the issuance of the Senior Secured Notes in connection with the Debt Exchange (discussed below), and they implemented an availability blocker equal to 25% of the newly issued amount of Senior Secured Notes. As ofJune 30, 2020 , we had$370.0 million in borrowings outstanding and$290.0 million in available borrowing capacity, which was net of$8.2 million in letters of credit outstanding and the availability blocker of$31.8 million . CRP's Credit Agreement contains restrictive covenants that limit its ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of our expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage in transactions with affiliates. CRP's Credit Agreement also requires us to maintain compliance with the following financial ratios: (i) a current ratio, which is the ratio of CRP's consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding any current portion of long-term debt due under the credit agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; (ii) a first lien leverage ratio, as defined within the Credit Agreement as the ratio of first lien debt to EBITDAX for the rolling four fiscal quarter period, which may not exceed 2.75 to 1.00 beginning with the quarter endingJune 30, 2020 and extending through the quarter endingDecember 31, 2021 , after which the maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in 2022; and (iii) a leverage ratio, as defined with the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the rolling four fiscal quarter period. Pursuant to the 2020 Amendments, the leverage ratio is suspended untilMarch 31, 2022 , at which time, the ratio may not exceed 5.00 to 1.00, with such maximum ratio declining at a rate of 0.25 for each succeeding quarter untilMarch 31, 2023 when the ratio is set at not greater than 4.0 to 1.0. CRP was in compliance with the covenants and the financial ratios described above as ofJune 30, 2020 and through the filing of this Quarterly Report. 44
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For further information on the Credit Agreement, refer to Note 4-Long-Term Debt under Part I, Item I of this Quarterly Report. Senior Unsecured Note Debt Exchange and Senior Secured Notes OnMay 22, 2020 , CRP completed the Debt Exchange pursuant to which$110.6 million aggregate principal amount of CRP's 2026 Senior Notes and$143.7 million aggregate principal amount of CRP's 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of$127.1 million aggregate principal amount of newly issued Senior Secured Notes. The Senior Secured Notes bear interest at an annual rate of 8% and are due onJune 1, 2025 . Interest is payable semi-annually in arrears on eachJune 1 andDecember 1 , commencing onDecember 1, 2020 . The Debt Exchange was accounted for as a troubled debt restructuring in accordance with ASC 470-60. Thus, the carrying value of the Senior Secured Notes includes undiscounted amounts of both principal and future interest payments. As ofJune 30, 2020 ,$51.1 million of future interest on the Senior Secured Notes has been recognized as long-term debt in our consolidated balance sheets, which payable balance will be reduced as semi-annual interest payments are made. As a result, future interest expense reflected in our Consolidated Statements of Operations will be significantly lower than our actual cash interest payments. The Senior Secured Notes are guaranteed, subject to certain exceptions, by us and each of CRP's subsidiaries and are secured on a second-priority basis (subject in priority only to certain exceptions) by substantially all of CRP's and our assets, including deposit accounts and substantially all proved reserves and undeveloped acreage. Senior Unsecured Notes OnNovember 30, 2017 , CRP issued$400.0 million of 5.375% senior notes due 2026 and onMarch 15, 2019 , CRP issued$500.0 million of 6.875% senior notes due 2027 in 144A private placements. The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP's current subsidiaries that guarantee CRP's revolving credit facility. InMay 2020 , a portion of Senior Unsecured Notes were exchanged for Senior Secured Notes (see above discussion for details of the exchange). The indentures governing the Senior Unsecured Notes and Senior Secured Notes (collectively, the "Senior Notes") contain covenants that, among other things and subject to certain exceptions and qualifications, limit CRP's ability and the ability of CRP's restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as ofJune 30, 2020 and through the filing of this Quarterly Report. For further information on any of our Senior Notes issuances, refer to Note 4-Long-Term Debt under Part I, Item I of this Quarterly Report. Contractual Obligations Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we routinely enter into, modify or extend. SinceDecember 31, 2019 , there have not been any significant, non-routine changes in our contractual obligations, other than the changes to certain of our operating lease commitments and principal and interest due under our Senior Unsecured Notes as a result of the Debt Exchange discussed above. Refer to Note 13-Leases under Part I, Item I of this Quarterly Report for updated contractual obligations associated with our operating leases as ofJune 30, 2020 . Critical Accounting Policies and Estimates There have been no material changes during the six months endedJune 30, 2020 to the critical accounting policies previously disclosed in our 2019 Annual Report. Please refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates in our 2019 Annual Report for a discussion of our critical accounting policies and estimates. New Accounting Pronouncements There were no significant new accounting standards adopted or new accounting pronouncements that would have a potential effect on us as ofJune 30, 2020 . 45
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