Delaware | 001-14039 | 64-0844345 |
(State or other jurisdiction of incorporation) | (Commission File Number) | (I.R.S. Employer Identification Number) |
1401 Enclave Parkway, Suite 600 Houston, TX 77077 |
(Address of principal executive offices, including zip code) |
(281) 589-5200 |
(Registrant’s telephone number, including area code) |
Not Applicable |
(Former name or former address, if changed since last report.) |
Exhibit Number | Title of Document | |
99.1 | ||
99.2 |
Callon Petroleum Company | |||
(Registrant) | |||
February 26, 2019 | /s/ James P. Ulm, II | ||
James P. Ulm, II | |||
Senior Vice President and Chief Financial Officer |
• | Full-year 2018 production of 32.9 Mboe/d (79% oil), an increase of 44% over 2017 volumes and at the top of the 2018 guidance range with a higher oil cut |
• | Year-end proved reserves of 238.5 MMboe (76% oil), a year-over-year increase of 74% combined with an oil content that has remained consistently over 75% since commencing horizontal development in 2012 |
• | Proved reserve additions replaced 690% of 2018 production at a “drill-bit” finding and development cost (i) of $7.03 per Boe and a proved developed finding and development cost(i) of $13.40 per Boe |
• | Generated an operating margin of $40.16 per Boe reflecting our high level of oil volumes, proactive investments in infrastructure and offtake relationships, and cost structure improvements |
• | Realized net income of $300.4 million and generated Adjusted EBITDA(i) of $432.5 million relative to cash drilling and completion capital expenditures of $403.5 million |
• | Completed the acquisition of 34,523 net working interest acres and 1,530 net mineral acres within our core operating areas, more than doubling our Delaware footprint since 2017, and also traded 4,420 net acres to further long-lateral development |
• | Divested 3,540 net acres as part of ongoing initiatives to monetize non-core assets and enhance returns on capital |
• | Executed firm transportation and marketing agreements that are expected to transition 25 MBbl/d of our gross oil production to a combination of Gulf Coast, Brent and waterborne pricing January 2020 |
• | Fourth quarter 2018 production of 41.1 Mboe/d (81% oil), an increase of 55% over fourth quarter 2017 volumes and a sequential increase of 18% |
• | Generated $151.6 million of cash provided by operating activities, exceeding cash used in investing activities for operational capital additions of $127.8 million in the development of oil and natural gas properties |
• | Began building an inventory of drilled, uncompleted wells to support our transition to larger scale development in the Delaware Basin in 2019 |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
Three Months Ended December 31, 2018 | ||||||||||||||||
Operational | Capitalized | Capitalized | Total Capital | |||||||||||||
Capital (a) | Interest | G&A | Expenditures | |||||||||||||
Cash basis (b) | $ | 127,823 | $ | 20,159 | $ | 7,839 | $ | 155,821 | ||||||||
Timing adjustments (c) | 13,354 | (2,659 | ) | — | 10,695 | |||||||||||
Non-cash items | — | — | 353 | 353 | ||||||||||||
Accrual basis | $ | 141,177 | $ | 17,500 | $ | 8,192 | $ | 166,869 |
(a) | Includes seismic, land and other items. |
(b) | Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with our development pace and rig count. |
(c) | Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period. |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
Three Months Ended, | ||||||||||||
December 31, 2018 | September 30, 2018 | December 31, 2017 | ||||||||||
Net production | ||||||||||||
Oil (MBbls) | 3,076 | 2,521 | 1,936 | |||||||||
Natural gas (MMcf) | 4,225 | 4,144 | 3,018 | |||||||||
Total (Mboe) | 3,780 | 3,212 | 2,439 | |||||||||
