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| 8-K - 8-K - Callon Petroleum Co | a2q18earnings8-k.htm |
Exhibit 99.1
Callon Petroleum Company Announces Second Quarter 2018 Results
Natchez, MS (August 6, 2018) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three and six months ended June 30, 2018.
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 second quarter of 2018 and other recent data points include:
• | Increased production to 29.0 MBOE/D (76% oil), an increase of 30% year-over-year |
• | Reduced lease operating expense by 10% year-over-year to $4.99 per BOE |
• | Generated an operating margin of $44.17 per BOE, an increase of 37% year-over-year |
• | Recent Wolfcamp A wells in the Fairway area of WildHorse outperforming oil type curves by approximately 30% |
• | Successful Wolfcamp A wells at Spur, including the initiation of pad co-development of the Upper and Lower Wolfcamp A, significantly outperforming initial operated wells |
• | Continued outperformance from ten-well downspacing test at Fairway through more than 200 days of production |
• | First “mega-pad” placed on production in July and performing favorably against offset three-well pads |
• | Announced entry into a definitive agreement and completed related financings to acquire approximately 28,657 net surface acres in the Delaware Basin, providing near-term value contribution from current production as well as upside potential, with the transaction projected to close later in the third quarter |
• | Executed a multi-year firm transportation agreement covering 15,000 barrels of oil per day to Gulf Coast destination points and corresponding long-term sales agreements for equivalent volumes based on Gulf Coast and international pricing benchmarks |
Joe Gatto, President and Chief Executive Officer, commented, “Our second quarter results reflect our continued commitment to maximizing returns while thoughtfully growing our business with the support of leading internal cash margins. Halfway through the year, we have drilled and completed more wells than originally anticipated while still managing our capital spending within our original expectations. The team’s continued efforts to reduce operating costs have allowed us to nearly match our operating margins from the first quarter, despite lower realized commodity prices.” He continued, “We have been preparing for the integration of our recently announced acquisition into a combined Spur business plan and are looking forward to contributions from both the production base of acquired properties as well as incremental drilling and completion activity on the new footprint later this year, driving an expected combined production rate of over 40,000 BOE/d in the fourth quarter. Additionally, we have been preparing for growing production volumes with recent additions to our hedging program and a new firm transportation agreement that is a meaningful first step to increasing our exposure to pricing points outside of the Permian Basin.”
Operations Update
At June 30, 2018, we had 267 gross (200.9 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended June 30, 2018 grew approximately 30% to 29.0 MBOE/D (76% oil) as compared to the same period of 2017. The Company expects production for the month of July to be approximately 31.1 MBOE/D (78% oil).
For the three months ended June 30, 2018, we drilled 18 gross (13.7 net) horizontal wells and placed a combined 15 gross (13.7 net) horizontal wells on production.
Midland Basin
During the second quarter, approximately 60% of the net wells placed on production were located in the Midland Basin, with the majority of these wells within our WildHorse area. Of the wells placed on production at WildHorse, over 90% were placed on production during the month of June. These wells had an average lateral length of roughly 8,400 feet. The only wells placed on production in our Monarch area in Midland County were our Casselman 40 21AH and 14H, a Wolfcamp A and B pair test. These wells reached a peak thirty day average of 173 BOE (81% oil) and 214 BOE (83% oil) per lateral foot respectively. Through the first 100 days of production, both have outperformed the 5,000 foot oil type curve for this area.
In the Fairway area of WildHorse, our recent Barclays B Unit pad and Players three-well pad (06AH, 07AH, and 08AH) have both outperformed their respective oil type curves by 29% and 33% (on average) through the initial 40 days of production. Nearby, the Open
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations | ||
1
A2 #1AH and A3 #3AH wells that comprised our 10-well spacing test continue to outperform offsetting comparable pads with eight-well spacing after more than 200 days of production.
