CALLON PETROLEUM COMPANY A discussion and analysis of the Company's financial condition and results of operations for the year endedDecember 31, 2017 can be found in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of its Annual Report on Form 10-K for the year endedDecember 31, 2018 , which was filed with theSEC onFebruary 27, 2019 and is incorporated herein by reference. General The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. 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 2019 Annual Report on Form 10-K. We are an independent oil and natural gas company incorporated in theState of Delaware in 1994, but our roots go back nearly 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 theMidland and Delaware Basins, both of which are part of the larger Permian Basis inWest Texas . In 2019, though our acquisition of Carrizo, we doubled our core acreage position in theDelaware Basin and entered theEagle Ford Shale . 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 acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Overview Significant Accomplishments in 2019 • OnDecember 20, 2019 , we completed the Carrizo Acquisition which increased
our portfolio to: (i) over 116,000 net acres in the
doubled our footprint in the
portfolio to include over 76,000 net acres in the mature, high-margin,
free cash flow generating
• In connection with the Carrizo Acquisition, we entered into the Credit
Facility, which has a maximum credit amount of $5.0 billion . As of
December 31, 2019 , the borrowing base under the Credit Facility was $2.5
billion , with an elected commitment amount of $2.0 billion .
• During 2019, we completed divestitures of non-core assets for aggregate
net proceeds of $294.4 million . In addition, we could receive cash for
settlements of our contingent consideration arrangement of up to $60.0
million if crude oil prices exceed specified thresholds for each of the
years of 2019 through 2021.
• Our total production in 2019 increased by 26% to 15.1 MMBoe (77% oil) as
compared to 2018.
• On
• For the year ended
horizontal wells, completed 55 gross (47.1 net) horizontal wells and had,
as of
completion.
• Estimated proved reserves as of December 31, 2019 were 540.0 MMBoe (64%
oil), with 43% classified as proved developed.
Reserves Growth
As of December 31, 2019 , our estimated proved reserves increased 126% to 540.0
MMBoe compared to 238.5 MMBoe of estimated proved reserves at year-end 2018. Our
significant growth in proved reserves was primarily attributable to the Carrizo
Acquisition, along with our horizontal development efforts. Our estimated proved
reserves at year-end 2019 and 2018 were 64% and 76% oil, respectively.
43
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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:
?
Years Ended December 31,
2019 (1) 2018 $ Change % Change
Total production (2)
Oil (MBbls) 11,665 9,443 2,222 24 %
Natural gas (MMcf) 19,718 15,447 4,271 28 %
NGLs (MBbls) 135 - 135 100 %
Total barrels of oil equivalent (MBoe) 15,086 12,018 3,068 26 %
Total daily production (Boe/d) 41,331 32,926 8,405 26 %
Oil as % of total daily production 77 % 79 %
Average realized sales price (excluding
impact of settled derivatives)
Oil (per Bbl) $54.27 $56.22 ($1.95 ) (3 %)
Natural gas (per Mcf) 1.85 3.67 (1.82 ) (50 %)
NGLs (per Bbl) 15.37 - 15.37 100 %
Total (per Boe) 44.52 48.90 (4.38 ) (9 %)
Average realized sales price (including
impact of settled derivatives)
Oil (per Bbl) $53.31 $53.31 $- - %
Natural gas (per Mcf) 2.22 3.69 (1.47 ) (40 %)
NGLs (per Bbl) 15.37 - 15.37 100 %
Total (per Boe) 44.27 46.63 (2.36 ) (5 %)
Revenues (in thousands)
Oil $633,107 $530,898 $102,209 19 %
Natural gas 36,390 56,726 (20,336 ) (36 %)
NGLs 2,075 - 2,075 100 %
Total revenues $671,572 $587,624 $83,948 14 %
Additional per Boe data
Lease operating expense (3) 6.09 5.76 0.33 6 %
Production taxes 2.83 2.98 (0.15 ) (5 %)
Benchmark prices(4)
WTI (per Bbl) $56.98 $65.23 ($8.25 ) (13 %)
Henry Hub (per Mcf) 2.56 3.15 (0.59 ) (19 %)
(1) Includes activity from the Carrizo Acquisition subsequent to the
2019 closing date.
