What changed in this filing

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Item 2. Management’s Discussion and Analysis

2020-08-03 compared with 2020-05-04 · 321 added, 161 removed, 165 unchanged (74% of the section changed)

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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 in this Quarterly Report and our 2019 Annual Report under the heading “Item 1A.

Risk Factors,” all of which are difficult to predict.

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.

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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 during the first quarter of 2020.

Specifically, WTI spot prices for crude oil dropped to $20.09 per barrel on March 30, 2020 from a high of $63.27 per barrel on January 6, 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, other geopolitical events, weather conditions and other factors.

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:

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Natural gas (per MMBtu)

A sustained drop in oil, natural gas and NGL prices, such as we are experiencing thus far in March and April 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 our realized differentials), such as those that we are continuing to observe thus far in the second quarter of 2020 and in the futures curve, 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.

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, 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.

Additionally,

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 in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and the communities in which we operate.

Our operational employees are currently still able to work on site.

However, we have taken various precautionary measures with respect to such operational employees such as 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, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected) and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Center for Disease Control.

In addition, the vast majority of our non-operational employees are now working remotely.

We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak, nor have we had any confirmed cases of COVID-19 on any of our work sites.

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 the Center 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 decline in commodity prices that occurred during the first quarter of 2020 discussed above have significantly impacted our results of operations for the three months ended March 31, 2020.

However, the majority of these market impacts were experienced at the end of the first quarter of 2020.

Therefore, we believe that our future operating results and near-term financial condition will continue to be impacted.

Further, our results of operations for the three months ended March 31, 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.

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 ended June 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 ended June 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 three months of 2020 , which enabled us to complete and bring online 22 gross operated wells with an average effective lateral length of approximately 6,900 feet.

Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we have recently suspended all drilling and completion activities in order to preserve capital.

Specifically, we recently reduced our operated drilling rig program to zero rigs in April of 2020.

In addition, given the weakness in realized oil prices, we are actively evaluating whether to voluntarily curtail or shut-in a substantial portion of our current production volumes, and we expect to voluntarily curtail up to 40% of our production during the month of May.

Further potential 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.

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.

Divestiture Highlights

On February 24, 2020, we entered into a purchase and sale agreement to sell our water disposal assets for a base sale price of approximately $150.0 million in cash at closing with up to an additional $75.0 million in deferred incentive payments based on future drilling activity (all amounts are subject to post-closing adjustments).

The water disposal assets include certain saltwater disposal wells and the associated water infrastructure located in Reeves and Ward counties in Texas.

The original closing date of the sale was March 31, 2020, however, the transaction has been delayed.

While the transaction currently remains pending, either party may terminate the transaction if closing does not occur on or before May 15, 2020.

Financing Highlights

On April 22, 2020, we commenced offers to all eligible holders of our 5.375% Senior Notes due 2026 (the “2026 Senior Notes”) and 6.875% Senior Notes due 2027 (“the 2027 Senior Notes” and together with the 2026 Senior Notes, the “Senior Notes”) to exchange (the “Exchange Offers”) any and all of their Senior Notes held for up to $250.0 million aggregate principal amount of newly issued 8% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) and up to $200.0 million aggregate principal amount of newly issued 8% Third Lien Senior Secured Notes due 2027 (together with the Second Lien Notes, the “New Notes”).

In accordance with the Exchange Offers, the eligible holders of the Senior Notes can early tender their holdings on or before May 5, 2020 or can normally tender on or before May 19, 2020 .

The transaction is currently expected to close on May 22, 2020 , subject to customary closing conditions.

On May 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.

On May 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 Amendments, the borrowing base and elected commitments were reduced to $700.0 million .

In addition, to the extent that the Exchange Offers close, the Amendments introduce a minimum availability condition to borrowing at the lesser of $100.0 million and 25% of the aggregate principal amount of New Notes outstanding from the Exchange Offers.

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, introduced a new financial covenant testing the ratio of first lien debt to EBITDAX, and permitted the issuance of new senior secured notes in connection with the Exchange Offers described above.

Marketing Highlights

We have entered into fixed price oil swaps for April through December of 2020 to protect against possible, additional near-term declines in oil prices.

During this period, the Company has hedged an average of approximately 19,400 barrels per day of oil at a weighted average price of $26.79 per barrel.

