UNITED STATES
SECURITIES ANDEXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☒Quarterly Report Pursuant to SectionQUARTERLY REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities Exchange Act ofOF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period EndedSeptember 30, 20172019
ORor
☐Transition Report Pursuant to SectionTRANSITION REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities Exchange Act ofOF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission File Number 001-14039
Callon Petroleum Company
|
| | |
| Callon Petroleum Company
(Exact Name of Registrant as Specified in Its Charter) | |
|
| | | |
Delaware | | 64-0844345 |
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)Organization | | 64-0844345
(IRSI.R.S. Employer
Identification No.) |
| | |
200 North Canal Street
Natchez, Mississippi
(One Briarlake Plaza
| | |
2000 W. Sam Houston Parkway S., Suite 2000 | | |
Houston, | Texas | | 77042 |
Address of Principal Executive Offices)Offices | | Zip Code |
|
| | | | | | | |
| (281) | 589-5200 | |
| Registrant’s Telephone Number, Including Area Code | |
|
|
|
|
|
| | 39120
(Zip Code)
|
| Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report | |
601-442-1601
(Registrant’s Telephone Number, Including Area Code)Securities registered pursuant to Section 12(b) of the Act:
Not Applicable |
| | | | |
Title of Each Class | | Trading Symbol(s) | | Name of Each Exchange on Which Registered |
Common Stock, $0.01 par value | | CPE | | New York Stock Exchange |
(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act (check one):Act:
|
| | | | | | |
Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | (Do not check if smaller reporting company) |
| | | | | | |
Non-accelerated filer | ☐ | Smaller reporting company | ☐ | | |
| | | | | |
| | Emerging growth company | ☐ | | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The Registrant had 201,836,172228,386,100 shares of common stock outstanding as of November 1, 2017.2019.
Table of Contents
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Part I. Financial Information | |
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Item 1. Financial Statements (Unaudited) | |
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Part II. Other Information | |
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DEFINITIONS
GLOSSARY OF CERTAIN TERMS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:
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• | ARO: asset retirement obligation. |
| |
• | ASU: accounting standards update. |
| |
• | Bbl or Bbls: barrel or barrels of oil or natural gas liquids. |
| |
• | BOE: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. |
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• | Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. |
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• | Completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. |
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• | Cushing: An oil delivery point that serves as the benchmark oil price for West Texas Intermediate. |
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• | FASB: Financial Accounting Standards Board. |
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• | GAAP: Generally Accepted Accounting Principles in the United States. |
| |
• | Henry Hub: A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts. |
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• | Horizontal drilling: A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval. |
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• | LIBOR: London Interbank Offered Rate. |
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• | LOE: lease operating expense. |
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• | MBbls: thousand barrels of oil. |
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• | Mcf: thousand cubic feet of natural gas. |
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• | MEH: Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil. |
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• | MMcf: million cubic feet of natural gas. |
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• | NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. |
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• | NYMEX: New York Mercantile Exchange. |
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• | Oil: includes crude oil and condensate. |
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• | Realized price: The cash market price less all expected quality, transportation and demand adjustments. |
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• | Royalty interest: An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development. |
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• | RSU: restricted stock units. |
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• | SEC: United States Securities and Exchange Commission. |
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• | Waha: A delivery point in West Texas that serves as the benchmark for natural gas. |
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• | Working interest: An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. |
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• | WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. |
ARO: asset retirement obligation.
ASU: accounting standards update.
Bbl or Bbls: barrel or barrels of oil or natural gas liquids.
BOE: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
Cushing: An oil delivery point that serves as the benchmark oil price for West Texas Intermediate.
FASB: Financial Accounting Standards Board.
GAAP: Generally Accepted Accounting Principles in the United States.
Henry Hub: A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
LIBOR: London Interbank Offered Rate.
LOE: lease operating expense.
MBbls: thousand barrels of oil.
Mcf: thousand cubic feet of natural gas.
MMcf: million cubic feet of natural gas.
NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.
NYMEX: New York Mercantile Exchange.
Oil: includes crude oil and condensate.
Realized price: The cash market price less all expected quality, transportation and demand adjustments.
SEC: United States Securities and Exchange Commission.
WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.
Part I. Financial Information
Item I.1. Financial Statements
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)
| | | September 30, 2017 | | December 31, 2016 | | September 30, 2019 | | December 31, 2018 |
ASSETS | Unaudited | | | | Unaudited | | |
Current assets: | | | | | | | |
Cash and cash equivalents | $ | 61,609 |
| | $ | 652,993 |
| | $ | 11,309 |
| | $ | 16,051 |
|
Accounts receivable | 81,973 |
| | 69,783 |
| | 114,120 |
| | 131,720 |
|
Fair value of derivatives | 3,333 |
| | 103 |
| | 25,032 |
| | 65,114 |
|
Other current assets | 2,583 |
| | 2,247 |
| | 14,912 |
| | 9,740 |
|
Total current assets | 149,498 |
| | 725,126 |
| | 165,373 |
| | 222,625 |
|
Oil and natural gas properties, full cost accounting method: | | | | | | | |
Evaluated properties | 3,283,985 |
| | 2,754,353 |
| | 4,830,499 |
| | 4,585,020 |
|
Less accumulated depreciation, depletion, amortization and impairment | (2,026,809 | ) | | (1,947,673 | ) | | (2,458,026 | ) | | (2,270,675 | ) |
Net evaluated oil and natural gas properties | 1,257,176 |
| | 806,680 |
| |
Evaluated oil and natural gas properties, net | | | 2,372,473 |
| | 2,314,345 |
|
Unevaluated properties | 1,173,614 |
| | 668,721 |
| | 1,405,993 |
| | 1,404,513 |
|
Total oil and natural gas properties | 2,430,790 |
| | 1,475,401 |
| |
Total oil and natural gas properties, net | | | 3,778,466 |
| | 3,718,858 |
|
Operating lease right-of-use assets | | | 24,447 |
| | — |
|
Other property and equipment, net | 18,626 |
| | 14,114 |
| | 24,770 |
| | 21,901 |
|
Restricted investments | 3,362 |
| | 3,332 |
| | 3,490 |
| | 3,424 |
|
Deferred financing costs | 5,209 |
| | 3,092 |
| | 5,081 |
| | 6,087 |
|
Fair value of derivatives | 1,121 |
| | — |
| | 11,209 |
| | — |
|
Acquisition deposit | — |
| | 46,138 |
| |
Prepaid | 4,650 |
| | — |
| |
Other assets, net | 827 |
| | 384 |
| | 4,087 |
| | 6,278 |
|
Total assets | $ | 2,614,083 |
| | $ | 2,267,587 |
| | $ | 4,016,923 |
| | $ | 3,979,173 |
|
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | |
Current liabilities: | | | | | | | |
Accounts payable and accrued liabilities | $ | 147,338 |
| | $ | 95,577 |
| | $ | 243,481 |
| | $ | 261,184 |
|
Operating lease liabilities | | | 19,196 |
| | — |
|
Accrued interest | 18,375 |
| | 6,057 |
| | 25,660 |
| | 24,665 |
|
Cash-settleable restricted stock unit awards | 4,158 |
| | 8,919 |
| | 535 |
| | 1,390 |
|
Asset retirement obligations | 1,841 |
| | 2,729 |
| | 1,250 |
| | 3,887 |
|
Fair value of derivatives | 6,380 |
| | 18,268 |
| | 8,941 |
| | 10,480 |
|
Other current liabilities | | | 1,948 |
| | 13,310 |
|
Total current liabilities | 178,092 |
| | 131,550 |
| | 301,011 |
| | 314,916 |
|
Senior secured revolving credit facility | — |
| | — |
| | 200,000 |
| | 200,000 |
|
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs | 595,115 |
| | 390,219 |
| |
6.125% senior unsecured notes due 2024 | | | 596,337 |
| | 595,788 |
|
6.375% senior unsecured notes due 2026 | | | 394,317 |
| | 393,685 |
|
Operating lease liabilities | | | 4,995 |
| | — |
|
Asset retirement obligations | 3,163 |
| | 3,932 |
| | 8,294 |
| | 10,405 |
|
Cash-settleable restricted stock unit awards | 2,626 |
| | 8,071 |
| | 1,737 |
| | 2,067 |
|
Deferred tax liability | 1,158 |
| | 90 |
| | 39,007 |
| | 9,564 |
|
Fair value of derivatives | 659 |
| | 28 |
| | 2,573 |
| | 7,440 |
|
Other long-term liabilities | 405 |
| | 295 |
| | — |
| | 100 |
|
Total liabilities | 781,218 |
| | 534,185 |
| | 1,548,271 |
| | 1,533,965 |
|
Commitments and contingencies |
| |
| |
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Stockholders’ equity: | | | | | | | |
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 1,458,948 shares outstanding | 15 |
| | 15 |
| |
Common stock, $0.01 par value, 300,000,000 shares authorized; 201,827,995 and 201,041,320 shares outstanding, respectively | 2,018 |
| | 2,010 |
| |
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 0 and 1,458,948 shares outstanding, respectively | | | — |
| | 15 |
|
Common stock, $0.01 par value, 300,000,000 shares authorized; 228,372,081 and 227,582,575 shares outstanding, respectively | | | 2,284 |
| | 2,276 |
|
Capital in excess of par value | 2,179,258 |
| | 2,171,514 |
| | 2,421,559 |
| | 2,477,278 |
|
Accumulated deficit | (348,426 | ) | | (440,137 | ) | |
Retained earnings (accumulated deficit) | | | 44,809 |
| | (34,361 | ) |
Total stockholders’ equity | 1,832,865 |
| | 1,733,402 |
| | 2,468,652 |
| | 2,445,208 |
|
Total liabilities and stockholders’ equity | $ | 2,614,083 |
| | $ | 2,267,587 |
| | $ | 4,016,923 |
| | $ | 3,979,173 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited; in thousands, except per share data)
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 | 2019 | | 2018 | | 2019 | | 2018 |
Operating revenues: | | | | | | | | | | | | | | |
Oil sales | $ | 73,349 |
| | $ | 49,095 |
| | $ | 218,242 |
| | $ | 117,093 |
| $ | 148,210 |
| | $ | 142,601 |
| | $ | 450,036 |
| | $ | 380,500 |
|
Natural gas sales | 11,265 |
| | 6,832 |
| | 30,019 |
| | 14,677 |
| 7,168 |
| | 18,613 |
| | 25,441 |
| | 45,229 |
|
Total operating revenues | 84,614 |
| | 55,927 |
| | 248,261 |
| | 131,770 |
| 155,378 |
| | 161,214 |
| | 475,477 |
| | 425,729 |
|
Operating expenses: | | | | | | | | | | | | | | |
Lease operating expenses | 11,624 |
| | 9,961 |
| | 36,708 |
| | 24,229 |
| 19,668 |
| | 18,525 |
| | 66,511 |
| | 44,705 |
|
Production taxes | 5,444 |
| | 3,478 |
| | 16,168 |
| | 8,153 |
| 11,866 |
| | 10,263 |
| | 33,810 |
| | 26,265 |
|
Depreciation, depletion and amortization | 28,525 |
| | 17,303 |
| | 79,172 |
| | 49,318 |
| 56,002 |
| | 48,257 |
| | 178,690 |
| | 122,407 |
|
General and administrative | 7,259 |
| | 7,891 |
| | 18,894 |
| | 19,755 |
| 9,388 |
| | 9,721 |
| | 31,705 |
| | 26,779 |
|
Merger and integration expense | | 5,943 |
| | — |
| | 5,943 |
| | — |
|
Settled share-based awards | — |
| | — |
| | 6,351 |
| | — |
| — |
| | — |
| | 3,024 |
| | — |
|
Accretion expense | 131 |
| | 187 |
| | 523 |
| | 762 |
| 128 |
| | 202 |
| | 585 |
| | 626 |
|
Write-down of oil and natural gas properties | — |
| | — |
| | — |
| | 95,788 |
| |
Acquisition expense | 205 |
| | 456 |
| | 3,027 |
| | 2,410 |
| |
Other operating expense | | (161 | ) | | 1,435 |
| | 931 |
| | 3,750 |
|
Total operating expenses | 53,188 |
| | 39,276 |
| | 160,843 |
| | 200,415 |
| 102,834 |
| | 88,403 |
| | 321,199 |
| | 224,532 |
|
Income (loss) from operations | 31,426 |
| | 16,651 |
| | 87,418 |
| | (68,645 | ) | |
Income from operations | | 52,544 |
| | 72,811 |
| | 154,278 |
| | 201,197 |
|
Other (income) expenses: | | | | | | | | | | | | | | |
Interest expense, net of capitalized amounts | 444 |
| | 831 |
| | 1,698 |
| | 10,502 |
| 739 |
| | 711 |
| | 2,218 |
| | 1,765 |
|
(Gain) loss on derivative contracts | 14,162 |
| | (5,135 | ) | | (11,636 | ) | | 11,281 |
| (21,809 | ) | | 34,339 |
| | 31,415 |
| | 55,374 |
|
Other income | (498 | ) | | (122 | ) | | (1,270 | ) | | (299 | ) | (122 | ) | | (1,657 | ) | | (270 | ) | | (2,571 | ) |
Total other (income) expense | 14,108 |
| | (4,426 | ) | | (11,208 | ) | | 21,484 |
| (21,192 | ) | | 33,393 |
| | 33,363 |
| | 54,568 |
|
Income (loss) before income taxes | 17,318 |
| | 21,077 |
| | 98,626 |
| | (90,129 | ) | |
Income tax (benefit) expense | 237 |
| | (62 | ) | | 1,026 |
| | (62 | ) | |
Net income (loss) | 17,081 |
| | 21,139 |
| | 97,600 |
| | (90,067 | ) | |
Income before income taxes | | 73,736 |
| | 39,418 |
| | 120,915 |
| | 146,629 |
|
Income tax expense | | 17,902 |
| | 1,487 |
| | 29,444 |
| | 2,463 |
|
Net income | | 55,834 |
| | 37,931 |
| | 91,471 |
| | 144,166 |
|
Preferred stock dividends | (1,824 | ) | | (1,824 | ) | | (5,471 | ) | | (5,471 | ) | (350 | ) | | (1,823 | ) | | (3,997 | ) | | (5,471 | ) |
Income (loss) available to common stockholders | $ | 15,257 |
| | $ | 19,315 |
| | $ | 92,129 |
| | $ | (95,538 | ) | |
Income (loss) per common share: | | | | | | | | |
Loss on redemption of preferred stock | | (8,304 | ) | | — |
| | (8,304 | ) | | — |
|
Income available to common stockholders | | $ | 47,180 |
| | $ | 36,108 |
| | $ | 79,170 |
| | $ | 138,695 |
|
Income per common share: | | | | | | | | |
Basic | $ | 0.08 |
| | $ | 0.14 |
| | $ | 0.46 |
| | $ | (0.85 | ) | $ | 0.21 |
| | $ | 0.16 |
| | $ | 0.35 |
| | $ | 0.65 |
|
Diluted | $ | 0.08 |
| | $ | 0.14 |
| | $ | 0.46 |
| | $ | (0.85 | ) | $ | 0.21 |
| | $ | 0.16 |
| | $ | 0.35 |
| | $ | 0.65 |
|
Shares used in computing income (loss) per common share: | | | | | | | |
Weighted average common shares outstanding: | | | | | | | | |
Basic | 201,827 |
| | 136,983 |
| | 201,422 |
| | 112,925 |
| 228,322 |
| | 227,564 |
| | 228,054 |
| | 213,409 |
|
Diluted | 202,337 |
| | 137,483 |
| | 201,995 |
| | 112,925 |
| 228,469 |
| | 228,140 |
| | 228,557 |
| | 214,079 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
| | | Nine Months Ended September 30, | | | | | |
| 2017 | | 2016 | Nine Months Ended September 30, |
Cash flows from operating activities: | | | | 2019 | | 2018 |
Net income (loss) | $ | 97,600 |
| | $ | (90,067 | ) | |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | | | | |
Net income | | $ | 91,471 |
| | $ | 144,166 |
|
Adjustments to reconcile net income to cash provided by operating activities: | | | | |
Depreciation, depletion and amortization | 80,829 |
| | 50,560 |
| 182,153 |
| | 124,430 |
|
Write-down of oil and natural gas properties | — |
| | 95,788 |
| |
Accretion expense | 523 |
| | 762 |
| 585 |
| | 626 |
|
Amortization of non-cash debt related items | 1,695 |
| | 2,371 |
| 2,218 |
| | 1,749 |
|
Deferred income tax (benefit) expense | 1,026 |
| | (62 | ) | |
Net (gain) loss on derivatives, net of settlements | (15,608 | ) | | 27,105 |
| |
Loss on sale of other property and equipment | 62 |
| | — |
| |
Deferred income tax expense | | 29,444 |
| | 2,463 |
|
Loss on derivatives, net of settlements | | 30,979 |
| | 29,696 |
|
(Gain) loss on sale of other property and equipment | | 36 |
| | (80 | ) |
Non-cash expense related to equity share-based awards | 7,014 |
| | 1,954 |
| 7,868 |
| | 4,466 |
|
Change in the fair value of liability share-based awards | 2,423 |
| | 6,045 |
| 106 |
| | 1,428 |
|
Payments to settle asset retirement obligations | (1,831 | ) | | (895 | ) | (1,425 | ) | | (1,080 | ) |
Payments for cash-settled restricted stock unit awards | | (1,425 | ) | | (4,990 | ) |
Changes in current assets and liabilities: | | | | | | |
Accounts receivable | (12,148 | ) | | (16,444 | ) | 17,600 |
| | (54,384 | ) |
Other current assets | (336 | ) | | (251 | ) | (5,172 | ) | | (1,665 | ) |
Current liabilities | 7,534 |
| | 19,815 |
| (13,038 | ) | | 64,801 |
|
Change in other long-term liabilities | 121 |
| | 86 |
| |
Change in long-term prepaid | (4,650 | ) | | — |
| |
Change in other assets, net | (1,376 | ) | | (1,671 | ) | |
Payments to settle vested liability share-based awards | (13,173 | ) | | (10,300 | ) | |
Other | | (2,662 | ) | | 4,389 |
|
Net cash provided by operating activities | 149,705 |
| | 84,796 |
| 338,738 |
| | 316,015 |
|
Cash flows from investing activities: | | | | | | |
Capital expenditures | (267,218 | ) | | (122,698 | ) | (503,425 | ) | | (455,352 | ) |
Acquisitions | (714,504 | ) | | (302,057 | ) | (40,788 | ) | | (595,984 | ) |
Acquisition deposit | 46,138 |
| | (32,700 | ) | |
Proceeds from sales of mineral interests and equipment | — |
| | 22,923 |
| |
Proceeds from sale of assets | | 279,952 |
| | 8,326 |
|
Net cash used in investing activities | (935,584 | ) | | (434,532 | ) | (264,261 | ) | | (1,043,010 | ) |
Cash flows from financing activities: | | | | | | |
Borrowings on senior secured revolving credit facility | — |
| | 217,000 |
| 581,000 |
| | 270,000 |
|
Payments on senior secured revolving credit facility | — |
| | (257,000 | ) | (581,000 | ) | | (230,000 | ) |
Issuance of 6.125% senior unsecured notes due 2024 | 200,000 |
| | — |
| |
Premium on the issuance of 6.125% senior unsecured notes due 2024 | 8,250 |
| | — |
| |
Issuance of 6.375% senior unsecured notes due 2026 | | — |
| | 400,000 |
|
Issuance of common stock | — |
| | 722,715 |
| — |
| | 288,364 |
|
Payment of preferred stock dividends | (5,471 | ) | | (5,471 | ) | (3,997 | ) | | (5,471 | ) |
Payment of deferred financing costs | (7,166 | ) | | (640 | ) | (31 | ) | | (9,960 | ) |
Tax withholdings related to restricted stock units | (1,118 | ) | | (2,207 | ) | (2,174 | ) | | (1,804 | ) |
Net cash provided by financing activities | 194,495 |
| | 674,397 |
| |
Redemption of preferred stock | | (73,017 | ) | | — |
|
Net cash provided by (used in) financing activities | | (79,219 | ) | | 711,129 |
|
Net change in cash and cash equivalents | (591,384 | ) | | 324,661 |
| (4,742 | ) | | (15,866 | ) |
Balance, beginning of period | 652,993 |
| | 1,224 |