(2) The production associated with reserves acquired in the Carrizo Acquisition
are presented on a three-stream basis and include NGLs, whereas, all other
reserve volumes are on a two-stream basis.
(3) Excludes gathering and treating expense.
(4) Reflects calendar average daily spot market prices.
44--------------------------------------------------------------------------------
Revenues
The following table is intended to reconcile the change in oil, natural gas,
NGLs, and total revenue for the period presented by reflecting the effect of
changes in volume and in the underlying commodity prices.
Oil Natural Gas NGLs Total
(In thousands)
Revenues for the year ended December 31, 2018$530,898 $56,726 $-$587,624 Volume increase (decrease) 124,869 15,683 2,075 142,627 Price increase (decrease) (22,660 ) (36,019 ) - (58,679 ) Net increase (decrease) 102,209 (20,336 ) 2,075 83,948 Revenues for the year ended December 31, 2019 (1)(2)$633,107 $36,390 $2,075 $671,572
(1) Includes activity from the Carrizo Acquisition subsequent to the
2019 closing date.
(2) The revenues associated with production from reserves acquired in the Carrizo
Acquisition are presented on a three-stream basis and include NGLs, whereas,
all other revenue is presented on a two-stream basis.
Commodity Prices The prices for oil, natural gas, and NGLs remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions byOPEC and other countries and government actions. 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 Credit Facility; and
• the value of our oil and natural gas properties.
Oil revenue For the year endedDecember 31, 2019 , oil revenues of$633.1 million increased$102.2 million , or 19%, compared to revenues of$530.9 million for the year endedDecember 31, 2018 . The increase in oil revenue was primarily attributable to a 24% increase in production, partially offset by a 3% decrease in the average realized sales price, which declined to$54.27 per Bbl from$56.22 per Bbl. The increase in production was comprised of 3.2 MMBbls attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells. Natural gas revenue Natural gas revenues decreased$20.3 million , or 36%, during the year endedDecember 31, 2019 to$36.4 million as compared to$56.7 million for the year endedDecember 31, 2018 . The decrease primarily relates to an approximate 50% decrease in the average price realized, which declined to$1.85 per Mcf from$3.67 per Mcf. The decrease was partially offset by a 28% increase in natural gas volumes. The increase in production was comprised of 4.6 Bcf attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells. NGL revenue We recognized NGL revenues of$2.1 million as a result of the recent Carrizo Acquisition. Operating Expenses ? Years Ended December 31, Per Per Total Change Boe Change 2019 Boe 2018 Boe $ % $ % (In thousands, except per Boe and % amounts) Lease operating expenses$91,827 $6.09 $69,180 $5.76 $22,647 33 %$0.33 6 % Production taxes 42,651 2.83 35,755 2.98 6,896 19 % (0.15 ) (5 %) Depreciation, depletion and amortization 240,642 15.95 182,783 15.21 57,859 32 % 0.74 5 % General and administrative 45,331 3.00 35,293 2.94 10,038 28 % 0.06 2 % Merger and integration expenses 74,363 4.93 - - 74,363 100 % 4.93 100 % Settled share-based awards 3,024 0.20 - - 3,024 100 % 0.20 100 % ? 45
-------------------------------------------------------------------------------- Lease operating expenses. These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties. Lease operating expenses for the year endedDecember 31, 2019 increased by 33% to$91.8 million compared to$69.2 million for the same period of 2018, primarily due to production volumes increasing 26%. Lease operating expense per Boe for the year endedDecember 31, 2019 increased to$6.09 compared to$5.76 for the same period of 2018 primarily due to increased non-operated activity related to previous acquisitions and workovers. Production taxes. Production taxes include severance and ad valorem taxes. In general, severance taxes are based upon current year commodity prices whereas ad valorem taxes