Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Callon Petroleum Co | a4q17earnings8-k.htm |
Exhibit 99.1
Callon Petroleum Company Announces Fourth Quarter 2017 Results
Natchez, MS (February 27, 2018) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three months and full-year ended December 31, 2017.
Presentation slides accompanying this earnings release are available on the Company’s website at www.callon.com located on the “Presentations” page within the Investors section of the site.
Financial and operational highlights for the fourth quarter of 2017, and other recent data points, include:
• | Full-year 2017 production of 22.9 MBOE/d (78% oil), an increase of 50% over 2016 volumes |
• | Fourth quarter 2017 production of 26.5 MBOE/d (79% oil), a sequential quarterly increase of 18% |
• | Year-end proved reserves of 137.0 MMBOE (78% oil), a year-over-year increase of 50% |
• | Organic reserve replacement(i) of 566% of 2017 production at a “Drill-Bit” finding and development cost concept(i) of $8.21 per BOE on a two-stream basis |
• | Reduced lease operating expense to $4.84 per BOE in the fourth quarter of 2017, a sequential quarterly decrease of 5%, contributing to a total reduction of 27% since the first quarter of 2017 |
• | Generated a fourth quarter operating margin of $40.51 per BOE |
• | Currently operating five horizontal rigs and two dedicated completion crews |
Joe Gatto, President and Chief Executive Officer commented, “Our full year results for 2017 highlight solid execution by our team, resulting in annual production growth of more than 50% and a greater than 25% reduction in lease operating expense over the course of the year. Our operating margins improved 30% over 2016 and our oil content remained just below 80%, contributing to strong internal cash flow generation. Importantly, these top tier cash margins, coupled with drill-bit finding and development cost below $10 per BOE, are a fundamental driver of corporate level returns that continue to improve in parallel with our growth in producing assets. We have recently increased our operating activity to five drilling rigs and plan to remain at this pace for the balance of 2018 as we incorporate larger pad development concepts into our program and drive steady improvement in our net cash flow profile over the course of the year.”
Operations Update
At December 31, 2017, we had 232 gross (171.8 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended December 31, 2017 grew approximately 44% to 26.5 thousand barrels of oil equivalent per day (approximately 79% oil) as compared to the same period of 2016. Full year production for 2017 averaged 22,940 barrels of oil equivalent per day (approximately 78% oil) reflecting growth of 50% over 2016 volumes.
Midland Basin
During the fourth quarter, over 50% of the wells placed on production were from our WildHorse area with an average completed lateral length of approximately 7,300 feet. This area continues to be a key area of production growth for the company and is projected to comprise in excess of 30% of our total gross drilling activity in 2018. Completed lateral lengths are projected to average over 8,000 feet and the majority of activity will continue to focus predominantly on the development of the Wolfcamp A.
In our Monarch area, we placed six wells on production during the quarter. Activity in this area continues to focus on the Lower Spraberry which has consistently generated some of the highest returns in our portfolio. The three-well Kendra pad, with average completed lateral lengths of approximately 10,350, has produced over 236,000 BOE (87% oil) over the first 90 days online. Additionally, we commenced production of our first multi-well pad that utilized recycled flowback water volumes and plan to increase recycling activity in Monarch with upcoming wells. Our 2018 activity plan for Monarch will feature two separate “mega-pad” concepts incorporating simultaneous development of two contiguous three-well pads. Each pad will be drilled concurrently by dedicated rigs and all six wells placed on production at the same time. We expect these larger pads to be placed on production during the second half of the year.
In Reagan County at the Ranger area, our first Wolfcamp C well, together with two Lower Wolfcamp B wells, was completed during the fourth quarter and began flowback in January. The Wolfcamp C well continues to produce under natural flowing pressure with recent production rates in excess of 1,000 BOE/d (85% - 90% oil) and is still in the process of establishing a peak rate. We anticipate drilling four (gross) additional Wolfcamp C wells in Ranger during the course of 2018 with an average working interest of approximately 55%.
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
1
Delaware Basin
We recently completed drilling of our first two-well pad in the area and also added a second rig to our Spur development program in February. As part of this increased activity, we plan to enhance our existing saltwater disposal capacity of over 100,000 barrels per day with the connection to a pipeline system operated by Goodnight Midstream that will move water disposal volumes outside of our operating area. In addition, we are in the final stages of establishing a recycling program in this area and targeting usage of up to 50% recycled volumes for completion operations by year end 2018. During the fourth quarter, the Saratoga 7LA well came online and has produced at an average daily rate of approximately 1,015 BOE/d (83% oil) during its first 56 days of production.