| 16,051 |
| | 27,995 |
|
Balance, end of period | $ | 61,609 |
| | $ | 325,885 |
| $ | 11,309 |
| | $ | 12,129 |
|
| | | | |
Supplemental cash flow information: | | | | |
Interest paid, net of capitalized amounts | | $ | — |
| | $ | — |
|
Income taxes paid | | — |
| | — |
|
Cash paid for amounts included in the measurement of lease liabilities: | | | | |
Operating cash flows from operating leases | | 1,667 |
| | — |
|
Investing cash flows from operating leases | | 25,455 |
| | — |
|
Non-cash investing and financing activities: | | | | |
Change in accrued capital expenditures | | $ | (15,032 | ) | | $ | 42,062 |
|
Change in asset retirement costs | | (393 | ) | | 4,847 |
|
Right-of-use assets obtained in exchange for operating lease liabilities | | 2,588 |
| | — |
|
Contingent consideration arrangement | | 8,512 |
| | — |
|
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(Unaudited; in thousands)
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Retained | | |
| Preferred | | Common | | Capital in | | Earnings | | Total |
| Stock | | Stock | | Excess | | (Accumulated | | Stockholders' |
| Shares | | $ | | Shares | | $ | | of Par | | Deficit) | | Equity |
Balance at 12/31/2018 | 1,459 |
| | $ | 15 |
| | 227,583 |
| | $ | 2,276 |
| | $ | 2,477,278 |
| | $ | (34,361 | ) | | $ | 2,445,208 |
|
Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (19,543 | ) | | (19,543 | ) |
Shares issued pursuant to employee benefit plans | — |
| | — |
| | 24 |
| | — |
| | 154 |
| | — |
| | 154 |
|
Restricted stock | — |
| | — |
| | 277 |
| | 3 |
| | 4,447 |
| | — |
| | 4,450 |
|
Preferred stock dividend ($1.25 per share) | — |
| | — |
| | — |
| | — |
| | — |
| | (1,824 | ) | | (1,824 | ) |
Balance at 03/31/2019 | 1,459 |
| | $ | 15 |
| | 227,884 |
| | $ | 2,279 |
| | $ | 2,481,879 |
| | $ | (55,728 | ) | | $ | 2,428,445 |
|
Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 55,180 |
| | 55,180 |
|
Restricted stock | — |
| | — |
| | 380 |
| | 4 |
| | 2,071 |
| | — |
| | 2,075 |
|
Preferred stock dividend ($1.25 per share) | — |
| | — |
| | — |
| | — |
| | — |
| | (1,823 | ) | | (1,823 | ) |
Preferred stock redemption costs | — |
| | — |
| | — |
| | — |
| | (5 | ) | | — |
| | (5 | ) |
Balance at 06/30/2019 | 1,459 |
| | $ | 15 |
| | 228,264 |
| | $ | 2,283 |
| | $ | 2,483,945 |
| | $ | (2,371 | ) | | $ | 2,483,872 |
|
Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 55,834 |
| | 55,834 |
|
Restricted stock | — |
| | — |
| | 108 |
| | 1 |
| | 2,307 |
| | — |
| | 2,308 |
|
Preferred stock dividend ($0.24 per share) | — |
| | — |
| | — |
| | — |
| | — |
| | (350 | ) | | (350 | ) |
Preferred stock redemption | (1,459 | ) | | (15 | ) | | — |
| | — |
| | (64,693 | ) | | — |
| | (64,708 | ) |
Loss on redemption of preferred stock | — |
| | — |
| | — |
| | — |
| | — |
| | (8,304 | ) | | (8,304 | ) |
Balance at 09/30/2019 | — |
| | $ | — |
| | 228,372 |
| | $ | 2,284 |
| | $ | 2,421,559 |
| | $ | 44,809 |
| | $ | 2,468,652 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Preferred | | Common | | Capital in | | | | Total |
| Stock | | Stock | | Excess | | Accumulated | | Stockholders' |
| Shares | | $ | | Shares | | $ | | of Par | | Deficit | | Equity |
Balance at 12/31/2017 | 1,459 |
| | $ | 15 |
| | 201,836 |
| | $ | 2,018 |
| | $ | 2,181,359 |
| | $ | (327,426 | ) | | $ | 1,855,966 |
|
Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 55,761 |
| | 55,761 |
|
Shares issued pursuant to employee benefit plans | — |
| | — |
| | 7 |
| | — |
| | 88 |
| | — |
| | 88 |
|
Restricted stock | — |
| | — |
| | 105 |
| | 1 |
| | 1,152 |
| | — |
| | 1,153 |
|
Preferred stock dividend ($1.25 per share) | — |
| | — |
| | — |
| | — |
| | — |
| | (1,824 | ) | | (1,824 | ) |
Balance at 03/31/2018 | 1,459 |
| | $ | 15 |
| | 201,948 |
| | $ | 2,019 |
| | $ | 2,182,599 |
| | $ | (273,489 | ) | | $ | 1,911,144 |
|
Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 50,474 |
| | 50,474 |
|
Shares issued pursuant to employee benefit plans | — |
| | — |
| | 11 |
| | — |
| | 141 |
| | — |
| | 141 |
|
Restricted stock | — |
| | — |
| | 248 |
| | 3 |
| | 1,312 |
| | — |
| | 1,315 |
|
Common stock issued | — |
| | — |
| | 25,300 |
| | 253 |
| | 288,103 |
| | — |
| | 288,356 |
|
Preferred stock dividend ($1.25 per share) | — |
| | — |
| | — |
| | — |
| | — |
| | (1,824 | ) | | (1,824 | ) |
Balance at 06/30/2018 | 1,459 |
| | $ | 15 |
| | 227,507 |
| | $ | 2,275 |
| | $ | 2,472,155 |
| | $ | (224,837 | ) | | $ | 2,249,608 |
|
Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 37,931 |
| | 37,931 |
|
Shares issued pursuant to employee benefit plans | — |
| | — |
| | 12 |
| | — |
| | 131 |
| | — |
| | 131 |
|
Restricted stock | — |
| | — |
| | 49 |
| | 1 |
| | 2,454 |
| | — |
| | 2,455 |
|
Common stock issued | — |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | 8 |
|
Preferred stock dividend ($1.25 per share) | — |
| | — |
| | — |
| | — |
| | — |
| | (1,823 | ) | | (1,823 | ) |
Balance at 09/30/2018 | 1,459 |
| | $ | 15 |
| | 227,568 |
| | $ | 2,276 |
| | $ | 2,474,748 |
| | $ | (188,731 | ) | | $ | 2,288,308 |
|
The accompanying notes are an integral part of these consolidated financial statements.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTSIndex to the Notes to the Consolidated Financial Statements
| | | Description of Business and Basis of Presentation | | Fair Value Measurements | | 8. | |
| Acquisitions | | Income Taxes | | 9. | |
| Earnings Per Share | | Asset Retirement Obligations | | 10. | |
| Borrowings | | Equity Transactions | | 11. | |
| Derivative Instruments and Hedging Activities | | Other | | 12. | |
6. | | | 13. | |
7. | | | |
Note 1 - Description of Business and Basis of Presentation
Description of business
Callon Petroleum Company is an independenthas been engaged in the development, acquisition and production of oil and natural gas company established inproperties since 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. We were incorporated in the state of Delaware in 1994.
Callon is focused on the acquisition development, exploration and exploitationdevelopment of unconventional onshore oil and natural gas reserves in the Permian Basin. The Company’s operations to datePermian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have been predominantly focused on the horizontal development of several prospective intervals, including multiple levels ofMidland Basin and entered the Wolfcamp formation andDelaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Lower Spraberry shales. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventoryDelaware Basin through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions leasing programs, acreage purchases, joint ventures and asset swaps. in 2018.
Basis of presentation
Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data.
The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries,a subsidiary, namely Mississippi Marketing, Inc. Effective February 28, 2019, Callon Offshore Production, Inc. was merged with and Mississippi Marketing, Inc.into CPOC.
These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.2018. The balance sheet at December 31, 20162018 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2017.2019.
In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may have been reclassified to conform to current year presentation.
Accounting Standards Updates (“ASUs”)
Recently issued accounting policiesadopted ASUs - Leases
In May 2014,February 2016, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2014-09”2016-02”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015,January 2018, the FASB issued ASU No. 2015-14, deferring2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the effective dateFASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).
ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of ASU 2014-09 by one year. As a result,12 months) on the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption.
balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company has substantially completedengaged a third-party consultant to assist with assessing its assessment of the adoption of this standard on its revenue-related contracts. The Company currently recognizes revenue under the entitlements method of accounting,existing contracts, as well as future potential contracts, and to date, has not identified any contracts that would require a change from the entitlements method. The Company continues to evaluatedetermine the impact of the standard’s provisions regarding gross-versus-net presentation. To date, the Company has not identified any material impact that the new standard will haveits application on the Company’sits consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases,
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
Consolidated Financial Statements withcompressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.
The new standard was effective for us in the exceptionfirst quarter of new disclosures. The Company intends to adopt2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2018 using2019. Consequently, upon transition, we recognized the modified retrospective methodcumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the datefollowing:
Whether any expired or existing contracts were or contained leases;
The lease classification for any expired or existing leases; and
Initial direct costs for any existing leases.
Additionally, we elected the practical expedient under ASU 2018-01, which did not require us to evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. We also chose not to separate lease and non-lease components for the various classes of adoption.underlying assets. In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases. Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term.
Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on our consolidated balance sheet at September 30, 2019, resulting from the recognition during the current period of right-of-use assets and lease liabilities for operating leases. We have no leases that meet the criteria for classification as a finance lease. We lease certain office space, office equipment, production facilities, compressors, drilling rigs, vehicles and other ancillary drilling equipment under cancelable and non-cancelable leases to support our operations. See Note 10 for additional information regarding the impact of adoption of the new leases standard on our current period results.
Adoption of the new leases standard did not impact our consolidated statement of operations or cash provided from or used in operating, investing or financing in our consolidated statement of cash flows.
We note that the standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.
Recently adopted accounting policiesASUs - Other
In March 2016,June 2018, the FASB issued ASU No. 2016-09, 2018-07, Compensation –- Stock Compensation (Topic 718): Improvements to EmployeeNonemployee Share-Based Payment Accounting (“ASU 2016-09”2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the income tax consequences, classificationtiming and measurement of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein.nonemployee awards. The Company adopted this ASUupdate on January 1, 20172019 and it did not have a material impact on its consolidated financial statements. The Company has elected to no longer estimate forfeitures.statements upon adoption of this guidance.
Note 2 - Acquisitions Revenue Recognition
Acquisitions were accountedRevenue from contracts with customers
Oil sales
Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.
Natural gas sales
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for under the acquisition methodresulting sale of accounting, which involves determiningnatural gas. The Company’s share of revenue received from the fair valuesale of NGLs is included in the natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of operating revenues. For the three and nine months ended September 30, 2019, $2,566 and $7,779 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively. For the three and nine months ended September 30, 2018,
|
| | |
| Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
$2,209 and $5,413 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively.
Accounts receivable from revenues from contracts with customers
Net accounts receivable include amounts billed and currently due from revenue contracts with customers related to our oil and natural gas production, which had a balance at September 30, 2019 and December 31, 2018 of $83,442 and $87,061, respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from the sale of oil and natural gas are included in accounts receivable on the consolidated balance sheets.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
Note 3 - Acquisitions and Dispositions
2019 Acquisitions and Dispositions
In the second quarter of 2019, the Company completed its divestiture of certain non-core assets acquiredin the southern Midland Basin (the “Ranger Asset Divestiture”) for net cash proceeds received at closing of $244,935, including customary purchase price adjustments. The transaction also provides for potential contingent consideration in payments of up to $60,000 based on West Texas Intermediate average annual pricing over a three-year period (see Notes 6 and liabilities assumed under7 for additional information regarding the income approach.contingent consideration payments). The divestiture encompasses the Ranger operating area in the southern Midland Basin which includes approximately 9,850 net Wolfcamp acres with an average 66% working interest. The divestiture did not significantly alter the relationship between capitalized costs and proved reserves, and as such, net cash proceeds and contingent consideration were recorded as adjustments to our full cost pool with no gain or loss recognized.
2017In the first quarter of 2019, the Company completed various acquisitions and dispositions of additional working interests and acreage located in our existing core operating areas within the Permian Basin. The Company purchased mineral rights for $21,407 in the Spur operating area and received proceeds of $14,084, including customary purchase price adjustments, for certain leasehold interests in our WildHorse acreage. In the second quarter of 2019, the Company completed various acreage swaps in the Permian Basin and received proceeds of $19,108, including customary purchase price adjustments, for certain working interests in our Spur acreage.
|
| | |
| Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
2018 Acquisitions
On February 13, 2017,August 31, 2018, the Company completed the acquisition of 29,175 gross (16,688 net)approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC,Cimarex Energy Company, for total cash consideration of $646,559, excluding$539,519, including customary purchase price adjustments (the “Ameredev Transaction”“Delaware Asset Acquisition”). The Company fundedissued debt and equity to fund, in part, the cash purchase price with the net proceeds of an equity offering (see NoteDelaware Asset Acquisition. See Notes 5 and 9 for additional information regarding the Company’s debt obligations and equity offering). The Company obtained an 82% average working interest in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016.offerings. The following table summarizes the estimated acquisition date fair values of the acquisition:
|
| | | |
Evaluated oil and natural gas properties | $ | 253,089 |
|
Unevaluated oil and natural gas properties | 287,000 |
|
Asset retirement obligations | (570 | ) |
Net assets acquired | $ | 539,519 |
|
|
| | | |
Evaluated oil and natural gas properties | $ | 137,368 |
|
Unevaluated oil and natural gas properties | 509,359 |
|
Asset retirement obligations | (168 | ) |
Net assets acquired | $ | 646,559 |
|
The preliminary purchase price allocation is subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.
On June 5, 2017,In addition, the Company completed the acquisitionvarious acquisitions of 7,031 gross (2,488 net) acresadditional working interests and mineral rights, and associated production volumes, in the Delaware Basin, located nearCompany’s existing core operating areas within the acreage acquired inPermian Basin. In the Ameredev Transaction discussed above,first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for total cash consideration of $52,500, excluding$37,770, including customary purchase price adjustments. The Company fundedIn the cash purchase price with its available cash and proceeds from the issuancefourth quarter of an additional $200,000 of its 6.125% senior notes due 2024 (see Note 4 for additional information regarding the Company’s debt obligations).
2016 acquisitions
On October 20, 2016,2018, the Company completed the acquisitionacquisitions of 6,904 gross (5,952 net) acres in the Midland Basin, primarily located in Howard County, Texas from Plymouth Petroleum, LLCleasehold interests and additional sellers that exercised their “tag-along” salesmineral rights within its WildHorse and Spur operating areas for total cash consideration of $339,687, excluding$87,865, including customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see adjustments.
Note 9 for additional information regarding the equity offering). The Company obtained an 82% average working interest (62% average net revenue interest) in the properties acquired in the Plymouth Transaction.4 - EarningsPer Share
On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres in the Midland Basin, primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of common stock (at an assumed offering price of $11.74Basic earnings per share which is computed by dividing income available to common stockholders by the last reported sale priceweighted average number of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329,573, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest (61% average net revenue interest) in the properties acquired in the Big Star Transaction.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
| |
Unaudited pro forma financial statements
The following unaudited summary pro forma financial informationshares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Ameredev Transaction, Plymouth Transaction and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | (a) | | 2016 | (a) | | 2017 | (a) | | 2016 | (a) |
Revenues | $ | 84,614 |
| | | $ | 67,544 |
| | | $ | 251,313 |
| | | $ | 168,618 |
| |
Income (loss) from operations | 31,426 |
| | | 20,644 |
| | | 90,076 |
| | | (61,918 | ) | |
Income (loss) available to common stockholders | 15,257 |
| | | 23,322 |
| | | 94,786 |
| | | (80,690 | ) | |
| |
| | | |
| | | |
| | | |
| |
Net income (loss) per common share: | |
| | | |
| | | |
| | | |
| |
Basic | $ | 0.08 |
| | | $ | 0.13 |
| | | $ | 0.47 |
| | | $ | (0.53 | ) | |
Diluted | $ | 0.08 |
| | | $ | 0.13 |
| | | $ | 0.47 |
| | | $ | (0.53 | ) | |
| |
(a) | The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transaction occurred as of January 1, 2015. |
The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.