are based upon prior year commodity prices. Severance 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. For the year endedDecember 31, 2019 , production taxes increased 19% to$42.7 million compared to$35.8 million for the same period in 2018, due to an increase in severance taxes based on higher production volumes as well as an increase in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions. On a per Boe basis, production taxes for the year endedDecember 31, 2019 decreased by 5% compared to the same period of 2018. Also, production taxes as a percentage of total revenues for the year endedDecember 31, 2019 increased to 6.4% compared to 6.1% for the same period of 2018, due to higher ad valorem taxes as a result of higher valuations of our oil and gas properties during 2019. 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 gas 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. For the year endedDecember 31, 2019 , DD&A increased 32% to$240.6 million from$182.8 million compared to the same period of 2018. The increase is primarily attributable to a 26% increase in production, as discussed above, and a 5% increase in our DD&A per Boe rate. For the year endedDecember 31, 2019 , DD&A per Boe increased to$15.95 compared to$15.21 for the same period of 2018. General and administrative, net of amounts capitalized ("G&A"). G&A for the year endedDecember 31, 2019 increased to$45.3 million compared to$35.3 million for the same period of 2018. G&A for the periods indicated include the following: Years Ended December 31, 2019 2018 $ Change % Change (In thousands, except % amounts) G&A$37,174 $28,710 $8,464 29 % Share-based compensation 7,043 6,224 819 13 % Fair value adjustments of cash-settled RSU awards 672 359 313 87 % Fair value adjustments of cash-settled stock appreciation rights 442 - 442 100 % Total G&A expenses$45,331 $35,293 $10,038 28 % Merger and integration expense. For the year endedDecember 31, 2019 , the Company incurred$74.4 million of expenses associated with the Carrizo Acquisition. See "Note 4 - Acquisitions and Divestitures" of the Notes to our Consolidated Financial Statements for additional information regarding the merger with Carrizo. Settled share-based awards. During the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in$3.0 million recorded on the consolidated statements of operations. Other Income and Expenses Years Ended December 31, 2019 2018 $ Change % Change (In thousands, except % amounts) Interest expense$81,399 $58,651 $22,748 39 % Capitalized interest (78,492 ) (56,151 ) (22,341 ) 40 % Interest expense, net of capitalized amounts 2,907 2,500 407 16 % (Gain) loss on derivative contracts$62,109 ($48,544 )
?
Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our 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
46
--------------------------------------------------------------------------------
include the amortization of deferred financing costs (including origination and
amendment fees), commitment fees and annual agency fees in interest expense.
Interest expense, net of capitalized amounts, incurred during the year
ended December 31, 2019 increased $0.4 million to $2.9 million compared to $2.5
million for the same period of 2018.
Loss on extinguishment of debt. During December 2019 , in connection with the
Carrizo Acquisition, we entered into a new credit facility and simultaneously
terminated our prior credit facility. As a result of terminating the prior
credit facility, we recorded a loss on extinguishment of debt of $4.9 million ,
which was comprised solely of the write-off of unamortized deferred financing
costs associated with the prior credit facility. See "Note 7 - Borrowings" of
the Notes to our Consolidated Financial Statements for additional information.
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.
For the year ended December 31, 2019 , the net loss on derivative contracts
was $62.1 million , compared to a $48.5 million net gain in 2018. The net
gain (loss) on derivative contracts for the periods indicated includes the
following:
?