Capital Expenditures
For the three months ended December 31, 2017, we incurred $115.8 million in accrued operational capital expenditures (excluding other items) compared to $113.4 million in the third quarter of 2017. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):
Three Months Ended December 31, 2017 | ||||||||||||||||||||
Operational | Capitalized | Capitalized | Total Capital | |||||||||||||||||
Capital | Other (a) | Interest | G&A | Expenditures | ||||||||||||||||
Cash basis (b) | $ | 123,664 | $ | 5,006 | $ | 18,848 | $ | 5,103 | $ | 152,621 | ||||||||||
Timing adjustments (c) | (7,910 | ) | — | (9,140 | ) | — | (17,050 | ) | ||||||||||||
Non-cash items | — | — | — | 1,173 | 1,173 | |||||||||||||||
Accrual (GAAP) basis | $ | 115,754 | $ | 5,006 | $ | 9,708 | $ | 6,276 | $ | 136,744 | ||||||||||
(a) | Includes seismic, land and other items. |
(b) | Cash basis is a non-GAAP measure that we believe helps users of the financial information reconcile amounts to the cash flow statement and to account for timing related operational changes such as 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. |
We also divested certain infrastructure during the fourth quarter for proceeds of just over $20 million. We anticipate Callon will have additional opportunities to selectively monetize other infrastructure and facilities investments as we leverage strategic partnerships and increasingly transition to the use of recycled water volumes in our completion operations.
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
2
Operating and Financial Results
The following table presents summary information for the periods indicated:
Three Months Ended | ||||||||||||
December 31, 2017 | September 30, 2017 | December 31, 2016 | ||||||||||
Net production | ||||||||||||
Oil (MBbls) | 1,936 | 1,591 | 1,287 | |||||||||
Natural gas (MMcf) | 3,018 | 2,900 | 2,412 | |||||||||
Total (MBOE) | 2,439 | 2,074 | 1,689 | |||||||||
Average daily production (BOE/d) | 26,511 | 22,543 | 18,359 | |||||||||
% oil (BOE basis) | 79 | % | 77 | % | 76 | % | ||||||
Oil and natural gas revenues (in thousands) | ||||||||||||
Oil revenue | $ | 104,132 | $ | 73,349 | $ | 60,559 | ||||||
Natural gas revenue | 14,081 | 11,265 | 8,522 | |||||||||
Total | 118,213 | 84,614 | 69,081 | |||||||||
Impact of cash-settled derivatives | (4,501 | ) | (1,214 | ) | 2,079 | |||||||
Adjusted Total Revenue (i) | $ | 113,712 | $ | 83,400 | $ | 71,160 | ||||||
Average realized sales price (excluding impact of cash settled derivatives) | ||||||||||||
Oil (Bbl) | $ | 53.79 | $ | 46.10 | $ | 47.05 | ||||||
Natural gas (Mcf) | 4.67 | 3.88 | 3.53 | |||||||||
Total (BOE) | 48.47 | 40.80 | 40.90 | |||||||||
Average realized sales price (including impact of cash settled derivatives) | ||||||||||||
Oil (Bbl) | $ | 51.28 | $ | 45.24 | $ | 48.87 | ||||||
Natural gas (Mcf) | 4.78 | 3.94 | 3.43 | |||||||||
Total (BOE) | 46.62 | 40.21 | 42.13 | |||||||||
Additional per BOE data | ||||||||||||
Sales price (a) | $ | 48.47 | $ | 40.80 | $ | 40.90 | ||||||
Lease operating expense (b) | 4.84 | 5.08 | 7.96 | |||||||||
Gathering and treating expense | 0.57 | 0.52 | 0.40 | |||||||||
Production taxes | 2.55 | 2.62 | 2.20 | |||||||||
Operating margin | $ | 40.51 | $ | 32.58 | $ | 30.34 | ||||||
Depletion, depreciation and amortization | $ | 14.98 | $ | 13.75 | $ | 13.06 | ||||||
Adjusted G&A (c) | ||||||||||||
Cash component (d) | $ | 2.46 | $ | 2.50 | $ | 2.84 | ||||||
Non-cash component | 0.54 | 0.65 | 0.54 | |||||||||
(a) | Excludes the impact of cash settled derivatives. |
(b) | Excludes gathering and treating expense. |
(c) | Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. |
(d) | Excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization. |
Total Revenue. For the quarter ended December 31, 2017, Callon reported total revenue of $118.2 million and total revenue including cash-settled derivatives (“Adjusted Total Revenue,” a non-GAAP financial measure(i)) of $113.7 million, including the impact of a $4.5 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company’s revenue. Average daily production for the quarter was 26.5 MBOE/d compared to average daily production of 22.5 MBOE/d in the third quarter of 2017. Average realized prices, including and excluding the effects of hedging, are detailed below.