Delaware Basin
The Rendezvous A1 #01LA and A2 #09UA, which were placed on production in April, have collectively produced over 260,000 BOE (~85% oil) in their first 100 days on production, significantly outperforming all previous Callon wells at our Spur area. The wells were completed with approximately 7,500 and 7,800 foot laterals, respectively. During the middle of the quarter, we placed the Moran A1 01LA on production with a completed lateral length of just under 5,800 feet. Through the first 75 days of production, the Moran well has produced approximately 80,000 BOE (~75% oil). In June, the Rag Run A1 #01LA and 134 South #25CH wells were completed with lateral lengths of approximately 9,300 and 4,800 feet, respectively, and placed on production. The A1 #01LA has produced approximately 75,000 BOE (~85% oil) through the first 40 days of production. The 134 South #25CH, our first Wolfcamp C test on our Delaware acreage position, has produced over 23,000 BOE (~80% oil) through 43 days.
Firm Transportation Agreement
Recently, 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, Ward, Reagan and Upton 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 commitment of 15,000 Bbls per day for a multi-year term. Multi-year, firm sales agreements covering all 15,000 barrels have already been agreed upon with established buyers in the Gulf Coast region.
Infrastructure and Operational Efficiency
During the second quarter, significant progress was made in the planned infrastructure build out across our operating areas. All planned work at our Ranger area has been completed. At Spur, our new recycling facilities and recycling frac pits are complete, the majority of water transfer line work has been finished, and we have finished the installation of a new power substation.
Continued focus on operational efficiencies resulted in the company placing more wells on production during the second quarter than originally anticipated. Compared to the first quarter, the company placed nearly double the amount of net lateral feet on production during the second quarter, with over half of that coming in June. We have begun to increase our water recycling efforts and have recycled over a half million barrels of produced water through the first half of 2018. The company expects to continue ramping those volumes during the second half of the year. We also recently renewed the contract on a fifth drilling rig for a term of two years.
Capital Expenditures
For the three months ended June 30, 2018, we incurred $163.5 million in cash operational capital expenditures (including other items) compared to $105.3 million in the first quarter of 2018. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):
Three Months Ended June 30, 2018 | ||||||||||||||||
Operational | Capitalized | Capitalized | Total Capital | |||||||||||||
Capital (a) | Interest | G&A | Expenditures | |||||||||||||
Cash basis (b) | $ | 163,462 | $ | 19,189 | $ | 4,389 | $ | 187,040 | ||||||||
Timing adjustments (c) | 2,500 | (7,139 | ) | — | (4,639 | ) | ||||||||||
Non-cash items | — | — | 427 | 427 | ||||||||||||
Accrual (GAAP) basis | $ | 165,962 | $ | 12,050 | $ | 4,816 | $ | 182,828 | ||||||||
(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. |
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 | ||||||||||||
June 30, 2018 | March 31, 2018 | June 30, 2017 | ||||||||||
Net production | ||||||||||||
Oil (MBbls) | 1,995 | 1,851 | 1,596 | |||||||||
Natural gas (MMcf) | 3,839 | 3,240 | 2,550 | |||||||||
Total (MBOE) | 2,635 | 2,391 | 2,021 | |||||||||
Average daily production (BOE/d) | 28,954 | 26,567 | 22,209 | |||||||||
% oil (BOE basis) | 76 | % | 77 | % | 79 | % | ||||||
Oil and natural gas revenues (in thousands) | ||||||||||||
Oil revenue | $ | 122,613 | $ | 115,286 | $ | 72,885 | ||||||
Natural gas revenue (a) | 14,462 | 12,154 | 9,398 | |||||||||
Total revenue | 137,075 | 127,440 | 82,283 | |||||||||