Average daily production (Boe/d) | 41,087 | 34,913 | 26,511 | |||||||||
% oil (Boe basis) | 81 | % | 78 | % | 79 | % | ||||||
Oil and natural gas revenues (in thousands) | ||||||||||||
Oil revenue | $ | 150,398 | $ | 142,601 | $ | 104,132 | ||||||
Natural gas revenue (a) | 11,497 | 18,613 | 14,081 | |||||||||
Total operating revenues | 161,895 | 161,214 | 118,213 | |||||||||
Impact of settled derivatives | (1,594 | ) | (9,239 | ) | (4,501 | ) | ||||||
Adjusted Total Revenue (i) | $ | 160,301 | $ | 151,975 | $ | 113,712 | ||||||
Average realized sales price (excluding impact of settled derivatives) | ||||||||||||
Oil (Bbl) | $ | 48.89 | $ | 56.57 | $ | 53.79 | ||||||
Natural gas (Mcf) | 2.72 | 4.49 | 4.67 | |||||||||
Total (Boe) | 42.83 | 50.19 | 48.47 | |||||||||
Average realized sales price (including impact of settled derivatives) | ||||||||||||
Oil (Bbl) | $ | 48.52 | $ | 52.87 | $ | 51.28 | ||||||
Natural gas (Mcf) | 2.62 | 4.51 | 4.78 | |||||||||
Total (Boe) | 42.41 | 47.31 | 46.62 | |||||||||
Additional per Boe data | ||||||||||||
Sales price (b) | $ | 42.83 | $ | 50.19 | $ | 48.47 | ||||||
Lease operating expense (c) | 6.47 | 5.77 | 4.84 | |||||||||
Gathering and treating expense (a) | — | — | 0.57 | |||||||||
Production taxes | 2.51 | 3.20 | 2.55 | |||||||||
Operating margin | $ | 33.85 | $ | 41.22 | $ | 40.51 | ||||||
Depletion, depreciation and amortization | $ | 15.74 | $ | 15.02 | $ | 14.98 | ||||||
Adjusted G&A (d) | ||||||||||||
Cash component (e) | $ | 2.03 | $ | 2.17 | $ | 2.46 | ||||||
Non-cash component | 0.50 | 0.57 | 0.54 |
(a) | On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the three and twelve months ended December 31, 2018 were accounted for as a reduction to revenue. |
(b) | Excludes the impact of settled derivatives. |
(c) | Excludes gathering and treating expense. |
(d) | Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. |
(e) | Excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization. |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
Three Months Ended December 31, 2018 | ||||||||
In Thousands | Per Unit | |||||||
Oil derivatives | ||||||||
Net loss on settlements | $ | (1,157 | ) | $ | (0.37 | ) | ||
Net gain on fair value adjustments | 101,693 | |||||||
Total gain on oil derivatives | $ | 100,536 | ||||||
Natural gas derivatives | ||||||||
Net loss on settlements | $ | (437 | ) | $ | (0.10 | ) | ||
Net gain on fair value adjustments | 3,819 | |||||||
Total gain on natural gas derivatives | $ | 3,382 | ||||||
Total oil & natural gas derivatives | ||||||||
Net loss on settlements | $ | (1,594 | ) | $ | (0.42 | ) | ||
Net gain on fair value adjustments | 105,512 | |||||||
Total gain on total oil & natural gas derivatives | $ | 103,918 |
Three Months Ended December 31, 2018 | ||||
Total G&A expense | $ | 8,514 | ||
Change in the fair value of liability share-based awards (non-cash) | 1,069 | |||
Adjusted G&A – total | 9,583 | |||
Restricted stock share-based compensation (non-cash) | (1,802 | ) | ||
Corporate depreciation & amortization (non-cash) | (94 | ) | ||
Adjusted G&A – cash component | $ | 7,687 |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
Proved reserves: | |||
Reserves at December 31, 2017 | 136,974 | ||
Extensions and discoveries | 84,955 | ||
Purchase of reserves in place | 39,683 | ||
Revisions to previous estimates | (2,021 | ) | |
Reclassifications due to changes in development plan | (9,065 | ) | |
Production | (12,018 | ) | |
Reserves at December 31, 2018 | 238,508 |
Full Year | Full Year | |||
2018 Actual | 2019 Guidance | |||
Total production (Mboe/d) | 32.9 | 39.5 - 41.5 | ||
% oil | 79% | 77% - 78% | ||
Income statement expenses (per Boe) | ||||
LOE, including workovers | $5.76 | $5.50 - $6.50 | ||