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
3
Hedging impacts. For the quarter ended December 31, 2017, Callon recognized the following hedging-related items (in thousands, except per unit data):
Three Months Ended December 31, 2017 | ||||||||
In Thousands | Per Unit | |||||||
Oil derivatives | ||||||||
Net loss on settlements | $ | (4,854 | ) | $ | (2.51 | ) | ||
Net loss on fair value adjustments | (26,010 | ) | ||||||
Total loss on oil derivatives | $ | (30,864 | ) | |||||
Natural gas derivatives | ||||||||
Net gain on settlements | $ | 353 | $ | 0.11 | ||||
Net loss on fair value adjustments | (26 | ) | ||||||
Total gain on natural gas derivatives | $ | 327 | ||||||
Total oil & natural gas derivatives | ||||||||
Net loss on settlements | $ | (4,501 | ) | $ | (1.85 | ) | ||
Net loss on fair value adjustments | (26,036 | ) | ||||||
Total loss on total oil & natural gas derivatives | $ | (30,537 | ) | |||||
Lease Operating Expenses, including workover and gathering expense (“LOE”). LOE per BOE for the three months ended December 31, 2017 was $5.41 per BOE, compared to LOE of $5.60 per BOE in the third quarter of 2017. The decrease in this metric resulted primarily from an increase in production period over period.
Production Taxes, including ad valorem taxes. Production taxes were $2.55 per BOE for the three months ended December 31, 2017, representing approximately 5.3% of total revenue before the impact of derivative settlements.
Depreciation, Depletion and Amortization (“DD&A”). DD&A for the three months ended December 31, 2017 was $14.98 per BOE compared to $13.75 per BOE in the third quarter of 2017. The increase on a per unit basis was primarily attributable to greater increases in our depreciable asset base and assumed future development costs related to undeveloped proved reserves as compared to the estimated total proved reserve base.
General and Administrative (“G&A”). G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, (“Adjusted G&A”, a non-GAAP measure(i)) was $7.3 million, or $3.00 per BOE, for the three months ended December 31, 2017 compared to $6.5 million, or $3.15 per BOE, for the third quarter of 2017. The cash component of Adjusted G&A was $6.0 million, or $2.46 per BOE, for the three months ended December 31, 2017 compared to $5.2 million, or $2.50 per BOE, for the third quarter of 2017.
For the three months ended December 31, 2017, G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands):
Three Months Ended December 31, 2017 | ||||
Total G&A expense | $ | 8,173 | ||
Less: Change in the fair value of liability share-based awards (non-cash) | (844 | ) | ||
Adjusted G&A – total | 7,329 | |||
Less: Restricted stock share-based compensation (non-cash) | (1,202 | ) | ||
Less: Corporate depreciation & amortization (non-cash) | (125 | ) | ||
Adjusted G&A – cash component | $ | 6,002 | ||
Income tax expense. Callon typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. We recorded an income tax expense of $0.2 million for the three months ended December 31, 2017 which relates to deferred State of Texas gross margin tax. At December 31, 2017 we had a valuation allowance of $60.9 million. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision of $8.3 million (or $0.04 per diluted share) for the quarter as if the valuation allowance did not exist.
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
4
Proved Reserves
The Company recently completed the reserve audit for the year ended December 31, 2017 with its independent reserve auditor, DeGolyer and MacNaughton. As of December 31, 2017, Callon’s estimated total proved reserves were 137.0 MMBOE, a 50% increase over the previous year-end. The proved reserves estimate is comprised of 78% oil of which our total proved developed estimated volumes are comprised of 75% oil.
The following table presents the progression of our estimated net proved oil and natural gas reserves from December 31, 2016 to 2017, and in each case, prepared in accordance with the rules and regulations of the SEC.