Years Ended December 31,
2019 2018 Change
(In thousands)
Oil derivatives
Net gain (loss) on settlements ($11,188 ) ($27,510 ) Net gain (loss) on fair value adjustments (62,125 ) 72,973
(135,098 ) Total gain (loss) on oil derivatives ($73,313 )$45,463 ($118,776 ) Natural gas derivatives Net gain (loss) on settlements$7,399 $238
Net gain (loss) on fair value adjustments 1,490 2,843
(1,353 )
Total gain (loss) on natural gas derivatives $8,889 $3,081 Contingent consideration arrangements Net gain (loss) on fair value adjustments$2,315 $-
Total gain (loss) on derivative contracts (
See "Note 8 - Derivative Instruments and Hedging Activities" and "Note 9 - 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. The Company recorded income tax expense of$35.3 million for the year endedDecember 31, 2019 compared to$8.1 million for the same period of 2018. The change in income tax is primarily related to the change in the Company's tax position in the current period, as the Company no longer maintains a valuation allowance against its deferred tax assets. Current period income tax expense is comprised of both deferred federal and state income tax expense. Preferred stock dividends. Holders of our Preferred Stock were entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the$50.00 liquidation preference per share (equivalent to$5.00 per annum per share). Preferred stock dividends for the year endedDecember 31, 2019 decreased 45% to$4.0 million compared to$7.3 million in 2018. The decrease is attributable to the redemption of our preferred stock inJuly 2019 . See "Note 11 - Stockholders' Equity" of the Notes to our Consolidated Financial Statements for additional information. Loss on redemption of preferred stock. As a result of the redemption of our Preferred Stock mentioned above, we recognized an$8.3 million loss due to the excess of the$73.0 million redemption price over the$64.7 million redemption date carrying value. See "Note 11 - Stockholders' Equity" of the Notes to our Consolidated Financial Statements for additional information. 47 -------------------------------------------------------------------------------- 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, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. 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. As we pursue reserves and production growth, we regularly consider which 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 year endedDecember 31, 2019 , cash and cash equivalents decreased$2.7 million to$13.3 million compared to$16.1 million atDecember 31, 2018 . Years EndedDecember 31, 2019 2018 (In thousands) Net cash provided by operating activities$476,316
Net cash used in investing activities (388,389 )
(1,324,057 ) Net cash provided by (used in) financing activities (90,637 ) 844,459
Net change in cash and cash equivalents ($2,710 )
(
Operating activities. Net cash provided by operating activities was$476.3 million and$467.7 million for the years endedDecember 31, 2019 and 2018, respectively. The change in operating activities was predominantly attributable to the following: • An increase in revenue due to higher production volumes, offset by a decrease in realized pricing; • An offsetting increase in operating expenses as a result of higher production volumes;
• An offsetting increase in cash G&A expense due to increase personnel
costs, and;
• Changes related to timing of working capital payments and receipts.
Production, realized prices, and operating expenses are discussed below in Results of Operations. See "Note 8 - Derivative Instruments and Hedging Activities" and "Note 9 - 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. Net cash used in investing activities was$388.4 million and$1,324.1 million for the years endedDecember 31, 2019 and 2018, respectively. The change in investing activities was primarily attributable to the following: • A$285.4 million increase in proceeds received from the sale of non-core
assets as compared to the year ended
• A
• A
from our 2019 development program, focused on multi-well pads, as well as
additional investments in facilities and infrastructure.
Our investing activities, on a cash basis, include the following for the periods
indicated:
Years Ended December 31,
2019 2018 $ Change
(In thousands)
Operational expenditures $520,614 $537,514 ($16,900 )
Seismic, leasehold and other 8,984 8,555 429
Capitalized general and administrative costs 31,612 24,383
7,229
Capitalized interest 79,330 40,721
38,609
Total capital expenditures (1)$640,540 $611,173
Acquisitions$42,266 $718,793 ($676,527 ) Proceeds from the sale of assets (294,417 ) (9,009 ) (285,408 ) Additions to other assets - 3,100 (3,100 ) Total investing activities$388,389 $1,324,057 ($935,668 )
(1) Includes activity from the Carrizo Acquisition subsequent to the
2019 closing date.