Impact of cash-settled derivatives | (7,980 | ) | (8,459 | ) | (267 | ) | ||||||
Adjusted Total Revenue (i) | $ | 129,095 | $ | 118,981 | $ | 82,016 | ||||||
Average realized sales price (excluding impact of cash settled derivatives) | ||||||||||||
Oil (Bbl) | $ | 61.46 | $ | 62.28 | $ | 45.67 | ||||||
Natural gas (Mcf) | 3.77 | 3.75 | 3.69 | |||||||||
Total (BOE) | 52.02 | 53.30 | 40.71 | |||||||||
Average realized sales price (including impact of cash settled derivatives) | ||||||||||||
Oil (Bbl) | $ | 57.38 | $ | 57.47 | $ | 45.47 | ||||||
Natural gas (Mcf) | 3.81 | 3.89 | 3.70 | |||||||||
Total (BOE) | 48.99 | 49.76 | 40.58 | |||||||||
Additional per BOE data | ||||||||||||
Sales price (b) | $ | 52.02 | $ | 53.30 | $ | 40.71 | ||||||
Lease operating expense (c) | 4.99 | 5.45 | 5.56 | |||||||||
Gathering and treating expense (a) | — | — | 0.45 | |||||||||
Production taxes | 2.86 | 3.54 | 2.38 | |||||||||
Operating margin | $ | 44.17 | $ | 44.31 | $ | 32.32 | ||||||
Depletion, depreciation and amortization | $ | 14.70 | $ | 14.81 | $ | 12.97 | ||||||
Adjusted G&A (d) | ||||||||||||
Cash component (e) | $ | 2.69 | $ | 2.74 | $ | 2.67 | ||||||
Non-cash component | 0.64 | 0.51 | 0.53 | |||||||||
(a) | On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the three and six months ended June 30, 2018 were accounted for as a reduction to revenue. |
(b) | Excludes the impact of cash-settled derivatives. |
(c) | Excludes gathering and treating expense. |
(d) | 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. |
(e) | Excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization. |
Total Revenue. For the quarter ended June 30, 2018, Callon reported total revenue of $137.1 million and total revenue including cash-settled derivatives (“Adjusted Total Revenue,” a non-GAAP financial measure(i)) of $129.1 million, including the impact of an $8.0 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 29.0 MBOE/d compared to average daily production of 26.6 MBOE/d in the first quarter of 2018. Average realized prices, including and excluding the effects of hedging, are detailed above.
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations | ||
3
Hedging impacts. For the quarter ended June 30, 2018, Callon recognized the following hedging-related items (in thousands, except per unit data):
In Thousands | Per Unit | ||||||
Oil derivatives | |||||||
Net loss on settlements | $ | (8,131 | ) | $ | (4.08 | ) | |
Net loss on fair value adjustments | (8,311 | ) | |||||
Total loss on oil derivatives | $ | (16,442 | ) | ||||
Natural gas derivatives | |||||||
Net gain on settlements | $ | 151 | $ | 0.04 | |||
Net loss on fair value adjustments | (263 | ) | |||||
Total loss on natural gas derivatives | $ | (112 | ) | ||||
Total oil & natural gas derivatives | |||||||
Net loss on settlements | $ | (7,980 | ) | $ | (3.03 | ) | |
Net loss on fair value adjustments | (8,574 | ) | |||||
Total loss on total oil & natural gas derivatives | $ | (16,554 | ) | ||||
Lease Operating Expenses, including workover (“LOE”). LOE per BOE for the three months ended June 30, 2018 was $4.99 per BOE, compared to LOE of $5.45 per BOE in the first quarter of 2018. The decrease in this metric resulted primarily from a decrease in saltwater disposal costs and an increase in production volumes period over period.
Production Taxes, including ad valorem taxes. Production taxes were $2.86 per BOE for the three months ended June 30, 2018, representing approximately 5.5% of total revenue before the impact of derivative settlements.
Depreciation, Depletion and Amortization (“DD&A”). DD&A for the three months ended June 30, 2018 was $14.70 per BOE compared to $14.81 per BOE in the first quarter of 2018. The decrease is attributable to our increased estimated proved reserves relative to our depreciable base and assumed future development costs related to undeveloped proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions.