In addition, we have natural gas hedges and oil basis swaps in place for 2020.

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.

Results of Operations

Three Months Ended March 31, 2020 Compared to Three Months Ended March 31, 2019

Three Months Ended June 30, 2020 Compared to Three Months Ended June 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 March 31,

Three Months Ended June 30,

Increase/(Decrease)

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Oil, Natural Gas and NGL Sales Revenues .

Total net revenues for the three months ended March 31, 2020 were $21.8 million (or 10% ) lower than total net revenues for the three months ended March 31, 2019 .

Total net revenues for the three months ended June 30, 2020 were $153.7 million (or 63% ) lower than total net revenues for the three months ended June 30, 2019 .

Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Average realized sales prices for oil, natural gas and NGLs decreased in the first quarter of 2020 compared to the same 2019 period.

The average price for oil before the effects of hedging decreased 6% , the average price for natural gas before the effects of

hedging decreased 44% , and the average price for NGLs decreased 28% between periods.

The 6% decrease in the average realized oil price was the result of lower NYMEX crude prices between periods (average NYMEX prices decreased 16% ), and this lower index price was partially offset by improved oil differentials (a decrease of $5.70 per Bbl).

The average realized sales price of natural gas decreased 44% due to lower average NYMEX gas prices between periods (average NYMEX prices decreased $1.00 ), but this decrease was partially offset by improved gas differentials (a decrease of $0.39 per Mcf) between periods.

The 28% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in the first quarter of 2020 as compared to the first quarter of 2019 .

The market prices for oil, natural gas and NGLs were all impacted by the lower global demand for oil and gas as a result of COVID-19 as well as commodity supply disruptions, which resulted in significant price declines in March and April of 2020 as discussed in the market conditions section above.

The decreases in realized sales prices were partially offset by slightly higher net production volumes between periods.

Net production volumes for oil and natural gas increased 4% and 20% , respectively, while NGL production volumes decreased 28% between periods.

The oil volume increase resulted primarily from our successful drilling activities in the Delaware Basin.

Since the first quarter 2019 , we placed 86 gross operated wells on production in the Delaware, which added 1,864 MBbls of net oil production to the first quarter of 2020 .

These oil volume increases were partially offset by normal field production declines across our existing wells.

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 lower Mont 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 in West Texas as several producers shut-in wells and curtailed production in the Permian 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 in March 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 the Delaware Basin since the second quarter of 2019 , which added 1,604 MBbls of net oil production to the three months ended June 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 first quarter of 2020, the main processor of our raw gas operated in ethane-rejection as compared to operating in ethane-recovery during the same 2019 period.

As a result of this switch, we recovered an increased amount of natural gas from our wet gas stream and recovered fewer NGLs, resulting in a significant increase in natural gas volumes between periods (up 20% ) and a 28% decrease in NGL volumes between periods.

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 Ended March 31,

Three Months Ended June 30,

Increase/(Decrease)

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Lease Operating Expenses.

Lease operating expenses (“LOE”) for the three months ended March 31, 2020 increased $2.8 million compared to the three months ended March 31, 2019 .

Higher LOE for the first quarter of 2020 was primarily related to a $5.6 million increase in expense associated with our higher well count.

We had 377 gross operated horizontal wells as of March 31, 2020 as compared to 280 gross operated horizontal wells as of March 31, 2019 .

The net increase in well count was mainly due to our drilling activity adding 86 gross operated wells since the first quarter of 2019 , which was further adjusted for acquisitions and divestitures.

Such increase was partially offset by a $2.8 million decreased in workover expense between periods as a result of lower workover activity.

LOE on a per Boe basis increased when comparing the first quarter of 2020 to the same 2019 period.

LOE per Boe was $4.99 for the first quarter of 2020 , which represents an increase of $0.38 per Boe from the first quarter of 2019 .

This increase in rate was mainly due to the following factors:

(i) a decline in the ratio of flush production to base production based on our level of D&C activity in 2020;

(ii) increased wellhead chemical costs;

and (iii) higher electricity expense in the first quarter of 2020 .

These increases were partially offset by lower contract labor costs between periods and the lower level of workover activity discussed above.

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.

Severance and Ad Valorem Taxes.

Severance and ad valorem taxes for the three months ended March 31, 2020 increased $0.5 million compared to the three months ended March 31, 2019 .

