Item 2. Management’s Discussion and Analysis
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation
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 the 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 (the “Saudi-Russia oil price war”) 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 was a significant decline in commodity prices starting at the end of 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, while U.S. producers substantially reduced or suspended drilling activity and in most cases curtailed production due to low oil prices and poor economics. The current oil production cuts by OPEC and other producing countries have since been extended through the end of 2020, and U.S. drilling activity has remained low throughout the third quarter of 2020. 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 per barrel) 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 $43.39 per barrel on August 26, 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
Q3
Crude oil (per Bbl)
$
62.91
$
68.07
$
69.50
$
58.81
$
54.90
$
59.81
$
56.45
$
56.94
$
46.19
$
28.00
$
40.93
Natural gas (per MMBtu)
$
3.08
$
2.85
$
2.93
$
3.77
$
2.88
$
2.51
$
2.33
$
2.34
$
1.88
$
1.65
$
1.95
A sustained drop in oil, natural gas and NGL prices, such as those we have experienced during 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 can 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
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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.
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, 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 reported back to our offices on a limited basis starting in mid-May. We have taken various precautionary measures with respect to our operational employees, direct contractors and employees who returned to our offices or job sites 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 or contractors who have shown signs or symptoms of COVID-19 (regardless of whether such person has been confirmed to be infected), (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 (the “CDC”) as well as local and state authorities, (iv) requiring all employees and contractors to have a fit-test for and wear KN-95 type respirators while in our offices and work sites, and (v) encouraging all employees and contractors to follow the CDC recommended preventive measures (including those mentioned above) to limit the spread of COVID-19 . 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 nine months of 2020 discussed above have significantly impacted our results of operations for the three and nine months ended September 30, 2020, and we believe that our future operating results and near-term financial condition could continue to be impacted, until such time that oil supply and demand dynamics re-balance and stabilize. Further, our results of operations for the three and nine months ended September 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 drilling rigs in operation until the end of the third quarter. In addition, given the weakness in realized oil prices, we voluntarily curtailed or shut-in a portion of our production volumes in May of 2020. Specifically, we curtailed approximately 20% of our production during the month of May, but were able to bring the majority of this production back online in June as crude oil prices recovered, with minimal incremental cost. In addition, we filled our on-site tank batteries with crude oil during May in order to minimize the number of wells that we needed to shut-in, ultimately selling these barrels in June at higher prices.
During the third quarter of 2020, we did not experience any further curtailments to our production and recommenced drilling and completion activity. We completed 5 gross operated wells during the third quarter, which were previously drilled during the first quarter of 2020, with an effective lateral length of approximately 9,000 feet. Additionally, we initiated a one-rig drilling program at the end of the third quarter, which we expect to operate through the remainder of 2020.
Financing Highlights
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 aggregate principal amount of Senior Unsecured Notes from the long-term debt balance in our consolidated balance sheets.
On May 1, 2020 , we entered into the second and third amendments to CRP’s amended and restated credit agreement (the “Q2 2020 Amendments”) with the lenders to our existing credit agreement. Pursuant to the Q2 2020 Amendments, the borrowing base and level of elected commitments were both reduced to $700.0 million from their previous amounts of $1.2 billion and $800 million, respectively. The Q2 2020 Amendments, which were approved by the lenders, 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%
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of the newly issued and outstanding Senior Secured Notes. Among other things, the Q2 2020 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.
In connection with CRP’s credit facility fall 2020 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were reaffirmed at $700.0 million .