48-------------------------------------------------------------------------------- On an accrual basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the year endedDecember 31, 2019 were$506.1 million . Inclusive of seismic, leasehold and other, capitalized general and administrative, and capitalized interest costs, total capital expenditures for the year endedDecember 31, 2019 were$629.7 million . General and administrative expenses and capitalized interest are discussed below in Results of Operations. See "Note 4 - Acquisitions and Divestitures" and "Note 17 - Commitments and Contingencies" of the Notes to our Consolidated Financial Statements for additional information on significant acquisitions and drilling rig leases. 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 year endedDecember 31, 2019 , net cash used in financing activities was$90.6 million compared to net cash provided by financing activities of$844.5 million during the same period of 2018. The change in net cash provided by (used in) financing activities was primarily attributable to the following: • Repayment of Carrizo's credit facility and funded the redemption of preferred stock upon closing the Carrizo Acquisition.
• Redemption of Preferred Stock for approximately
• Completed an underwritten public offering of 25.3 million shares of common
stock for total estimated net proceeds of approximately
2018.
• Issuance of Senior Notes due 2026, as defined below, for
net proceeds in 2018 in conjunction with the Delaware Asset Acquisition.
Net cash provided by (used in) financing activities includes the following for
the periods indicated:
Years Ended December 31,
2019 2018 $ Change
(In thousands)
Net borrowings on Credit Facility $1,560,400 $175,000 $1,385,400
Repayment of Prior Credit Facility (475,400 ) - (475,400 )
Repayment of Carrizo credit facility (853,549 ) - (853,549 )
Repayment of Carrizo preferred stock (220,399 ) - (220,399 )
Issuance of 6.375% Senior Notes due 2026 - 400,000 (400,000 )
Issuance of common stock - 287,988 (287,988 )
Payment of preferred stock dividends (3,997 ) (7,295 ) 3,298
Redemption of preferred stock (73,017 ) - (73,017 )
Payment of deferred financing costs (22,480 ) (9,430 ) (13,050 ) Tax withholdings related to restricted stock units (2,195 ) (1,804 )
(391 )
Net cash provided by (used in) financing activities (
See "Note 7 - Borrowings" of the Notes to our Consolidated Financial Statements for additional information about the Company's debt. See "Note 11 - Stockholders' Equity" of the Notes to our Consolidated Financial Statements for additional information about the Company's equity offerings and the redemption of our Preferred Stock. Senior Secured Credit Facility. Upon consummation of the Merger onDecember 20, 2019 , the Company terminated the Sixth Amended and Restated Credit Agreement to the Credit Facility (the "Prior Credit Facility") and entered into the credit agreement with a syndicate of lenders (the "Credit Facility"). The Credit Facility provides for interest-only payments untilDecember 20, 2024 (subject to springing maturity dates of (i)January 14, 2023 if the 6.25% Senior Notes are outstanding at such time and (ii)July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is$5.0 billion . The borrowing base under the Credit Facility 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 Credit Facility is secured by first preferred mortgages covering the Company's major producing properties. The capitalized terms which hare not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement. As ofDecember 31, 2019 , the borrowing base under the Credit Facility was$2.5 billion , with an elected commitment amount of$2.0 billion , and borrowings outstanding of$1.3 billion . The weighted average interest rate of our outstanding borrowings was 3.56%. The Company also had$17.7 million in letters of credit outstanding under the Credit Facility as ofDecember 31, 2019 . EffectiveApril 5, 2018 , the Company entered into the first amendment to the Prior Credit Facility, as defined below, which (1) increased the borrowing base to$825.0 million , (2) increased the elected commitment amount to$650.0 million , (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date toMay 25, 2023 . EffectiveSeptember 27, 2018 , the Company entered into the second amendment to the Prior Credit Facility, which (1) increased the borrowing base to$1.1 billion , (2) increase the elected commitment amount to$850.0 million , and (3) amended various covenants and terms to reflect current market trends. 49 -------------------------------------------------------------------------------- Each of the first and second amendments to the Prior Credit Facility were terminated in conjunction with the termination of the Prior Credit Facility. See "Note 7 - Borrowings" of the Notes to our Consolidated Financial Statements for additional information. Senior Notes Upon consummation of the Merger, we became successor-in-interest to the indenture governing Carrizo's 8.25% Senior Notes due 2025 (the "8.25% Senior Notes") and the 6.25% Senior Notes due 2023 (the "6.25% Senior Notes"). Both the 8.25% Senior Notes and the 6.25% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary,Callon Petroleum Operating Company , and may be guaranteed by certain future subsidiaries. The assumed Senior Notes are described below along with Callon's legacy Senior Notes. 