Production taxes, including ad valorem (% unhedged revenue) | 6% | 7% | ||
Adjusted G&A: cash component (a) | $2.35 | $2.00 - $2.50 | ||
Adjusted G&A: non-cash component (b) | $0.55 | $0.50 - $1.00 | ||
Cash interest expense (c) | $0.00 | $0.00 | ||
Effective income tax rate | 22% | 22% | ||
Capital expenditures ($MM, accrual basis) | ||||
Total operational (d) | $583 | $500 - $525 | ||
Capitalized interest and G&A expenses | $84 | $100 - $105 | ||
Net operated horizontal wells placed on production | 54 | 47 - 49 |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
(a) | Excludes stock-based compensation and corporate depreciation and amortization. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. |
(b) | Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. |
(c) | All interest expense anticipated to be capitalized. |
(d) | Includes facilities, equipment, seismic, land and other items. Excludes capitalized expenses. |
For the Full Year of | For the Full Year of | |||||||
Oil contracts (WTI) | 2019 | 2020 | ||||||
Puts | ||||||||
Total volume (Bbls) | 912,500 | — | ||||||
Weighted average price per Bbl | $ | 65.00 | $ | — | ||||
Put spreads | ||||||||
Total volume (Bbls) | 912,500 | — | ||||||
Weighted average price per Bbl | ||||||||
Floor (long put) | $ | 65.00 | $ | — | ||||
Floor (short put) | $ | 42.50 | $ | — | ||||
Collar contracts combined with short puts (three-way collars) | ||||||||
Total volume (Bbls) | 4,564,000 | — | ||||||
Weighted average price per Bbl | ||||||||
Ceiling (short call) | $ | 67.62 | $ | — | ||||
Floor (long put) | $ | 56.60 | $ | — | ||||
Floor (short put) | $ | 43.60 | $ | — | ||||
Oil contracts (Midland basis differential) | ||||||||
Swap contracts | ||||||||
Total volume (Bbls) | 4,746,500 | 4,024,000 | ||||||
Weighted average price per Bbl | $ | (4.72 | ) | $ | (1.51 | ) | ||
Natural gas contracts (Henry Hub) | ||||||||
Collar contracts (two-way collars) | ||||||||
Total volume (MMBtu) | 8,282,500 | — | ||||||
Weighted average price per MMBtu | ||||||||
Ceiling (short call) | $ | 3.46 | $ | — | ||||
Floor (long put) | $ | 2.91 | $ | — | ||||
Natural gas contracts (Waha basis differential) | ||||||||
Swap contracts | ||||||||
Total volume (MMBtu) | 11,321,000 | 4,758,000 | ||||||
Weighted average price per MMBtu | $ | (1.23 | ) | $ | (1.12 | ) |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
Three Months Ended | ||||||||||||
Adjusted Income per fully diluted common share: | December 31, 2018 | September 30, 2018 | December 31, 2017 | |||||||||
Income available to common stockholders | $ | 154,370 | $ | 36,108 | $ | 21,001 | ||||||
Net (gain) loss on derivatives, net of settlements | (105,512 | ) | 25,100 | 26,037 | ||||||||
Change in the fair value of liability share-based awards | (1,053 | ) | 879 | 865 | ||||||||
Tax effect on adjustments above | 22,379 | (5,456 | ) | (9,416 | ) | |||||||
Change in valuation allowance | (30,281 | ) | (8,323 | ) | (8,285 | ) | ||||||
Adjusted Income | $ | 39,903 | $ | 48,308 | $ | 30,202 | ||||||
Adjusted Income per fully diluted common share | $ | 0.17 | $ | 0.21 | $ | 0.15 |
Three Months Ended | ||||||||||||
Adjusted EBITDA: | December 31, 2018 | September 30, 2018 | December 31, 2017 | |||||||||
Net income | $ | 156,194 | $ | 37,931 | $ | 22,824 | ||||||
Net (gain) loss on derivatives, net of settlements | (105,512 | ) | 25,100 | 26,037 | ||||||||
Non-cash stock-based compensation expense | 770 | 2,587 | 2,101 | |||||||||
Acquisition expense | 1,333 | 1,435 | (112 | ) | ||||||||
Income tax expense | 5,647 | 1,487 | 248 | |||||||||
Interest expense | 735 | 711 | 461 | |||||||||
Depreciation, depletion and amortization | 60,301 | 48,977 | 37,222 | |||||||||
Accretion expense | 248 | 202 | 154 | |||||||||