Results of Operations
Three Months Ended September 30, 2020 Compared to Three Months Ended September 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 September 30,
Increase/(Decrease)
2020
2019
$
%
Net revenues (in thousands):
Oil sales
$
119,966
$
200,196
$
(80,230
)
(40
)%
Natural gas sales
11,907
11,070
837
8
%
NGL sales
17,228
17,864
(636
)
(4
)%
Oil and gas sales
$
149,101
$
229,130
$
(80,029
)
(35
)%
Average sales prices:
Oil (per Bbl)
$
36.95
$
51.71
$
(14.76
)
(29
)%
Effect of derivative settlements on average price (per Bbl)
(9.82
)
(3.00
)
(6.82
)
(227
)%
Oil net of hedging (per Bbl)
$
27.13
$
48.71
$
(21.58
)
(44
)%
Average NYMEX price for oil (per Bbl)
$
40.93
$
56.45
$
(15.52
)
(27
)%
Oil differential from NYMEX
(3.98
)
(4.74
)
0.76
16
%
Natural gas (per Mcf)
$
1.15
$
0.96
$
0.19
20
%
Effect of derivative settlements on average price (per Mcf)
(0.25
)
0.30
(0.55
)
(183
)%
Natural gas net of hedging (per Mcf)
$
0.90
$
1.26
$
(0.36
)
(29
)%
Average NYMEX price for natural gas (per Mcf)
$
1.95
$
2.33
$
(0.38
)
(16
)%
Natural gas differential from NYMEX
(0.80
)
(1.37
)
0.57
42
%
NGL (per Bbl)
$
12.58
$
14.47
$
(1.89
)
(13
)%
Net production:
Oil (MBbls)
3,247
3,872
(625
)
(16
)%
Natural gas (MMcf)
10,354
11,491
(1,137
)
(10
)%
NGL (MBbls)
1,370
1,234
136
11
%
Total (MBoe) (1)
6,342
7,021
(679
)
(10
)%
Average daily net production:
Oil (Bbls/d)
35,292
42,079
(6,787
)
(16
)%
Natural gas (Mcf/d)
112,545
124,896
(12,351
)
(10
)%
NGL (Bbls/d)
14,885
13,417
1,468
11
%
Total (Boe/d) (1)
68,934
76,312
(7,378
)
(10
)%
(1)
Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
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Oil, Natural Gas and NGL Sales Revenues . Total net revenues for the three months ended September 30, 2020 were $80.0 million (or 35% ) lower than total net revenues for the three months ended September 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 and NGLs decreased in the third quarter of 2020 compared to the same 2019 period. The average price for oil before the effects of hedging decreased 29% and the average price for NGLs decreased 13% between periods. The 29% decrease in the average realized oil price was the result of lower NYMEX crude prices between periods (average NYMEX prices decreased 27% ), which was partially offset by improved oil differentials ( $0.76 per Bbl). The 13% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in the third quarter of 2020 as compared to the third quarter of 2019 . Conversely, the average realized sales price of natural gas before the effects of hedging increased 20% in the third quarter 2020 compared to the same 2019 period. This increase was mainly due to improved gas differentials ( $0.57 per Mcf), which was partially offset by lower average NYMEX gas prices between periods (average NYMEX prices decreased 16% ). 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 third quarter and as new pipelines have been placed into service. These pipelines have provided relief from the gas takeaway capacity constraints experienced in 2019. The market prices for oil, natural gas and NGLs have all been significantly impacted by lower demand globally for oil and gas as a result of COVID-19 as well as by supply disruptions from the Russia-Saudi oil price war, which combined have resulted in significant price declines starting in March 2020 as discussed in the market conditions section above.
Net production volumes for oil and natural gas decreased 16% and 10% , respectively, while NGLs increased 11% between periods. The crude oil production volume decrease was the result of (i) limited drilling and completion activity in the third quarter of 2020, which resulted in only five new wells completed and brought online during the second half of the quarter as compared to 17 wells completed and brought online in the third quarter of 2019, and (ii) normal field production declines across our existing wells. These production decreases were partially offset by 58 gross operated wells placed on production in the Delaware Basin since the third quarter of 2019 , which added 1,363 MBbls of net oil production to the three months ended September 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 third quarter of 2020, we flared significantly less wellhead gas as compared to the same 2019 period, resulting in a higher ratio of natural gas and NGL sales compared to oil sales during the period. In addition, the main processor of our raw gas operated in full ethane-recovery during the third quarter of 2020, as compared to operating in partial ethane-rejection for two-thirds of the third quarter of 2019. As a result, we sold less natural gas from our wet gas stream and recovered more NGLs during the 2020 period, which resulted in natural gas volumes decreasing (10%) and NGL volumes increasing (11%) between periods.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
Three Months Ended September 30,
Increase/(Decrease)
2020
2019
$
%
Operating costs (in thousands):
Lease operating expenses
$
24,543
$
42,330
$
(17,787
)
(42
)%
Severance and ad valorem taxes
7,839
12,213
(4,374
)
(36
)%
Gathering, processing and transportation expenses
19,130
20,853
(1,723
)
(8
)%
Operating costs per Boe:
Lease operating expenses
$
3.87
$
6.03
$
(2.16
)
(36
)%
Severance and ad valorem taxes
1.24
1.74
(0.50
)
(29
)%
Gathering, processing and transportation expenses
3.02
2.97
0.05
2
%
Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended September 30, 2020 decreased $17.8 million compared to the three months ended September 30, 2019 . Lower LOE for the third quarter of 2020 was primarily related to a $12.4 million decrease in expenses associated with cost reduction initiatives, described below, and lower variable and semi-variable costs as a result of lower production activity between periods. In addition, there was a $5.4 million decrease in workover expense as a result of lower workover activity between periods. These decreases were partially offset by LOE costs associated with our higher well count. We had 387 gross operated horizontal wells as of September 30, 2020 compared to 319 gross operated horizontal wells as of September 30, 2019 . The net increase in well count was mainly the result of our drilling activity adding 58 gross operated wells since the third quarter of 2019 , which was further adjusted for acquisitions and divestitures.