6.375% Senior Notes. OnJune 7, 2018 , we issued$400.0 million aggregate principal amount of 6.375% Senior Notes due 2026 (the "6.375% Senior Notes"), which mature onJuly 1, 2026 and have interest payable semi-annually eachJanuary 1 andJuly 1 . The net proceeds from the offering of approximately$394.0 million , after deducting initial purchasers' discounts and estimated offering expenses, were used to fund a portion of the Delaware Asset Acquisition, described below. The 6.375% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary,Callon Petroleum Operating Company , and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 6.125% Senior Notes. OnOctober 3, 2016 , we issued$400.0 million aggregate principal amount of 6.125% Senior Notes with a maturity date ofOctober 1, 2024 and interest payable semi-annually eachApril 1 andOctober 1 . The 6.125% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary,Callon Petroleum Operating Company , and may be guaranteed by certain future subsidiaries. OnMay 19, 2017 , we issued an additional$200.0 million aggregate principal amount of 6.125% Senior Notes which, with the existing$400.0 million aggregate principal amount of 6.125% Senior Notes, are treated as a single class of notes under the indenture. 8.25% Senior Notes. The 8.25% Senior Notes have an aggregate principal amount of$250.0 million , mature onJuly 15, 2025 and have interest payable semi-annually eachJanuary 15 andJuly 15 . BeforeJuly 15, 2020 , we may, at our option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. 6.25% Senior Notes. The 6.25% Senior Notes have an aggregate principal amount of$650.0 million , mature onApril 15, 2023 and have interest payable semi-annually eachApril 15 andOctober 15 . We may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 103.125% to 100% of the principal amount onApril 15, 2021 , plus accrued and unpaid interest. See "Note 7 - Borrowings" of the Notes to our Consolidated Financial Statements for additional information about our Senior Notes. Preferred Stock. Holders of the Preferred Stock were entitled to receive, when, as and if declared by the Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the$50.00 liquidation preference per share (equivalent to$5.00 per annum per share). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Board of Directors. Preferred Stock dividends were$4.0 million and$7.3 million for the years endedDecember 31, 2019 and 2018, respectively. OnJune 18, 2019 , we announced we had given notice for the redemption (the "Redemption") of all outstanding shares of the Preferred Stock. OnJuly 18, 2019 (the "Redemption Date"), the Preferred Stock were redeemed at a redemption price equal to$50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to$0.24 per share, for a total redemption price of$50.24 per share or$73.0 million (the "Redemption Price"). We recognized an$8.3 million loss on the redemption due to the excess of the$73.0 million redemption price over the$64.7 million redemption date carrying value of the Preferred Stock. After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. See "Note 11 - Stockholders' Equity" of the Notes to our Consolidated Financial Statements for additional discussion. 50 -------------------------------------------------------------------------------- 2020 Capital Plan and Outlook Our 2020 Capital Budget has been established at$975.0 million , which includes running an average of eight to nine drilling rig sand an average of three completion crews. Approximately 10-15% of the 2020 Capital Budget is comprised of infrastructure and facilities capital. As part of our 2020 operated horizontal drilling program, we expect to drill approximately 165 gross operated wells and complete approximately 160 gross operated wells. We currently expect to direct the majority of our 2020 Capital Budget towards opportunities in thePermian Basin . 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. Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our proved reserves. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. Contractual Obligations The following table includes our current contractual obligations and purchase commitments as ofDecember 31, 2019 : Payments due by Period < 1 Year Years 2 - 3 Years 4 - 5 > 5 Years 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 Credit Facility (2) - - 1,285,000 - 1,285,000 Interest expense and other fees related to debt commitments (3) 172,821 345,642 283,218 71,625 873,306 Drilling rig leases (4) 33,441 3,249 - - 36,690 Operating leases 12,423 12,762 8,319 17,902 51,406 Delivery commitments (5) 9,563 24,417 23,970 39,298 97,248 Produced water disposal commitments (6) 14,947 26,901 5,957 1,840 49,645 Asset retirement obligations (7) 468 314 565 48,386 49,733 Other commitments 1,240 844 159 - 2,243
Total contractual obligations
(1) Includes the outstanding principal amount only.