The properties associated with the Ameredev Transaction, Plymouth Transaction and Big Star Transaction have been commingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.
Note 3 - EarningsPer Share
anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:
|
| | | | | | | | | | | | | | | |
(share amounts in thousands) | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Net income (loss) | $ | 17,081 |
| | $ | 21,139 |
| | $ | 97,600 |
| | $ | (90,067 | ) |
Preferred stock dividends | (1,824 | ) | | (1,824 | ) | | (5,471 | ) | | (5,471 | ) |
Income (loss) available to common stockholders | $ | 15,257 |
| | $ | 19,315 |
| | $ | 92,129 |
| | $ | (95,538 | ) |
| | | | | | | |
Weighted average shares outstanding | 201,827 |
| | 136,983 |
| | 201,422 |
| | 112,925 |
|
Dilutive impact of restricted stock | 510 |
| | 500 |
| | 573 |
| | — |
|
Weighted average shares outstanding for diluted income (loss) per share | 202,337 |
| | 137,483 |
| | 201,995 |
| | 112,925 |
|
| | | | | | | |
Basic income (loss) per share | $ | 0.08 |
| | $ | 0.14 |
| | $ | 0.46 |
| | $ | (0.85 | ) |
Diluted income (loss) per share | $ | 0.08 |
| | $ | 0.14 |
| | $ | 0.46 |
| | $ | (0.85 | ) |
| | | | | | | |
Stock options (a) | — |
| | 15 |
| | — |
| | 15 |
|
Restricted stock (a) | 51 |
| | 25 |
| | 51 |
| | 25 |
|
|
| | | | | | | | | | | | | | | |
(amounts in thousands) | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
Net income | $ | 55,834 |
| | $ | 37,931 |
| | $ | 91,471 |
| | $ | 144,166 |
|
Preferred stock dividends | (350 | ) | | (1,823 | ) | | (3,997 | ) | | (5,471 | ) |
Loss on redemption of preferred stock | (8,304 | ) | | — |
| | (8,304 | ) | | — |
|
Income available to common stockholders | $ | 47,180 |
| | $ | 36,108 |
| | $ | 79,170 |
| | $ | 138,695 |
|
| | | | | | | |
Weighted average common shares outstanding | 228,322 |
| | 227,564 |
| | 228,054 |
| | 213,409 |
|
Dilutive impact of restricted stock | 147 |
| | 576 |
| | 503 |
| | 670 |
|
Weighted average common shares outstanding for diluted income per share | 228,469 |
| | 228,140 |
| | 228,557 |
| | 214,079 |
|
| | | | | | | |
Basic income per share | $ | 0.21 |
| | $ | 0.16 |
| | $ | 0.35 |
| | $ | 0.65 |
|
Diluted income per share | $ | 0.21 |
| | $ | 0.16 |
| | $ | 0.35 |
| | $ | 0.65 |
|
| | | | | | | |
Restricted stock (a) | 1,488 |
| | 154 |
| | 829 |
| | 154 |
|
| |
(a) | Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. |
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
Note 45 - Borrowings
The Company’s borrowings consisted of the following at:following:
|
| | | | | | | | |
| | As of |
Principal components: | | September 30, 2019 | | December 31, 2018 |
Senior secured revolving credit facility | | $ | 200,000 |
| | $ | 200,000 |
|
6.125% senior unsecured notes due 2024 | | 600,000 |
| | 600,000 |
|
6.375% senior unsecured notes due 2026 | | 400,000 |
| | 400,000 |
|
Total principal outstanding | | 1,200,000 |
| | 1,200,000 |
|
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization | | 5,625 |
| | 6,469 |
|
Unamortized deferred financing costs | | (14,971 | ) | | (16,996 | ) |
Total carrying value of borrowings (a) | | $ | 1,190,654 |
| | $ | 1,189,473 |
|
| |
(a) | Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,081 and $6,087 as of September 30, 2019 and December 31, 2018, respectively. |
|
| | | | | | | |
| September 30, 2017 | | December 31, 2016 |
Principal components: | | | |
Senior secured revolving credit facility | $ | — |
| | $ | — |
|
6.125% senior unsecured notes due 2024 | 600,000 |
| | 400,000 |
|
Total principal outstanding | 600,000 |
| | 400,000 |
|
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization | 7,875 |
| | — |
|
Unamortized deferred financing costs | (12,760 | ) | | (9,781 | ) |
Total carrying value of borrowings | $ | 595,115 |
| | $ | 390,219 |
|
Senior secured revolving credit facility (the “Credit Facility”)
On May 31,25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of May 25, 2022.Facility. JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include 17 institutional lenders. The total notional amount available under the Credit Facility is $2,000,000. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. Concurrent withThe maturity date of the execution ofCredit Facility is May 25, 2023.
Effective May 1, 2019, the Company entered into the third amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility to, among other things: (i) reaffirm the borrowing base at $1,100,000, excluding the Ranger assets sold; and (ii) amend various covenants and terms to reflect current market trends. As of September 30, 2019, the Credit Facility’s borrowing base increased to $650,000, but the Companyremained at $1,100,000 with an elected an aggregate commitment amount of $500,000. As of September 30, 2017, the Company continued to maintain the Credit Facility’s borrowing base at $500,000.$850,000.
As of September 30, 2017,2019, there was no balance$200,000 principal and $17,675 in letters of credit outstanding onunder the Credit Facility. For the quarterperiod ended September 30, 2017,2019, the Credit Facility had a weighted-average interest rate of 3.23%3.55%, calculated as the LIBOR plus a tiered rate ranging from 2.00%1.25% to 3.00%2.25%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base.
6.125% senior notes due 2024 (“6.125% Senior Notes”)
On October 3, 2016, the Company issued $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s 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.
On May 19, 2017, the Company issued an additional $200,000 aggregate principal amount of its 6.125% Senior Notes which with the existing $400,000 aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139. The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in Note 2) and for general corporate purposes.
The Company may redeem the 6.125% Senior Notes in accordance with the following terms: (1) prior to October 1, 2019, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022.
Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
| |
Restrictive covenants
The Company’s Credit Facility and the indentureindentures governing our 6.125% Senior Notesits senior notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at September 30, 2017.2019.
Note 56 - Derivative Instruments and Hedging Activities
Objectives and strategies for using commodity derivative instruments
The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps and put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty risk and offsetting
The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 67 for additional information regarding fair value.
|
| | |
| Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
Financial statement presentation and settlements
Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 67 for additional information regarding fair value.
Contingent consideration arrangement
Our Ranger Asset Divestiture in June of 2019 provides for potential contingent consideration to be received by the Company if commodity prices exceed specific thresholds in each of the next several years. On the disposition date, we recognized a derivative asset of $8,512 based on the initial fair value measurement. See Note 7 for additional information regarding fair value measurement. These contingent payments are summarized in the tables below (in thousands):
|
| | | | | | | | | | | | | | |
Year of Potential Settlement | | Threshold (a) | | Contingent Payment Amount | | Threshold (a) | | Contingent Payment Amount | | Fair Value as of September 30, 2019 (b) | | Aggregate Settlements Limit(c) |
| | | | | | | | | | | | $ | 60,000 |
|
2019 | | Greater than $60/bbl, less than $65/bbl | | $9,000 | | Equal to or greater than $65/bbl | | $20,833 | | $116 | | |
2020 | | Greater than $60/bbl, less than $65/bbl | | $9,000 | | Equal to or greater than $65/bbl | | $20,833 | | $3,977 | | |
2021 | | Greater than $60/bbl, less than $65/bbl | | $9,000 | | Equal to or greater than $65/bbl | | $20,833 | (c) | $3,496 | | |
| |
(a) | The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc. |
| |
(b) | Contingent consideration to be received will be classified as cash flows from financing activities up to the initial recognition fair value of $8,512; amounts in excess of the initial recognition fair value will be classified as cash flows from operating activities. |
| |
(c) | In the event that the 2019 and 2020 prices exceed the $65/bbl threshold, the aggregate amount of contingent consideration is limited to $60,000, resulting in the potential reduction in settlement for 2021 to $18,334. |
Derivatives not designated as hedging instruments
The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Cash settlementsSettlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations.
|
| | |
| Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
|
| | | | | | | | | | | | | | |
As of September 30, 2019 |
Derivative Instrument | | Balance Sheet Presentation | | Asset | | Liability | | Net Asset (Liability) |
Commodity - Oil | | Fair value of derivatives - Current | | $ | 23,487 |
| | $ | (8,795 | ) | | $ | 14,692 |
|
Commodity - Natural gas | | Fair value of derivatives - Current | | 1,429 |
| | (146 | ) | | 1,283 |
|
Contingent consideration arrangement | | Fair value of derivatives - Current | | 116 |
| | — |
| | 116 |
|
Commodity - Oil | | Fair value of derivatives - Non-current | | 3,736 |
| | (2,233 | ) | | 1,503 |
|
Commodity - Natural gas | | Fair value of derivatives - Non-current | | — |
| | (340 | ) | | (340 | ) |
Contingent consideration arrangement | | Fair value of derivatives - Non-current | | 7,473 |
| | — |
| | 7,473 |
|
Totals | | | | $ | 36,241 |
| | $ | (11,514 | ) | | $ | 24,727 |
|
| | | | | | | | |
As of December 31, 2018 |
Derivative Instrument | | Balance Sheet Presentation | | Asset | | Liability | | Net Asset (Liability) |
Commodity - Oil | | Fair value of derivatives - Current | | $ | 60,097 |
| | $ | (10,480 | ) | | $ | 49,617 |
|
Commodity - Natural gas | | Fair value of derivatives - Current | | 5,017 |
| | — |
| | 5,017 |
|
Commodity - Oil | | Fair value of derivatives - Non-current | | — |
| | (5,672 | ) | | (5,672 | ) |
Commodity - Natural gas | | Fair value of derivatives - Non-current | | — |
| | (1,768 | ) | | (1,768 | ) |
Totals | | | | $ | 65,114 |
| | $ | (17,920 | ) | | $ | 47,194 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance Sheet Presentation | | Asset Fair Value | | Liability Fair Value | | Net Derivative Fair Value |
Commodity | | Classification | | Line Description | | 9/30/2017 | | 12/31/2016 | | 9/30/2017 | | 12/31/2016 | | 9/30/2017 | | 12/31/2016 |
Natural gas | | Current | | Fair value of derivatives | | $ | 431 |
| | $ | — |
| | $ | — |
| | $ | (593 | ) | | $ | 431 |
| | $ | (593 | ) |
Oil | | Current | | Fair value of derivatives | | 2,902 |
| | 103 |
| | (6,380 | ) | | (17,675 | ) | | (3,478 | ) | | (17,572 | ) |
Oil | | Non-current | | Fair value of derivatives | | 1,121 |
| | — |
| | (659 | ) | | (28 | ) | | 462 |
| | (28 | ) |
| | Totals | | | | $ | 4,454 |
| | $ | 103 |
| | $ | (7,039 | ) | | $ | (18,296 | ) | | $ | (2,585 | ) | | $ | (18,193 | ) |
As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of commodity derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
|
| | | | | | | | | | | |
| As of September 30, 2019 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
Current assets: Fair value of commodity derivatives | $ | 35,936 |
| | $ | (11,020 | ) | | $ | 24,916 |
|
Long-term assets: Fair value of commodity derivatives | 7,464 |
| | (3,728 | ) | | 3,736 |
|
| | | | | |
Current liabilities: Fair value of commodity derivatives | $ | (19,961 | ) | | $ | 11,020 |
| | $ | (8,941 | ) |
Long-term liabilities: Fair value of commodity derivatives | (6,301 | ) | | 3,728 |
| | (2,573 | ) |
|
| | | | | | | | | | | |
| As of December 31, 2018 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
Current assets: Fair value of commodity derivatives | $ | 78,091 |
| | $ | (12,977 | ) | | $ | 65,114 |
|
| | | | | |
Current liabilities: Fair value of commodity derivatives | $ | (23,457 | ) | | $ | 12,977 |
| | $ | (10,480 | ) |
Long-term liabilities: Fair value of commodity derivatives | (7,440 | ) | | — |
| | (7,440 | ) |
For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
Oil derivatives | | | | | | | |
Net gain (loss) on settlements | $ | (1,045 | ) | | $ | (9,306 | ) | | $ | (7,048 | ) | | $ | (26,353 | ) |
Net gain (loss) on fair value adjustments | 25,767 |
| | (24,476 | ) | | (27,750 | ) | | (28,720 | ) |
Total gain (loss) on oil derivatives | 24,722 |
| | (33,782 | ) | | (34,798 | ) | | (55,073 | ) |
Natural gas derivatives | | | | | | | |
Net gain (loss) on settlements | 2,056 |
| | 67 |
| | 6,612 |
| | 675 |
|
Net gain (loss) on fair value adjustments | (733 | ) | | (624 | ) | | (2,306 | ) | | (976 | ) |
Total gain (loss) on natural gas derivatives | 1,323 |
| | (557 | ) | | 4,306 |
| | (301 | ) |
Contingent consideration arrangement | | | | | | | |
Net gain (loss) on fair value adjustments | (4,236 | ) | | — |
| | (923 | ) | | — |
|
Total gain (loss) on derivatives | $ | 21,809 |
| | $ | (34,339 | ) | | $ | (31,415 | ) | | $ | (55,374 | ) |
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
|
| | | | | | | | | | | |
| September 30, 2017 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
Current assets: Fair value of derivatives | $ | 5,441 |
| | $ | (2,108 | ) | | $ | 3,333 |
|
Long-term assets: Fair value of derivatives | 1,388 |
| | (267 | ) | | 1,121 |
|
| | | | | |
Current liabilities: Fair value of derivatives | $ | (8,488 | ) | | $ | 2,108 |
| | $ | (6,380 | ) |
Long-term liabilities: Fair value of derivatives | (926 | ) | | 267 |
| | (659 | ) |
|
| | | | | | | | | | | |
| December 31, 2016 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
Current assets: Fair value of derivatives | $ | 1,836 |
| | $ | (1,733 | ) | | $ | 103 |
|
| | | | | |
Current liabilities: Fair value of derivatives | $ | (20,001 | ) | | $ | 1,733 |
| | $ | (18,268 | ) |
Long-term liabilities: Fair value of derivatives | (28 | ) | | — |
| | (28 | ) |
For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Oil derivatives | | | | | | | |
Net gain (loss) on settlements | $ | (1,373 | ) | | $ | 4,252 |
| | $ | (4,213 | ) | | $ | 15,467 |
|
Net gain (loss) on fair value adjustments | (12,811 | ) | | 699 |
| | 14,584 |
| | (26,904 | ) |
Total gain (loss) on oil derivatives | $ | (14,184 | ) | | $ | 4,951 |
| | $ | 10,371 |
| | $ | (11,437 | ) |
Natural gas derivatives | | | | | | | |
Net gain (loss) on settlements | $ | 159 |
| | $ | (161 | ) | | $ | 241 |
| | $ | 357 |
|
Net gain (loss) on fair value adjustments | (137 | ) | | 345 |
| | 1,024 |
| | (201 | ) |
Total gain on natural gas derivatives | $ | 22 |
| | $ | 184 |
| | $ | 1,265 |
| | $ | 156 |
|
| | | | | | | |
Total gain (loss) on oil & natural gas derivatives | $ | (14,162 | ) | | $ | 5,135 |
| | $ | 11,636 |
| | $ | (11,281 | ) |
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
| |
Derivative positions
Listed in the tables below are the outstanding oil and natural gas derivative contracts as of September 30, 2017:2019:
|
| | | | | | | |
| For the Remainder of | | For the Full Year of |
Oil contracts (WTI) | 2017 | | 2018 |
Swap contracts combined with short puts (enhanced swaps) | | | |
Total volume (MBbls) | 184 |
| | — |
|
Weighted average price per Bbl | | | |
Swap | $ | 44.50 |
| | $ | — |
|
Short put option | $ | 30.00 |
| | $ | — |
|
Swap contracts | | | |
Total volume (MBbls) | 184 |
| | 1,460 |
|
Weighted average price per Bbl | $ | 45.74 |
| | $ | 50.93 |
|
Deferred premium put spread option | | | |
Total volume (MBbls) | 253 |
| | — |
|
Premium per Bbl | $ | 2.45 |
| | $ | — |
|
Weighted average price per Bbl | | | |
Long put option | $ | 50.00 |
| | $ | — |
|
Short put option | $ | 40.00 |
| | $ | — |
|
Collar contracts (two-way collars) | | | |
Total volume (MBbls) | 340 |
| | — |
|
Weighted average price per Bbl | | | |
Ceiling (short call) | $ | 58.19 |
| | $ | — |
|
Floor (long put) | $ | 47.50 |
| | $ | — |
|
Call option contracts | | | |
Total volume (MBbls) | 169 |
| | — |
|
Premium per Bbl | $ | 1.82 |
| | $ | — |
|
Weighted average price per Bbl | | | |
Short call strike price (a) | $ | 50.00 |
| | $ | — |
|
Long call strike price (a) | $ | 50.00 |
| | $ | — |
|
Collar contracts combined with short puts (three-way collars) | | | |
Total volume (MBbls) | — |
| | 3,468 |
|
Weighted average price per Bbl | | | |
Ceiling (short call option) | $ | — |
| | $ | 60.86 |
|
Floor (long put option) | $ | — |
| | $ | 48.95 |
|
Short put option | $ | — |
| | $ | 39.21 |
|
|
| | | | | | | | | | | | |
| For the Remainder | | For the Full Year | | For the Full Year | |
Oil contracts (WTI) | of 2019 | | of 2020 | | of 2021 | |
Puts | | | | | | |
Total volume (Bbls) | 230,000 |
| | — |
| | — |
| |
Weighted average price per Bbl | $ | 65.00 |
| | $ | — |
| | $ | — |
| |
Put spreads | | | | | | |
Total volume (Bbls) | 230,000 |
| | — |
| | — |
| |
Weighted average price per Bbl | | | | | | |
Floor (long put) | $ | 65.00 |
| | $ | — |
| | $ | — |
| |
Floor (short put) | $ | 42.50 |
| | $ | — |
| | $ | — |
| |
Collar contracts with short puts (three-way collars) | | | | | | |
Total volume (Bbls) | 1,196,000 |
| | 5,124,000 |
| | — |
| |
Weighted average price per Bbl | | | | | | |
Ceiling (short call) | $ | 67.46 |
| | $ | 65.46 |
| | $ | — |
| |
Floor (long put) | $ | 56.54 |
| | $ | 55.45 |
| | $ | — |
| |
Floor (short put) | $ | 43.65 |
| | $ | 44.66 |
| | $ | — |
| |
Collar contracts (two-way collars) | | | | | | |
Total volume (Bbls) | 276,000 |
| | — |
| | — |
| |
Weighted average price per Bbl | | | | | | |
Ceiling (short call) | $ | 60.00 |
| | $ | — |
| | $ | — |
| |
Floor (long put) | $ | 55.00 |
| | $ | — |
| | $ | — |
| |
Short call | | | | | | |
Total volume (Bbls) | — |
| | — |
| | 1,825,000 |
| (a) |
Weighted average price per Bbl | $ | — |
| | $ | — |
| | $ | 63.00 |
| |
Swap contracts | | | | | | |
Total volume (Bbls) | 276,000 |
| | 1,098,000 |
| | — |
| |
Weighted average price per Bbl | $ | 60.17 |
| | $ | 56.17 |
| | $ | — |
| |
| | | | | | |
Oil contracts (Brent ICE) | | | | | | |
Collar contracts with short puts (three-way collars) | | | | | | |
Total volume (Bbls) | — |
| | 837,500 |
| | — |
| |
Weighted average price per Bbl | | | | | | |
Ceiling (short call) | $ | — |
| | $ | 70.00 |
| | $ | — |
| |
Floor (long put) | $ | — |
| | $ | 58.24 |
| | $ | — |
| |
Floor (short put) | $ | — |
| | $ | 50.00 |
| | $ | — |
| |
| | | | | | |
Oil contracts (Midland basis differential) | | | | | | |
Swap contracts | | | | | | |
Total volume (Bbls) | 2,176,000 |
| | 4,576,000 |
| | 1,095,000 |
| |
Weighted average price per Bbl | $ | (2.50 | ) | | $ | (1.29 | ) | | $ | 1.00 |
| |
| | | | | | |
Oil contracts (Argus Houston MEH basis differential) | | | | | | |
Swap contracts | | | | | | |
Total volume (Bbls) | — |
| | 1,439,205 |
| | — |
| |
Weighted average price per Bbl | $ | — |
| | $ | 2.40 |
| | $ | — |
| |
| | | | | | |
Natural gas contracts (Henry Hub) | | | | | | |
Collar contracts (two-way collars) | | | | | | |
Total volume (MMBtu) | 598,000 |
| | — |
| | — |
| |
Weighted average price per MMBtu | | | | | | |
Ceiling (short call) | $ | 3.50 |
| | $ | — |
| | $ | — |
| |
Floor (long put) | $ | 3.13 |
| | $ | — |
| | $ | — |
| |
Swap contracts | | | | | | |
Total volume (MMBtu) | 155,000 |
| | — |
| | — |
| |
Weighted average price per MMBtu | $ | 2.87 |
| | $ | — |
| | $ | — |
| |
| | | | | | |
Natural gas contracts (Waha basis differential) | | | | | | |
Swap contracts | | | | | | |
Total volume (MMBtu) | 2,116,000 |
| | 4,758,000 |
| | — |
| |
Weighted average price per MMBtu | $ | (1.18 | ) | | $ | (1.12 | ) | | $ | — |
| |
(a) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps.