LOE on a per Boe basis decreased when comparing the third quarter of 2020 to the same 2019 period. LOE per Boe was $3.87 for the third quarter of 2020 , which represents a decrease of $2.16 per Boe (or 36% ) from the third quarter of 2019 . This
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decrease in rate was achieved as a result of oilfield cost reduction initiatives during the 2020 period including (i) moving multiple wells off generators to more cost-efficient electrical line-power, (ii) switching wells away from electric submersible pumps (“ESPs”) to more reliable and lower cost gas lift, (iii) lowering water disposal costs on producing wells through water recycling and reduced hauling fees, and (v) performing field reviews to reduce various costs for contract labor, oilfield equipment and supplies. In addition, our LOE per Boe rate for the third quarter of 2020 benefited from significantly lower electricity rates due to lower consumer and industry demand in West Texas compared to the 2019 period, and lower levels of workover activity between periods.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended September 30, 2020 decreased $4.4 million compared to the three months ended September 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 were 5.3% for both the third quarter of 2020 and 2019 , and they remained lower than our historical rates of 7% to 8% due to tax credits received of $2.2 million and $3.2 million , in each respective period, on wells designated as “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 September 30, 2020 decreased $1.7 million as compared to the three months ended September 30, 2019 primarily due to a $2.7 million decrease in plant processing, transportation and gathering fees as a result of lower wellhead gas and crude oil production between periods. This was partially offset by a $1.0 million decrease in reimbursements (net of related fees) received from third parties for their usage of our available firm transport (“FT”) capacity.
On a per Boe basis, GP&T increased from $2.97 for the third quarter of 2019 to $3.02 for the third quarter of 2020 . However, these fees are mainly incurred on our volumes of natural gas and NGLs processed, and the Boe rate on a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) decreased between periods to $6.18 from $6.62 for the three months ended September 30, 2020 and 2019, respectively. The decrease in rate was mainly attributable to (i) lower NGL prices between periods, as NGLs are a primary cost component of plant processing fees, and (ii) lower oil trucking fees incurred during the third quarter of 2020 as compared to the same 2019 period. These decreases, however, were partially offset by a lower amount of FT reimbursements (net of related fees) for the usage of our available FT capacity as referenced above.
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated:
Three Months Ended September 30,
(in thousands, except per Boe data)
2020
2019
Depreciation, depletion and amortization
$
89,444
$
112,720
Depreciation, depletion and amortization per Boe
$
14.10
$
16.06
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 September 30, 2020 , DD&A expense amounted to $89.4 million , a decrease of $23.3 million over the same 2019 period. The primary factor contributing to lower DD&A expense in 2020 was our lower DD&A rates between periods, which decreased DD&A expense by $12.4 million , while the decrease in our overall production volumes between periods lowered our DD&A expense by $10.9 million during the three months ended September 30, 2020 .
DD&A per Boe was $14.10 for the third quarter of 2020 compared to $16.06 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 net downward revisions in our proved reserves since the third quarter of 2019, which are mainly due to lower SEC reserve pricing.
Impairment and Abandonment Expense . Impairment and abandonment expense for the three months ended September 30, 2020 was $19.9 million as compared to $6.7 million for the three months ended September 30, 2019 due to an increase of $13.2 million in the amortization of leasehold expiration costs associated with individually insignificant unproved properties. This higher amortization was due to an increase in our estimated number of undeveloped acres subject to expiration, and this change in estimate was due to our revised 2020 development plan as well as changes made to our future drilling plans due to lower prices.