Severance taxes are primarily based on the market value of production at the wellhead, while ad valorem taxes are generally based on the 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 increased to 8.6% for three months ended March 31, 2020 as compared to 7.5% for the same 2019 period due to increased ad valorem taxes of $1.1 million between periods, resulting from our higher well count and higher oil and gas reserve valu es.

Severance and ad valorem taxes for the three months ended June 30, 2020 decreased $11.5 million compared to the three months ended June 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 of Texas.

Gathering, Processing and Transportation Expenses.

Gathering, processing and transportation expenses (“GP&T”) for the three months ended March 31, 2020 increased $1.9 million as compared to the three months ended March 31, 2019 primarily due to a $2.8 million decrease in reimbursements (net of related fees) received from third parties for their usage of our firm transport (“FT”) capacity.

This was partially offset by a decrease in plant processing costs, transportation tariffs and gathering fees incurred between periods.

On a per Boe basis, GP&T increased 12% from $2.32 for the first quarter of 2019 to $2.59 per Boe for the first quarter of 2020 .

Gathering, processing and transportation expenses (“GP&T”) for the three months ended June 30, 2020 increased $1.0 million as compared to the three months ended June 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 $6.14 from $5.29 for the three months ended March 31, 2020 and 2019, respectively.

These rate increases were mainly attributable to a decrease in reimbursements (net of related FT fees) received from third parties for their usage of our FT capacity as discussed above.

This was partially offset by decreased plant processing costs, which are primarily based on natural gas and NGL prices that were both lower between periods.

excluding crude oil barrels) the Boe rate likewise increased between periods to $6.16 from $5.41 for the three months ended June 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 Ended March 31,

Three Months Ended June 30,

(in thousands, except per Boe data)

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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 ended March 31, 2020 , DD&A expense amounted to $101.3 million , an increase of $4.7 million over the same 2019 period.

The primary factor contributing to higher DD&A expense in 2020 was the increase in DD&A rates between periods, which added $3.9 million of incremental DD&A expense to the first quarter of 2020 , while the increase in our overall production volumes between periods contributed an additional $0.8 million of DD&A expense to the first quarter of 2020 .

DD&A per Boe was $15.49 for the first quarter of 2020 compared to $14.89 for the same period in 2019 .

The increase in the DD&A rate was due to a higher level of infrastructure costs in the trailing twelve months, which have no associated proved reserve adds when they are incurred.

However, our DD&A per Boe rate of $15.49 decreased from our fourth quarter DD&A rate of $16.75 due to proved developed and proved undeveloped reserves added during the first quarter of 2020 combined with lower drilling and completion costs per well that we realized during the three months ended March 31, 2020.

In addition, we anticipate that our DD&A per Boe rate for the remainder of 2020 may continue to decline as a result of the proved property impairment recognized in the first quarter of 2020 as discussed below.

For the three months ended June 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 lower SEC 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 ended March 31, 2020 , $611.3 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 at March 31, 2020, and (ii) $19.5 million related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties.

During the three months ended June 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 ended June 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)

Geological and geophysical costs

Rig termination fees

Severance payments

Stock-based compensation

Other expenses

Exploration expense

Exploration expense was $4.1 million for the three months ended June 30, 2020 compared to $3.9 million for the three months ended June 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 Ended June 30,

(in thousands)

Cash general and administrative expenses

Stock-based compensation

Severance payments

General and administrative expenses

G&A expenses for the three months ended June 30, 2020 were $18.0 million compared to $18.4 million for the three months ended June 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 on May 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 ended June 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)

Credit facility

8.00% Senior Secured Notes due 2025

5.375% Senior Unsecured Notes due 2026

6.875% Senior Unsecured Notes due 2027

Amortization of debt issuance costs and discount

Interest capitalized

Interest expense was $2.9 million higher for the three months ended June 30, 2020 as compared to the three months ended June 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 ended June 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 ended June 30, 2020 and 2019, respectively, as a result of lower LIBOR in the second quarter of 2020 versus the prior year quarter.

Gain on exchange of debt.

A gain of $143.4 million was recognized for the three months ended June 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)

Settlement gains (losses)

Non-cash mark-to-market derivative gain (loss)

Income Tax Expense .