Adjusted EBITDA | $ | 119,716 | $ | 118,430 | $ | 88,935 |
Three Months Ended | ||||||||||||
December 31, 2018 | September 30, 2018 | December 31, 2017 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income | $ | 156,194 | $ | 37,931 | $ | 22,824 | ||||||
Adjustments to reconcile net income to cash provided by operating activities: | ||||||||||||
Depreciation, depletion and amortization | 60,301 | 48,977 | 37,222 | |||||||||
Accretion expense | 248 | 202 | 154 | |||||||||
Amortization of non-cash debt related items | 734 | 708 | 455 | |||||||||
Deferred income tax expense | 5,647 | 1,487 | 247 | |||||||||
(Gain) loss on derivatives, net of settlements | (105,512 | ) | 25,100 | 26,037 | ||||||||
Gain on sale of other property and equipment | (64 | ) | (102 | ) | — | |||||||
Non-cash expense related to equity share-based awards | 1,823 | 1,708 | 1,240 | |||||||||
Change in the fair value of liability share-based awards | (1,053 | ) | 879 | 865 | ||||||||
Discretionary cash flow | $ | 118,318 | $ | 116,890 | $ | 89,044 | ||||||
Changes in working capital | 33,710 | (347 | ) | $ | (8,642 | ) | ||||||
Payments to settle asset retirement obligations | (389 | ) | (507 | ) | (216 | ) | ||||||
Net cash provided by operating activities | $ | 151,639 | $ | 116,036 | $ | 80,186 |
As of December 31, 2018 | ||||
Standardized measure of discounted future net cash flows | $ | 2,941,293 | ||
Add: 10 percent annual discount, net of income taxes | 3,716,571 | |||
Add: future undiscounted income taxes | 782,470 | |||
Undiscounted future net cash flows | 7,440,334 | |||
Less: 10 percent annual discount without tax effect | (4,291,127 | ) | ||
Total Proved Reserves - Pre-tax PV-10 | 3,149,207 | |||
Total Proved Developed Reserves - Pre-tax PV-10 | 2,222,049 | |||
Total Proved Undeveloped Reserves - Pre-tax PV-10 | $ | 927,158 |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
Calculation | 2018 | |||||
Parameters | Metrics | |||||
Production (Mboe) | (A) | 12,018 | ||||
Proved reserve data | ||||||
Proved reserves (Mboe) | ||||||
Total Proved extensions, discoveries, and other additions | (B) | 84,955 | ||||
Proved Undeveloped extensions, discoveries, and other additions, net of revisions | (C) | 52,526 | ||||
Proved Undeveloped transfers to Proved Developed | (D) | 11,075 | ||||
Total Proved additions, net of revisions and reclassifications | (E) | 113,552 | ||||
Total Proved extensions, discoveries, and other additions, net of revisions | (F) | 82,934 | ||||
Costs Incurred: | ||||||
Acquisition costs: | ||||||
Evaluated properties | $ | 347,305 | ||||
Unevaluated properties | 466,816 | |||||
Development costs | (G) | 259,410 | ||||
Exploration costs | (H) | 323,458 | ||||
Total costs incurred | $ | 1,396,989 | ||||
Drill-bit F&D costs per Boe (two-stream) | (G + H) / (F) | $7.03 | ||||
PD F&D per Boe (two-stream) | (G + H) / (B - C + D) | $13.40 | ||||
Organic reserve replacement ratio | (F) / (A) | 690% | ||||
All-sources reserve replacement ratio | (E) / (A) | 945% |
(i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
December 31, 2018 | December 31, 2017 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 16,051 | $ | 27,995 | |||
Accounts receivable | 131,720 | 114,320 | |||||
Fair value of derivatives | 65,114 | 406 | |||||
Other current assets | 9,740 | 2,139 | |||||
Total current assets | 222,625 | 144,860 | |||||
Oil and natural gas properties, full cost accounting method: | |||||||
Evaluated properties | 4,585,020 | 3,429,570 | |||||
Less accumulated depreciation, depletion, amortization and impairment | (2,270,675 | ) | (2,084,095 | ) | |||
Net evaluated oil and natural gas properties | 2,314,345 | 1,345,475 | |||||
Unevaluated properties | 1,404,513 | 1,168,016 | |||||