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Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated:
Three Months Ended September 30,
(in thousands)
2020
2019
Geological and geophysical costs
$
1,055
$
2,116
Stock-based compensation
256
753
Other expenses
1,359
—
Exploration and other expenses
$
2,670
$
2,869
Exploration and other expenses were $2.7 million for the three months ended September 30, 2020 compared to $2.9 million for the three months ended September 30, 2019 . Exploration and other expenses mainly consist of topographical studies, geographical and geophysical (“G&G”) projects, salaries and expenses of G&G personnel and includes other operating costs. The period over period decrease was primarily related to (i) a $0.7 million decrease in costs incurred on G&G projects and seismic studies, and (ii) $0.4 million in lower ongoing G&G personnel costs and $0.5 million in lower stock-based compensation incurred in the 2020 period. The G&G compensation cost reductions were associated with our lower headcount from the workforce reduction that occurred in the second quarter of 2020 (as further described below under General and Administrative Expenses ). These decreases were partially offset by $1.4 million in environmental remediation costs incurred in the third quarter of 2020 associated with a recently acquired proved property.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:
Three Months Ended September 30,
(in thousands)
2020
2019
Cash general and administrative expenses
$
11,741
$
12,679
Stock-based compensation - equity awards
4,772
7,357
Stock-based compensation - liability awards
487
—
Severance payments
582
—
General and administrative expenses
$
17,582
$
20,036
G&A expenses for the three months ended September 30, 2020 were $17.6 million compared to $20.0 million for the three months ended September 30, 2019 . The lower G&A expenses incurred in the third quarter of 2020 was primarily the result of a reduction to our workforce, effective May 1, 2020, and reduced salaries for the employees retained. These two factors combined resulted in a $0.6 million decrease in payroll and other personnel related costs and a $2.6 million decrease in equity-based stock compensation expense between periods. These decreases were partially offset by charges incurred during the three months ended September 30, 2020 related to $0.6 million in severance payments paid to G&A employees included in the workforce reduction and $0.5 million in stock compensation expense related to liability awards granted to G&A employees in the third quarter of 2020, that will be paid in cash upon award vesting (refer to Note 6—Stock-Based Compensation for additional information regarding the liability awards).
Other Income and Expenses.
Interest Expense. The following table summarizes our interest expense for the periods indicated:
Three Months Ended September 30,
(in thousands)
2020
2019
Credit facility
$
3,930
$
1,566
8.00% Senior Secured Notes due 2025
2,514
—
5.375% Senior Notes due 2026
3,889
5,375
6.875% Senior Notes due 2027
6,125
8,594
Amortization of debt issuance costs and discount
1,778
783
Interest capitalized
(518
)
(1,072
)
Total
$
17,718
$
15,246
Interest expense was $2.5 million higher for the three months ended September 30, 2020 as compared to the three months ended September 30, 2019 primarily due to (i) $2.5 million in interest incurred on our new Senior Secured Notes issued in May of 2020 in connection with the Debt Exchange; (ii) $2.4 million in increased interest expense incurred on our credit facility
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borrowings; and (iii) $1.0 million in higher amortization of the debt issuance costs and debt discount recognized in May 2020 in connection with the Debt Exchange discussed in Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report. These increases were partially offset by lower interest expense incurred on our Senior Unsecured Notes during the third quarter of 2020, as $110.6 million of the 2026 Senior Notes and $143.7 million of the 2027 Senior Notes were extinguished in the Debt Exchange transaction.
Our weighted average borrowings outstanding under our credit facility were $389.6 million versus $101.0 million for the three months ended September 30, 2020 and 2019, respectively. Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) was 3.5% and 3.9% for the three months ended September 30, 2020 and 2019, respectively, as a result of lower LIBOR in the third quarter of 2020 versus the prior year quarter.
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 outstanding 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 September 30,
(in thousands)
2020
2019
Settlement gains (losses)
$
(34,486
)
$
(8,218
)
Non-cash mark-to-market derivative gain (loss)
32,518
9,740
Total
$
(1,968
)
$
1,522
Income Tax (Expense) Benefit . The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated:
Three Months Ended September 30,
(in thousands)
2020
2019
Income (loss) before income taxes
$
(51,529
)
$
(2,320
)
Income tax (expense) benefit
—
(1,393
)
Our provisions for income taxes for the three months ended September 30, 2020 and 2019 differs 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) permanent differences, and (iii) any changes during the period in our deferred tax asset valuation allowance.
For the three months ended September 30, 2020, we recognized (i) a discrete permanent item of $3.5 million for lower deductions on stock awards that vested during the period, and (ii) a deferred tax asset valuation allowance of $8.3 million against net operating losses (“NOLs”) that we generated during the quarter, which are estimated as unlikely to be realized in future periods. The permanent item together with the increase in valuation allowance were the primary factors reducing our income tax benefit for the third quarter of 2020 (which is based on the U.S. statutory rate) to zero.
For the three months ended September 30, 2019, we recognized a discrete permanent item of $1.1 million. This permanent item was the primary factor reducing our income tax benefit for the third quarter of 2019 (which is based on the U.S. statutory rate) to income tax expense of $1.4 million.