We recognized income tax benefit of $1.9 million and income tax expense of $5.9 million for the three months ended June 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 statutory U.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.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

Six Months Ended June 30,

Increase/(Decrease)

Net revenues (in thousands):

Natural gas sales

Oil and gas sales

Average sales prices:

Oil (per Bbl)

Effect of derivative settlements on average price (per Bbl)

Oil net of hedging (per Bbl)

Average NYMEX price for oil (per Bbl)

Oil differential from NYMEX

Natural gas (per Mcf)

Effect of derivative settlements on average price (per Mcf)

Natural gas net of hedging (per Mcf)

Average NYMEX price for natural gas (per Mcf)

Natural gas differential from NYMEX

NGL (per Bbl)

Net production:

Natural gas (MMcf)

Total (MBoe) (1)

Average daily net production:

Natural gas (Mcf/d)

NGLs (Bbls/d)

Total (Boe/d) (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 ended June 30, 2020 were $175.5 million , or 38% , lower than total net revenues for the six months ended June 30, 2019 .

Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

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 lower Mont 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 in March 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 the Delaware Basin since the second quarter of 2020, which added 3,207 MBbls of net oil production to the six months ended June 30, 2020.

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)

Operating costs (in thousands):

Lease operating expenses

Severance and ad valorem taxes

Gathering, processing and transportation expenses

Operating costs per Boe:

Lease operating expenses

Severance and ad valorem taxes

Gathering, processing and transportation expenses

Lease Operating Expenses.

LOE for the six months ended June 30, 2020 decreased $6.3 million as compared to the six months ended June 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 of June 30, 2020 compared to 302 gross operated horizontal wells as of June 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 ended June 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.

Severance and Ad Valorem Taxes.

Severance and ad valorem taxes for the six months ended June 30, 2020 decreased $11.0 million compared to the six months ended June 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 ended June 30, 2020 increased $3.0 million compared to the six months ended June 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 ended June 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)

Depreciation, depletion and amortization

Depreciation, depletion and amortization per Boe

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 ended June 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 lower SEC 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 ended June 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 is estimated using an income approach that is based on the discounted expected future net cash flows from these assets.

This valuation is based on inputs which require significant judgments and include estimates of:

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;

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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.

During the three months ended March 31, 2019, $31.3 million of impairment and abandonment expense was incurred related to undeveloped leasehold acreage.

This expense consisted of (i) $14.7 million related to non-core acreage that expired during the period 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.

We did not recognize any additional impairment write-downs with respect to our proved oil and gas properties for the three months ended June 30, 2020 .

During the six months ended June 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:

Three Months Ended March 31,

Six Months Ended June 30,

(in thousands)

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Stock-based compensation

Severance payments

Other expenses

Exploration expense

Exploration expense was $4.0 million for the three months ended March 31, 2020 compared to $2.5 million for the three months ended March 31, 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 $1.2 million increase in rig termination fees incurred in the first quarter of 2020 as a result of reducing our operated drilling program from five rigs to one in March of 2020.

Exploration was $8.1 million for the six months ended June 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 general and administrative (“G&A”) expenses for the periods indicated:

Three Months Ended March 31,

The following table summarizes our G&A expenses for the periods indicated:

Six Months Ended June 30,

(in thousands)

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Stock-based compensation

Severance payments

General and administrative expenses

G&A expenses for the three months ended March 31, 2020 were consistent with the same period of 2019.

This was a result of consistent head count and activity during both periods.

As a result of our reduction in force announced in the second quarter of 2020, we will incur one-time non-reoccurring severance costs in the second quarter of 2020.

Further, we anticipate that our cash G&A expenses will decline from the expense level incurred in the first quarter of 2020, as a result of these reductions in personnel.

G&A expenses for the six months ended June 30, 2020 were $36.9 million compared to $36.6 million for the six months ended June 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 ended June 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.

Other Income and Expenses.

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The following table summarizes our interest expense for the periods indicated:

Three Months Ended March 31,

Six Months Ended June 30,

(in thousands)

Credit facility

5.375% Senior Notes due 2026

6.875% Senior Notes due 2027

Amortization of debt issuance costs and debt discount

8.00% Senior Secured Notes due 2025

5.375% Senior Unsecured Notes due 2026

6.875% Senior Unsecured Notes due 2027

Amortization of debt issuance costs and discount

Interest capitalized

Interest expense was $6.3 million higher for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 primarily due to $7.1 million in increased interest on our 2027 Senior Notes due to the fact that they were issued in March of 2019.