Proved developed and undeveloped reserves | Oil (MBbls) | Natural Gas (MMcf) | Total (MBOE) | ||||||
As of December 31, 2016 | 71,145 | 122,611 | 91,580 | ||||||
Revisions to previous estimates | (5,171 | ) | 6,336 | (4,115 | ) | ||||
Extensions and discoveries | 39,267 | 48,648 | 47,375 | ||||||
Purchases, net of sales, of reserves in place | 8,388 | 12,711 | 10,507 | ||||||
Production | (6,557 | ) | (10,896 | ) | (8,373 | ) | |||
As of December 31, 2017 | 107,072 | 179,410 | 136,974 | ||||||
Callon added a total of 47.4 MMBOE in 2017 from horizontal development of our properties, replacing 566% of 2017 production as calculated by the sum of reserve extensions and discoveries, divided by annual production (“Organic reserve replacement”). The Company’s finding and development costs from extensions and discoveries (“Drill-Bit F&D costs”) were $8.21 per BOE calculated as accrual costs incurred for exploration and development divided by the reserves (in barrels of oil equivalent) added from extensions and discoveries. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations.
Guidance Update
As a result of the Tax Cuts and Jobs Act, signed into law in December 2017 and effective January 1, 2018, the new federal statutory income tax rate was reduced to 21% from 35%. In addition, the Company adopted the Revenue from Contracts with Customers accounting standard on January 1, 2018. Starting with the first quarter of 2018, certain natural gas gathering and treating expenses will be accounted for as a reduction to revenue.
2017 Actual | 2018 Forecast | |||
Total production (MBOE/d) | 22.9 | 29.5 - 32.0 | ||
% oil | 78% | 77% | ||
Income statement expenses (per BOE) | ||||
LOE, including workovers | $5.46 | $5.25 - $6.25 | ||
Production taxes, including ad valorem (% unhedged revenue) | 6% | 6% | ||
Adjusted G&A: cash component (a) | $2.51 | $1.75 - $2.50 | ||
Adjusted G&A: non-cash component (b) | $0.57 | $0.50 - $1.00 | ||
Interest expense (c) | $0.00 | $0.00 | ||
Statutory income tax rate | 36% | 22% | ||
Capital expenditures ($MM, accrual basis) | ||||
Operational (net of monetizations) (d) | $389 | $500 - $540 | ||
Capitalized expenses | $48 | $60 - $70 | ||
Net operated horizontal wells placed on production | 37 | 43 - 46 | ||
(a) | Excludes stock-based compensation and corporate depreciation and amortization. |
(b) | Excludes certain non-recurring expenses and non-cash valuation adjustments. |
(c) | All interest expense anticipated to be capitalized. |
(d) | Includes seismic, land and other items. Excludes capitalized expenses. |
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
5
Hedge Portfolio Summary
The following tables summarize our open derivative positions for the periods indicated:
For the Full Year of | For the Full Year of | |||||||
Oil contracts (WTI) | 2018 | 2019 | ||||||
Swap contracts | ||||||||
Total volume (MBbls) | 2,009 | — | ||||||
Weighted average price per Bbl | $ | 51.78 | $ | — | ||||
Collar contracts (two-way collars) | ||||||||
Total volume (MBbls) | 365 | — | ||||||
Weighted average price per Bbl | ||||||||
Ceiling (short call) | $ | 60.50 | $ | — | ||||
Floor (long put) | $ | 50.00 | $ | — | ||||
Collar contracts combined with short puts (three-way collars) | ||||||||
Total volume (MBbls) | 3,468 | 1,825 | ||||||
Weighted average price per Bbl | ||||||||
Ceiling (short call option) | $ | 60.86 | $ | 62.40 | ||||
Floor (long put option) | $ | 48.95 | $ | 53.00 | ||||
Short put option | $ | 39.21 | $ | 43.00 | ||||
For the Full Year of | For the Full Year of | |||||||
Oil contracts (Midland basis differential) | 2018 | 2019 | ||||||
Swap contracts | ||||||||
Volume (MBbls) | 5,289 | — | ||||||
Weighted average price per Bbl | $ | (0.86 | ) | $ | — | |||
| For the Full Year of | For the Full Year of | ||||||
Natural gas contracts | 2018 | 2019 | ||||||
Collar contracts (Henry Hub, two-way collars) | ||||||||
Total volume (BBtu) | 720 | — | ||||||
Weighted average price per MMBtu | ||||||||
Ceiling (short call option) | $ | 3.84 | $ | — | ||||
Floor (long put option) | $ | 3.40 | $ | — | ||||
Swap contracts (Henry Hub) | ||||||||
Total volume (BBtu) | 3,366 | — | ||||||
Weighted average price per MMBtu | $ | 2.95 | $ | — | ||||
Income (Loss) Available to Common Shareholders. The Company reported net income available to common shareholders of $21.0 million for the three months ended December 31, 2017 and Adjusted Income available to common shareholders of $30.2 million, or $0.15 per diluted share. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision for the quarter as if the valuation allowance did not exist. The following tables reconcile to the related GAAP measure the Company’s income (loss) available to common stockholders to Adjusted Income and the Company’s net income (loss) to Adjusted EBITDA (in thousands):
Three Months Ended | ||||||||||||
December 31, 2017 | September 30, 2017 | December 31, 2016 | ||||||||||
Income (loss) available to common stockholders | $ | 21,001 | $ | 15,257 | $ | (3,570 | ) | |||||
Change in valuation allowance | (8,285 | ) | (6,064 | ) | 559 | |||||||
Net loss on derivatives, net of settlements | 16,924 | 8,416 | 7,170 | |||||||||
Change in the fair value of share-based awards | 562 | 475 | 590 | |||||||||
Loss on early extinguishment of debt | — | — | 8,374 | |||||||||
Adjusted Income | $ | 30,202 | $ | 18,084 | $ | 13,123 | ||||||
Adjusted Income per fully diluted common share | $ | 0.15 | $ | 0.09 | $ | 0.08 | ||||||
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
6
Three Months Ended | ||||||||||||
December 31, 2017 | September 30, 2017 | December 31, 2016 | ||||||||||
Net income (loss) | $ | 22,824 | $ | 17,081 | $ | (1,746 | ) | |||||
Net loss on derivatives, net of settlements | 26,037 | 12,947 | 11,030 | |||||||||
Non-cash stock-based compensation expense | 2,101 | 1,952 | 1,718 | |||||||||
Loss on early extinguishment of debt | — | — | 12,883 | |||||||||
Acquisition expense | (112 | ) | 205 | 1,263 | ||||||||
Income tax expense | 248 | 237 | 48 | |||||||||
Interest expense | 461 | 444 | 1,369 | |||||||||
Depreciation, depletion and amortization | 37,222 | 29,132 | 22,512 | |||||||||
Accretion expense | 154 | 131 | 196 | |||||||||
Adjusted EBITDA | $ | 88,935 | $ | 62,129 | $ | 49,273 | ||||||
Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended December 31, 2017 was $89.0 million and is reconciled to operating cash flow in the following table (in thousands):
Three Months Ended | ||||||||||||
December 31, 2017 | September 30, 2017 | December 31, 2016 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income (loss) | $ | 22,824 | $ | 17,081 | $ | (1,746 | ) | |||||
Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||||||||||||
Depreciation, depletion and amortization | 37,222 | 29,132 | 22,512 | |||||||||
Accretion expense | 154 | 131 | 196 | |||||||||
Amortization of non-cash debt related items | 455 | 441 | 744 | |||||||||
Deferred income tax expense | 247 | 237 | 48 | |||||||||
Net loss on derivatives, net of settlements | 26,037 | 12,947 | 11,030 | |||||||||
Loss on early extinguishment of debt | — | — | 9,883 | |||||||||
Non-cash expense related to equity share-based awards | 1,240 | 1,219 | 811 | |||||||||
Change in the fair value of liability share-based awards | 865 | 732 | 908 | |||||||||
Discretionary cash flow | $ | 89,044 | $ | 61,920 | $ | 44,386 | ||||||
Changes in working capital | (8,642 | ) | (7,777 | ) | $ | (7,832 | ) | |||||
Payments to settle asset retirement obligations | (216 | ) | (250 | ) | (576 | ) | ||||||
Net cash provided by operating activities | $ | 80,186 | $ | 53,893 | $ | 35,978 | ||||||
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
7
F&D and Reserve Replacement
Calculation | 2017 | |||||
Parameters | Metrics | |||||
Production (MBOE) | (A) | 8,373 | ||||
Proved reserve data | ||||||
Proved reserves (MBOE) | ||||||
Total (MBOE) extensions and discoveries | (B) | 47,375 | ||||
PUD additions | (C) | 24,322 | ||||
PUDs transferred to PDP | (D) | 8,281 | ||||
Total annual reserve additions, net of revisions | (E) | 53,767 | ||||
Capital costs (in thousands) | ||||||
Property acquisition costs | ||||||
Exploration costs | $ | 239,453 | ||||
Development costs | 279,424 | |||||
Unevaluated properties | ||||||
Exploration costs | (F) | 6,374 | ||||
Transfers to evaluated properties | (131,170 | ) | ||||
Leasehold and seismic | 5,006 | |||||
Total capital costs incurred | (G) | $ | 389,075 | |||
Drill-Bit F&D costs per BOE (two-stream) | (G) / (B) | $ | 8.21 | |||
PD F&D per BOE (two-stream) | (G - F) / (B - C + D) | $ | 12.21 | |||
Organic reserve replacement ratio | (B) / (A) | 566 | % | |||
All-sources reserve replacement ratio | (E) / (A) | 642 | % | |||
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations |
8
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)
December 31, 2017 | December 31, 2016 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 27,995 | $ | 652,993 | ||||
Accounts receivable | 114,320 | 69,783 | ||||||
Fair value of derivatives | 406 | 103 | ||||||
Other current assets | 2,139 | 2,247 | ||||||
Total current assets | 144,860 | 725,126 | ||||||
Oil and natural gas properties, full cost accounting method: | ||||||||
Evaluated properties | 3,429,570 | 2,754,353 | ||||||
Less accumulated depreciation, depletion, amortization and impairment | (2,084,095 | ) | (1,947,673 | ) | ||||
Net evaluated oil and natural gas properties | 1,345,475 | 806,680 | ||||||
Unevaluated properties | 1,168,016 | 668,721 | ||||||
Total oil and natural gas properties, net | 2,513,491 | 1,475,401 | ||||||
Other property and equipment, net | 20,361 | 14,114 | ||||||
Restricted investments | 3,372 | 3,332 | ||||||
Deferred tax asset | 52 | — | ||||||
Deferred financing costs | 4,863 | 3,092 | ||||||
Acquisition deposit | 900 | 46,138 | ||||||
Other assets, net | 5,397 | 384 | ||||||
Total assets | $ | 2,693,296 | $ | 2,267,587 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 162,878 | $ | 95,577 | ||||
Accrued interest | 9,235 | 6,057 | ||||||
Cash-settleable restricted stock unit awards | 4,621 | 8,919 | ||||||
Asset retirement obligations | 1,295 | 2,729 | ||||||
Fair value of derivatives | 27,744 | 18,268 | ||||||
Total current liabilities | 205,773 | 131,550 | ||||||
Senior secured revolving credit facility | 25,000 | — | ||||||
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs | 595,196 | 390,219 | ||||||
Asset retirement obligations | 4,725 | 3,932 | ||||||
Cash-settleable restricted stock unit awards | 3,490 | 8,071 | ||||||
Deferred tax liability | 1,457 | 90 | ||||||
Fair value of derivatives | 1,284 | 28 | ||||||
Other long-term liabilities | 405 | 295 | ||||||
Total liabilities | 837,330 | 534,185 | ||||||
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; 201,836,172 and 201,041,320 shares outstanding, respectively | 2,018 | 2,010 | ||||||
Capital in excess of par value | 2,181,359 | 2,171,514 | ||||||
Accumulated deficit | (327,426 | ) | (440,137 | ) | ||||
Total stockholders’ equity | 1,855,966 | 1,733,402 | ||||||
Total liabilities and stockholders’ equity | $ | 2,693,296 | $ | 2,267,587 | ||||
9
Callon Petroleum Company
Consolidated Statements of Operations
(in thousands, except per share data)
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Operating revenues: | ||||||||||||||||
Oil sales | $ | 104,132 | $ | 60,559 | $ | 322,374 | $ | 177,652 | ||||||||
Natural gas sales | 14,082 | 8,522 | 44,100 | 23,199 | ||||||||||||
Total operating revenues | 118,214 | 69,081 | 366,474 | 200,851 | ||||||||||||
Operating expenses: | ||||||||||||||||
Lease operating expenses | 13,201 | 14,124 | 49,907 | 38,353 | ||||||||||||
Production taxes | 6,228 | 3,717 | 22,396 | 11,870 | ||||||||||||
Depreciation, depletion and amortization | 36,543 | 22,051 | 115,714 | 71,369 | ||||||||||||
General and administrative | 8,172 | 6,562 | 27,067 | 26,317 | ||||||||||||
Settled share-based awards | — | — | 6,351 | — | ||||||||||||
Accretion expense | 154 | 196 | 677 | 958 | ||||||||||||
Write-down of oil and natural gas properties | — | — | — | 95,788 | ||||||||||||
Acquisition expense | (112 | ) | 1,263 | 2,916 | 3,673 | |||||||||||
Total operating expenses | 64,186 | 47,913 | 225,028 | 248,328 | ||||||||||||
Income (loss) from operations | 54,028 | 21,168 | 141,446 | (47,477 | ) | |||||||||||
Other (income) expenses: | ||||||||||||||||
Interest expense, net of capitalized amounts | 461 | 1,369 | 2,159 | 11,871 | ||||||||||||
Loss on early extinguishment of debt | — | 12,883 | — | 12,883 | ||||||||||||
Loss on derivative contracts | 30,536 | 8,952 | 18,901 | 20,233 | ||||||||||||
Other income | (41 | ) | (338 | ) | (1,311 | ) | (637 | ) | ||||||||