(2) The Credit Facility has a maturity date of
springing maturity dates as discussed above. See "Note 7 - 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 of December 31, 2019 , at the applicable commitment fee
rate.
(4) Drilling rig leases represent future minimum expenditure commitments fordrilling rig services under contracts to which the Company was a party on
we are committed to pay. However, we will record our proportionate share
based on our working interest in our consolidated financial statements as
incurred. See "Note 17 - Commitments and Contingencies" of the Notes to
our Consolidated Financial Statements for additional information related
to the Company's drilling rig leases.
(5) Delivery commitments represent contractual obligations we have entered
into for certain gathering, processing and transportation service
agreements which require minimum volumes of natural gas to be delivered.
The amounts in the table above reflect the aggregate undiscounted
deficiency fees assuming no delivery of any natural gas.
(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) 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 thepolitical and regulatory environment. See "Note 14 - Asset Retirement
Obligations" of the Notes to our Consolidated Financial Statements for
additional information.
51-------------------------------------------------------------------------------- Other commitments InJuly 2019 , the Company executed a crude oil sales contract that provides dedicated capacity on a new pipeline system that originates inMidland County, Texas and will have delivery points in several locations along theGulf Coast . We will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. InJune 2019 , the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates inMidland, Texas and terminates inHouston, Texas . Subject to completion of the new pipeline system, which will have delivery points in several locations along theGulf Coast , we will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along theGulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. InJanuary 2019 , the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties inHoward andWard counties,Texas and will have delivery points in several locations along theGulf Coast , providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. InAugust 2018 , the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties inHoward andWard counties,Texas to multiple marketing points in thePermian Basin . Subject to completion of the new pipeline system, which will have delivery points in several locations along theGulf Coast , we will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along theGulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. InMarch 2018 , the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective onApril 16, 2018 for a two-year period. The agreement was amended effectiveOctober 16, 2018 to reflect updated market conditions and to extend the contract expiration date toDecember 31, 2021 . 52
-------------------------------------------------------------------------------- Summary of Critical Accounting Policies The following summarizes our critical accounting policies. See a complete list of significant accounting policies in "Note 2 - Summary of Significant Accounting Policies" of the Notes to our Consolidated Financial Statements. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of proved oil and natural gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates. Oil and natural gas properties Oil and natural gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized as oil and gas properties. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. Proceeds from the sale or disposition of evaluated and unevaluated oil and gas properties are accounted for as a reduction of evaluated oil and gas property costs, unless the sale significantly alters the relationship between capitalized costs and proved reserves in which case a gain or loss is recognized. For the years endedDecember 31, 2019 and 2018, we did not have any sales of oil and gas properties that significantly altered such relationship. Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or we determine that these costs have been impaired. We assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense. Write-down ofEvaluated Properties At the end of each quarter, the net book value of oil and gas properties, less 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 amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an write-down of evaluated oil and gas properties. A write-down recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price, held flat for the life of the production, 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 commodity derivative instruments as we elected not to meet the criteria to qualify for hedge accounting treatment. 53 --------------------------------------------------------------------------------
Details of the 12-Month Average Realized Price of crude oil for the years ended
Years Ended
2019 2018
Write-down of evaluated oil and natural gas properties (In thousands)
$- $-
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period
$58.40
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period
$53.90
Crude Oil 12-Month Average Realized Price percentage increase (decrease)