|
| | | | | | | |
| For the Remainder of | | For the Full Year of |
Oil contracts (Midland basis differential) | 2017 | | 2018 |
Swap contracts | | | |
Volume (MBbls) | 552 |
| | 4,563 |
|
Weighted average price per Bbl | $ | (0.52 | ) | | $ | (0.98 | ) |
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
|
| | | | | | | |
| For the Remainder of | | For the Full Year of |
Natural gas contracts | 2017 | | 2018 |
Collar contracts combined with short puts (Henry Hub, three-way collars) | | | |
Total volume (BBtu) | 368 |
| | — |
|
Weighted average price per MMBtu | | | |
Ceiling (short call option) | $ | 3.71 |
| | $ | — |
|
Floor (long put option) | $ | 3.00 |
| | $ | — |
|
Short put option | $ | 2.50 |
| | $ | — |
|
Collar contracts (Henry Hub, two-way collars) | | | |
Total volume (BBtu) | 856 |
| | 720 |
|
Weighted average price per MMBtu | | | |
Ceiling (short call option) | $ | 3.77 |
| | $ | 3.84 |
|
Floor (long put option) | $ | 3.23 |
| | $ | 3.40 |
|
Swap contracts | |
| | |
|
Total volume (BBtu) | 124 |
| | — |
|
Weighted average price per MMBtu | $ | 3.39 |
| | $ | — |
|
Subsequent event
The following derivative contracts were executed subsequent to September 30, 2017:
|
| | | | | | | |
| For the Remainder of | | For the Full Year of |
Oil contracts (Midland basis differential) | 2017 | | 2018 |
Swap contracts | | | |
Volume (MBbls) | — |
| | 546 |
|
Weighted average price per Bbl | $ | — |
| | $ | (0.23 | ) |
| | | |
| For the Remainder of | | For the Full Year of |
Oil contracts (WTI) | 2017 | | 2018 |
Swap contracts | | | |
Volume (MBbls) | — |
| | 365 |
|
Weighted average price per Bbl | $ | — |
| | $ | 53.40 |
|
Note 67 - Fair Value Measurements
The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.
Fair value offinancial instruments
Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximated fair value due to the short-term nature or maturity of the instruments.
Debt. The carrying amount of the Company’s floating-rate debt approximated fair value, because the interest rates were variable and reflective of market rates.
| | | September 30, 2017 | | December 31, 2016 | | September 30, 2019 | | December 31, 2018 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
Credit Facility (a) | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 200,000 |
| | $ | 200,000 |
| | $ | 200,000 |
| | $ | 200,000 |
|
6.125% Senior Notes (b) | 595,115 |
| | 621,000 |
| | 390,219 |
| | 412,000 |
| | 596,337 |
| | 595,194 |
| | 595,788 |
| | 558,000 |
|
6.375% Senior Notes (b) | | | 394,317 |
| | 393,540 |
| | 393,685 |
| | 372,000 |
|
Total | $ | 595,115 |
| | $ | 621,000 |
| | $ | 390,219 |
| | $ | 412,000 |
| | $ | 1,190,654 |
| | $ | 1,188,734 |
| | $ | 1,189,473 |
| | $ | 1,130,000 |
|
| |
(b) | The fair value was based upon Level 2 inputs. See Note 45 for additional information about the Company’s 6.125% and 6.375% Senior Notes. |
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
| |
Assets and liabilities measured at fair value on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:
Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 56 for additional information regarding the Company’s derivative instruments.
Contingent consideration arrangement - embedded derivative financial instrument. The embedded option within the contingent consideration arrangement is considered a financial instrument under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded option on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates an undiscounted payout, and risk adjusts for the discount rates inclusive of adjustments for the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangement, the inputs are considered Level 2 inputs within the fair value hierarchy. See Note 6 for additional information regarding the Company’s contingent consideration arrangement.
|
| | |
| Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
| | September 30, 2017 | Classification | | Level 1 | | Level 2 | | Level 3 | | Total | |
September 30, 2019 | | | Classification | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets | | | | | | | | | | | | | | | | | | | |
Derivative financial instruments | Fair value of derivatives | | $ | — |
| | $ | 4,454 |
| | $ | — |
| | $ | 4,454 |
| | Fair value of derivatives | | $ | — |
| | $ | 36,241 |
| | $ | — |
| | $ | 36,241 |
|
Liabilities | | | | | | | | | | | | | | | | | | | |
Derivative financial instruments | Fair value of derivatives | | — |
| | (7,039 | ) | | — |
| | (7,039 | ) | | Fair value of derivatives | | — |
| | (11,514 | ) | | — |
| | (11,514 | ) |
Total net liabilities | | | $ | — |
| | $ | (2,585 | ) | | $ | — |
| | $ | (2,585 | ) | |
Total net assets (liabilities) | | | | | $ | — |
| | $ | 24,727 |
| | $ | — |
| | $ | 24,727 |
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2016 | Classification | | Level 1 | | Level 2 | | Level 3 | | Total | |
December 31, 2018 | | | Classification | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets | | | | | | | | | | | | | | | | | | | |
Derivative financial instruments | Fair value of derivatives | | $ | — |
| | $ | 103 |
| | $ | — |
| | $ | 103 |
| | Fair value of derivatives | | $ | — |
| | $ | 65,114 |
| | $ | — |
| | $ | 65,114 |
|
Liabilities | | | | | | | | | | | | | | | | | | | |
Derivative financial instruments | Fair value of derivatives | | — |
| | (18,296 | ) | | — |
| | (18,296 | ) | | Fair value of derivatives | | — |
| | (17,920 | ) | | — |
| | (17,920 | ) |
Total net liabilities | | | $ | — |
| | $ | (18,193 | ) | | $ | — |
| | $ | (18,193 | ) | |
Total net assets | | | | | $ | — |
| | $ | 47,194 |
| | $ | — |
| | $ | 47,194 |
|
Assets andliabilitiesmeasured atfairvalue on anonrecurringbasis
Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs.
Note 78 - Income Taxes
The Company typically provides for income taxes at athe statutory rate of 35%21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. AsThe following table presents a resultreconciliation of the write-downreported amount of oil and natural gas properties in the latter part of 2015 and the first half of 2016, the Company incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a full valuation allowance for the net U.S. federal deferred tax asset in 2015. In subsequent periods where the Company has recorded pre-tax income, it has reversed a portion of the U.S. federal valuation allowance, net of discrete items, to the extent necessary to offset U.S. federal income tax expense on pre-taxto the amount of income recorded for the period. Income tax expense recorded in this period relatesthat would result from applying domestic federal statutory tax rates to deferred State of Texas gross margin tax. The valuation allowance was $109,815 as of September 30, 2017. pretax income from continuing operations:
The Company recently adopted a new accounting standard that simplified the accounting for stock-based compensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2017 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. Due to the Company’s valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2017, and therefore, the net effect of this new accounting standard was zero. See Note 1 for additional information about this new accounting standard.
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Components of income tax rate reconciliation | 2019 | | 2018 | | 2019 | | 2018 |
Income tax expense computed at the statutory federal income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
State taxes net of federal expense | 1 | % | | 3 | % | | 1 | % | | 2 | % |
Section 162(m) | — | % | | 2 | % | | — | % | | 1 | % |
Valuation allowance | — | % | | (21 | )% | | — | % | | (21 | )% |
Effective income tax rate, before discrete items | 22 | % | | 5 | % | | 22 | % | | 3 | % |
Discrete items (a) | 2 | % | | (1 | )% | | 2 | % | | (1 | )% |
Effective income tax rate, after discrete items | 24 | % | | 4 | % | | 24 | % | | 2 | % |
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)(a)
| periodic volatility of stock-based compensation tax deductions on future effective tax rates. |
Note 8 - Asset Retirement Obligations
The table below summarizes the activity for the Company’s asset retirement obligations:
|
| | | |
| For The Nine Months Ended |
| September 30, 2017 |
Asset retirement obligations at January 1, 2017 | $ | 6,661 |
|
Accretion expense | 523 |
|
Liabilities incurred | 224 |
|
Liabilities settled | (227 | ) |
Revisions to estimate (a) | (2,177 | ) |
Asset retirement obligations at end of period | 5,004 |
|
Less: Current asset retirement obligations | (1,841 | ) |
Long-term asset retirement obligations at September 30, 2017 | $ | 3,163 |
|
Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the Consolidated Balance Sheets at September 30, 2017 as long-term restricted investments were $3,362. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.
Note 9 - Equity Transactions
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s 10.00% Series A Cumulative Preferred Stock arewere entitled to receive, when, as and if declared by our Boardthe Company’s board of Directors,directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends arewere payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by ourthe Company’s Board of Directors. Preferred Stock dividends were $1,824$350 and $1,824$1,823 for the three months ended September 30, 20172019 and 2016,2018, respectively, and $5,471$3,997 and $5,471 for the nine months ended September 30, 20172019 and 2016,2018, respectively.
On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. The redemption date of the Preferred Stock was July 18, 2019 (the “Redemption Date”). The Preferred Stock has no stated maturity and is not subjectwere redeemed at the redemption price equal to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus anyan 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 (the “Redemption Price”). After the redemption date.Redemption Date, the Preferred
Following a change of control in which the Company or the acquirer |
| | |
| Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
Stock were no longer have a class of common securities listeddeemed outstanding, dividends on a national exchange, the Company will have the option to redeem the Preferred Stock in whole but not in part for $50.00 per share in cash, plus accruedceased to accrue, and unpaid dividends (whether or not declared),all rights of the holders with respect to the redemption date. If the Company does not exercise its option to redeem thesuch Preferred Stock upon such changewere terminated, except the right of control, the holders ofto receive the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common Redemption Price, without interest.
Commonstock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on September 30, 2017, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $11.24 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.4 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.
On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of SeptemberMay 30, 2017, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.
Commonstock
On December 19, 2016,2018, the Company completed an underwritten public offering of 40,000,00025.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses)costs) of approximately $634,934. Proceeds$287,988. The Company used proceeds from the offering were used to substantiallypartially fund the Ameredev Transaction,Delaware Asset Acquisition completed in the third quarter of 2018, described in Note 2.3.
Note 10 - Leases
Leases
We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. Based on our evaluation of leases for the three and nine months ended September 6, 2016,30, 2019, we have no leases that meet the Company completedcriteria for classification as a finance lease. We capitalize operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underwritten public offering of 29,900,000 shares of its common stockunderlying asset for total estimated net proceeds (after the underwriter’s discountslease term, and estimated offering expenses) of approximately $421,864. Proceedslease liabilities represent our obligation to make lease payments arising from the offering were usedlease.
Operating leases are included in operating lease ROU assets, current operating lease liabilities, and long-term operating lease liabilities in our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to substantially fund the Plymouth Transaction, describedlessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.
Nature of leases
In support of our operations, we lease certain drilling rigs, office space, office equipment, production facilities, compressors, vehicles and other ancillary drilling equipment under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.
Drilling rigs
The Company enters into daywork and long-term contracts for drilling rigs with third party service contractors to support the development of undeveloped reserves. Our daywork drilling rig arrangements are typically structured with a term that is in Note 2. effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells, well pads or contractually stated extension terms by providing 30 days’ notice prior to the end of the original contract term.
The Company’s long-term drilling contracts are generally structured with an initial non-cancelable term of one to two years. We have concluded that our long-term drilling rig arrangements represent operating leases with a lease term greater than twelve months. Additionally, we have concluded that our daywork drilling rig arrangements represent short-term operating leases with a lease term that equals the period of time required to complete drilling operations on the contractually specified well or well pad (that is, generally one to a few months from commencement of drilling).
We do not include the option to extend the drilling rig contract in the lease term due to the continuously evolving nature of our drilling schedules, which requires significant flexibility in the structure of the term of these arrangements, and the potential volatility in commodity prices in an annual period. We have further elected to apply the practical expedient for short-term leases to our daywork drilling rig leases. Accordingly, we do not apply the lease recognition requirements to our daywork drilling rig contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term.
Corporate and field offices
We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of two to five years. To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
On May 26, 2016,Transportation, gathering and processing arrangements
We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly-owned and operated by the Company issued 9,333,333 sharesmidstream counterparty. Under most of common stock to partially fundthese arrangements, we do not utilize substantially all of the Big Star Transaction, described in Note 2, atunderlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an assumed offering price of $11.74 per share, which isidentified asset.
The following tables reflect the last reported sale pricecurrent period impact of our common stock onadoption of the New York Stock Exchange onnew leases standard. As we have no leases that date.meet the criteria for classification as a finance lease, all information contained herein represents our operating leases.
The components of our total lease cost were as follows:
On April 25, 2016, the Company completed an underwritten public offering |
| | | | | | | |
| Three Months Ended | | Nine Months Ended |
| September 30, 2019 | | September 30, 2019 |
Operating lease cost | $ | 7,964 |
| | $ | 27,122 |
|
Short-term lease cost (a) | 293 |
| | 3,640 |
|
(a) Short-term lease cost excludes expenses related to leases with a contract term of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869. Proceeds from the offering were used to fund the Big Star Transaction, described in Note 2, and other working interest acquisitions.one month or less.
On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948. Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.
Note 10 - Other
Operating leases
As of September 30, 2017 the Company had contracts2019, our weighted average remaining lease term and our weighted average discount rate for four horizontal drilling rigs (the “Cactus 1 Rig”our operating leases were 1.36 years and 4.03%, “Cactus 2 Rig”, “Cactus 3 Rig”, and “Independence Rig”). Therespectively.
Our operating lease liabilities with enforceable contract terms that are greater than one year mature as amended in July 2017, of the Cactus 1 Rig and Cactus 2 Rig will end in January 2020 and February 2021, respectively. The contract terms, as amended in July 2017, of the Cactus 3 Rig that commenced drilling in mid-January 2017, will end in July 2018. Effective April 2017, the Company entered into a contract for the Independence Rig, which commenced drilling in July 2017. The contract terms of the Independence Rig will end in July 2019. The rig lease agreements include early termination provisions that obligate the Company to pay reduced minimum rentals for the remaining term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee.follows:
|
| | | |
| As of September 30, 2019 |
Remainder of 2019 | $ | 7,932 |
|
2020 | 13,933 |
|
2021 | 1,576 |
|
2022 | 534 |
|
2023 | 517 |
|
Thereafter | 431 |
|
Total lease payments | 24,923 |
|
Less imputed interest | 732 |
|
Total | $ | 24,191 |
|
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
| |
Special Note Regarding Forward Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:
our oil and gas reserve quantities, and the discounted present value of these reserves;
the amount and nature of our capital expenditures;
our future drilling and development plans and our potential drilling locations;
the timing and amount of future production and operating costs;
commodity price risk management activities and the impact on our average realized prices;
business strategies and plans of management;
our ability to efficiently integrate recently completed acquisitions; and
prospect development and property acquisitions.
Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:
general economic conditions including the availability of credit and access to existing lines of credit;
the volatility of oil and natural gas prices;
the uncertainty of estimates of oil and natural gas reserves;
impairments;
the impact of competition;
the availability and cost of seismic, drilling and other equipment;
operating hazards inherent in the exploration for and production of oil and natural gas;
difficulties encountered during the exploration for and production of oil and natural gas;
difficulties encountered in delivering oil and natural gas to commercial markets;
changes in customer demand and producers’ supply;
the uncertainty of our ability to attract capital and obtain financing on favorable terms;
compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;
the impact of government regulation, including regulation of endangered species;
any increase in severance or similar taxes;
litigation relating to hydraulic fracturing, the climate and over-the-counter derivatives;
the financial impact of accounting regulations and critical accounting policies;
the comparative cost of alternative fuels;
credit risk relating to the risk of loss as a result of non-performance by our counterparties;
weather conditions; and
any other factors listed in the reports we have filed and may file with the SEC.
We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.
Should one or more of the risks or uncertainties described herein or in our 2016 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results | |
Note 11 - Asset Retirement Obligations
The table below summarizes the activity for the Company’s ARO:
|
| | | |
| Nine Months Ended |
| September 30, 2019 |
Asset retirement obligations at January 1, 2019 | $ | 14,292 |
|
Accretion expense | 585 |
|
Liabilities incurred | 325 |
|
Liabilities settled | (3,187 | ) |
Dispositions | (1,753 | ) |
Revisions to estimate | (718 | ) |
Asset retirement obligations at end of period | 9,544 |
|
Less: Current asset retirement obligations | (1,250 | ) |
Long-term asset retirement obligations at September 30, 2019 | $ | 8,294 |
|
| |
• | Liabilities incurred include additions from acquisitions, asset swaps, and new wells drilled during the year. |
| |
• | Liabilities settled include the retirement of 28 wells during the year and settlement of abandonment obligations attributable to historical activity within the Gulf of Mexico. |
| |
• | Dispositions are primarily attributable to the Ranger Asset Divestiture in the second quarter of 2019. See Note 3 for details about the Ranger Asset Divestiture. |
| |
• | Revisions to estimates were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells. |
|
| | |
| Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at September 30, 2019 as long-term restricted investments were $3,490. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.
Note 12 - Other
Other commitments
In August 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 in Howard and Ward counties to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf 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 the Gulf 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.
In January 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 in Howard and Ward counties and will have delivery points in several locations along the Gulf 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.
In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf 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 the Gulf 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.
In July 2019, the Company executed a crude oil sales contact that provides dedicated capacity on a new pipeline system that originates in Midland County and will have delivery points in several locations along the Gulf 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.
Note 13 - Carrizo Acquisition
On July 14, 2019, Callon and Carrizo Oil & Gas, Inc. (“Carrizo”) entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, upon the terms and subject to the conditions set forth therein, Carrizo will merge with and into Callon, with Callon as the surviving corporation (the “Merger” or the “Carrizo Acquisition”). The combination will result in a portfolio of core oil-weighted assets in both the Permian Basin and Eagle Ford Shale.
Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each outstanding share of Carrizo common stock, will be converted into the right to receive 2.05 shares of Callon common stock. Following the closing of the Merger, Callon’s existing shareholders and Carrizo’s existing shareholders will own approximately 54% and 46%, respectively, of the outstanding shares of the combined company.
The Merger Agreement provides that, upon consummation of the Merger, the board of directors of Callon will consist of the eight members of the board of directors of Callon immediately prior to the Effective Time and three members of the board of directors of Carrizo. Callon and Carrizo have agreed that the Director Designees will be appointed to the Callon board immediately after the effective time, with the Callon designee being appointed as a Class III director, with a term ending at the 2021 annual meeting of the shareholders of Callon, and the Carrizo designees being appointed as Class I directors, each with a term ending at the 2022 annual meeting of the shareholders of Callon. Callon and Carrizo expect that the Callon designee will be Frances Aldrich Sevilla-Sacasa and the Carrizo designees will be S.P. Johnson IV and Steven A. Webster.
Additionally, the Merger Agreement provides that, upon consummation of the Merger, the officers of Callon immediately prior to the Effective Time shall be the officers of the combined company. Callon will continue to be headquartered in Houston, Texas, where both
|
| | |
| Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data) | |
companies are currently based. Callon expects that the acquisition will close during the fourth quarter of 2019, subject to the approval of both shareholder bases, the satisfaction of certain regulatory approvals and other closing conditions.
Special Note Regarding Forward Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:
matters relating to the Carrizo Acquisition;
our oil and natural gas reserve quantities, and the discounted present value of these reserves;
the amount and nature of our capital expenditures;
our future drilling and development plans and our potential drilling locations;
the timing and amount of future capital and operating costs;
production decline rates from our wells being greater than expected;
commodity price risk management activities and the impact on our average realized prices;
business strategies and plans of management;
our ability to consummate and efficiently integrate recent acquisitions; and
prospect development and property acquisitions.
Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:
general economic conditions including the availability of credit and access to existing lines of credit;
the volatility of oil and natural gas prices;
the uncertainty of estimates of oil and natural gas reserves;
impairments;
the impact of competition;
the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel;
operating hazards inherent in the exploration for and production of oil and natural gas;
difficulties encountered during the exploration for and production of oil and natural gas;
the potential impact of future drilling on production from existing wells;
difficulties encountered in delivering oil and natural gas to commercial markets;
changes in customer demand and producers’ supply;
the uncertainty of our ability to attract capital and obtain financing on favorable terms;
compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;
the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;
any increase in severance or similar taxes;
the financial impact of accounting regulations and critical accounting policies;
the comparative cost of alternative fuels;
credit risk relating to the risk of loss as a result of non-performance by our counterparties;
cyberattacks on the Company or on systems and infrastructure used by the oil and gas industry;
weather conditions;
risks associated with acquisitions, including the Carrizo Acquisition;
failure to consummate the Carrizo Acquisition in a timely manner, or at all, and failure to realize the expected benefits thereof;
any litigation relating to the Carrizo Acquisition; and
any other factors listed in the reports we have filed and may file with the SEC.
We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.
Should one or more of the risks or uncertainties described above or in our 2018 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation
to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.
Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
|
| | |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 20162018 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 the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this reportQuarterly Report on Form 10-Q.
We are an independent oil and natural gas company establishedincorporated in the State 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 development, exploration and exploitationdevelopment of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. WeSince our entry into the Permian Basin in late 2009, we have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completed in February 2017. We further expanded our presence in the Delaware Basin through our acquisitions in 2018. 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, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. 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. Our production was approximately 78% oil and 22% natural gas for the nine months ended September 30, 2017. 2019.
Recent Developments
On September 30, 2017, ourJune 12, 2019, we completed the Ranger Asset Divestiture for net acreage positioncash proceeds received at closing of $245 million, including customary purchase price adjustments.
On July 18, 2019, we redeemed all outstanding shares of the Preferred Stock at a Redemption Price of $50.24 per share for a total redemption of $73 million. 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.
In July 2019, Callon and Carrizo entered into the Merger Agreement, pursuant to which, upon the terms and subject to the conditions set forth therein, Carrizo will merge with and into Callon, with Callon as the surviving corporation. The combination will result in a portfolio of core oil-weighted assets in both the Permian Basin was approximately 58,336 net acres.and Eagle Ford Shale. The Company expects that the acquisition will close during the fourth quarter of 2019. See Note 2 in the Footnotes to the Financial Statements13 for additional information aboutregarding the Company’s acquisitions.
Carrizo Acquisition.
Operational Highlights
All of our producing properties are located in the Permian Basin. As a result of our acquisitionhorizontal development and horizontal developmentacquisition efforts, our production grew 36%8% and 53%31% for the three and nine months ended September 30, 2017, respectively,2019, compared to the same periods of 2016.2018, respectively. Production increased to 2,0743,481 MBOE for the three months ended September 30, 20172019 from 1,5273,212 MBOE for the three months ended September 30, 2016same period of 2018, and increased to 5,93410,796 MBOE for the nine months ended September 30, 20172019 from 3,8848,238 MBOE for the nine months endedsame period of 2018. As of September 30, 2016.2019, we had 800 gross (602.4 net) working interest oil and natural gas wells.
For the three months ended September 30, 2017,2019, we drilled 1312 gross (10.3(11.0 net) horizontal wells and completed 1516 gross (13.2(15.6 net) horizontal wells. For the nine months ended September 30, 20172019, we drilled 3648 gross (28.9(41.7 net) horizontal wells and completed 3441 gross (27.7(38.1 net) horizontal wells. As of September 30, 2017,2019, we had 918 gross (6.4(13.1 net) horizontal wells awaiting completion.
As of September 30, 2017, we had 535 gross (418.1 net) working interest oil wells, three gross (0.1 net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. We continue to evaluate other sources of capital to complement our cash flows from operations as we pursue our long-term growth plans. As of September 30, 2017, there was no balance outstanding on the Credit Facility, which has a borrowing base of $650 million with a current elected commitment of $500 million. For the nine months ended September 30, 2017, cash and cash equivalents decreased $264.3 million to $61.6 million compared to $325.9 million at September 30, 2016.
Liquidity and cash flow
|
| | | | | | | | |
| | Nine Months Ended September 30, |
(in millions) | | 2017 | | 2016 |
Net cash provided by operating activities | | $ | 149.7 |
| | $ | 84.8 |
|
Net cash used in investing activities | | (935.6 | ) | | (434.5 | ) |
Net cash provided by financing activities | | 194.5 |
| | 674.4 |
|
Net change in cash and cash equivalents | | $ | (591.4 | ) | | $ | 324.7 |
|
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Operating activities. For the nine months ended September 30, 2017, net cash provided by operating activities was $149.7 million compared to net cash provided by operating activities of $84.8 million for the same period in 2016. The change was predominantly attributable to the following:
An increase in revenue;
A decrease on settlements of derivative contracts;
An increase in certain operating expenses related to acquired properties;
An increase in payments in cash-settled restricted stock unit (“RSU”) awards; and
A change related to the timing of working capital payments and receipts.
Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 4, 5 and 6 in the Footnotes to the Financial Statements for additional information on our debt and 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 nine months ended September 30, 2017, net cash used in investing activities was $935.6 million compared to $434.5 million for the same period in 2016. The change was predominantly attributable to the following:
A $141.7 million increase in operational expenditures due to the transition from a two-rig to a three-rig program in January 2017 and from a three-rig to a four-rig program in July 2017; and
A $333.6 million increase attributable to acquisition activity. See Note 2 in the Footnotes to the Financial Statements for additional information on the Company’s acquisitions.
Our investing activities, on a cash basis, include the following for the periods indicated (in millions):
|
| | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 | | $ Change |
Operational expenditures | | $ | 232.2 |
| | $ | 90.5 |
| | $ | 141.7 |
|
Seismic, leasehold and other | | 11.4 |
| | 10.0 |
| | 1.4 |
|
Capitalized general and administrative costs | | 11.9 |
| | 9.0 |
| | 2.9 |
|
Capitalized interest | | 11.7 |
| | 13.2 |
| | (1.4 | ) |
Total capital expenditures(a) | | 267.2 |
| | 122.7 |
| | 144.5 |
|
| | | | | | |
Acquisitions | | 714.5 |
| | 302.1 |
| | 412.4 |
|
Acquisition deposits | | (46.1 | ) | | 32.7 |
| | (78.8 | ) |
Proceeds from the sale of mineral interest and equipment | | — |
| | (22.9 | ) | | 22.9 |
|
Total investing activities | | $ | 935.6 |
| | $ | 434.5 |
| | $ | 501.1 |
|
| |
(a) | On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the nine months ended September 30, 2017 were $277.0 million. Inclusive of capitalized general and administrative and interest costs, total capital expenditures for the nine months ended September 30, 2017 were $326.5 million. |
General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 2 in the Footnotes to the Financial Statements for additional information on acquisitions.
Financing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2017, net cash provided by financing activities was $194.5 million compared to $674.4 million for the same period of 2016. The change was predominantly attributable to the following:
A $201.7 million increase in borrowings on fixed-rate debt, resulting from the issuance of $200 million of 6.125% senior unsecured notes due 2024, including a premium issue price of 104.125% and net of payments of deferred financing costs
We had no issuance of common stock during the nine months ended September 30, 2017, a change of $722.7 million compared to the same period of 2016.
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| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results | |
Net cash provided by financing activities includes the following for the periods indicated (in millions):
|
| | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
| 2017 | | 2016 | | $ Change |
Net borrowings on senior secured revolving credit facility | $ | — |
| | $ | (40.0 | ) | | $ | 40.0 |
|
Issuance of 6.125% senior unsecured notes due 2024 | 200.0 |
| | — |
| | 200.0 |
|
Premium on the issuance of 6.125% senior unsecured notes due 2024 | 8.3 |
| | — |
| | 8.3 |
|
Issuance of common stock | — |
| | 722.7 |
| | (722.7 | ) |
Payment of preferred stock dividends | (5.5 | ) | | (5.5 | ) | | — |
|
Payment of deferred financing costs | (7.2 | ) | | (0.6 | ) | | (6.6 | ) |
Tax withholdings related to restricted stock units | (1.1 | ) | | (2.2 | ) | | 1.1 |
|
Net cash provided by financing activities | $ | 194.5 |
| | $ | 674.4 |
| | $ | (479.9 | ) |
See Notes 4 and 9 in the Footnotes to the Financial Statements for additional information on our debt and equity offerings.
Capital Plan and Year to Date 2017 Summary
Our operational capital budget for 2017 was established at $350 million on an accrual, or GAAP, basis, inclusive of a transition from a three-rig program that commenced in January 2017 to a four-rig program in July 2017 that includes horizontal development activity at our recent Delaware Basin acquisition (see Note 2 in the Footnotes to the Financial Statements for information on this acquisition).
In addition to the operational capital budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest expenses, both on an accrual, or GAAP, basis.
Operational capital expenditures on an accrual basis were $277.0 million for the nine months ended September 30, 2017. In addition to the operational capital expenditures, $14.0 million of capitalized general and administrative and $24.1 million of capitalized interest expenses were accrued in the nine months ended September 30, 2017. Based on current activity levels and service cost expectations, for full-year 2017 we estimate operational capital expenditures of approximately $375 million, net of the monetization of certain infrastructure assets, including natural gas gathering lines and saltwater disposal facilities.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, 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.