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 $8.8 million, or $3.33 per BOE, for the three months ended June 30, 2018 compared to $7.8 million, or $3.25 per BOE, for the first quarter of 2018. The cash component of Adjusted G&A was $7.1 million, or $2.69 per BOE, for the three months ended June 30, 2018 compared to $6.5 million, or $2.74 per BOE, for the first quarter of 2018.
For the three months ended June 30, 2018, 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 June 30, 2018 | |||
Total G&A expense | $ | 8,289 | |
Plus: Change in the fair value of liability share-based awards (non-cash) | 484 | ||
Adjusted G&A – total | 8,773 | ||
Less: Restricted stock share-based compensation (non-cash) | (1,587 | ) | |
Less: Corporate depreciation & amortization (non-cash) | (109 | ) | |
Adjusted G&A – cash component | $ | 7,077 | |
Income tax expense. Callon provides for income taxes at a statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls and shortfalls, and state income taxes. We recorded an income tax expense of $0.5 million for the three months ended June 30, 2018 which relates to deferred state franchise tax. At June 30, 2018 we had a valuation allowance of $38.6 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 $10.6 million (or $0.05 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
2018 Guidance
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 were accounted for as a reduction to revenue. The Company expects to provide updated guidance upon the closing of the previous announced acquisition of assets in the Delaware Basin for $570 million.
Second Quarter | First Half | Full Year | ||||
2018 Actual | 2018 Actual | 2018 Guidance | ||||
Total production (MBOE/d) | 29.0 | 27.8 | 29.5 - 32.0 | |||
% oil | 76% | 77% | 77% | |||
Income statement expenses (per BOE) | ||||||
LOE, including workovers | $4.99 | $5.21 | $5.25 - $6.25 | |||
Production taxes, including ad valorem (% unhedged revenue) | 5% | 6% | 6% | |||
Adjusted G&A: cash component (a) | $2.69 | $2.71 | $1.75 - $2.50 | |||
Adjusted G&A: non-cash component (b) | $0.64 | $0.58 | $0.50 - $1.00 | |||
Interest expense (c) | $0.00 | $0.00 | $0.00 | |||
Effective income tax rate | 22% | 22% | 22% | |||
Capital expenditures ($MM, accrual basis) | ||||||
Operational (d) | $166 | $283 | $500 - $540 | |||
Capitalized expenses | $17 | $33 | $60 - $70 | |||
Net operated horizontal wells placed on production | 14 | 23 | 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 Remainder | For the Full Year | For the Full Year | |||||||||
Oil contracts (WTI) | of 2018 | of 2019 | of 2020 | ||||||||
Swap contracts | |||||||||||
Total volume (Bbls) | 1,104,000 | — | — | ||||||||
Weighted average price per Bbl | $ | 52.07 | $ | — | $ | — | |||||
Collar contracts (two-way collars) | |||||||||||
Total volume (Bbls) | 184,000 | — | — | ||||||||
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 (Bbls) | 1,748,000 | 3,469,000 | — | ||||||||
Weighted average price per Bbl | |||||||||||
Ceiling (short call option) | $ | 60.86 | $ | 63.71 | $ | — | |||||
Floor (long put option) | $ | 48.95 | $ | 53.95 | $ | — | |||||
Short put option | $ | 39.21 | $ | 43.95 | $ | — | |||||
Puts | |||||||||||
Total volume (Bbls) | 552,000 | 1,825,000 | — | ||||||||
Weighted average price per Bbl | $ | 65.00 | $ | 65.00 | $ | — | |||||
Oil contracts (Midland basis differential) | |||||||||||
Swap contracts | |||||||||||
Total volume (Bbls) | 2,208,000 | 4,380,000 | 3,660,000 | ||||||||
Weighted average price per Bbl | $ | (4.26 | ) | $ | (4.77 | ) | $ | (1.47 | ) | ||
Natural gas contracts (Henry Hub) | |||||||||||
Swap contracts | |||||||||||