(8%) 18%
The table below presents various pricing scenarios to demonstrate the sensitivity of ourDecember 31, 2019 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as ofDecember 31, 2019 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent toDecember 31, 2019 that may require revisions to estimates of proved reserves. See also Part I, "Item 1A. Risk Factors-If oil and natural gas prices remain depressed for extended periods of time, we could be required to make significant downward adjustments to the carrying value of our oil and natural gas properties." Excess of cost Increase center ceiling (decrease) of over net book cost center value, less ceiling over net related book value, less 12-Month Average deferred related deferred Realized Prices income taxes income taxes Crude Oil Natural Gas Full Cost Pool Scenarios ($/Bbl) ($/Mcf) (In millions) (In millions) December 31, 2019 Actual$53.90 $1.55 $631 Crude Oil and Natural Gas Price SensitivityCrude Oil and Natural Gas +10%$59.47 $1.85 $1,456 $825 Crude Oil and Natural Gas -10%$48.33 $1.25 ($369 ) ($1,000 ) Crude Oil Price Sensitivity Crude Oil +10%$59.47 $1.55 $1,378 $747 Crude Oil -10%$48.33 $1.55 ($270 ) ($901 ) Natural Gas Price Sensitivity Natural Gas +10%$53.90 $1.85 $702 $71 Natural Gas -10%$53.90 $1.25 $546 ($85 ) We estimate that the first quarter of 2020 cost center ceiling will exceed the net book value, less related deferred income taxes, resulting in no write-down of evaluate oil and gas properties. This estimate of the first quarter of 2020 cost center ceiling test is based on an estimated 12-Month Average Realized Price of crude oil of$56.09 per barrel as ofMarch 31, 2020 , which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Both of these estimates assume that all other inputs and assumptions are as ofDecember 31, 2019 , other than the price of crude oil, and remain unchanged. As such, drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent toDecember 31, 2019 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling. Estimating reserves and present value of estimated future net cash flows Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include: • the prices at which the Company can sell its production in the
future. Oil, natural gas, and NGL prices are volatile, but we are required
to assume that they remain constant, using the 12-Month Average Realized
Price. In general, higher oil, natural gas, and NGL prices will increase
quantities of estimated proved reserves and the present value of estimated
future net cash flows from such reserves, while lower prices will decrease
these amounts; and
54--------------------------------------------------------------------------------
• the costs to develop and produce the Company's reserves and the costs to
dismantle its production facilities when reserves are depleted. These
costs are likely to change over time, but we are required to assume that
they remain constant. Increases in costs will reduce estimated proved
reserves and the present value of estimated future net cash flows, while
decreases in costs will increase such amounts.
Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated proved reserves for the Company's properties that have relatively short productive lives. If oil, natural gas, and NGL prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of proved reserves. In addition, the process of estimating proved oil and natural gas reserves requires that the Company's independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, "Item 1A. Risk Factors." Asset retirement obligations We record an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in "Depreciation, depletion and amortization" in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the consolidated balance sheets. See "Note 14 - Asset Retirement Obligations" of the Notes to our Consolidated Financial Statements for additional information. Estimating the future plugging and abandonment costs of wells and related facilities requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Derivative Instruments To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, put and call options and other structures) on approximately 40% to 60% of our projected production volumes in any given year. We do not use these instruments for speculative purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price. Our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see "Note 8 - Derivative Instruments and Hedging Activities" and "Note 9 - Fair Value Measurements" of the Notes to our Consolidated Financial Statements and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk". 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. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company had no valuation allowance as ofDecember 31, 2019 and 2018. See "Note 12 - Income Taxes" of the Notes to our Consolidated Financial Statements for additional information regarding income taxes. Accounting Standards Updates See "Note 2 - Summary of Significant Accounting Policies" of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by theFinancial Accounting Standards Board . Off-balance Sheet Arrangements We had no off-balance sheet arrangements as ofDecember 31, 2019 . 55
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