Total oil and natural gas properties, net | 3,718,858 | 2,513,491 | |||||
Other property and equipment, net | 21,901 | 20,361 | |||||
Restricted investments | 3,424 | 3,372 | |||||
Deferred tax asset | — | 52 | |||||
Deferred financing costs | 6,087 | 4,863 | |||||
Acquisition deposit | — | 900 | |||||
Other assets, net | 6,278 | 5,397 | |||||
Total assets | $ | 3,979,173 | $ | 2,693,296 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and accrued liabilities | $ | 261,184 | $ | 162,878 | |||
Accrued interest | 24,665 | 9,235 | |||||
Cash-settleable restricted stock unit awards | 1,390 | 4,621 | |||||
Asset retirement obligations | 3,887 | 1,295 | |||||
Fair value of derivatives | 10,480 | 27,744 | |||||
Other current liabilities | 13,310 | — | |||||
Total current liabilities | 314,916 | 205,773 | |||||
Senior secured revolving credit facility | 200,000 | 25,000 | |||||
6.125% senior unsecured notes due 2024 | 595,788 | 595,196 | |||||
6.375% senior unsecured notes due 2026 | 393,685 | — | |||||
Asset retirement obligations | 10,405 | 4,725 | |||||
Cash-settleable restricted stock unit awards | 2,067 | 3,490 | |||||
Deferred tax liability | 9,564 | 1,457 | |||||
Fair value of derivatives | 7,440 | 1,284 | |||||
Other long-term liabilities | 100 | 405 | |||||
Total liabilities | 1,533,965 | 837,330 | |||||
Commitments and contingencies | |||||||
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; 227,582,575 and 201,836,172 shares outstanding, respectively | 2,276 | 2,018 | |||||
Capital in excess of par value | 2,477,278 | 2,181,359 | |||||
Accumulated deficit | (34,361 | ) | (327,426 | ) | |||
Total stockholders’ equity | 2,445,208 | 1,855,966 | |||||
Total liabilities and stockholders’ equity | $ | 3,979,173 | $ | 2,693,296 |
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Operating revenues: | |||||||||||||||
Oil sales | $ | 150,398 | $ | 104,132 | $ | 530,898 | $ | 322,374 | |||||||
Natural gas sales | 11,497 | 14,082 | 56,726 | 44,100 | |||||||||||
Total operating revenues | 161,895 | 118,214 | 587,624 | 366,474 | |||||||||||
Operating expenses: | |||||||||||||||
Lease operating expenses | 24,475 | 13,201 | 69,180 | 49,907 | |||||||||||
Production taxes | 9,490 | 6,228 | 35,755 | 22,396 | |||||||||||
Depreciation, depletion and amortization | 59,502 | 36,543 | 181,909 | 115,714 | |||||||||||
General and administrative | 8,514 | 8,172 | 35,293 | 27,067 | |||||||||||
Settled share-based awards | — | — | — | 6,351 | |||||||||||
Accretion expense | 248 | 154 | 874 | 677 | |||||||||||
Acquisition expense | 1,333 | (112 | ) | 5,083 | 2,916 | ||||||||||
Total operating expenses | 103,562 | 64,186 | 328,094 | 225,028 | |||||||||||
Income from operations | 58,333 | 54,028 | 259,530 | 141,446 | |||||||||||
Other (income) expenses: | |||||||||||||||
Interest expense, net of capitalized amounts | 735 | 461 | 2,500 | 2,159 | |||||||||||
(Gain) loss on derivative contracts | (103,918 | ) | 30,536 | (48,544 | ) | 18,901 | |||||||||
Other income | (325 | ) | (41 | ) | (2,896 | ) | (1,311 | ) | |||||||
Total other (income) expense | (103,508 | ) | 30,956 | (48,940 | ) | 19,749 | |||||||||
Income before income taxes | 161,841 | 23,072 | 308,470 | 121,697 | |||||||||||
Income tax (benefit) expense | 5,647 | 248 | 8,110 | 1,273 | |||||||||||
Net income | 156,194 | 22,824 | 300,360 | 120,424 | |||||||||||
Preferred stock dividends | (1,824 | ) | (1,823 | ) | (7,295 | ) | (7,295 | ) | |||||||
Income available to common stockholders | $ | 154,370 | $ | 21,001 | $ | 293,065 | $ | 113,129 | |||||||
Income per common share: | |||||||||||||||
Basic | $ | 0.68 | $ | 0.10 | $ | 1.35 | $ | 0.56 | |||||||
Diluted | $ | 0.68 | $ | 0.10 | $ | 1.35 | $ | 0.56 | |||||||
Shares used in computing income per common share: | |||||||||||||||
Basic | 227,580 | 201,835 | 216,941 | 201,526 | |||||||||||
Diluted | 228,191 | 202,426 | 217,596 | 202,102 |
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Cash flows from operating activities: | |||||||||||||||
Net income (loss) | $ | 156,194 | $ | 22,824 | $ | 300,360 | $ | 120,424 | |||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||
Depreciation, depletion and amortization | 60,301 | 37,222 | 184,731 | 118,051 | |||||||||||
Accretion expense | 248 | 154 | 874 | 677 | |||||||||||
Amortization of non-cash debt related items | 734 | 455 | 2,483 | 2,150 | |||||||||||
Deferred income tax (benefit) expense | 5,647 | 247 | 8,110 | 1,273 | |||||||||||
Net (gain) loss on derivatives, net of settlements | (105,512 | ) | 26,037 | (75,816 | ) | 10,429 | |||||||||
(Gain) loss on sale of other property and equipment | (64 | ) | — | (144 | ) | 62 | |||||||||
Non-cash expense related to equity share-based awards | 1,823 | 1,240 | 6,289 | 8,254 | |||||||||||
Change in the fair value of liability share-based awards | (1,053 | ) | 865 | 375 | 3,288 | ||||||||||
Payments to settle asset retirement obligations | (389 | ) | (216 | ) | (1,469 | ) | (2,047 | ) | |||||||
Payments for cash-settled restricted stock unit awards | — | — | (4,990 | ) | (13,173 | ) | |||||||||
Changes in current assets and liabilities: | |||||||||||||||
Accounts receivable | 37,033 | (32,347 | ) | (17,351 | ) | (44,495 | ) | ||||||||
Other current assets | (5,936 | ) | 444 | (7,601 | ) | 108 | |||||||||
Current liabilities | 9,510 | 23,413 | 74,311 | 30,947 | |||||||||||
Other long-term liabilities | (6,065 | ) | — | (278 | ) | 121 | |||||||||
Other assets, net | (832 | ) | (152 | ) | (2,230 | ) | (1,528 | ) | |||||||
Other | — | — | — | (4,650 | ) | ||||||||||
Net cash provided by operating activities | 151,639 | 80,186 | 467,654 | 229,891 | |||||||||||
Cash flows from investing activities: | |||||||||||||||
Capital expenditures | (155,821 | ) | (152,621 | ) | (611,173 | ) | (419,839 | ) | |||||||
Acquisitions | (122,809 | ) | (3,952 | ) | (718,793 | ) | (718,456 | ) | |||||||
Acquisition deposit | — | (900 | ) | — | 45,238 | ||||||||||
Proceeds from sales of assets | 683 | 20,525 | 9,009 | 20,525 | |||||||||||
Additions to other assets | (3,100 | ) | — | (3,100 | ) | — | |||||||||
Net cash used in investing activities | (281,047 | ) | (136,948 | ) | (1,324,057 | ) | (1,072,532 | ) | |||||||
Cash flows from financing activities: | |||||||||||||||
Borrowings on senior secured revolving credit facility | 230,000 | 25,000 | 500,000 | 25,000 | |||||||||||
Payments on senior secured revolving credit facility | (95,000 | ) | — | (325,000 | ) | — | |||||||||
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 | — | |||||||||||
Payment of deferred financing costs | 530 | (28 | ) | (9,430 | ) | (7,194 | ) | ||||||||
Issuance of common stock | (376 | ) | — | 287,988 | — | ||||||||||
Payment of preferred stock dividends | (1,824 | ) | (1,824 | ) | (7,295 | ) | (7,295 | ) | |||||||
Tax withholdings related to restricted stock units | — | — | (1,804 | ) | (1,118 | ) | |||||||||
Net cash provided by financing activities | 133,330 | 23,148 | 844,459 | 217,643 | |||||||||||
Net change in cash and cash equivalents | 3,922 | (33,614 | ) | (11,944 | ) | (624,998 | ) | ||||||||
Balance, beginning of period | 12,129 | 61,609 | 27,995 | 652,993 | |||||||||||
Balance, end of period | 16,051 | 27,995 | $ | 16,051 | $ | 27,995 |