This increase was partially offset by lower interest expense incurred on the credit facility due to decreased borrowings outstanding coupled with lower interest rates in the first quarter of 2020.

Our weighted average borrowings outstanding under our credit facility were $233.9 million versus $304.3 million for the three months ended March 31, 2020 and 2019, respectively.

Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) was 2.84% and 4.37% for the three months ended March 31, 2020 and 2019, respectively.

LIBOR was lower in the first quarter of 2020 versus the prior year quarter.

Interest expense was $9.2 million higher for the six months ended June 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 in March 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 ended June 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 ended June 30, 2020 related to our opportunistic Debt Exchange that was executed in the second quarter of 2020.

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 corresponding changes in the forward price curves for the underlying commodities and (ii) monthly cash settlements on our hedged derivative positions.

The following table presents gains and losses on our derivative instruments for the periods indicated:

Three Months Ended March 31,

The following table presents gains and losses for derivative instruments for the periods indicated:

Six Months Ended June 30,

(in thousands)

Cash settlement gains (losses)

Settlement gains (losses)

Non-cash mark-to-market derivative gain (loss)

Income Tax Expense .

We recognized income tax benefits of $83.2 million and $2.3 million for the three months ended March 31, 2020 and 2019 , respectively.

The increase in income tax benefit for the three months ended March 31, 2020 as compared to 2019 was primarily due to a larger pre-tax book loss of $622.8 million between periods.

Our provisions for income taxes for the first quarter of 2020 and 2019 differed from the amounts that would be provided by applying the statutory U.S.

federal income tax rate of 21% to pre-tax book loss primarily due to i) state income taxes;

We recognized income tax benefit of $85.1 million and income tax expense of $3.7 million for the six months ended June 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 statutory U.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) the recognition of a $55.6 million valuation allowance in the first quarter of 2020 against deferred tax assets that are not expected to be realized.

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.

Liquidity and Capital Resources

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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 in March 2020 and have continued to deteriorate and have remained low since.

Prices for oil and natural gas began to decline significantly in March 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 three months ended March 31, 2020 :

The following table summarizes our capital expenditures (“capex”) incurred for the six months ended June 30, 2020 :

(in millions)

Three Months Ended March 31, 2020

Six Months Ended June 30, 2020

Drilling and completion capital expenditures

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We continually evaluate our capital needs and compare them to our capital resources.

As a result of the recent decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we have recently suspended all drilling and completion activities in order to preserve capital.

Specifically, we recently reduced our operated drilling rig program to zero rigs, which is down from the four-rig program that we announced with our 2020 operational guidance.

Consequently, we expect that our total capex budget for 2020 will be between $240.0 million to $290.0 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 .

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.

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seasonal conditions;

drilling and acquisition costs;

property or land acquisition costs;

and the level of participation by other working interest owners.

Given the weakness in realized oil prices, we are actively evaluating whether to voluntarily curtail or shut-in a substantial portion of our current production volumes, and we expect to voluntarily curtail up to 40% of our production during the month of May.

Further potential curtailment decision 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 expenditure.

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.

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 on economic terms in the future will be affected by general economic conditions, the domestic and global 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 have initiated the Exchange Offers with respect to our Senior Notes in April 2020 which if successful, would lower our outstanding debt and future interest payments.

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 in May 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.

Analysis of Cash Flow Changes

The following table summarizes our cash flows for the periods indicated:

Three Months Ended March 31,

Six Months Ended June 30,

(in thousands)

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Net cash provided by financing activities

For the three months ended March 31, 2020 , we generated $100.8 million of cash from operating activities, a decrease of only $0.2 million from the same period in 2019 .

Cash provided by operating activities decreased primarily due to lower realized prices for crude oil, natural gas and NGLs, lower NGL production volumes, higher lease operating expenses, production taxes, GP&T costs, exploration expense, cash G&A expenses, and the timing of supplier payments during the three months ended March 31, 2020 .

These declining factors were partially offset by higher crude oil and natural gas production volumes, lower interest payments, lower cash settlement losses from derivatives, and the timing of our receivable collections for the three months ended March 31, 2020 as compared to the same 2019 period.

For the six months ended June 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 ended June 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 ended June 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 three months ended March 31, 2020 , cash flows from operating activities, cash on hand, and net borrowings of $60.0 million under our credit facility were used to finance $161.9 million of drilling and development capex and to fund $5.8 million in oil and gas property acquisitions.