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Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 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:
Nine Months Ended September 30,
Increase/(Decrease)
2020
2019
$
%
Net revenues (in thousands):
Oil sales
$
363,571
$
590,055
$
(226,484
)
(38
)%
Natural gas sales
29,052
31,655
(2,603
)
(8
)%
NGL sales
39,756
66,228
(26,472
)
(40
)%
Oil and gas sales
$
432,379
$
687,938
$
(255,559
)
(37
)%
Average sales prices:
Oil (per Bbl)
$
34.86
$
51.58
$
(16.72
)
(32
)%
Effect of derivative settlements on average price (per Bbl)
(3.58
)
(1.15
)
(2.43
)
(211
)%
Oil net of hedging (per Bbl)
$
31.28
$
50.43
$
(19.15
)
(38
)%
Average NYMEX price for oil (per Bbl)
$
38.37
$
57.05
$
(18.68
)
(33
)%
Oil differential from NYMEX
(3.51
)
(5.47
)
1.96
36
%
Natural gas (per Mcf)
$
0.93
$
1.04
$
(0.11
)
(11
)%
Effect of derivative settlements on average price (per Mcf)
(0.13
)
0.36
(0.49
)
(136
)%
Natural gas net of hedging (per Mcf)
$
0.80
$
1.40
$
(0.60
)
(43
)%
Average NYMEX price for natural gas (per Mcf)
$
1.82
$
2.57
$
(0.75
)
(29
)%
Natural gas differential from NYMEX
(0.89
)
(1.53
)
0.64
42
%
NGL (per Bbl)
$
11.50
$
16.88
$
(5.38
)
(32
)%
Net production:
Oil (MBbls)
10,429
11,440
(1,011
)
(9
)%
Natural gas (MMcf)
31,209
30,409
800
3
%
NGL (MBbls)
3,458
3,923
(465
)
(12
)%
Total (MBoe) (1)
19,088
20,431
(1,343
)
(7
)%
Average daily net production:
Oil (Bbls/d)
38,061
41,903
(3,842
)
(9
)%
Natural gas (Mcf/d)
113,900
111,388
2,512
2
%
NGLs (Bbls/d)
12,619
14,371
(1,752
)
(12
)%
Total (Boe/d) (1)
69,664
74,839
(5,175
)
(7
)%
(1)
Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
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Oil, Natural Gas and NGL Sales Revenues . Total net revenues for the nine months ended September 30, 2020 were $255.6 million , or 37% , lower than total net revenues for the nine months ended September 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 for the first nine months of 2020 all decreased when compared to the same 2019 period. The average price for oil before the effects of hedging decreased 32% , the average price for natural gas before the effects of hedging decreased 11% , and the average price for NGLs decreased 32% between periods. The 32% decrease in the average realized oil price was mainly the result of lower NYMEX crude prices between periods (average NYMEX prices decreased 33% ), which was minimally offset by improved oil differentials ( $1.96 per Bbl). The average realized sales price of natural gas decreased 11% due to lower average NYMEX gas prices between periods (average NYMEX prices decreased 29% ), but this decrease was largely offset by improved gas differentials ( $0.64 per Mcf). The 32% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products for the first nine months of 2020 compared to the first nine months of 2019. The market prices for oil, natural gas and NGLs have all been significantly impacted by lower demand globally for oil and gas as a result of COVID-19 as well as by supply disruptions from the Russia-Saudi oil price war, which combined have 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 9% and 12% , respectively, while natural gas production volumes increased 3% between periods. The oil production volume decrease was the result of (i) the temporary suspension of our drilling and completion activity during most of the second and third quarter of 2020, which resulted in only 31 new wells being completed and brought online during the first nine months of 2020 as compared to 57 wells completed and brought online during the same 2019 period, (ii) the curtailment of a portion of our production during the second quarter of 2020, and (iii) normal field production declines across our existing wells. These production decreases were partially offset by 58 operated wells placed on production in the Delaware Basin since the third quarter of 2019, which added 4,036 MBbls of net oil production to the nine months ended September 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, for over half of the first nine months of 2020, the main processor of our raw gas operated in ethane-rejection as compared to operating in ethane-recovery during the majority of the 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 (3%) in natural gas volumes and a decrease ( 12% ) in NGL volumes between periods.