Total other (income) expense | 30,956 | 22,866 | 19,749 | 44,350 | ||||||||||||
Income (loss) before income taxes | 23,072 | (1,698 | ) | 121,697 | (91,827 | ) | ||||||||||
Income tax (benefit) expense | 248 | 48 | 1,273 | (14 | ) | |||||||||||
Net income (loss) | 22,824 | (1,746 | ) | 120,424 | (91,813 | ) | ||||||||||
Preferred stock dividends | (1,823 | ) | (1,824 | ) | (7,295 | ) | (7,295 | ) | ||||||||
Income (loss) available to common stockholders | $ | 21,001 | $ | (3,570 | ) | $ | 113,129 | $ | (99,108 | ) | ||||||
Income (loss) per common share: | ||||||||||||||||
Basic | $ | 0.10 | $ | (0.02 | ) | $ | 0.56 | $ | (0.78 | ) | ||||||
Diluted | $ | 0.10 | $ | (0.02 | ) | $ | 0.56 | $ | (0.78 | ) | ||||||
Shares used in computing income (loss) per common share: | ||||||||||||||||
Basic | 201,835 | 166,258 | 201,526 | 126,258 | ||||||||||||
Diluted | 202,426 | 166,258 | 202,102 | 126,258 | ||||||||||||
10
Callon Petroleum Company
Consolidated Statements of Cash Flows
(in thousands)
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | 22,824 | $ | (1,746 | ) | $ | 120,424 | $ | (91,813 | ) | ||||||
Adjustments to reconcile net income to cash provided by operating activities: | ||||||||||||||||
Depreciation, depletion and amortization | 37,222 | 22,512 | 118,051 | 73,072 | ||||||||||||
Write-down of oil and natural gas properties | — | — | — | 95,788 | ||||||||||||
Accretion expense | 154 | 196 | 677 | 958 | ||||||||||||
Amortization of non-cash debt related items | 455 | 744 | 2,150 | 3,115 | ||||||||||||
Deferred income tax (benefit) expense | 247 | 48 | 1,273 | (14 | ) | |||||||||||
Loss on derivatives, net of settlements | 26,037 | 11,030 | 10,429 | 38,135 | ||||||||||||
Loss on sale of other property and equipment | — | — | 62 | — | ||||||||||||
Non-cash loss on early extinguishment of debt | — | 9,883 | — | 9,883 | ||||||||||||
Non-cash expense related to equity share-based awards | 1,240 | 811 | 8,254 | 2,765 | ||||||||||||
Change in the fair value of liability share-based awards | 865 | 908 | 3,288 | 6,953 | ||||||||||||
Payments to settle asset retirement obligations | (216 | ) | (576 | ) | (2,047 | ) | (1,471 | ) | ||||||||
Changes in current assets and liabilities: | ||||||||||||||||
Accounts receivable | (32,347 | ) | (13,611 | ) | (44,495 | ) | (30,055 | ) | ||||||||
Other current assets | 444 | (535 | ) | 108 | (786 | ) | ||||||||||
Current liabilities | 23,413 | 5,473 | 30,947 | 25,288 | ||||||||||||
Other long-term liabilities | — | 10 | 121 | 96 | ||||||||||||
Long-term prepaid | — | — | (4,650 | ) | — | |||||||||||
Other assets, net | (152 | ) | 831 | (1,528 | ) | (840 | ) | |||||||||
Payments for cash-settled restricted stock unit awards | — | — | (13,173 | ) | (10,300 | ) | ||||||||||
Net cash provided by operating activities | 80,186 | 35,978 | 229,891 | 120,774 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Capital expenditures | (152,621 | ) | (67,334 | ) | (419,839 | ) | (190,032 | ) | ||||||||
Acquisitions | (3,952 | ) | (352,622 | ) | (718,456 | ) | (654,679 | ) | ||||||||
Acquisition deposit | (900 | ) | (13,438 | ) | 45,238 | (46,138 | ) | |||||||||
Proceeds from sales of mineral interest and equipment | 20,525 | 1,639 | 20,525 | 24,562 | ||||||||||||
Net cash used in investing activities | (136,948 | ) | (431,755 | ) | (1,072,532 | ) | (866,287 | ) | ||||||||
Cash flows from financing activities: | ||||||||||||||||
Borrowings on senior secured revolving credit facility | 25,000 | — | 25,000 | 217,000 | ||||||||||||
Payments on senior secured revolving credit facility | — | — | — | (257,000 | ) | |||||||||||
Payments on term loans | — | (300,000 | ) | — | (300,000 | ) | ||||||||||
Issuance of 6.125% senior unsecured notes due 2024 | — | 400,000 | 200,000 | 400,000 | ||||||||||||
Premium on the issuance of 6.125% senior unsecured notes due 2024 | — | — | 8,250 | — | ||||||||||||
Payment of deferred financing costs | (28 | ) | (10,153 | ) | (7,194 | ) | (10,793 | ) | ||||||||
Issuance of common stock | — | 634,862 | — | 1,357,577 | ||||||||||||
Payment of preferred stock dividends | (1,824 | ) | (1,824 | ) | (7,295 | ) | (7,295 | ) | ||||||||
Tax withholdings related to restricted stock units | — | — | (1,118 | ) | (2,207 | ) | ||||||||||