During the three months ended March 31, 2019 , cash flows from operating activities, cash on hand, 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 $217.2 million of drilling and development capex and to fund $25.7 million in oil and gas property acquisitions.

During the six months ended June 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 ended June 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

On May 4, 2018 , CRP, our consolidated subsidiary, entered into an amended and restated credit agreement with a syndicate of banks that as of March 31, 2020 had a borrowing base of $1.2 billion and elected commitments of $800.0 million .

The credit agreement provides for a five-year secured revolving credit facility, maturing on May 4, 2023 .

As of March 31, 2020 , we had $235.0 million borrowings outstanding and $564.2 million in available borrowing capacity, which was net of $0.8 million in letters of credit outstanding.

On May 1, 2020 , we entered into the Amendments with the lenders to the existing credit agreement.

Pursuant to the Amendments, the borrowing base and elected commitment were reduced to $700.0 million .

If the minimum availability condition to borrowing were to be determined at its maximum level of $100.0 million , it would have the resulting effect of limiting the amount of borrowings that CRP could draw against its $700.0 million credit facility to $600.0 million .

CRP, our consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing on May 4, 2023 (the “Credit Agreement”).

On May 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 of June 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:

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(iv) make or declare dividends;

(v) enter into commodity hedges exceeding a specified percentage of CRP’s expected production;

(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;

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and (ix) engage in transactions with affiliates.

CRP’s credit agreement also requires it 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 the current portion of long-term debt under the credit agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0;

and (ii) a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP’s credit agreement) to consolidated EBITDAX (as defined in CRP’s credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0.

CRP was in compliance with these covenants and the financial ratios described above as of March 31, 2020 and through the filing of this Quarterly Report.

For further information on the credit agreement and related Amendments, refer to Note 4—Long-Term Debt and Note 14—Subsequent Events under Part I, Item I of this Quarterly Report.

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 ending June 30, 2020 and extending through the quarter ending December 31, 2021, after which the maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in 2022;

(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 until March 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 until March 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 of June 30, 2020 and through the filing of this Quarterly Report.

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

On May 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 on June 1, 2025.

Interest is payable semi-annually in arrears on each June 1 and December 1, commencing on December 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 of June 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

On November 30, 2017 , CRP issued $400.0 million of 5.375% senior notes due 2026 and on March 15, 2019 , CRP issued $500.0 million of 6.875% senior notes due 2027 in 144A private placements.

The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility.

The Senior Notes are not guaranteed by Centennial, nor are we subject to the terms of the indentures governing the Senior Notes.

The indentures governing 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:

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.

In May 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;

(ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness;

(iii) transfer or sell assets;

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and (ix) create unrestricted subsidiaries.

CRP was in compliance with these covenants as of March 31, 2020 and through the filing of this Quarterly Report.

On April 22, 2020, we commenced the Exchange Offers to all eligible holders of our Senior Notes to exchange any and all of our outstanding Senior Notes held for up to $250.0 million aggregate principal amount of newly issued 8% Second Lien Senior Secured Notes due 2025 and up to $200.0 million aggregate principal amount of newly issued 8% Third Lien Senior Secured Notes due 2027 .

The transaction is currently expected to close on May 22, 2020 , subject to customary closing conditions.

For further information on our Senior Notes and the Exchange Offers, refer to Note 4—Long-Term Debt and Note 14—Subsequent Events under Part I, Item I of this Quarterly Report.

CRP was in compliance with these covenants as of June 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.

Since December 31, 2019 , there have not been any significant, non-routine changes in our contractual obligations.

Since December 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 of June 30, 2020 .

Critical Accounting Policies and Estimates

There have been no material changes during the three months ended March 31, 2020 to the critical accounting policies previously disclosed in our 2019 Annual Report.

There have been no material changes during the six months ended June 30, 2020 to the critical accounting policies previously disclosed in our 2019 Annual Report.

Please refer to Part II, Item 7.

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New Accounting Pronouncements

There were no significant new accounting standards adopted or new accounting pronouncements that would have a potential effect on us as of March 31, 2020 .

There were no significant new accounting standards adopted or new accounting pronouncements that would have a potential effect on us as of June 30, 2020 .

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis