CALLON PETROLEUM COMPANY General
The following management's discussion and analysis describes the principal factors affecting the Company's results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 2019 Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. Our website address is www.callon.com. All of our filings with theSEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, theSEC . Information on our website does not form part of this Quarterly Report on Form 10-Q. We are an independent oil and natural gas company incorporated in theState of Delaware in 1994, but our roots go back 70 years to our Company's establishment in 1950. We are focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South andWest Texas . Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the largerPermian Basin inWest Texas , as well as theEagle Ford Shale , which we entered into through the Carrizo Acquisition in late 2019. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in thePermian Basin , including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and more recently as a result of the Carrizo Acquisition, theEagle Ford Shale . We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Recent Developments COVID-19 Outbreak and Global Industry Downturn The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision bySaudi Arabia inMarch 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements amongOPEC and other countries such asRussia further increased uncertainty and volatility around global oil supply-demand dynamics. As a result, there is an excess supply of oil inthe United States , which could continue for a sustained period; this is in addition to recent and continued excess supply of natural gas inthe United States . This excess supply has, in turn, resulted in transportation and storage capacity constraints inthe United States , and may even cause the elimination of available storage, including in thePermian Basin . The COVID-19 outbreak and its development into a pandemic inMarch 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, 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, being prepared to quarantine 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, in accordance with the guidelines released by theCenter for Disease Control . In addition, most 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. Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we reduced our operations in order to preserve capital. We expect to fund the remainder of our 2020 capital expenditures with cash flows from operations and borrowings under our revolving credit facility. As substantially all of our revenues are generated by the production and sale of hydrocarbons, if it became necessary to curtail or shut-in a significant portion of our production, it could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. We have resumed production from wells that were curtailed as a result of field level economic decisions in the second quarter, and we do not forecast additional shut-ins at this time. Previously deferred initial flowback was initiated from wells in the Wildhorse area in June, and all wells are now on production. We have various firm transportation agreements on pipelines in both thePermian Basin as well as theEagle Ford Shale to help manage delivery risk of our production and provide us with the ability to deliver to various regional markets where we have the potential to receive more favorable pricing as compared to selling to purchasers at the wellhead. See "-Contractual Obligations" below for further details. 31 --------------------------------------------------------------------------------
Overview
Second Quarter 2020 Highlights •Total production for the three months endedJune 30, 2020 was 108,664 Boe/d, an increase of 168% from the three months endedJune 30, 2019 , primarily due to production from the Carrizo Acquisition and new wells placed on production during 2020, partially offset by normal production decline and the sale of our Ranger assets in 2019. •Operated drilling and completion activity for the three months endedJune 30, 2020 along with our drilled but uncompleted and producing wells as ofJune 30, 2020 are summarized in the table below. Three Months Ended June 30, 2020 As of June 30, 2020 Drilled Completed Drilled But Uncompleted Producing Region Gross Net Gross Net Gross Net Gross Net Permian Basin 19 17.1 16 15.0 36 33.4 840 729.7 Eagle Ford Shale 10 9.9 10 9.9 35 34.9 631 568.3 Total 29 27.0 26 24.9 71 68.3 1,471 1,298.0 ?Operational capital expenditures, inclusive of leasehold and seismic, for the second quarter of 2020 were$85.1 million , of which approximately 85% were in thePermian Basin with the remaining balance in the Eagle Ford. In response to the decline in commodity prices for oil and natural gas, we reduced activity relative to our original plan, including the suspension of all completion activity in April and transition to one active drilling rig in mid-May. We do not currently have any active rigs or completion crews, but we do intend to resume development activity during the third quarter of 2020. Near-term operational activity will be focused on completing a drilled, but uncompleted inventory of approximately 70 wells in both thePermian Basin andEagle Ford Shale with one dedicated completion crew. We also intend to return two to three drilling rigs to service later in the third quarter of 2020 for the balance of the year. As a result, we currently forecast total operational capital expenditures of approximately$140.0 to$165.0 million over the remaining two quarters of 2020 and expect operational capital expenditures to be approximately$500.0 to$525.0 million for the full year 2020. See "-Liquidity and Capital Resources-2020 Capital Plan and Outlook" for additional details. •We recorded a loss available to common stockholders for the three months endedJune 30, 2020 of$1.6 billion , or$3.94 per diluted share, as compared to net income available to common stockholders for the three months endedJune 30, 2019 of$53.4 million , or$0.23 per diluted share. The change from net income available to common stockholders to net loss available to common stockholders between the respective periods was driven primarily by the recording of an impairment of evaluated oil and gas properties of$1.3 billion during the second quarter of 2020 as well as a loss on derivative contracts of approximately$127.0 million during the second quarter of 2020 compared to a gain on derivative contracts of approximately$14.0 million during the second quarter of 2019 and an approximate 65% decrease in total average realized sales prices between the two periods, partially offset by an approximate 168% increase in total production for the three months endedJune 30, 2020 compared to the three months endedJune 30, 2019 . See "-Results of Operations" below for further details. 32 -------------------------------------------------------------------------------- Results of Operations The following table sets forth certain operating information with respect to the Company's oil and natural gas operations for the periods indicated: Three Months EndedJune 30 , Six Months EndedJune 30, 2020 2019 Change % Change 2020 2019 Change % Change Total production (1) Oil (MBbls) 6,396 2,848 3,548 125 % 12,243 5,706 6,537 115 % Natural gas (MMcf) 11,009 5,031 5,978 119 % 20,802 9,650 11,152 116 % NGLs (MBbls) 1,657 - 1,657 100 % 3,364 - 3,364 100 % Total barrels of oil equivalent (MBoe) 9,888 3,687 6,201 168 % 19,074 7,314 11,760 161 % Total daily production (Boe/d) 108,664 40,516 68,148 168 % 104,802 40,409 64,393 159 % Oil as % of total daily production 65 % 77 % 64 % 78 % Average realized sales price (excluding impact of settled derivatives) Oil (per Bbl)$20.41 $56.44 ($36.03 ) (64 %)$32.37 $52.90 ($20.53 ) (39 %) Natural gas (per Mcf) 1.11 1.26 (0.15) (12 %) 0.88 1.89 (1.01) (53 %) NGLs (per Bbl) 8.74 - 8.74 100 % 9.69 - 9.69 100 % Total (per Boe)$15.90 $45.31 ($29.41 ) (65 %)$23.44 $43.77 ($20.33 ) (46 %) Revenues (in thousands) Oil$130,513 $160,728 ($30,215 ) (19 %)$396,280 $301,826 $94,454 31 % Natural gas 12,242 6,324 5,918 94 % 18,271 18,273 (2) - % NGLs 14,479 - 14,479 100 % 32,602 - 32,602 100 % Total revenues$157,234 $167,052 ($9,818 ) (6 %)$447,153 $320,099 $127,054 40 % Benchmark prices (2) WTI (per Bbl)$27.85 $59.88 ($32.03 ) (53 %)$36.97 $57.39 ($20.42 ) (36 %)Henry Hub (per Mcf) 1.76 2.57 (0.81) (32 %) 1.81 2.74 (0.93) (34 %) (1) EffectiveJanuary 1, 2020 , certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent toJanuary 1, 2020 . For periods prior toJanuary 1, 2020 , except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, we presented our sales and reserves volumes, prices, and revenues for NGLs with natural gas. (2) Reflects calendar average daily spot market prices. Revenues The following table is intended to reconcile the change in oil, natural gas, NGLs, and total revenue for the respective period presented by reflecting the effect of changes in volume and in the underlying commodity prices: Three Months EndedJune 30 Six Months EndedJune 30 Oil Natural Gas NGLs Total Oil Natural Gas NGLs Total (In thousands) Revenues for the periods ended in 2019$160,728 $6,324 $-$167,052 $301,826 $18,273 $-$320,099 Volume increase (decrease) 199,104 7,516 14,479 221,099 344,725 21,117 32,602 398,444 Price increase (decrease) (229,319) (1,598) - (230,917) (250,271) (21,119) - (271,390) Net increase (decrease) (30,215) 5,918 14,479 (9,818) 94,454 (2) 32,602 127,054 Revenues for the periods ended in 2020 (1)$130,513 $12,242 $14,479 $157,234 $396,280 $18,271 $32,602 $447,153 (1) EffectiveJanuary 1, 2020 , certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent toJanuary 1, 2020 . For periods prior toJanuary 1, 2020 , except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, we presented our sales and reserves volumes, prices, and revenues for NGLs with natural gas. 33 -------------------------------------------------------------------------------- Commodity Prices The prices for oil, natural gas, and NGLs remain extremely volatile primarily due to the underlying supply and demand concerns as a result of COVID-19 as well as the actions taken byOPEC and other countries as described above. Prices of oil, natural gas, and NGLs will affect the following aspects of our business: •our revenues, cash flows and earnings; •the amount of oil and natural gas that we are economically able to produce; •our ability to attract capital to finance our operations and cost of the capital; •the amount we are allowed to borrow under the revolving credit facility; and •the value of our oil and natural gas properties. Period over Period Variances The change in absolute value for the three and six months endedJune 30, 2020 as compared toJune 30, 2019 can be primarily attributed to the Carrizo Acquisition which closed inDecember 2019 . The Carrizo Acquisition had a material impact to our reported results of operations. In order to provide a more meaningful basis for comparison, we focused our discussion on per unit metrics and only expanded on changes in absolute value where appropriate. Oil revenue For the three months endedJune 30, 2020 , oil revenues of$130.5 million decreased$30.2 million , or 19%, compared to revenues of$160.7 million for the same period of 2019. The decrease was primarily attributable to a 64% decline in the average realized sales price which fell to$20.41 per Bbl from$56.44 per Bbl. The decrease in pricing was partially offset by the 125% increase in production from the Carrizo Acquisition and our development efforts. For the six months endedJune 30, 2020 , oil revenues of$396.3 million increased$94.5 million , or 31%, compared to revenues of$301.8 million for the same period of 2019. The increase was primarily attributable to the 115% increase in production from the Carrizo Acquisition and our development efforts. The increase was partially offset by a 39% decline in the average realized sales price which fell to$32.37 per Bbl from$52.90 per Bbl. Natural gas revenue For the three months endedJune 30, 2020 , natural gas revenues of$12.2 million increased$5.9 million , or 94%, compared to$6.3 million for the same period of 2019. The increase was primarily attributable to the 119% increase in production from the Carrizo Acquisition and our development efforts. The increase was partially offset by a 12% decline in the average realized sale price which fell to$1.11 per Mcf from$1.26 per Mcf. For the six months endedJune 30, 2020 , natural gas revenues of$18.3 million remained relatively consistent despite a 53% decline in the average realize sales price, which fell to$0.88 per Mcf from$1.89 per Mcf. The price decrease was offset by a 116% increase in production from the Carrizo Acquisition and our development efforts. NGL revenue For the three and six months endedJune 30, 2020 , NGL revenues were$14.5 million and$32.6 million , or$8.74 and$9.69 per Bbl, compared to no revenues for the same period of 2019. The increase was due to the modification of certain of our natural gas processing agreements, which allowed us to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent toJanuary 1, 2020 . For periods prior toJanuary 1, 2020 , except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, we presented our sales and reserves volumes, prices, and revenues for NGLs with natural gas. 34 -------------------------------------------------------------------------------- Operating Expenses Three Months Ended June 30, Per Per Total Change Boe Change 2020 Boe 2019 Boe $ % $ % (In thousands, except per Boe and % amounts)
Lease operating expenses$50,838 $5.14 $22,776 $6.18 $28,062 123 % ($1.04 ) (17 %) Production and ad valorem taxes 10,361 1.05 11,131 3.02 (770) (7 %) (1.97) (65 %) Gathering, transportation and processing 20,037 2.03 - - 20,037 100 % 2.03 100 % Depreciation, depletion and amortization 138,930 14.05 63,137 17.12 75,793 120 % (3.07) (18 %) General and administrative 10,024 1.01 10,564 2.87 (540) (5 %) (1.86) (65 %) Impairment of evaluated oil and gas properties 1,276,518 129.10 - - 1,276,518 100 % 129.10 100 % Merger and integration expenses 8,067 0.82 - - 8,067 100 % 0.82 100 % Six Months Ended June 30, Per Per Total Change Boe Change 2020 Boe 2019 Boe $ % $ % (In thousands, except per Boe and % amounts) Lease operating expenses$103,221 $5.41 $46,843 $6.40 $56,378 120 % ($0.99 ) (15 %) Production and ad valorem taxes 30,041 1.57 21,944 3.00 8,097 37 % (1.43) (48 %) Gathering, transportation and processing 34,415 1.80 - - 34,415 100 % 1.80 100 % Depreciation, depletion and amortization 270,393 14.18 123,145 16.84 147,248 120 % (2.66) (16 %) General and administrative 18,349 0.96 25,341 3.46 (6,992) (28 %) (2.50) (72 %) Impairment of evaluated oil and gas properties 1,276,518 66.92 - - 1,276,518 100 % 66.92 100 % Merger and integration expenses 23,897 1.25 - - 23,897 100 % 1.25 100 % Lease operating expenses. These are daily costs incurred to extract oil, natural gas and NGLs and maintain our producing properties. Such costs also include maintenance, repairs, salt water disposal, insurance and workover expenses related to our oil and natural gas properties. Lease operating expenses for the three months endedJune 30, 2020 increased to$50.8 million compared to$22.8 million for the same period of 2019. The increase in lease operating expense was primarily related to a 168% increase in production over the comparative periods, which carries a variable component for each unit of production. Lease operating expense on a per unit basis decreased to$5.14 for the second quarter of 2020, which represents a decrease of$1.04 per Boe from the second quarter of 2019. The lower per unit metric reflects the distribution of fixed costs spread over higher production volumes. Lease operating expenses for the six months endedJune 30, 2020 increased to$103.2 million compared to$46.8 million for the same period of 2019. The increase in LOE was primarily related to a 161% increase in production over the comparative periods, which carries a variable component for each unit of production. Lease operating expenses on a per unit basis decreased to$5.41 for the six months endedJune 30, 2020 , which represents a decrease of$0.99 per Boe from the comparable period in 2019. The lower per unit metric reflects the distribution of fixed costs spread over higher production volumes. Production and ad valorem taxes. In general, production taxes are based upon current year commodity prices whereas ad valorem taxes are based upon prior year commodity prices. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions' valuation of our oil and gas properties. We benefit from tax credits and exemptions in our various taxing jurisdictions where available. Production and ad valorem taxes for the three months endedJune 30, 2020 decreased 7% to$10.4 million compared to$11.1 million for the same period of 2019, which is primarily related to a 6% decrease in total revenues. Production and ad valorem taxes for the six months endedJune 30, 2020 increased 37% to$30.0 million compared to$21.9 million for the same period of 2019, which is primarily related to a 40% increase in total revenues. Production and ad valorem taxes as a percentage of total revenues were consistent across the comparable periods at approximately 6.7%. Gathering, transportation and processing expenses. Gathering, transportation and processing costs for the three and six months endedJune 30, 2020 were$20.0 million and$34.4 million , respectively. No expense was recognized for gathering, transportation and processing costs during the same period of 2019. The change is due to the assumption of the processing agreements assumed in the 35 -------------------------------------------------------------------------------- Carrizo acquisition and certain contract modifications effectiveJanuary 1, 2020 . As such, the Company now records contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, as gathering, transportation and processing expense. These fees were historically recorded as a reduction of revenue depending on when control transferred to the purchaser. Depreciation, depletion and amortization ("DD&A"). Under the full cost accounting method, we capitalize costs within a cost center and then systematically amortize those costs on an equivalent unit-of-production method based on production and estimated proved reserve quantities. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to twenty years. The following table sets forth the components of our depreciation, depletion and amortization for the periods indicated: Three Months EndedJune 30 , Six Months EndedJune 30, 2020 2019 2020 2019 (In thousands, except per Boe amounts) Amount Per Boe Amount Per Boe Amount Per Boe Amount Per Boe DD&A of evaluated oil and gas properties$136,218 $13.78 $62,915 $17.06 $265,654 $13.93 $122,673 $16.77 Depreciation of other property and equipment 1,129 0.11 6 - 2,072 0.11 15 0.01 Amortization of other assets 733 0.07 - - 995 0.05 - - Accretion of asset retirement obligations 850 0.09 216 0.06 1,672 0.09 457 0.06 DD&A$138,930 $14.05 $63,137 $17.12 $270,393 $14.18 $123,145 $16.84 For the three and six months endedJune 30, 2020 , DD&A expense was$138.9 million and$270.4 million compared to$63.1 million and$123.1 million for the same periods of 2019. The additional DD&A was primarily related to DD&A of evaluated oil and gas properties, which is determined using the units of production method. The increase in DD&A of evaluated oil and gas properties for the three and six months endedJune 30, 2020 , resulted from production increases of 168% and 161%, respectively, which were partially offset by lower DD&A rates between the periods. Those factors accounted for an$85.3 million increase and$12.0 million offsetting decrease, respectively, during the second quarter of 2020. Similarly, the increased production and decreased per unit rate accounted for a$163.7 million increase and$20.7 million offsetting decrease, respectively, for the six months endedJune 30, 2020 as compared to 2019. The decrease in DD&A on a per unit basis rates across both periods was primarily a result of the Carrizo Acquisition which contributed to a significant increase in our proved reserves at a lower relative cost per Boe than our historical DD&A rate. General and administrative, net of amounts capitalized ("G&A"). G&A for the three months endedJune 30, 2020 was relatively consistent compared to the same period in 2019. We recorded a marginal decrease to$10.0 million compared to$10.6 million due to cost saving initiatives, which were partially offset by increased headcount of the combined companies. Additionally, G&A for the six months endedJune 30, 2020 decreased$7.0 million compared to 2019 primarily due to cost saving initiatives and a decrease in the fair value of the Cash-Settled RSU Awards and Cash SARs. Impairment of evaluated oil and gas properties. We recognized an impairment of evaluated oil and gas properties of$1.3 billion for the three and six months endedJune 30, 2020 due primarily to declines in the average realized prices for sales of oil and gas on the first calendar day of each month during the trailing 12-month period prior toJune 30, 2020 . There was no impairment of evaluated oil and gas properties for the three or six months endedJune 30, 2019 . Merger and integration expense. For the three and six months endedJune 30, 2020 , the Company incurred$8.1 million and$23.9 million of expenses associated with the Carrizo Acquisition. See "Note 3 - Acquisitions and Divestitures" of the Notes to our Consolidated Financial Statements for additional information regarding the merger with Carrizo. Other Income and Expenses Three Months EndedJune 30 , Six Months EndedJune 30, 2020 2019 $ Change % Change 2020 2019 $ Change % Change (In thousands, except % amounts) Interest expense$43,606 $19,478 $24,128 124 %$88,069 $40,059 $48,010 120 % Capitalized interest (20,924) (18,737) (2,187) 12 % (44,909) (38,580) (6,329) 16 % Interest expense, net of capitalized amounts 22,682 741 21,941 2,961 % 43,160 1,479 41,681 2,818 % (Gain) loss on derivative contracts$126,965 ($14,036 )$141,001 (1,005 %) ($125,004 )$53,224 ($178,228 ) (335 %) Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our revolving credit facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees, annual agency fees, and interest from our financing leases in interest expense. 36 -------------------------------------------------------------------------------- Interest expense, net of capitalized amounts, incurred during the three months endedJune 30, 2020 increased$21.9 million to$22.7 million compared to$0.7 million for the same period of 2019. Additionally, interest expense, net of capitalized amounts, incurred during the six months endedJune 30, 2020 increased$41.7 million to$43.2 million compared to$1.5 million for the same period of 2019. The increase is primarily due to debt that was assumed as a result of the Carrizo Acquisition. (Gain) loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) (gain) loss related to fair value adjustments on our open derivative contracts and (ii) (gains) losses on settlements of derivative contracts for positions that have settled within the period. The net (gain) loss on derivative instruments for the periods indicated includes the following: Three Months Ended June 30, Six Months Ended June 30, 2020 2019 2020 2019 (In thousands) (Gain) loss on oil derivatives$122,369 ($8,849 ) ($134,954 )$59,520 (Gain) loss on natural gas derivatives 4,695 (1,874) 11,524 (2,983) Gain on NGL derivatives (4) - (4) - Gain on contingent consideration arrangements (95) (3,313) (1,570) (3,313) (Gain) loss on derivative contracts$126,965 ($14,036 ) ($125,004 )$53,224 See "Note 7 - Derivative Instruments and Hedging Activities" and "Note 8 - Fair Value Measurements" of the Notes to our Consolidated Financial Statements for additional information. Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate, based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. We recorded income tax expense of$51.3 million for the three months endedJune 30, 2020 , compared to$16.7 million for the same period of 2019. Additionally, we recorded income tax expense of$115.3 million for the six months endedJune 30, 2020 , compared to$11.5 million for the same period of 2019. The increase in expense is due to the recording of a valuation allowance during the three months endedJune 30, 2020 . Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position atJune 30, 2020 , driven primarily by the impairment of evaluated oil and gas properties recognized for the three months endedJune 30, 2020 , which limits the ability to consider other subjective evidence such as our potential for future growth. Based on the evaluation of the evidence available during the three months endedJune 30, 2020 , we concluded that it is more likely than not that the net deferred tax assets will not be realized and recorded a valuation allowance of$377.6 million , reducing the net deferred tax assets as ofJune 30, 2020 to zero. See "Note 9 - Income Taxes" of the Notes to our Consolidated Financial Statements for additional information on income tax. Preferred stock dividends. OnJuly 18, 2019 , we redeemed all outstanding shares of Preferred Stock, after which, the Preferred Stock was no longer deemed outstanding and dividends ceased to accrue. As such, we did not make any Preferred Stock dividend payments during the three and six months endedJune 30, 2020 . Preferred Stock dividends of$1.8 million and$3.6 million were paid during the three and six months endedJune 30, 2019 . Liquidity and Capital Resources Our primary uses of capital have historically been for the acquisition, development, and exploration of oil and natural gas properties. Our capital program could vary depending upon factors, including, but not limited to, continued depressed commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments and other factors. In addition, depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material. Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. We regularly consider which 37 -------------------------------------------------------------------------------- resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements. Overview of Cash Flow Activities. For the six months endedJune 30, 2020 , cash and cash equivalents decreased$5.8 million to$7.5 million compared to$13.3 million atDecember 31, 2019 . Six Months Ended June 30, 2020 2019 (In thousands) Net cash provided by operating activities$289,496 $225,046 Net cash used in investing activities (453,656) (124,504) Net cash provided by (used in) financing activities 158,319 (100,541) Net change in cash and cash equivalents ($5,841 )$1 Operating activities. For the six months endedJune 30, 2020 , net cash provided by operating activities was$289.5 million compared to net cash provided by operating activities of$225.0 million for the same period in 2019. The change in operating activities was predominantly attributable to the following: •An increase in revenue due to a 161% increase in production volumes predominantly as a result of the Carrizo Acquisition, which was partially offset by a decrease in realized pricing, and •An offsetting increase in operating expenses as a result of higher production volumes. Production, realized prices, and operating expenses are discussed in Results of Operations. See "Note 7 - Derivative Instruments and Hedging Activities" and "Note 8 - Fair Value Measurements" of the Notes to our Consolidated Financial Statements for a reconciliation of the components of the Company's derivative contracts and disclosures related to derivative instruments including their composition and valuation. Investing activities. For the six months endedJune 30, 2020 , net cash used in investing activities was$453.7 million compared to$124.5 million for the same period in 2019. Net cash used in investing activities for the following periods included: Six Months Ended June 30, 2020 2019 $ Change (In thousands) Capital expenditures$430,569 $359,430 $71,139 Acquisitions - 39,370 (39,370) Proceeds from the sale of assets (10,079) (274,296) 264,217 Cash paid for settlements of contingent consideration arrangements, net 40,000 - 40,000 Additions to other assets (6,834) - (6,834) Total investing activities$453,656 $124,504 $329,152 Cash used in investing activities increased by approximately$329.2 million for the six months endedJune 30, 2020 compared to the same period in 2019 due primarily to lower proceeds from the sale of assets during the six months endedJune 30, 2020 . In 2019 Callon sold certain non-core assets in the southernMidland Basin (the "Ranger Asset Divestiture") for net cash proceeds of$244.9 million . See Note 3 - "Acquisitions and Divestitures" for further discussion of this divestiture. Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our credit facility, term debt and equity offerings. For the six months endedJune 30, 2020 , net cash provided by financing activities was$158.3 million compared to net cash used in financing activities of$100.5 million for the same period of 2019. 38 --------------------------------------------------------------------------------
Net cash provided by (used in) financing activities for the following periods included:
Six Months Ended June 30,
2020 2019 $ Change
(In thousands)
Net borrowings on Credit Facility $165,000 ($95,000 ) $260,000
Payment of deferred financing costs (6,011) (31) (5,980)
Payment of preferred stock dividends(1) - (3,647) 3,647
Tax withholdings related to restricted stock units (388) (1,858) 1,470
Other, net (282) (5) (277)
Net cash provided by (used in) financing activities $158,319 ($100,541 ) $258,860
(1) On July 18, 2019 , we redeemed all outstanding shares of the Preferred Stock,
after which, the Preferred Stock were no longer deemed outstanding and dividends
on the Preferred Stock ceased to accrue.
See "Note 6 - Borrowings" and "Note 10 - Stockholders' Equity" of the Notes to
our Consolidated Financial Statements for additional information on our debt and
equity transactions.
Senior Secured Revolving Credit Facility. We have a senior secured revolving
credit facility with a syndicate of lenders that, as of June 30, 2020 , had a
borrowing base of $1.7 billion , with an elected commitment amount of $1.7
billion , borrowings outstanding of $1.45 billion at a weighted average interest
rate of 3.01%, and $19.7 million in letters of credit outstanding. The borrowing
base under the credit agreement is subject to regular redeterminations in the
spring and fall of each year, as well as special redeterminations described in
the credit agreement, which in each case may reduce the amount of the borrowing
base. The revolving credit facility is secured by first preferred mortgages
covering our major producing properties.
On May 7, 2020 , we entered into the first amendment to our credit agreement
governing the revolving credit facility. See "Note 6 - Borrowings" of the Notes
to our Consolidated Financial Statements for further discussion of the first
amendment. Primarily as a result of the recent downturn in commodity prices as
well as demand as a result of COVID-19, our available liquidity has tightened,
however, we expect to have sufficient liquidity to pay interest on our revolving
credit facility and our Senior Notes as well as to fund our development program.
Upon a redetermination, if any borrowings in excess of the revised borrowing
base were outstanding, we could be forced to immediately repay a portion of the
borrowings outstanding under the credit agreement. Additionally, if the current
commodity price environment were to persist for an extended period, our ability
to remain in compliance with our restrictive financial covenants could be
challenged. If we are unable to remain in compliance with our restrictive
financial covenants, we could be subject to lender elections for default
resolution.
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Hedging. As of
For the Remainder For the Full Year
Oil contracts (WTI) of 2020 of 2021
Swap contracts
Total volume (Bbls) 6,291,880 1,377,000
Weighted average price per Bbl $42.08 $42.00 Collar contracts
Total volume (Bbls) 2,863,040 3,741,250
Weighted average price per Bbl
Ceiling (short call)$45.00 $45.02 Floor (long put)$35.00 $40.00 Short put contracts Total volume (Bbls) 1,104,000 - Weighted average price per Bbl$42.50 $-
Long call contracts
Total volume (Bbls) 920,000 - Weighted average price per Bbl$67.50 $-
Short call contracts
Total volume (Bbls) 920,000 (1) 4,825,300 (1) Weighted average price per Bbl$55.00 $63.62 Short call swaption contracts Total volume (Bbls) - 730,000 (2) Weighted average price per Bbl $-$47.00 Oil contracts (WTI Calendar Month Average Roll) Swap contracts Total volume (Bbls) 3,864,000 - Weighted average price per Bbl ($2.75 ) $-
Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls) 184,000 1,272,450 Weighted average price per Bbl$46.15 $38.24
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls) 3,094,700 4,015,100 Weighted average price per Bbl ($1.75 )$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls) 3,256,004 - Weighted average price per Bbl$0.06 $-
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls) 368,000 2,969,050 Weighted average price per Bbl$57.71 $39.48 (1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps. (2) The short call swaption contract has an exercise expiration date ofOctober 30, 2020 . 40 -------------------------------------------------------------------------------- For the Remainder For the Full Year Natural gas contracts (Henry Hub) of 2020 of 2021
Swap contracts
Total volume (MMBtu) 8,566,000 12,923,000 Weighted average price per MMBtu$2.07 $2.66
Collar contracts (three-way collars)
Total volume (MMBtu) 2,755,000 1,350,000
Weighted average price per MMBtu
Ceiling (short call) $2.73 $2.70
Floor (long put) $2.47 $2.42
Floor (short put) $2.00 $2.00 Collar contracts (two-way collars)
Total volume (MMBtu) 1,525,000 7,750,000
Weighted average price per MMBtu
Ceiling (short call) $3.25 $2.93
Floor (long put) $2.67 $2.55
Long call contracts
Total volume (MMBtu) 3,036,000 -
Weighted average price per MMBtu $3.50 $-
Short call contracts
Total volume (MMBtu) 6,072,000 7,300,000 Weighted average price per MMBtu$3.50 $3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu) 12,885,000 6,387,500 Weighted average price per MMBtu ($0.92 ) ($0.58 ) For the Remainder For the Full Year NGL contracts (OPIS Mont Belvieu Purity Ethane) of 2020 of 2021 Swap contracts Total volume (Bbls) - 1,825,000 Weighted average price per Bbl $-$7.62 2020 Capital Plan and Outlook Our original operational capital budget for 2020 was established at$975.0 million , which included running an average of eight to nine drilling rigs and an average of three completion crews. In response to the decline in commodity prices for oil and natural gas, we reduced activity relative to our original plan, including the suspension of all completion activity in April and transition to one active drilling rig in mid-May. We do not currently have any active rigs or completion crews, but we do intend to resume development activity during the third quarter of 2020. Near-term operational activity will be focused on completing a drilled, but uncompleted inventory of approximately 70 wells in both thePermian Basin andEagle Ford Shale with one dedicated completion crew. We also intend to return two to three drilling rigs to service later in the third quarter of 2020 for the balance of the year. As a result, we currently forecast total operational capital expenditures of approximately$140.0 to$165.0 million over the remaining two quarters of 2020 and expect operational capital expenditures to be approximately$500.0 to$525.0 million for the full year 2020. Our revenues, earnings, liquidity, and ability to deliver returns to our shareholders are substantially dependent on the prices we receive for, and our ability to develop our proved reserves. We monitor current and expected market conditions including the commodity price environment and our liquidity needs, and we may adjust our capital investment plan accordingly. Additionally, we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us. 41 -------------------------------------------------------------------------------- Contractual Obligations The following table includes our current contractual obligations and purchase commitments as ofJune 30, 2020 : Payments due by Period July - December 2020 2021 2022 2023 2024 and Thereafter Total (In thousands)
6.25% Senior Notes (1) $- $- $-$650,000 $-$650,000 6.125% Senior Notes (1) - - - - 600,000 600,000 8.25% Senior Notes (1) - - - - 250,000 250,000 6.375% Senior Notes (1) - - - - 400,000 400,000 Senior secured revolving credit facility (2) - - - - 1,450,000 1,450,000 Interest expense and other fees related to debt commitments (3) 133,059 154,245 154,245 133,933 183,934 759,416 Delivery commitments (4) 6,549 13,437 10,980 11,553 51,715 94,234 Operating leases 7,419 10,494 5,453 5,013 22,990 51,369 Asset retirement obligations (5) 2,330 22 374 194 48,175 51,095 Produced water disposal commitments (6) 9,055 14,968 11,933 4,387 3,410 43,753 Drilling rig leases (7) 9,047 3,562 - - - 12,609 Other commitments 731 845 508 392 39 2,515 Total contractual obligations$168,190 $197,573 $183,493 $805,472 $3,010,263 $4,364,991 (1)Includes the outstanding principal amount only. (2)The revolving credit facility has a maturity date ofDecember 20, 2024 , subject to springing maturity dates as discussed above. See "Note 6 - Borrowings" of the Notes to our Consolidated Financial Statements for additional information. (3)Includes estimated cash payments on the 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, the Credit Facility and commitment fees calculated based on the unused portion of lender commitments as ofJune 30, 2020 , at the applicable commitment fee rate. (4)Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil and natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. (5)Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. (6)Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. (7)Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party onJune 30, 2020 . The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. Critical Accounting Policies The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, and commitments and contingencies. These policies and estimates are described in "Note 2 - Summary of Significant Accounting Policies" of the Notes to Consolidated Financial Statements in our 2019 Annual Report. See "Note 7 - Derivative Instruments and Hedging Activities" and "Note 8 - Fair Value Measurements" for details of the contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued. Impairment ofEvaluated Oil and Gas Properties Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the "cost center ceiling" equal to (i) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (B) the costs of unevaluated properties not being amortized, and (C) the lower of cost or estimated fair value of unevaluated properties included in the costs being 42 -------------------------------------------------------------------------------- amortized; less (ii) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices in the future increase the cost center ceiling applicable to the subsequent period. The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period ("12-Month Average Realized Price"). Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments because we elected not to meet the criteria to qualify our derivative instruments for hedge accounting treatment. Due primarily to declines in the average realized prices for sales of oil and gas on the first calendar day of each month during the trailing 12-month period prior toJune 30, 2020 , the capitalized costs of oil and gas properties exceeded the cost center ceiling resulting in an impairment in the carrying value of evaluated oil and gas properties for the three months endedJune 30, 2020 as summarized in the table below:
Three Months Ended
2020 2019
Impairment of evaluated oil and gas properties (in thousands) $1,276,518 $-
Beginning of period 12-Month Average Realized Price ($/Bbl) $54.63 $54.58
End of period 12-Month Average Realized Price ($/Bbl) $45.87 $53.00
Percent decrease in 12-Month Average Realized Price (16) % (3) %
The decrease in the 12-Month Average Realized Price as of June 30, 2020 reduced
our proved oil and gas reserve volumes by less than 2% of our December 31, 2019
proved oil and gas reserves volumes. This reduction was primarily attributable
to proved developed reserves of producing wells and proved undeveloped reserves
with shorter economic lives. There were no proved undeveloped reserve locations
that became uneconomic as a result of the decrease in the 12-Month Average
Realized Price as of June 30, 2020 . There were no impairments of evaluated oil
and gas properties for the three months ended March 31, 2020 or for the
corresponding prior year periods.
Based on the first calendar day of each month oil and gas prices available for
the 11 months ended August 1, 2020 as well as forecasted costs, we anticipate
recording an additional after-tax impairment in the carrying value of oil and
gas properties in the third quarter of 2020 in the range of $750.0 million to
$1.0 billion . We currently estimate that the forecasted decrease in the 12-Month
Average Realized Price as of September 30, 2020 will result in a reduction of
our proved oil and gas reserve volumes of less than 1% of our December 31, 2019
proved oil and gas reserves volumes. This estimated reduction is primarily
attributable to proved developed reserves of producing wells and proved
undeveloped reserves with shorter economic lives. Additionally, we estimate that
none of our proved undeveloped reserve locations will be uneconomic and would
need to be removed from proved reserves based on these estimated prices. Further
impairments in subsequent quarters may occur if the trailing 12-month commodity
prices continue to be lower than the comparable trailing 12-month commodity
prices applicable to the second and third quarters of 2020. Based on the current
outlook for future commodity prices, we do not believe that those prices, if
realized, would have a significant adverse impact on our proved oil and gas
reserves volumes.
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The table below presents various pricing scenarios to demonstrate the
sensitivity of our June 30, 2020 cost center ceiling to changes in 12-month
average benchmark crude oil and natural gas prices underlying the 12-month
average realized prices. The sensitivity analysis is as of June 30, 2020 and,
accordingly, does not consider drilling and completion activity, acquisitions or
dispositions of oil and gas properties, production, changes in crude oil and
natural gas prices, and changes in development and operating costs occurring
subsequent to June 30, 2020 that may require revisions to estimates of proved
reserves.
Increase
(decrease) of
cost center
Excess (deficit) of ceiling over
cost center ceiling net book
over net book value, value, less
less related related
12-Month Average deferred income deferred
Realized Prices taxes income taxes
Crude Oil Natural Gas
Full Cost Pool Scenarios ($/Bbl) ($/Mcf) (In millions) (In millions)
June 30, 2020 Actual $45.87 $0.95 $-
Crude Oil and Natural Gas
Price Sensitivity
Crude Oil and Natural Gas +10% $50.59 $1.16 $818 $818
Crude Oil and Natural Gas -10% $41.15 $0.74 ($818 ) ($818 )
Crude Oil Price Sensitivity
Crude Oil +10% $50.59 $0.95 $762 $762
Crude Oil -10% $41.15 $0.95 ($762 ) ($762 )
Natural Gas Price Sensitivity
Natural Gas +10% $45.87 $1.16 $56 $56
Natural Gas -10% $45.87 $0.74 ($56 ) ($56 )
Income taxes
The amount of income taxes recorded requires interpretations of complex rules
and regulations of federal and state tax jurisdictions. We recognize current tax
expense based on estimated taxable income for the current period and the
applicable statutory tax rates. We routinely assess potential uncertain tax
positions and, if required, estimate and establish accruals for such amounts. We
have recognized deferred tax assets and liabilities for temporary differences,
operating losses and other tax carryforwards.
Management monitors company-specific, oil and natural gas industry and worldwide
economic factors and assesses the likelihood that
our net deferred tax assets will be utilized prior to their expiration. A
significant item of objective negative evidence considered was the cumulative
historical three year pre-tax loss and a net deferred tax asset position at
June 30, 2020 , driven primarily by the impairment of evaluated oil and gas
properties recognized for the three months ended June 30, 2020 , which limits the
ability to consider other subjective evidence such as our potential for future
growth. Based on the evaluation of the evidence available during the three
months ended June 30, 2020 , we concluded that it is more likely than not that
the net deferred tax assets will not be realized and recorded a valuation
allowance of $377.6 million , reducing the net deferred tax assets as of June 30,
2020 to zero.
We will continue to evaluate whether the valuation allowance is needed in future
reporting periods. The valuation allowance will remain until we can conclude
that the net deferred tax assets are more likely than not to be realized. Future
events or new evidence which may lead us to conclude that it is more likely than
not its net deferred tax assets will be realized include, but are not limited
to, cumulative historical pre-tax earnings, improvements in crude oil prices,
and taxable events that could result from one or more transactions. The
valuation allowance does not preclude us from utilizing the tax attributes if we
recognize taxable income. As long as we continue to conclude that the valuation
allowance against our net deferred tax assets is necessary, we will have no
significant deferred income tax expense or benefit. See "Note 9 - Income Taxes"
of the Notes to our Consolidated Financial Statements for additional information
regarding income taxes.
Recently Adopted and Recently Issued Accounting Pronouncements
See "Note 1 - Description of Business and Basis of Presentation" for discussion.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk,
interest rate risk and counterparty and customer credit risk. We mitigate these
risks through a program of risk management including the use of commodity
derivative instruments.
Commodity price risk
Our revenues are derived from the sale of its oil, natural gas and NGL
production. The prices for oil, natural gas and NGLs remain volatile and
sometimes experience large fluctuations as a result of relatively small changes
in supply, government actions, economic
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conditions, and weather conditions. From time to time, we enter into derivative
financial instruments to manage oil, natural gas and NGL price risk, related
both to NYMEX benchmark prices and regional basis differentials. The total
volumes we hedge through use of our derivative instruments varies from period to
period. Generally our objective is to hedge approximately 60% of our anticipated
internally forecast production for the next 12 to 24 months, subject to the
covenants under our Credit Facility. Given the current commodity price
environment, we have increased our hedge coverage for 2020 and 2021, however,
our hedge policies and objectives may change significantly with movements in
commodities prices or futures prices.