Net cash provided by financing activities | 23,148 | 722,885 | 217,643 | 1,397,282 | ||||||||||||
Net change in cash and cash equivalents | (33,614 | ) | 327,108 | (624,998 | ) | 651,769 | ||||||||||
Balance, beginning of period | 61,609 | 325,885 | 652,993 | 1,224 | ||||||||||||
Balance, end of period | $ | 27,995 | $ | 652,993 | $ | 27,995 | $ | 652,993 | ||||||||
11
Non-GAAP Financial Measures and Reconciliations
This news release refers to non-GAAP financial measures such as “Discretionary Cash Flow,” “Adjusted G&A,” “Adjusted Income,” “Adjusted EBITDA,” “Adjusted Total Revenue,” “Drill-Bit F&D costs,” “PD F&D costs” and “Organic reserve replacement” These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.
• | Callon believes that the non-GAAP measure of discretionary cash flow is useful as an indicator of an oil and natural gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The Company also 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 may not relate to the period in which the operating activities occurred. Discretionary cash flow is calculated using net income (loss) adjusted for certain items including depreciation, depletion and amortization, the impact of financial derivatives (including the mark-to-market effects, net of cash settlements and premiums paid or received related to our financial derivatives), accretion expense, restructuring and other non-recurring costs, deferred income taxes and other non-cash income items. |
• | 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 above details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A. |
• | We believe 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 above. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted Income and Adjusted Income per diluted share above were computed in accordance with GAAP. |
• | We calculate 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, we believe 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 we present may not be comparable to similarly titled measures of other companies. |
• | We believe 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 account for derivative contracts and hedges and include their effects in revenue. We believe Adjusted Total Revenue is also useful to investors as a measure of the actual cash inflows generated during the period. |
• | We believe “Drill-Bit F&D costs,” “PD F&D costs” and “Organic reserve replacement” ratios 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&A costs,” “PD F&D costs” and “Organic reserve replacement” 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. |
12
Earnings Call Information
The Company will host a conference call on Wednesday, February 28, 2018, to discuss fourth quarter and full-year 2017 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: | Wednesday, February 28, 2018, 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. |
Presentation Slides: | Select “Presentations” under the “Investors” section of the Company’s website: www.callon.com. |
Alternatively, you may join by telephone using the following numbers:
Domestic: | 1-888-317-6003 |
Canada: | 1-866-284-3684 |
International: | 1-412-317-6061 |
Access code: | 2180929 |
An archive of the conference call webcast will also be available at www.callon.com under the “Investors” section of the website.
About Callon Petroleum
Callon Petroleum Company is an independent energy company focused on the acquisition, development, exploration, and operation of oil and natural gas properties in the Permian Basin in West Texas.
This news release is posted on the Company’s website at www.callon.com and will be archived there for subsequent review under the “News” link on the top of the homepage.
Cautionary Statement Regarding Forward Looking Statements
This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; the Company’s 2018 guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; and the implementation of the Company’s business plans and strategy, as well as statements including the words “believe,” “expect,” “plans” and words of similar meaning. These statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on our website or the SEC’s website at www.sec.gov.
Contact information:
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
1-281-589-5279
13