Operating Expenses. The following table summarizes our operating expenses for the periods indicated:
Nine Months Ended September 30,
Increase/(Decrease)
2020
2019
$
%
Operating costs (in thousands):
Lease operating expenses
$
83,021
$
107,077
$
(24,056
)
(22
)%
Severance and ad valorem taxes
30,108
45,519
(15,411
)
(34
)%
Gathering, processing and transportation expenses
53,353
52,120
1,233
2
%
Operating costs per Boe:
Lease operating expenses
$
4.35
$
5.24
$
(0.89
)
(17
)%
Severance and ad valorem taxes
1.58
2.23
(0.65
)
(29
)%
Gathering, processing and transportation expenses
2.80
2.55
0.25
10
%
Lease Operating Expenses. LOE for the nine months ended September 30, 2020 decreased $24.1 million as compared to the nine months ended September 30, 2019 . Lower LOE for the first nine months of 2020 was primarily related to a $15.8 million decrease in workover expense between periods as a result of less workover activity and an $8.3 million decrease in expense associated with cost reduction initiatives, described below, as well as lower variable and semi-variable costs as a result of lower production activity between periods. These decreases were partially offset by LOE costs associated with our higher well count. We had 387 gross operated horizontal wells as of September 30, 2020 compared to 319 gross operated horizontal wells as of September 30, 2019 . The net increase in well count was mainly the result of our drilling activity adding 58 gross operated wells since the third quarter of 2019 , which was further adjusted for acquisitions and divestitures.
LOE on a per Boe basis decreased when comparing the first nine months of 2020 to the same 2019 period. LOE per Boe was $4.35 for the nine months ended September 30, 2020 , which represents a decrease of $0.89 per Boe (or 17% ) from the comparable 2019 period. This decrease in rate was mainly due to the lower level of workover activity as well as cost reduction initiatives we have undertaken such as (i) moving multiple wells off generators to more cost-efficient electrical line-power, (ii) switching wells away from ESP lift to more reliable and lower cost gas lift, and (iii) performing field reviews to reduce or eliminate various costs for contract labor, oilfield equipment and supplies. These decreases were partially offset by per BOE cost
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increases in the first nine months 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 monthly rental fees for compressors and other equipment, wellhead chemical costs, and water handling costs.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the nine months ended September 30, 2020 decreased $15.4 million compared to the nine months ended September 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 nine months of 2020 decreased $12.1 million compared to the same 2019 period primarily due to lower oil, natural gas and NGL revenues between periods. Ad valorem taxes decreased $3.3 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 7.0% for the first nine months of 2020 as compared to 6.6% for the same 2019 period. This increase in rate was due to the 2020 ad valorem tax assessment, which while lower between periods (down 25%), declined less than our oil and gas sales which decreased 37% between periods.
Gathering, Processing and Transportation Expenses. GP&T for the nine months ended September 30, 2020 increased $1.2 million compared to the nine months ended September 30, 2019 primarily due to a $6.6 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 $5.4 million decrease in plant processing, transportation and gathering fees incurred between periods.
On a per Boe basis, GP&T increased from $2.55 for the first nine months of 2019 to $2.80 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 from $5.80 to $6.16 for the nine months ended September 30, 2019 and 2020 , respectively. These rate increases were mainly attributable to a lower amount of FT reimbursements (net of related fees) for the usage of our available FT capacity as referenced above.
Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated:
Nine Months Ended September 30,
(in thousands, except per Boe data)
2020
2019
Depreciation, depletion and amortization
$
283,722
$
321,392
Depreciation, depletion and amortization per Boe
$
14.86
$
15.73
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 nine months ended September 30, 2020 , DD&A expense amounted to $283.7 million , a decrease of $37.7 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 $21.0 million during the first nine months of 2020 , while lower DD&A rates between periods lowered DD&A expense by $16.7 million .
DD&A per Boe was $14.86 for the first nine months of 2020 compared to $15.73 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 net downward revisions in our proved reserves since the third quarter of 2019, which were mainly due to lower SEC reserve pricing.
Impairment and Abandonment Expense. During the nine months ended September 30, 2020 , $650.6 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) $58.8 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 of March 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 of March 31, 2020. If future oil, natural gas and NGL prices were to decline to lower levels, or
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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 ended September 30, 2020 or June 30, 2020.
During the nine months ended September 30, 2019 , $42.4 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 nine months of 2019 after efforts to extend, sell or trade these leases were unsuccessful, (ii) $16.6 million for impaired acreage following an acreage sale initiated in the first quarter of 2019, and (iii) $6.7 million related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties.
Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated:
Nine Months Ended September 30,
(in thousands)
2020
2019
Geological and geophysical costs
$
4,129
$
6,928
Rig termination fees
3,046
284
Stock-based compensation
1,230
2,034
Severance payments
722
—
Other expenses
1,603
—
Exploration and other expenses
$
10,730
$
9,246
Exploration and other expenses were $10.7 million for the nine months ended September 30, 2020 compared to $9.2 million for the same prior year period. Exploration and other expenses mainly consist of topographical studies, G&G projects, 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 nine months of 2020, as a result of reducing our operated drilling activity in 2020; (ii) $0.7 million in nonrecurring severance payments to G&G personnel, resulting from our workforce reduction that took place in the second quarter of 2020; and (iii) $1.4 million in environmental remediation costs that we incurred in the third quarter of 2020 associated with a recently acquired proved property. These increases were partially offset by (i) a $1.6 million decrease in costs incurred on G&G projects and seismic studies, and (ii) $1.2 million in lower ongoing G&G personnel costs and $0.8 million in lower stock-based compensation incurred in the 2020 period, both of which were associated with the lower headcount from our workforce reduction that occurred in the second quarter of 2020.
General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated:
Nine Months Ended September 30,
(in thousands)
2020
2019
Cash general and administrative expenses
$
35,559
$
37,272
Stock-based compensation expense - equity awards
14,934
19,317
Stock-based compensation expense - liability awards
487
—
Severance payments
3,466
—
General and administrative expenses
$
54,446
$
56,589
G&A expenses for the nine months ended September 30, 2020 were $54.4 million compared to $56.6 million for the nine months ended September 30, 2019 . The lower G&A expenses incurred in the first nine months of 2020 was primarily the result of a reduction to our workforce and reduced salaries for the employees retained, effective May 1, 2020. These two factors combined resulted in a $2.6 million decrease in payroll and other personnel related costs and a $4.4 million decrease in equity-based stock compensation expense between periods. These decreases were partially offset by (i) $3.5 million of nonrecurring severance payments paid to G&A employees who were included in our workforce reduction; (ii) $0.5 million in stock compensation expense related to liability awards granted to G&A employees in the third quarter of 2020 that will be paid in cash upon award vesting (refer to Note 6—Stock-Based Compensation for additional information regarding the liability awards); and (iii) $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).
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Other Income and Expenses.
Interest Expense. The following table summarizes our interest expense for the periods indicated:
Nine Months Ended September 30,
(in thousands)
2020
2019
Credit facility
$
9,256
$
6,179
8.00% Senior Secured Notes due 2025
3,643
—
5.375% Senior Notes due 2026
13,995
16,124
6.875% Senior Notes due 2027
22,243
18,716
Amortization of debt issuance costs and discount
4,112
2,070
Interest capitalized
(1,739
)
(3,246
)
Total
$
51,510
$
39,843
Interest expense was $11.7 million higher for the nine months ended September 30, 2020 compared to the same 2019 period. The higher interest expense incurred in the first nine months of 2020 was mainly due to (i) $3.6 million in interest incurred on our new Senior Secured Notes issued in May of 2020 in connection with the Debt Exchange, (ii) $3.5 million in increased interest expense related to our 2027 Senior Notes that were issued in March 2019 and only outstanding for six and half months during the prior year period, (iii) $3.1 million in higher interest expense incurred on our credit facility borrowings, and (iv) $2.0 million in higher amortization related to the debt issuance costs and debt discount recognized in May 2020 in connection with the Debt Exchange discussed in Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report. These increases were partially offset by lower interest expense incurred on our Senior Unsecured Notes during the 2020 period, as $110.6 million of the 2026 Senior Notes and $143.7 million of the 2027 Senior Notes were extinguished in the Debt Exchange transaction.
Our weighted average borrowings outstanding under our credit facility were $322.3 million and $138.3 million for the first nine months of 2020 and 2019 , respectively. Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) was 3.2% and 3.9% for the nine months ended September 30, 2020 and 2019 , respectively. LIBOR was lower in the first nine months of 2020 versus the same prior year period.
Gain on exchange of debt. A gain of $143.4 million was recognized for the nine months ended September 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 of our newly issued Senior Secured Notes on their date of issuance. 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 outstanding and (ii) monthly settlements of our hedged derivative positions.
The following table presents gains and losses for derivative instruments for the periods indicated:
Nine Months Ended September 30,
(in thousands)
2020
2019
Settlement gains (losses)
$
(41,433
)
$
(2,207
)
Non-cash mark-to-market derivative gain (loss)
1,103
(14
)
Total
$
(40,330
)
$
(2,221
)
Income Tax (Expense) Benefit . The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated:
Nine Months Ended September 30,
(in thousands)
2020
2019
Income (loss) before income taxes
$
(681,668
)
$
11,810
Income tax (expense) benefit
85,124
(5,058
)
Our provisions for income taxes for the first nine months of 2020 and 2019 differs 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) permanent differences; and (iii) any changes during the period in our deferred tax asset valuation allowance.