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| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results | |
Results of Operations
The following table setstables set forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, |
| | 2017 | | 2016 | | Change | | % Change |
Net production: | | | | | | | | |
Oil (MBbls) | | 1,591 |
| | 1,153 |
| | 438 |
| | 38 | % |
Natural gas (MMcf) | | 2,900 |
| | 2,244 |
| | 656 |
| | 29 | % |
Total (MBOE) | | 2,074 |
| | 1,527 |
| | 547 |
| | 36 | % |
Average daily production (BOE/d) | | 22,543 |
| | 16,598 |
| | 5,945 |
| | 36 | % |
% oil (BOE basis) | | 77 | % | | 76 | % | | | | |
Average realized sales price: | | | | | | | | |
Oil (Bbl) (excluding impact of cash settled derivatives) | | $ | 46.10 |
| | $ | 42.58 |
| | $ | 3.52 |
| | 8 | % |
Oil (Bbl) (including impact of cash settled derivatives) | | 45.24 |
| | 46.27 |
| | (1.03 | ) | | (2 | )% |
Natural gas (Mcf) (excluding impact of cash settled derivatives) | | $ | 3.88 |
| | $ | 3.04 |
| | $ | 0.84 |
| | 28 | % |
Natural gas (Mcf) (including impact of cash settled derivatives) | | 3.94 |
| | 2.97 |
| | 0.97 |
| | 33 | % |
Total (BOE) (excluding impact of cash settled derivatives) | | $ | 40.80 |
| | $ | 36.63 |
| | $ | 4.17 |
| | 11 | % |
Total (BOE) (including impact of cash settled derivatives) | | 40.21 |
| | 39.30 |
| | 0.91 |
| | 2 | % |
Oil and natural gas revenues (in thousands): | | | | | | | | |
Oil revenue | | $ | 73,349 |
| | $ | 49,095 |
| | $ | 24,254 |
| | 49 | % |
Natural gas revenue | | 11,265 |
| | 6,832 |
| | 4,433 |
| | 65 | % |
Total | | $ | 84,614 |
| | $ | 55,927 |
| | $ | 28,687 |
| | 51 | % |
Additional per BOE data: | | | | | | | | |
Sales price (excluding impact of cash settled derivatives) | | $ | 40.80 |
| | $ | 36.63 |
| | $ | 4.17 |
| | 11 | % |
Lease operating expense (excluding gathering and treating expense) | | 5.08 |
| | 6.16 |
| | (1.08 | ) | | (18 | )% |
Gathering and treating expense | | 0.52 |
| | 0.36 |
| | 0.16 |
| | 44 | % |
Production taxes | | 2.62 |
| | 2.28 |
| | 0.34 |
| | 15 | % |
Operating margin | | $ | 32.58 |
| | $ | 27.83 |
| | $ | 4.75 |
| | 17 | % |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, |
| | 2019 | | 2018 | | Change | | % Change |
Net production | | | | | | | | |
Oil (MBbls) | | 2,725 |
| | 2,521 |
| | 204 |
| | 8 | % |
Natural gas (MMcf) | | 4,538 |
| | 4,144 |
| | 394 |
| | 10 | % |
Total (MBOE) | | 3,481 |
| | 3,212 |
| | 269 |
| | 8 | % |
Average daily production (BOE/d) | | 37,837 |
| | 34,913 |
| | 2,924 |
| | 8 | % |
% oil (BOE basis) | | 78 | % | | 78 | % | | | | |
Average realized sales price (excluding impact of settled derivatives) | | | | | | | | |
Oil (per Bbl) | | $ | 54.39 |
| | $ | 56.57 |
| | $ | (2.18 | ) | | (4 | )% |
Natural gas (per Mcf) | | 1.58 |
| | 4.49 |
| | (2.91 | ) | | (65 | )% |
Total (per BOE) | | 44.64 |
| | 50.19 |
| | (5.55 | ) | | (11 | )% |
Average realized sales price (including impact of settled derivatives) | | | | | | | | |
Oil (per Bbl) | | $ | 54.01 |
| | $ | 52.87 |
| | $ | 1.14 |
| | 2 | % |
Natural gas (per Mcf) | | 2.03 |
| | 4.51 |
| | (2.48 | ) | | (55 | )% |
Total (per BOE) | | 44.93 |
| | 47.31 |
| | (2.38 | ) | | (5 | )% |
Oil and natural gas revenues (in thousands) | | |
| | |
| | |
| | |
|
Oil revenue | | $ | 148,210 |
| | $ | 142,601 |
| | $ | 5,609 |
| | 4 | % |
Natural gas revenue | | 7,168 |
| | 18,613 |
| | (11,445 | ) | | (61 | )% |
Total | | $ | 155,378 |
| | $ | 161,214 |
| | $ | (5,836 | ) | | (4 | )% |
Additional per BOE data | | |
| | | | |
| | |
|
Sales price (a) | | $ | 44.64 |
| | $ | 50.19 |
| | $ | (5.55 | ) | | (11 | )% |
Lease operating expense (b) | | 5.65 |
| | 5.77 |
| | (0.12 | ) | | (2 | )% |
Production taxes | | 3.41 |
| | 3.20 |
| | 0.21 |
| | 7 | % |
Operating margin | | $ | 35.58 |
| | $ | 41.22 |
| | $ | (5.64 | ) | | (14 | )% |
Benchmark prices | | | | | | | | |
WTI (per Bbl) | | $ | 56.34 |
| | $ | 69.69 |
| | $ | (13.35 | ) | | (19 | )% |
Henry Hub (per Mmbtu) | | 2.38 |
| | 2.93 |
| | (0.55 | ) | | (19 | )% |
| |
(a) | Excludes the impact of settled derivatives. |
| |
(b) | Excludes gathering and treating expense. |
|
| | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 | | Change | | % Change |
Net production: | | | | | | | | |
Oil (MBbls) | | 4,621 |
| | 2,993 |
| | 1,628 |
| | 54 | % |
Natural gas (MMcf) | | 7,878 |
| | 5,345 |
| | 2,533 |
| | 47 | % |
Total (MBOE) | | 5,934 |
| | 3,884 |
| | 2,050 |
| | 53 | % |
Average daily production (BOE/d) | | 21,736 |
| | 14,175 |
| | 7,561 |
| | 53 | % |
% oil (BOE basis) | | 78 | % | | 77 | % | | | | |
Average realized sales price: | | | | | | | | |
Oil (Bbl) (excluding impact of cash settled derivatives) | | $ | 47.23 |
| | $ | 39.12 |
| | $ | 8.11 |
| | 21 | % |
Oil (Bbl) (including impact of cash settled derivatives) | | 46.32 |
| | 44.29 |
| | 2.03 |
| | 5 | % |
Natural gas (Mcf) (excluding impact of cash settled derivatives) | | $ | 3.81 |
| | $ | 2.75 |
| | $ | 1.06 |
| | 39 | % |
Natural gas (Mcf) (including impact of cash settled derivatives) | | 3.84 |
| | 2.81 |
| | 1.03 |
| | 37 | % |
Total (BOE) (excluding impact of cash settled derivatives) | | $ | 41.84 |
| | $ | 33.93 |
| | $ | 7.91 |
| | 23 | % |
Total (BOE) (including impact of cash settled derivatives) | | 41.17 |
| | 38.00 |
| | 3.17 |
| | 8 | % |
Oil and natural gas revenues (in thousands): | | | | | | | | |
Oil revenue | | $ | 218,242 |
| | $ | 117,093 |
| | $ | 101,149 |
| | 86 | % |
Natural gas revenue | | 30,019 |
| | 14,677 |
| | 15,342 |
| | 105 | % |
Total | | $ | 248,261 |
| | $ | 131,770 |
| | $ | 116,491 |
| | 88 | % |
Additional per BOE data: | | | | | | | | |
Sales price (excluding impact of cash settled derivatives) | | $ | 41.84 |
| | $ | 33.93 |
| | $ | 7.91 |
| | 23 | % |
Lease operating expense (excluding gathering and treating expense) | | 5.72 |
| | 5.96 |
| | (0.24 | ) | | (4 | )% |
Gathering and treating expense | | 0.47 |
| | 0.28 |
| | 0.19 |
| | 68 | % |
Production taxes | | 2.72 |
| | 2.10 |
| | 0.62 |
| | 30 | % |
Operating margin | | $ | 32.93 |
| | $ | 25.59 |
| | $ | 7.34 |
| | 29 | % |
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
|
| | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 | | Change | | % Change |
Net production | | | | | | | | |
Oil (MBbls) | | 8,431 |
| | 6,368 |
| | 2,063 |
| | 32 | % |
Natural gas (MMcf) | | 14,188 |
| | 11,222 |
| | 2,966 |
| | 26 | % |
Total (MBOE) | | 10,796 |
| | 8,238 |
| | 2,558 |
| | 31 | % |
Average daily production (BOE/d) | | 39,546 |
| | 30,176 |
| | 9,370 |
| | 31 | % |
% oil (BOE basis) | | 78 | % | | 77 | % | | | | |
Average realized sales price (excluding impact of settled derivatives) | | | | | | | | |
Oil (per Bbl) | | $ | 53.38 |
| | $ | 59.75 |
| | $ | (6.37 | ) | | (11 | )% |
Natural gas (per Mcf) | | 1.79 |
| | 4.03 |
| | (2.24 | ) | | (56 | )% |
Total (per BOE) | | 44.04 |
| | 51.68 |
| | (7.64 | ) | | (15 | )% |
Average realized sales price (including impact of settled derivatives) | | | | | | | | |
Oil (per Bbl) | | $ | 52.54 |
| | $ | 55.61 |
| | $ | (3.07 | ) | | (6 | )% |
Natural gas (per Mcf) | | 2.26 |
| | 4.09 |
| | (1.83 | ) | | (45 | )% |
Total (per BOE) | | 44.00 |
| | 48.56 |
| | (4.56 | ) | | (9 | )% |
Oil and natural gas revenues (in thousands) | | | | | | | | |
Oil revenue | | $ | 450,036 |
| | $ | 380,500 |
| | $ | 69,536 |
| | 18 | % |
Natural gas revenue | | 25,441 |
| | 45,229 |
| | (19,788 | ) | | (44 | )% |
Total | | $ | 475,477 |
| | $ | 425,729 |
| | $ | 49,748 |
| | 12 | % |
Additional per BOE data | | | | | | | | |
Sales price (a) | | $ | 44.04 |
| | $ | 51.68 |
| | $ | (7.64 | ) | | (15 | )% |
Lease operating expense (b) | | 6.16 |
| | 5.43 |
| | 0.73 |
| | 13 | % |
Production taxes | | 3.13 |
| | 3.19 |
| | (0.06 | ) | | (2 | )% |
Operating margin | | $ | 34.75 |
| | $ | 43.06 |
| | $ | (8.31 | ) | | (19 | )% |
Benchmark prices | | | | | | | | |
WTI (per Bbl) | | $ | 57.04 |
| | $ | 66.93 |
| | $ | (9.89 | ) | | (15 | )% |
Henry Hub (per Mmbtu) | | 2.62 |
| | 2.95 |
| | (0.33 | ) | | (11 | )% |
| |
(a) | Excludes the impact of settled derivatives. |
| |
(b) | Excludes gathering and treating expense. |
|
| | |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Revenues
The following table reconcilestables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices.
|
| | | | | | | | | | | | |
(in thousands) | | Oil | | Natural Gas | | Total |
Revenues for the three months ended September 30, 2016 | | $ | 49,095 |
| | $ | 6,832 |
| | $ | 55,927 |
|
Volume increase | | 18,650 |
| | 1,994 |
| | 20,644 |
|
Price increase | | 5,604 |
| | 2,439 |
| | 8,043 |
|
Net increase | | 24,254 |
| | 4,433 |
| | 28,687 |
|
Revenues for the three months ended September 30, 2017 | | $ | 73,349 |
| | $ | 11,265 |
| | $ | 84,614 |
|
| | | | | | |
(in thousands) | | Oil | | Natural Gas | | Total |
Revenues for the nine months ended September 30, 2016 | | $ | 117,093 |
| | $ | 14,677 |
| | $ | 131,770 |
|
Volume increase | | 63,687 |
| | 6,966 |
| | 70,653 |
|
Price increase | | 37,462 |
| | 8,376 |
| | 45,838 |
|
Net increase | | 101,149 |
| | 15,342 |
| | 116,491 |
|
Revenues for the nine months ended September 30, 2017 | | $ | 218,242 |
| | $ | 30,019 |
| | $ | 248,261 |
|
|
| | | | | | | | | | | | |
(in thousands) | | Oil | | Natural Gas | | Total |
Revenues for the three months ended September 30, 2018 | | $ | 142,601 |
| | $ | 18,613 |
| | $ | 161,214 |
|
Volume increase | | 11,540 |
| | 1,769 |
| | 13,309 |
|
Price decrease | | (5,931 | ) | | (13,214 | ) | | (19,145 | ) |
Net increase (decrease) | | 5,609 |
| | (11,445 | ) | | (5,836 | ) |
Revenues for the three months ended September 30, 2019 | | $ | 148,210 |
| | $ | 7,168 |
| | $ | 155,378 |
|
|
| | | | | | | | | | | | |
(in thousands) | | Oil | | Natural Gas | | Total |
Revenues for the nine months ended September 30, 2018 | | $ | 380,500 |
| | $ | 45,229 |
| | $ | 425,729 |
|
Volume increase | | 123,264 |
| | 11,953 |
| | 135,217 |
|
Price decrease | | (53,728 | ) | | (31,741 | ) | | (85,469 | ) |
Net increase (decrease) | | 69,536 |
| | (19,788 | ) | | 49,748 |
|
Revenues for the nine months ended September 30, 2019 | | $ | 450,036 |
| | $ | 25,441 |
| | $ | 475,477 |
|
Commodityprices
The prices for oil and natural gas can beremain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by the Organization of Petroleum Exporting Countries and other countries and government actions. Prices of oil and natural gas 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 our Credit Facility; and
the value of our oil and natural gas properties.
Oil revenue
For the three and nine months ended September 30, 2017, the average NYMEX price for a barrel of oil was $48.20 and $49.36 per Bbl compared to $44.94 and $41.47 per Bbl for the same periods of 2016, respectively. The NYMEX price for a barrel of oil for the three and nine months ended September 30, 2017 ranged from a low of $44.23 per Bbl to a high of $47.29 per Bbl and a low of $42.53 per Bbl to a high of $54.45 Bbl, respectively.
For the three and nine months ended September 30, 2017, the average NYMEX price for natural gas was $3.00 and $3.17 per MMBtu compared to $2.81 and $2.29 per MMBtu for the same periods of 2016. The NYMEX price for natural gas for the three and nine months ended September 30, 2017 ranged from a low of $2.77 per MMBtu to a high of $3.15 per MMBtu and a low of $2.56 per MMBtu to a high of $3.42 MMBtu, respectively.
Oil revenue
For the quarter ended September 30, 2017,2019, oil revenues of $73.3$148.2 millionincreased $24.2$5.6 million, or 49%4%, compared to revenues of $49.1$142.6 million for the same period of 2016.2018. The increase in oil revenue was primarily attributable to a 38%an 8% increase in production from our acquisition and an 8% increasedevelopment efforts, offset by a 4% decrease in the average realized sales price, which rosefell to $46.10$54.39 per Bbl in the third quarter of 2017 from $42.58$56.57 per Bbl in the third quarter of 2016. The increase in production was attributable to 633 MBbls from wells placed on production as a result of our horizontal drilling program and 241 MBbls from producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells. Bbl.
For the nine months ended September 30, 2017,2019, oil revenues of $218.2$450.0 million increased $101.1$69.5 million, or 86%18%, compared to revenues of $117.1$380.5 million for the same period of 2016.2018. The increase in oil revenue was primarily attributable to a 54%32% increase in production from our acquisition and a 21% increasedevelopment efforts, offset by an 11% decrease in the average realized sales price, which rosefell to $47.23$53.38 per Bbl from $59.75 per Bbl.
Natural gas revenue (including NGLs)
For the three months ended September 30, 2019, natural gas revenues of $7.2 million decreased $11.4 million, or 61%, compared to $18.6 million for the same period of 2018. The decrease was primarily attributable to a 65% decrease in the average realized sales price,which fell to $1.58 per Mcf from $4.49 per Mcf. The decrease in realized natural gas pricing was partially offset by a 10% increase in natural gas volumes.
For the nine months ended September 30, 2017 from $39.12 per Bbl2019, natural gas revenues of $25.4 million decreased $19.8 million, or 44%, compared to $45.2 million for the same period of 2016.2018. The decrease was primarily attributable to a 56% decrease in the average realized sales price,which fell to $1.79 per Mcf from $4.03 per Mcf. The decrease in realized natural gas pricing was partially offset by a 26% increase in production was comprised of 1,612 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 669 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.natural gas volumes.
See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions. |
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Natural gas revenue (including NGLs)
Natural gas revenues of $11.3 million increased $4.4 million, or 66%, during the three months ended September 30, 2017, compared to $6.8 million for the same period of 2016. The increase primarily relates to a 29% increase in natural gas volumes and a 28% increase in the average realized sales price, which rose to $3.88 per Mcf from $3.04 per Mcf, reflecting both natural gas and natural gas liquids prices. The increase in production was comprised of 735 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 287 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.
Natural gas revenues of $30.0 million increased $15.3 million, or 105%, during the nine months ended September 30, 2017, compared to $14.7 million for the same period of 2016. The increase primarily relates to a 47% increase in natural gas volumes and a 39% increase in the average realized sales price, which rose to $3.81 per Mcf from $2.75 per Mcf, reflecting both natural gas and natural gas liquids prices. The increase in production was comprised of 1,785 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 806 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.
See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
Operating Expenses
| | | | | Three Months Ended September 30, |
| | | | | | | | | | | | | | | | | | | | | Per | | | | Per | | Total Change | | BOE Change |
(in thousands, except per unit amounts) | | Three Months Ended September 30, | | 2019 | | BOE | | 2018 | | BOE | | $ | | % | | $ | | % |
| | | | Per | | | | Per | | Total Change | | BOE Change | |
| | 2017 | | BOE | | 2016 | | BOE | | $ | | % | | $ | | % | |
Lease operating expenses | | $ | 11,624 |
| | $ | 5.60 |
| | $ | 9,961 |
| | $ | 6.52 |
| | $ | 1,663 |
| | 17 | % | | $ | (0.92 | ) | | (14 | )% | | $ | 19,668 |
| | $ | 5.65 |
| | $ | 18,525 |
| | $ | 5.77 |
| | $ | 1,143 |
| | 6 | % | | $ | (0.12 | ) | | (2 | )% |
Production taxes | | 5,444 |
| | 2.62 |
| | 3,478 |
| | 2.28 |
| | 1,966 |
| | 57 | % | | 0.34 |
| | 15 | % | | 11,866 |
| | 3.41 |
| | 10,263 |
| | 3.20 |
| | 1,603 |
| | 16 | % | | 0.21 |
| | 7 | % |
Depreciation, depletion and amortization | | 28,525 |
| | 13.75 |
| | 17,303 |
| | 11.33 |
| | 11,222 |
| | 65 | % | | 2.42 |
| | 21 | % | | 56,002 |
| | 16.09 |
| | 48,257 |
| | 15.02 |
| | 7,745 |
| | 16 | % | | 1.07 |
| | 7 | % |
General and administrative | | 7,259 |
| | 3.50 |
| | 7,891 |
| | 5.17 |
| | (632 | ) | | (8 | )% | | (1.67 | ) | | (32 | )% | | 9,388 |
| | 2.70 |
| | 9,721 |
| | 3.03 |
| | (333 | ) | | (3 | )% | | (0.33 | ) | | (11 | )% |
Merger and integration expense | | | 5,943 |
| | 1.71 |
| | — |
| | — |
| | 5,943 |
| | 100 | % | | 1.71 |
| | 100 | % |
Accretion expense | | 131 |
| | 0.06 |
| | 187 |
| | 0.12 |
| | (56 | ) | | (30 | )% | | (0.06 | ) | | (50 | )% | | 128 |
| | 0.04 |
| | 202 |
| | 0.06 |
| | (74 | ) | | (37 | )% | | (0.02 | ) | | (33 | )% |
Acquisition expense | | 205 |
| | nm |
| | 456 |
| | nm |
| | (251 | ) | | nm |
| | nm |
| | nm |
| |
| | | | | | | | | | | | | | | | | |
(in thousands, except per unit amounts) | | Nine Months Ended September 30, | |
| | | | Per | | | | Per | | Total Change | | BOE Change | |
| | 2017 | | BOE | | 2016 | | BOE | | $ | | % | | $ | | % | |
Lease operating expenses | | $ | 36,708 |
| | $ | 6.19 |
| | $ | 24,229 |
| | $ | 6.24 |
| | $ | 12,479 |
| | 52 | % | | $ | (0.05 | ) | | (1 | )% | |
Production taxes | | 16,168 |
| | 2.72 |
| | 8,153 |
| | 2.10 |
| | 8,015 |
| | 98 | % | | 0.62 |
| | 30 | % | |
Depreciation, depletion and amortization | | 79,172 |
| | 13.34 |
| | 49,318 |
| | 12.70 |
| | 29,854 |
| | 61 | % | | 0.64 |
| | 5 | % | |
General and administrative | | 18,894 |
| | 3.18 |
| | 19,755 |
| | 5.09 |
| | (861 | ) | | (4 | )% | | (1.91 | ) | | (38 | )% | |
Settled share-based awards | | 6,351 |
| | nm |
| | — |
| | nm |
| | 6,351 |
| | nm |
| | nm |
| | nm |
| |
Accretion expense | | 523 |
| | 0.09 |
| | 762 |
| | 0.20 |
| | (239 | ) | | (31 | )% | | (0.11 | ) | | (55 | )% | |
Write-down of oil and natural gas properties | | — |
| | nm |
| | 95,788 |
| | nm |
| | (95,788 | ) | | nm |
| | nm |
| | nm |
| |
Acquisition expense | | 3,027 |
| | nm |
| | 2,410 |
| | nm |
| | 617 |
| | nm |
| | nm |
| | nm |
| |
Other operating expense | | | (161 | ) | | (0.05 | ) | | 1,435 |
| | 0.45 |
| | (1,596 | ) | | (111 | )% | | (0.50 | ) | | (111 | )% |
nm = not meaningful
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | | | Per | | | | Per | | Total Change | | BOE Change |
(in thousands, except per unit amounts) | | 2019 | | BOE | | 2018 | | BOE | | $ | | % | | $ | | % |
Lease operating expenses | | $ | 66,511 |
| | $ | 6.16 |
| | $ | 44,705 |
| | $ | 5.43 |
| | $ | 21,806 |
| | 49 | % | | $ | 0.73 |
| | 13 | % |
Production taxes | | 33,810 |
| | 3.13 |
| | 26,265 |
| | 3.19 |
| | 7,545 |
| | 29 | % | | (0.06 | ) | | (2 | )% |
Depreciation, depletion and amortization | | 178,690 |
| | 16.55 |
| | 122,407 |
| | 14.86 |
| | 56,283 |
| | 46 | % | | 1.69 |
| | 11 | % |
General and administrative | | 31,705 |
| | 2.94 |
| | 26,779 |
| | 3.25 |
| | 4,926 |
| | 18 | % | | (0.31 | ) | | (10 | )% |
Merger and integration expense | | 5,943 |
| | 0.55 |
| | — |
| | — |
| | 5,943 |
| | 100 | % | | 0.55 |
| | 100 | % |
Settled share-based awards | | 3,024 |
| | 0.28 |
| | — |
| | — |
| | 3,024 |
| | 100 | % | | 0.28 |
| | 100 | % |
Accretion expense | | 585 |
| | 0.05 |
| | 626 |
| | 0.08 |
| | (41 | ) | | (7 | )% | | (0.03 | ) | | (38 | )% |
Other operating expense | | 931 |
| | 0.09 |
| | 3,750 |
| | 0.46 |
| | (2,819 | ) | | (75 | )% | | (0.37 | ) | | (80 | )% |
Lease operating expenses (“LOE”). These are daily costs incurred to extract oil and natural gas together with the daily costs incurred toand 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.