• | Callon believes that the non-GAAP measure of discretionary cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company’s ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and payments to settle asset retirement obligations and vested liability share-based awards. Callon has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the Company may not control and the cash flow effect may not be reflected the period in which the operating activities occurred. Discretionary cash flow is not a measure of a company’s financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities (as defined under GAAP), or as a measure of liquidity, or as an alternative to net income. |
• | Adjusted general and administrative expense (“Adjusted G&A”) is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans, as well as non-cash corporate depreciation and amortization expense. Callon believes that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table here within details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A. |
• | Callon believes that the non-GAAP measure of Adjusted Income available to common shareholders (“Adjusted Income”) and Adjusted Income per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided here within. |
• | Callon calculates adjusted earnings before interest, income taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) as Adjusted Income plus interest expense, income tax expense (benefit) and depreciation, depletion and amortization expense. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, the Company believes that Adjusted EBITDA provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDA presented may not be comparable to similarly titled measures of other companies. |
• | Callon believes that the non-GAAP measure of Adjusted Total Revenue is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues. |
• | We believe “Drill-Bit F&D costs per Boe,” “PD F&D costs per Boe”, “Organic reserve replacement ratio”, and “All-sources reserve replacement ratio” are non-GAAP metrics commonly used by Callon and other companies in our industry, as well as analysts and investors, to measure and evaluate the cost of replenishing annual production and adding proved reserves. The Company’s definitions of “Drill-Bit F&D costs per Boe,” “PD F&D costs per Boe” and “Organic reserve replacement ratio” and “All-sources reserve replacement ratio” may differ significantly from definitions used by other companies to compute similar measures and as a result may not be comparable to similar measures provided by other companies. Consequently, we provided the detail of our calculation within the included tables. |
• | Year-end pre-tax PV-10 value is a non-GAAP financial measure as defined by the SEC. Callon believes that the presentation of pre-tax PV-10 value is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account future corporate income taxes and the Company’s current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies. The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows (“Standardized Measure”). Pre-tax PV-10 is calculated using the Standardized Measure before deducting future income taxes, discounted at 10 percent. The 12-month average benchmark pricing used to estimate proved reserves in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (“SEC”) and pre-tax PV-10 value for crude oil and natural gas was $65.56 per Bbl of WTI crude oil and $3.10 per MMBtu of natural gas at Henry Hub before differential adjustments. After differential adjustments, the Company’s SEC pricing realizations for year-end 2018 were $58.40 per Bbl of oil and $3.64 per Mcf of natural gas. |
Date/Time: | Wednesday, February 27, 2019, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time) |
Webcast: | Select “IR Calendar” under the “Investors” section of the Company’s website: www.callon.com. |
Domestic: | 1-888-317-6003 |
Canada: | 1-866-284-3684 |
International: | 1-412-317-6061 |
Access code: | 6127927 |
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