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For the nine months ended September 30, 2020, we recognized a deferred tax asset valuation allowance of $58.0 million against NOLs that we generated during the period, which are estimated as unlikely to be realized in future periods. This increase in valuation allowance was the primary factor reducing our income tax benefit for the first nine months of 2020 from the U.S. statutory rate to $85.1 million.
For the nine months ended September 30, 2019, we recognized a discrete permanent item of $1.3 million for lower deductions on stock awards that vested during the period and a projected permanent item of $1.8 million related to future stock compensation not expected to be deductible. These items were the primary factors increasing our income tax expense for the first nine months of 2020 from the U.S. statutory rate to $5.1 million.
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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 in March 2020 and have remained volatile since. These lower commodity prices negatively impact our cash flows and our ability 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 nine months ended September 30, 2020 :
(in millions)
Nine Months Ended September 30, 2020
Drilling and completion capital expenditures
$
187.9
Facilities, infrastructure and other
33.2
Land
3.8
Total capital expenditures incurred
$
224.9
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 drilling rigs in operation until the end of September 2020 when we resumed drilling activity with a one-rig drilling program. With respect to our completion activity, during the third quarter of 2020 we recommenced activity by completing 5 gross operated wells, which were drilled but not completed during the first quarter of 2020.These changes in our drilling rig program and completion activity levels represents a reduction from the four-rig program that we initially announced with our 2020 operational guidance at the beginning of the year. Consequently, we expect our total capex budget for 2020 will now be between $240.0 million to $265.0 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 . We expect to fund the remainder of our 2020 capital expenditures with cash flows from operations. In addition, we expect to be free cash flow positive over the remainder of 2020 such that we plan on continuing to pay down borrowings under our credit agreement during the fourth quarter of 2020.
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 and did not experience any further curtailments of our production during the third quarter 2020. 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 or reduced our drilling and completion activity could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
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 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.
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Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
Nine Months Ended September 30,
(in thousands)
2020
2019
Net cash provided by operating activities
$
130,232
$
384,875
Net cash used in investing activities
(308,009
)
(698,120
)
Net cash provided by financing activities
172,752
308,064
For the nine months ended September 30, 2020 , we generated $130.2 million of cash from operating activities, a decrease of $254.6 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 and other expenses, cash G&A expenses, interest payments, cash settlement losses on derivatives, and the timing of supplier payments during the nine months ended September 30, 2020 . These declining factors were partially offset by lower lease operating expenses, production taxes, and the timing of our receivable collections for the nine months ended September 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 on fluctuations in our operating expenses between periods.
During the nine months ended September 30, 2020 , cash flows from operating activities, cash on hand, and net borrowings of $180.0 million under our credit facility were used to finance $300.7 million of drilling and development cash expenditures, to fund $7.7 million in oil and gas property acquisitions, and to finance $6.7 million of debt issuance and exchange costs.
During the nine months ended September 30, 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 $180.0 million under our credit facility, to finance $644.9 million of drilling and development cash expenditures, to fund $73.3 million in oil and gas property acquisitions, and to purchase $8.2 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 on May 4, 2023 (the “Credit Agreement”). On May 1, 2020 , CRP as borrower and we, as parent guarantor, entered into the Q2 2020 Amendments, which among other things established a new borrowing base and level of elected commitments of $700.0 million . The Q2 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 September 30, 2020 , we had $355.0 million in borrowings outstanding and $304.4 million in available borrowing capacity, which was net of $8.8 million in letters of credit outstanding and the availability blocker of $31.8 million . In connection with the Credit Agreement’s fall 2020 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were reaffirmed at $700.0 million . Furthermore, we reduced our letters of credit outstanding under the Credit Agreement to $4.3 million as of October 31, 2020, from $8.8 million outstanding as of September 30, 2020.
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 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; 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 Q2 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 .
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CRP was in compliance with the covenants and the financial ratios described above as of September 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 Notes 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 an extinguishment of debt in accordance with Financial Accounting Standards Board’s Accounting Standard Codification Topic 470-50, Modifications and Extinguishments. As a result, a gain on the exchange of debt of $143.4 million was recognized in the consolidated statement of operations, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of new Senior Secured Notes issued, net of their associated debt discount of $21.0 million (which was based on the notes’ estimated fair value on the exchange date).
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 Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by Centennial and each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility.
In May 2020, a portion of the 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 of September 30, 2020 and through the filing of this Quarterly Report.
For further information on our Senior Notes, 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, 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 September 30, 2020 .
Critical Accounting Policies and Estimates
There have been no material changes during the nine months ended September 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 of September 30, 2020 .
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