ForLOE for the three months ended September 30, 2017, LOE2019 increased by 17% to $11.6$19.7 million compared to $10.0$18.5 million for the same period of 2016. Contributing2018. The increase in LOE primarily related to an 8% increase in production over the comparative periods.
LOE on a per unit basis decreased when comparing the third quarter of 2019 to the increase was $2.3 million related to oil and natural gas properties acquired during 2016 and the first half of 2017 (see Note 2same period in the Footnotes to the Financial Statements). For the three months ended September 30, 2017,2018. LOE per BOE decreased to $5.60$5.65 for the third quarter of 2019, which represents a decrease of $0.12 per BOE from the third quarter of 2018.
LOE for the nine months ended September 30, 2019 increased to $66.5 million compared to $6.52 per BOE$44.7 million for the same period of 2016, which was primarily attributable to higher production volumes offset by an increase in cost as previously discussed.2018. The increase in LOE primarily related to a 31% increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. over the comparative periods.
For the nine months ended September 30, 2017,2019, LOE on a per unit basis increased by 52% to $36.7 million compared to $24.2 million for the same period of 2016. Contributing to the increase was $10.1 million related to oil and natural gas properties acquired during 2016 and the first half of 2017 (see Note 2 in the Footnotes to the Financial Statements). Excluding LOE related to these acquired properties, LOE increased
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results | |
by $2.4 million, or 10%, compared to the same period of 2016, which was primarily due to an increase in cost driven by higher production volumes from our legacy assets. For the nine months ended September 30, 2017, LOE per BOE decreased to $6.19$6.16 per BOE compared to $6.24$5.43 per BOE for the same period of 2016, which was2018 primarily attributabledue to higher production volumes offset by an increase in cost as previously discussed. The increase in production was primarily attributableincreased non-operated activity related to an increased number of producing wells from our horizontal drilling programprevious acquisitions and acquisitions as discussed above. workovers.
Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, 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. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. 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.
Production taxes for the three months ended September 30, 20172019 increased by 57%16% to $5.4$11.9 million compared to $3.5$10.3 million for the same period of 2016. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. Also contributing to the increase was an increase in ad valorem taxes, which was attributable to an increase in the valuation of our oil and gas properties by taxing jurisdictions as a result of an increased number of producing wells from our horizontal drilling program, acquisitions as discussed above, and an increase in commodity prices year over year.2018. On a per BOE basis, production taxes for the three months ended September 30, 20172019 increased by 15%7% compared to the same period of 2016.2018.The increase in production taxes is partially due to higher severance taxes as a result of higher revenues. Severance taxes as a percentage of total revenue were consistent across the comparable periods at approximately 5%. Additionally, ad valorem taxes increased $2.2 million over the comparative periods due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions.
Production taxes for the nine months ended September 30, 20172019 increased by 98%29% to $16.2$33.8 million compared to $8.2$26.3 million for the same period of 2016. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. Also contributing to the increase was an increase in ad valorem taxes, which was attributable to an increase in the valuation of our oil and gas properties by taxing jurisdictions as a result of an increased number of producing wells from our horizontal drilling program, acquisitions as discussed above, and an increase in commodity prices year over year.2018. On a per BOE basis, production taxes for the threenine months ended September 30, 2017 increased2019 decreased by 30%2% compared to the same period of 2016.2018. The increase in production taxes is partially due to higher severance taxes as a result of higher revenues. Severance
|
| | |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
taxes as a percentage of total revenue were relatively unchanged across the comparable periods at approximately 5%. Additionally, ad valorem taxes increased $5.8 million over the comparative periods due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions.
Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation
DD&A rates fluctuate as a result of other propertychanges in finding and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
development costs, acquisitions, impairments, and changes in proved reserves. For the three months ended September 30, 2017,2019, DD&A increased 65% to $28.5expense was $56.0 million compared to $17.3$48.3 million for the same period of 2016.2018. The increase is primarily attributableadditional DD&A was related to a 36%8% increase in production and a 21% increase in our per BOEvolumes combined with higher DD&A rate. rates between the periods, which resulted in $4.0 million and $3.7 million, respectively, of incremental DD&A expense being incurred during the third quarter of 2019.
For the three months ended September 30, 2017,2019, DD&A on a per unit basis increased to $13.75$16.09 per BOE compared to $11.33$15.02 per BOE for the same period of 2016.2018. The increase is attributableprimary factor contributing to greater increases in our depreciable basethe increased DD&A rate were higher drilling and assumed future developmentcompletion costs to undeveloped proved reservesfor new wells placed on production over the past 12 months relative to our historical rate. Additionally, the rate increase in our estimated proved reserve base. The increases in our depreciable base, assumed future development costs and estimated proved reserve base area result of additions made through our horizontal drilling efforts and acquisitions.can be partially attributed to recent dispositions with a lower relative cost per BOE.
For the nine months ended September 30, 2017,2019, DD&A increased 61% to $79.2expense was $178.7 million compared to $49.3$122.4 million for the same period of 2016.2018. The increase is primarily attributableadditional DD&A was related to a 53%31% increase in production and a 5% increase in our per BOEvolumes combined with higher DD&A rate. Forrates between the periods, which resulted in $38.0 million and $18.3 million, respectively, of incremental DD&A expense being incurred during the nine months ended September 30, 2017, DD&A on2019.
On a per unit basis DD&A increased to $13.34$16.55 per BOE compared to $12.70$14.86 per BOE for the same period of 2016. The increase2018. As discussed above, the increased DD&A rate is attributable to our increased estimated proved reservesa function of recent drilling and completion costs incurred over the past 12 months relative to our depreciable base and assumed future development costs relatedhistorical rate. Additionally, the rate increase can be partially attributed to undeveloped proved reserves asrecent dispositions with a result of additions made through our horizontal drilling efforts and acquisitions, offset by the write down of oil and natural gas properties in the first half of 2016.lower relative cost per BOE.
General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results | |
G&A for the three months ended September 30, 20172019 decreased to $7.3$9.4 million compared to $7.9$9.7 million for the same period of 2016.2018. On a per unit basis, G&A decreased 11% to $2.70 per BOE for the three months ended September 30, 2019 compared to $3.03 per BOE for the same period in 2018. G&A expenses for the periods indicated include the following (in millions)thousands):
| | | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2017 | | 2016 | | $ Change | | % Change | | 2019 | | 2018 | | $ Change | | % Change |
Recurring expenses | | | | | | | | | | | | | | | | |
G&A | | $ | 5.3 |
| | $ | 3.8 |
| | $ | 1.5 |
| | 39 | % | | $ | 8,789 |
| | $ | 7,070 |
| | $ | 1,719 |
| | 24 | % |
Share-based compensation | | 1.2 |
| | 0.8 |
| | 0.4 |
| | 50 | % | | 1,525 |
| | 1,730 |
| | (205 | ) | | (12 | )% |
Fair value adjustments of cash-settled RSU awards | | 0.7 |
| | 3.4 |
| | (2.7 | ) | | (79 | )% | | (926 | ) | | 921 |
| | (1,847 | ) | | (201 | )% |
Total G&A expenses | | $ | 7.2 |
| | $ | 8.0 |
| | $ | (0.8 | ) | | (10 | )% | | $ | 9,388 |
| | $ | 9,721 |
| | $ | (333 | ) | | (3 | )% |
G&A for the nine months ended September 30, 2017 decreased2019 increased to $18.9$31.7 million compared to $19.8$26.8 million for the same period of 2016.2018. The increase is primarily attributable to a rise in personnel costs resulting from the growth in our operating activities.On a per unit basis, G&A decreased 10% to $2.94 per BOE for the nine months ended September 30, 2019 compared to $3.25 per BOE for the same period in 2018. G&A expenses for the periods indicated include the following (in millions)thousands):
| | | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | $ Change | | % Change | | 2019 | | 2018 | | $ Change | | % Change |
Recurring expenses | | | | | | | | | | | | | | | | |
G&A | | $ | 15.4 |
| | $ | 11.6 |
| | $ | 3.8 |
| | 33 | % | | $ | 26,889 |
| | $ | 20,929 |
| | $ | 5,960 |
| | 28 | % |
Share-based compensation | | 3.1 |
| | 1.9 |
| | 1.2 |
| | 63 | % | | 4,712 |
| | 4,422 |
| | 290 |
| | 7 | % |
Fair value adjustments of cash-settled RSU awards | | (0.1 | ) | | 6.0 |
| | (6.1 | ) | | (102 | )% | | 104 |
| | 1,428 |
| | (1,324 | ) | | (93 | )% |
Non-recurring expenses | | | | | | | | | |
Early retirement expenses | | 0.4 |
| | — |
| | 0.4 |
| | 100 | % | |
Early retirement expenses related to share-based compensation | | 0.1 |
| | — |
| | 0.1 |
| | 100 | % | |
Expense related to a threatened proxy contest | | — |
| | 0.2 |
| | (0.2 | ) | | (100 | )% | |
Total G&A expenses | | $ | 18.9 |
| | $ | 19.7 |
| | $ | (0.8 | ) | | (4 | )% | | $ | 31,705 |
| | $ | 26,779 |
| | $ | 4,926 |
| | 18 | % |
Settled share-based awards. In June 2017, the Company settled the outstanding share-based award agreements of its former Chief Executive Officer, resulting in $6.4 million recorded on the Consolidated Statements of Operations as Settled share-based awards.
AccretionMerger and integration expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the consolidated statements of operations.
Accretion expense related to our ARO decreased 30% and 31% for For the three and nine months ended September 30, 2017, compared to2019, the same periodCompany incurred $5.9 million of 2016. Accretion expense generally correlatesassociated with the Company’s ARO, which was $5.0 million at September 30, 2017 as compared to $5.5 million at September 30, 2016. See Note 8 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.planned merger with Carrizo Oil & Gas, Inc.
Acquisition expense. Acquisition expense for all periods was related to costs with respect to our acquisition efforts in the Permian Basin. See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
Write-down of oil and natural gas properties. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling.
For the comparative three months ended September 30, 2017 and 2016, the Company did not recognize write-downs of oil and natural gas properties. For the nine months ended September 30, 2017, the Company did not recognize a write-down of oil and natural gas properties compared to a write-down of $95.8 million for the nine months ended September 30, 2016, as a result of the ceiling test limitation. At September 30, 2017, the average prices used in determining the estimated future net cash flows from proved reserves were $49.81 per barrel of oil and $3.00 per Mcf of natural gas. If commodity prices were to decline, we could incur additional ceiling test write-downs in the future.
The table below presents the cumulative results of the full cost ceiling test along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling to changes in 12-month average oil and natural gas prices. This sensitivity analysis is as of September 30, 2017, and accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
development and operating costs subsequent to September 30, 2017 that may require revisions to our proved reserve estimates andSettled 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 estimated future net cash flows used in the full cost ceiling test.$3.0 million recorded on the consolidated statements of operations as settled share-based awards.
|
| | | | | | | | | | | | |
| | 12-Month Average Prices | | | | Excess (Deficit) of Full Cost Ceiling Over Net Capitalized Costs |
Pricing Scenarios | | Oil ($/Bbl) | | Natural gas ($/Mcf) | | (in thousands) |
September 30, 2017 Actual | | $ | 49.81 |
| | $ | 3.00 |
| | $ | 235,000 |
|
Combined price sensitivity | | | | | | |
Oil and natural gas +10% | | $ | 54.79 |
| | $ | 3.30 |
| | $ | 496,690 |
|
Oil and natural gas -10% | | $ | 44.83 |
| | $ | 2.70 |
| | (26,166 | ) |
Oil price sensitivity | | | | | | |
Oil +10% | | $ | 54.79 |
| | $ | 3.00 |
| | $ | 472,126 |
|
Oil -10% | | $ | 44.83 |
| | 3.00 |
| | (1,603 | ) |
Natural gas sensitivity | | | | | | |
Natural gas +10% | | $ | 49.81 |
| | $ | 3.30 |
| | $ | 259,825 |
|
Natural gas -10% | | 49.81 |
| | $ | 2.70 |
| | 210,698 |
|
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results | |
Other Income and Expenses and Preferred Stock Dividends
| | | | | | | | | | | | Three Months Ended September 30, |
(in thousands) | | Three Months Ended September 30, | | 2019 | | 2018 | | $ Change | | % Change |
| | 2017 | | 2016 | | $ Change | | % Change | |
Interest expense | | | $ | 18,869 |
| | $ | 17,244 |
| | $ | 1,625 |
| | 9 | % |
Capitalized interest | | | (18,130 | ) | | (16,533 | ) | | (1,597 | ) | | 10 | % |
Interest expense, net of capitalized amounts | | $ | 444 |
| | $ | 831 |
| | $ | (387 | ) | | (47 | )% | | 739 |
| | 711 |
| | 28 |
| | 4 | % |
(Gain) loss on derivative contracts | | 14,162 |
| | (5,135 | ) | | 19,297 |
| | (376 | )% | | (21,809 | ) | | 34,339 |
| | (56,148 | ) | | (164 | )% |
Other income | | (498 | ) | | (122 | ) | | (376 | ) | | 308 | % | | (122 | ) | | (1,657 | ) | | 1,535 |
| | (93 | )% |
Total | | $ | 14,108 |
| | $ | (4,426 | ) | | | | | |
Total other (income) expense | | | $ | (21,192 | ) | | $ | 33,393 |
| | $ | (54,585 | ) | | (163 | )% |
| | | | | | | | | | | | | | | | |
Income tax (benefit) expense | | $ | 237 |
| | $ | (62 | ) | | $ | 299 |
| | (482 | )% | |
Income tax expense | | | $ | 17,902 |
| | $ | 1,487 |
| | $ | 16,415 |
| | 1,104 | % |
Preferred stock dividends | | (1,824 | ) | | (1,824 | ) | | — |
| | — | % | | (350 | ) | | (1,823 | ) | | 1,473 |
| | (81 | )% |
| | | | | | | | | |
(in thousands) | | Nine Months Ended September 30, | |
| | 2017 | | 2016 | | $ Change | | % Change | |
Interest expense, net of capitalized amounts | | $ | 1,698 |
| | $ | 10,502 |
| | $ | (8,804 | ) | | (84 | )% | |
(Gain) loss on derivative contracts | | (11,636 | ) | | 11,281 |
| | (22,917 | ) | | (203 | )% | |
Other income | | (1,270 | ) | | (299 | ) | | (971 | ) | | 325 | % | |
Total | | $ | (11,208 | ) | | $ | 21,484 |
| | | | | |
| | | | | | | | | |
Income tax (benefit) expense | | $ | 1,026 |
| | $ | (62 | ) | | $ | 1,088 |
| | (1,755 | )% | |
Preferred stock dividends | | (5,471 | ) | | (5,471 | ) | | — |
| | — | % | |
Loss on redemption of preferred stock | | | (8,304 | ) | | — |
| | (8,304 | ) | | (100 | )% |
|
| | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
(in thousands) | | 2019 | | 2018 | | $ Change | | % Change |
Interest expense | | $ | 58,929 |
| | $ | 40,416 |
| | $ | 18,513 |
| | 46 | % |
Capitalized interest | | (56,711 | ) | | (38,651 | ) | | (18,060 | ) | | 47 | % |
Interest expense, net of capitalized amounts | | 2,218 |
| | 1,765 |
| | 453 |
| | 26 | % |
(Gain) loss on derivative contracts | | 31,415 |
| | 55,374 |
| | (23,959 | ) | | (43 | )% |
Other income | | (270 | ) | | (2,571 | ) | | 2,301 |
| | (89 | )% |
Total other (income) expense | | $ | 33,363 |
| | $ | 54,568 |
| | $ | (21,205 | ) | | (39 | )% |
| | | | | | | | |
Income tax expense | | $ | 29,444 |
| | $ | 2,463 |
| | $ | 26,981 |
| | 1,095 | % |
Preferred stock dividends | | (3,997 | ) | | (5,471 | ) | | 1,474 |
| | (27 | )% |
Loss on redemption of preferred stock | | $ | (8,304 | ) | | $ | — |
| | $ | (8,304 | ) | | (100 | )% |
Interest expense, net of capitalized amounts.amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements capital expenditures and acquisitions 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 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 three months ended September 30, 2017 decreased $0.42019 increased $0.0 million to $0.7 million compared to $0.7 million for the same period of 2016. The decrease is primarily attributable to a $2.4 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the three months ended September 30, 2017 as compared to the same period of 2016. The increase in unevaluated property was primarily due to acquired properties. Offsetting the decrease was a $2.0 million increase in interest expense on our Credit Facility and term debt.
2018. Interest expense, net of capitalized amounts, incurred during the nine months ended September 30, 2017 decreased $8.82019 increased $0.5 million to $2.2 million compared to $1.8 million for the same period of 2016. The decrease is primarily attributable to a $10.9 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the nine months ended September 30, 2017 as compared to the same period of 2016. The increase in unevaluated property was primarily due to acquired properties. Offsetting the decrease was a $2.1 million increase in interest expense on our Credit Facility and term debt.2018.