As of June 30, 2020 , for the remainder of 2020, the Company had 9,706,920 Bbls
of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston
benchmarks. The Company also had 4,609,200 Bbls of WTI Midland-Cushing oil basis
hedges and 3,256,004 Bbls of WTI Houston-Cushing oil basis hedges. Additionally,
for the remainder of 2020, the Company had 9,810,000 MMBtus of fixed price NYMEX
natural gas hedges and 12,885,000 MMBtus of Waha natural gas basis hedges. See
"Note 7 - Derivative Instruments and Hedging Activities" of the Notes to our
Consolidated Financial Statements for a description of the Company's outstanding
derivative contracts as of June 30, 2020 .
The Company may utilize fixed price swaps, which reduce the Company's exposure
to decreases in commodity prices and limit the benefit the Company might
otherwise have received from any increases in commodity prices. Swap contracts
may also be enhanced by the simultaneous sale of call or put options to
effectively increase the effective swap price as a result of the receipt of
premiums from the option sales.
The Company may utilize price collars to reduce the risk of changes in oil and
natural gas prices. Under these arrangements, no payments are due by either
party as long as the applicable market price is above the floor price (purchased
put option) and below the ceiling price (sold call option) set in the collar. If
the price falls below the floor, the counterparty to the collar pays the
difference to the Company, and if the price rises above the ceiling, the
counterparty receives the difference from the Company. Additionally, the Company
may sell put options at a price lower than the floor price in conjunction with a
collar (three-way collar) and use the proceeds to increase either or both the
floor or ceiling prices. In a three-way collar, to the extent that realized
prices are below the floor price of the sold put option (or above the ceiling
price of the sold call option), the Company's net realized benefit from the
three-way collar will be reduced on a dollar-for-dollar basis.
The Company may purchase puts, which reduce the Company's exposure to decreases
in oil and natural gas prices while allowing realization of the full benefit
from any increases in oil and natural gas prices. If the price falls below the
floor, the counterparty pays the difference to the Company.
The Company enters into these various agreements from time to time to reduce the
effects of volatile oil and natural gas prices and does not enter into
derivative transactions for speculative purposes. Presently, none of the
Company's derivative positions are designated as hedges for accounting purposes.
Interest rate risk
The Company is subject to market risk exposure related to changes in interest
rates on our indebtedness under our Credit Facility. As of June 30, 2020 , the
Company had $1.45 billion outstanding under the Credit Facility with a weighted
average interest rate of 3.01%. An increase or decrease of 1.00% in the interest
rate would have a corresponding increase or decrease in our annual net income of
approximately $14.5 million , based on the balance outstanding at June 30, 2020 .
See "Note 6 - Borrowings" of the Notes to our Consolidated Financial Statements
for more information on the Company's interest rates on our Credit Facility.
Counterparty and customer credit risk
The Company's principal exposures to credit risk are through receivables from
the sale of our oil and natural gas production, joint interest receivables and
receivables resulting from derivative financial contracts.
The Company markets its oil, natural gas and NGL production to energy marketing
companies. We are subject to credit risk due to the concentration of our oil,
natural gas and NGL receivables with several significant customers. The
inability of our significant customers to meet their obligations to us or their
insolvency or liquidation may adversely affect our financial results. In order
to mitigate potential exposure to credit risk, we may require from time to time
for our customers to provide financial security. At June 30, 2020 our total
receivables from the sale of our oil and natural gas production were
approximately $74.6 million .
Joint interest receivables arise from billings to entities that own partial
interests in the wells we operate. These entities participate in our wells
primarily based on their ownership in leases on which we have or intend to
drill. We have little ability to control whether these entities will participate
in our wells. At June 30, 2020 our joint interest receivables were approximately
$9.7 million .
Our oil, natural gas and NGL commodity derivative arrangements expose us to
credit risk in the event of nonperformance by counterparties. All of the
counterparties on our commodity derivative instruments currently in place are
lenders under our Credit Facility. We are likely to enter into additional
commodity derivative instruments with these or other lenders under our Credit
Facility, representing institutions with investment grade ratings. We have
existing ISDA Agreements with our commodity derivative counterparties. The terms
of the ISDA Agreements provide us and the counterparties with rights of offset
upon the occurrence of defined acts of default by either us or a counterparty to
a commodity derivative, whereby the party not in default may offset all
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commodity derivative liabilities owed to the defaulting party against all
commodity derivative asset receivables from the defaulting party. At June 30,
2020 , we had a net commodity derivative liability position of $5.9 million .
Item 4. Controls and Procedures
Disclosure controls and procedures. Disclosure controls and procedures include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by an issuer in the reports that it files or submits
under the Exchange Act is accumulated and communicated to the issuer's
management, including its principal executive and financial officers, or persons
performing similar functions, as appropriate to allow timely decisions regarding
required disclosure. Our Chief Executive Officer and Chief Financial Officer
performed an evaluation of our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation,
our principal executive and principal financial officers have concluded that the
Company's disclosure controls and procedures were effective as of June 30, 2020 .
Changes in internal control over financial reporting. In April 2020 , the Company
completed the implementation of Enertia Software ("Enertia"), which is an
integrated enterprise solution for managing accounting and financial reporting
information, and utilized Enertia for its accounting and reporting for the three
and six months ended June 30, 2020 . The Company believes the implementation of
the system and related changes to internal controls will enhance internal
controls over financial reporting. The Company has updated its internal
controls, as applicable, to facilitate modifications to its business processes
and accounting procedures and will continue to evaluate the operating
effectiveness of related key controls during subsequent periods. The Company
does not believe that the Enertia implementation has had an adverse effect on
its internal control over financial reporting.
There were no other changes to our internal control over financial reporting
during the three and six months ended June 30, 2020 that have materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
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