See Notes 2 and 4 in the Footnotes to the Financial Statements for additional information on our acquisitions and debt. |
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Gain (loss) on derivative instruments. 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.
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results | |
For the three months ended September 30, 2017, the net loss on derivative contracts was $14.2 million compared to a $5.1 million net gain for the same period of 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions)thousands):
| | | Three Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | 2019 | | 2018 | | 2019 | | 2018 |
Oil derivatives | | | | | | | | | | |
Net gain (loss) on settlements | $ | (1.4 | ) | | $ | 4.2 |
| $ | (1,045 | ) | | $ | (9,306 | ) | | $ | (7,048 | ) | | $ | (26,353 | ) |
Net gain (loss) on fair value adjustments | (12.8 | ) | | 0.7 |
| 25,767 |
| | (24,476 | ) | | (27,750 | ) | | (28,720 | ) |
Total gain (loss) on oil derivatives | $ | (14.2 | ) | | $ | 4.9 |
| 24,722 |
| | (33,782 | ) | | (34,798 | ) | | (55,073 | ) |
Natural gas derivatives | | | | | | | | | | |
Net gain on settlements | $ | 0.1 |
| | $ | (0.2 | ) | |
Net gain (loss) on settlements | | 2,056 |
| | 67 |
| | 6,612 |
| | 675 |
|
Net gain (loss) on fair value adjustments | (0.1 | ) | | 0.4 |
| (733 | ) | | (624 | ) | | (2,306 | ) | | (976 | ) |
Total gain (loss) on natural gas derivatives | $ | — |
| | $ | 0.2 |
| 1,323 |
| | (557 | ) | | 4,306 |
| | (301 | ) |
| | | | |
Total gain (loss) on oil & natural gas derivatives | $ | (14.2 | ) | | $ | 5.1 |
| |
Contingent consideration arrangement | | | | | | | | |
Net gain (loss) on fair value adjustments | | (4,236 | ) | | — |
| | (923 | ) | | — |
|
Total gain (loss) on derivatives | | $ | 21,809 |
| | $ | (34,339 | ) | | $ | (31,415 | ) | | $ | (55,374 | ) |
For the nine months ended September 30, 2017, the net gain on derivative contracts was $11.6 million compared to a $11.3 million net loss for the same period of 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions):
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Oil derivatives | | | |
Net gain (loss) on settlements | $ | (4.2 | ) | | $ | 15.5 |
|
Net gain (loss) on fair value adjustments | 14.6 |
| | (26.9 | ) |
Total gain (loss) on oil derivatives | $ | 10.4 |
| | $ | (11.4 | ) |
Natural gas derivatives | | | |
Net gain on settlements | $ | 0.2 |
| | $ | 0.4 |
|
Net gain (loss) on fair value adjustments | 1.0 |
| | (0.2 | ) |
Total gain on natural gas derivatives | $ | 1.2 |
| | $ | 0.2 |
|
| | | |
Total gain (loss) on oil & natural gas derivatives | $ | 11.6 |
| | $ | (11.2 | ) |
See Notes 56 and 67 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments.
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 had income tax expense of $0.2$17.9 million for the three months ended September 30, 2019, compared to income tax expense of $1.5 million for the same period of 2018. The Company had income tax expense of $29.4 million for the nine months ended September 30, 2019, compared to income tax expense of $2.5 million for the same period of 2018. The change in income tax is primarily related to the change in our tax position in the current period, for which there is no longer a cumulative three year loss trend and booking of a valuation allowance for deferred tax benefits as compared to the prior period. See Note 8 in the Footnotes to the Financial Statements for additional information on income tax.
Preferred Stock dividends. Preferred Stock dividends of $0.4 million and $1.0$4.0 million decreased for the three and nine months ended September 30, 2017,2019, respectively, as compared to income tax benefit of $0.1 million and $0.1 million for the same periods of 2016, respectively. The change in income tax expense is primarily related to deferred state income tax expense. The Company had a valuation allowance of $109.8 million as of September 30, 2017. See Note 7 in the Footnotes to the Financial Statements for additional information.
Preferred Stock dividends. Preferred Stock dividends of $1.8 million and $5.5 million for the three and nine months ended September 30, 2017 were consistent with dividends for the same periods of 2016, respectively.2018. Dividends reflecthistorically reflected a 10% dividend rate.yield. 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 9 in the Footnotes to the Financial Statements for additional information.
Loss on redemption of preferred stock. As a result of our planned redemption of all outstanding shares of Preferred Stock on July 18, 2019, we recognized a loss on redemption of $8.3 million for the three and nine months ended September 30, 2019. See Note 9 in the Footnotes to the Financial Statements for additional information.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and non-core asset dispositions. Our primary uses of capital have been for the acquisition and development of oil and natural gas properties, in addition to refinancing of debt instruments. We continue to evaluate other sources of capital to complement our cash flow from operations and as we pursue our long-term growth plans.
As of September 30, 2019, we had $200 million principal outstanding on our Credit Facility, which had a borrowing base of $1.1 billion with an elected commitment of $850 million. At September 30, 2019 and at December 31, 2018, we held cash and cash equivalents of $11.3 million and $16.1 million, respectively.
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
(in thousands) | | 2019 | | 2018 |
Net cash provided by operating activities | | $ | 338,738 |
| | $ | 316,015 |
|
Net cash used in investing activities | | (264,261 | ) | | (1,043,010 | ) |
Net cash provided by (used in) financing activities | | (79,219 | ) | | 711,129 |
|
Net change in cash and cash equivalents | | $ | (4,742 | ) | | $ | (15,866 | ) |
Operating activities. For the nine months ended September 30, 2019, net cash provided by operating activities was $338.7 million compared to net cash provided by operating activities of $316.0 million for the same period in 2018. The change was predominantly attributable to the following:
An increase in revenues 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 costs from personnel growth, and
Changes related to the timing of working capital payments and receipts.
Production, realized prices, and operating expenses are discussed in Results of Operations. See Notes 6 and 7 in the Footnotes to the 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 nine months ended September 30, 2019, net cash used in investing activities was $264.3 million compared to $1,043.0 million for the same period in 2018. The change was predominantly attributable to the following:
Acquisitions and divestiture activity, resulting in an increase to net cash provided of $826.8 million, which reflects a combination of proceeds received from our Ranger Asset Divestiture completed in June 2019 and fewer cash outflows from net acquisition activity between the comparative periods.
Our investing activities, on a cash basis, include the following for the periods indicated (in thousands):
|
| | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 | | $ Change |
Operational expenditures | | $ | 416,958 |
| | $ | 411,109 |
| | $ | 5,849 |
|
Seismic, leasehold and other | | 6,794 |
| | 7,137 |
| | (343 | ) |
Capitalized general and administrative costs | | 23,957 |
| | 16,544 |
| | 7,413 |
|
Capitalized interest | | 55,716 |
| | 20,562 |
| | 35,154 |
|
Total capital expenditures(a) | | 503,425 |
| | 455,352 |
| | 48,073 |
|
Acquisitions | | 40,788 |
| | 595,984 |
| | (555,196 | ) |
Proceeds from sale of assets | | (279,952 | ) | | (8,326 | ) | | (271,626 | ) |
Total investing activities | | $ | 264,261 |
| | $ | 1,043,010 |
| | $ | (778,749 | ) |
| |
(a) | On an accrual basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the nine months ended September 30, 2019 were $398.3 million. Inclusive of Contentsseismic, leasehold and other, capitalized general and administrative, and capitalized interest costs, total capital expenditures for the nine months ended September 30, 2019 were $489.1 million. |
See Note 3 in the Footnotes to the Financial Statements for additional information on acquisitions and dispositions.
Financing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2019, net cash used in financing activities was $79.2 million compared to net cash provided by financing activities of $711.1 million for the same period of 2018. In the
second quarter of 2019, the Company completed the Ranger Asset Divestiture for net cash proceeds received at closing of $244.9 million, including customary purchase price adjustments. The proceeds were used to accelerate our debt reduction initiatives and also allow us to retire our preferred stock, reducing our cash financing costs. This reduction in financing activity as compared to the same period in 2018 can also be partially attributed to funding our Delaware Asset Acquisition in the third quarter of 2018.
|
| | |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Net cash provided by financing activities includes the following for the periods indicated (in thousands):
|
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | 2018 | | $ Change |
Net borrowings on Credit Facility | $ | — |
| | $ | 40,000 |
| | $ | (40,000 | ) |
Issuance of 6.375% senior unsecured notes due 2026 | — |
| | 400,000 |
| | (400,000 | ) |
Issuance of common stock | — |
| | 288,364 |
| | (288,364 | ) |
Payment of preferred stock dividends | (3,997 | ) | | (5,471 | ) | | 1,474 |
|
Payment of deferred financing costs | (31 | ) | | (9,960 | ) | | 9,929 |
|
Tax withholdings related to restricted stock units | (2,174 | ) | | (1,804 | ) | | (370 | ) |
Redemption of preferred stock | (73,017 | ) | | — |
| | (73,017 | ) |
Net cash provided by (used in) financing activities | $ | (79,219 | ) | | $ | 711,129 |
| | $ | (790,348 | ) |
See Notes 5 and 9 in the Footnotes to the Financial Statements for additional information on our debt and equity transactions.
Capital Plan and Year to Date 2019 Summary
Our original operational capital budget for 2019 was established in the range of $500 to $525 million on an accrual, or GAAP, basis, running an average of five drilling rigs to support larger, and more efficient, multi-well pad development. In June 2019, we lowered our annual operational capital budget to a range of $495 to $520 million to reflect realized efficiencies and cost reductions. Of this range, approximately 15% is comprised of infrastructure and facilities capital. In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $100 to $105 million for capitalized interest and general and administrative expenses.
Operational capital expenditures, including other items, on an accrual basis were $405.1 million for the nine months ended September 30, 2019. During the nine months ended September 30, 2019, we placed 47 gross (42.7 net) horizontal wells on production. As of September 30, 2019, we have built a drilled, uncompleted inventory of 18 gross (13.1 net) wells to support a transition to larger pad development. In addition to the operational capital expenditures, $27.4 million of capitalized general and administrative and $56.7 million of capitalized interest expenses were accrued in the nine months ended September 30, 2019.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. 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
We had no material changes in our contractual obligations from amounts listed under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2018.
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 risk. We addressmitigate these risks through a program of risk management including the use of derivative instruments.
Commodity price risk
The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices, in addition to modification of our capital spending plans related to operational activities and acquisitions.prices.
The Company’s hedging portfolio linkedas of September 30, 2019, indexed to NYMEX benchmark pricing, covers approximately 1,130 MBbls2,208,000 Bbls and 1,348753,000 MMBtu of our expected oil and natural gas production, respectively, for the remainder of 2017.2019. We also have commodity hedging contracts linkedindexed to Midland WTI oil basis differentials relative to Cushing and Waha natural gas basis differentials covering approximately 552 MBbls2,176,000 Bbls and 2,116,000 MMBtu, respectively, of our expected oil and natural gas production for the remainder of 2017. See Note 5 in the Footnotes to the Financial Statements for2019. As of September 30, 2019, we had outstanding oil and natural gas derivative contracts with a descriptionnet asset position of $17.1 million. The following table provides a sensitivity analysis of the Company’s outstandingprojected incremental effect on income (loss) before income taxes of a hypothetical 10% change in NYMEX WTI, Henry Hub, Midland WTI, Waha, and Houston MEH prices on our open commodity derivative contracts atinstruments as of September 30, 2017, and derivative contracts established subsequent to that date.2019 (in thousands):
|
| | | | | | | |
| Hypothetical Price Increase of 10% | | Hypothetical Price Decrease of 10% |
Oil derivatives | $ | (33,212 | ) | | $ | 31,480 |
|
Natural gas derivatives | 670 |
| | (666 | ) |
Total | $ | (32,542 | ) | | $ | 30,814 |
|
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 counter-partycounterparty 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 (or call) options at a price lower than the floor price (or higher than the ceiling 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 put and call options, 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. See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at September 30, 2019.
Interest rate risk
The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. Though we had no balance outstanding on our Credit Facility atAs of September 30, 2017, based on a notional amount of $102019, the Company had $200.0 million outstanding under the facility, anCredit Facility with a weighted average interest rate of 3.55%. An increase or decrease of 1%1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $0.1 million.$2.0 million, based on the balance outstanding at September 30, 2019. See Note 45 in the Footnotes to the Consolidated Financial Statements for more information on the Company’s interest rates on its 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 and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require any of our customers to post
collateral, and theThe 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 September 30, 20172019 our total receivables from the sale of our oil and natural gas production were approximately $51.3$83.4 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 September 30, 20172019 our joint interest receivables were approximately $30.0$25.1 million.
Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our 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 derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.
The fair value of our contingent consideration arrangement was determined by a third-party valuation specialist using an option pricing model and includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. See Note 7 in the Footnotes to the Financial Statements for more information on the fair value of the contingent consideration arrangement. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes based on a hypothetical 10% change in the underlying forward oil price curve as of September 30, 2019 (in thousands):
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| | | | | | | |
| Hypothetical Price Increase of 10% | | Hypothetical Price Decrease of 10% |
Contingent consideration arrangement | $ | 4,013 |
| | $ | (3,161 | ) |
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 Securities Exchange Act of 1934, as amended (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 September 30, 2017.2019.
Changes in internal control over financial reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonablereasonably likely to materially affect, our internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
WeIn addition to the below, we are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.
On August 28, 2019, a purported shareholder of Carrizo filed an individual complaint in the United States District Court for the District of Delaware, captioned Shiva Stein v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01599-LPS (the “Stein Action”). On September 3, 2019, a purported shareholder of Carrizo filed a complaint in a putative class action in the United States District Court for the District of Delaware, captioned Eric Sabatini v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01644-CFC (the “Sabatini Action”). On September 5, 2019, a purported shareholder of Carrizo filed a complaint in a putative class action in the United States District Court for the District of Delaware, captioned Manoj Fernandes v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01658-LPS (the “Fernandes Action”). On October 9, 2019, a purported shareholder of Callon filed a putative class action in the United States District Court for the District of Delaware, captioned Desmond Davis et al. v. L. Richard Flury et al., Case No. 2019-0811 (the “Davis Action”)
The Stein Action, the Sabatini Action and the Fernandes Action allege that the preliminary joint proxy statement/prospectus, filed with the SEC on August 20, 2019, omits material information with respect to the Merger, rendering it false and misleading and thus that Carrizo, Callon and the directors of Carrizo violated Section 14(a) of the Exchange Act as well as Rule 14a-9 under the Exchange Act. The Stein Action, the Sabatini Action and the Fernandes Action further allege that the directors of Carrizo and Callon violated Section 20(a) of the Exchange Act. The Davis Action alleges that the directors of Callon failed to fulfill their fiduciary duties in connection with the Merger by failing to disclose all material information. The complaints seek injunctive relief enjoining the Merger, damages and costs, among other remedies. It is possible that additional, similar complaints may be filed. The defendants believe that the lawsuits are without merit and intend to vigorously defend them.
Item 1A. Risk Factors
In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 2018 Annual Report on Form 10-K and the risk factors and other cautionary statements contained in our other SEC filings, including our Quarterly Report on Form 10-Q for the period ended June 30, 2019 and our Registration Statement on Form S-4 that was initially filed on August 20, 2019 and declared effective on October 9, 2019, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes with respect to thein our risk factors disclosedfrom those described in our 20162018 Annual Report on Form 10-K.10-K or our other SEC filings, including our Quarterly Report on Form 10-Q for the period ended June 30, 2019 and our Registration Statement on Form S-4 that was initially filed on August 20, 2019 and declared effective on October 9, 2019.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.Not applicable.
Item 5. Other Information
None.
Item 6. Exhibits
The following exhibits are filed as part of this Form 10-Q.
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| | | | |
Exhibit Number | | Description |
3. | | | | Articles of Incorporation and By-Laws |
| 3.1 | | | |
| 3.2 | | | |
| 3.3 | | | Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408)
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4. | | | | Instruments defining the rights of security holders, including indentures |
| 4.1 | | | Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408)
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| 4.2 | | | |
| 4.3 | | | |
| 4.4 | | | |
31. | | | | Section 13a-14 Certifications |
| 31.1 | (a) | | |
| 31.2 | (a) | | |
32. | | | | Section 1350 Certifications |
| 32.1 | (b) | | |
101. | | (c) | | Interactive Data Files |
|
| | | | | | | | | |
| | | | | Incorporated by reference (File No. 001-14039, unless otherwise indicated) |
Exhibit Number | Description | | Form | | Exhibit | | Filing Date |
2.1 | ± | | | | 8-K | | 2.1 | | 07/14/2019 |
2.2 | (a) | | | | | | | | |
3.1 | | | | | 10-Q | | 3.1 | | 11/03/2016 |
3.2 | | | | | 10-K | | 3.2 | | 02/27/2019 |
10.1 | | | | | 8-K | | 10.1 | | 07/14/2019 |
31.1 | (a) | | | | | | | | |
31.2 | (a) | | | | | | | | |
32.1 | (b) | | | | | | | | |
101.INS | (a) | | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
101.SCH | (a) | | Inline XBRL Taxonomy Extension Schema Document | | | | | | |
101.CAL | (a) | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | |
101.DEF | (a) | | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | |
101.LAB | (a) | | Inline XBRL Taxonomy Extension Label Linkbase Document. | | | | | | |
101.PRE | (a) | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | |
104 | (a) | | Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
| |
(b) | Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. |
| |
(c)± | PursuantCertain schedules and similar attachments have been omitted pursuant to Rule 406TItem 601(a)(5) of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filedS-K. Callon agrees to furnish a supplemental copy of any omitted schedule or part of a registration statement or prospectus for purposes of Sections 11 or 12 ofattachment to the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.SEC upon request. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Callon Petroleum Company
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Signature | Title | Date |
| | |
/s/ Joseph C. Gatto, Jr. | President and | November 6, 20174, 2019 |
Joseph C. Gatto, Jr. | Chief Executive Officer | |
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| | |
/s/ Correne S. LoefflerJames P. Ulm, II | TreasurerSenior Vice President and | November 6, 20174, 2019 |
Correne S. LoefflerJames P. Ulm, II | Interim Chief Financial Officer | |