Total volume (MMBtu) | 2,760,000 | — | — | ||||||||
Weighted average price per MMBtu | $ | 2.91 | $ | — | $ | — | |||||
Collar contracts (two-way collars) | |||||||||||
Total volume (MMBtu) | 1,104,000 | 2,372,500 | — | ||||||||
Weighted average price per MMBtu | |||||||||||
Ceiling (short call) | $ | 3.19 | $ | 2.95 | $ | — | |||||
Floor (long put) | $ | 2.75 | $ | 2.65 | $ | — | |||||
Natural gas contracts (Waha basis differential) | |||||||||||
Swap contracts | |||||||||||
Total volume (MMBtu) | 1,104,000 | 2,190,000 | 2,196,000 | ||||||||
Weighted average price per MMBtu | $ | (1.14 | ) | $ | (1.14 | ) | $ | (1.14 | ) | ||
Income Available to Common Shareholders. The Company reported net income available to common shareholders of $48.7 million for the three months ended June 30, 2018 and Adjusted Income available to common shareholders of $44.5 million, or $0.21 per fully diluted share. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income 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 available to common stockholders to Adjusted Income and the Company’s net income to Adjusted EBITDA, a non-GAAP financial measure, (in thousands):
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations | ||
6
Three Months Ended | |||||||||||
June 30, 2018 | March 31, 2018 | June 30, 2017 | |||||||||
Income available to common stockholders | $ | 48,650 | $ | 53,937 | $ | 31,566 | |||||
Change in valuation allowance | (10,562 | ) | (11,753 | ) | (11,194 | ) | |||||
Net (gain) loss on derivatives, net of settlements | 6,772 | (3,143 | ) | (6,995 | ) | ||||||
Change in the fair value of share-based awards | (366 | ) | 799 | (315 | ) | ||||||
Settled share-based awards | — | — | 4,128 | ||||||||
Adjusted Income | $ | 44,494 | $ | 39,840 | $ | 17,190 | |||||
Adjusted Income per fully diluted common share | $ | 0.21 | $ | 0.20 | $ | 0.09 | |||||
Three Months Ended | |||||||||||
June 30, 2018 | March 31, 2018 | June 30, 2017 | |||||||||
Net income | $ | 50,474 | $ | 55,761 | $ | 33,390 | |||||
Net (gain) loss on derivatives, net of settlements | 8,572 | (3,978 | ) | (10,761 | ) | ||||||
Non-cash stock-based compensation expense | 1,164 | 2,143 | 499 | ||||||||
Settled share-based awards | — | — | 6,351 | ||||||||
Acquisition expense | 1,767 | 548 | 2,373 | ||||||||
Income tax expense | 481 | 495 | 322 | ||||||||
Interest expense | 594 | 460 | 589 | ||||||||
Depreciation, depletion and amortization | 39,387 | 36,066 | 26,765 | ||||||||
Accretion expense | 206 | 218 | 208 | ||||||||
Adjusted EBITDA | $ | 102,645 | $ | 91,713 | $ | 59,736 | |||||
Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended June 30, 2018 was $100.9 million and is reconciled to operating cash flow in the following table (in thousands):
Three Months Ended | |||||||||||
June 30, 2018 | March 31, 2018 | June 30, 2017 | |||||||||
Cash flows from operating activities: | |||||||||||
Net income | $ | 50,474 | $ | 55,761 | $ | 33,390 | |||||
Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||
Depreciation, depletion and amortization | 39,387 | 36,066 | 26,765 | ||||||||
Accretion expense | 206 | 218 | 208 | ||||||||
Amortization of non-cash debt related items | 588 | 453 | 589 | ||||||||
Deferred income tax expense | 481 | 495 | 323 | ||||||||
Net (gain) loss on derivatives, net of settlements | 8,572 | (3,978 | ) | (10,761 | ) | ||||||
Loss on sale of other property and equipment | 22 | — | 62 | ||||||||
Non-cash expense related to equity share-based awards | 1,627 | 1,131 | 4,865 | ||||||||
Change in the fair value of liability share-based awards | (463 | ) | 1,012 | 1,982 | |||||||
Discretionary cash flow | $ | 100,894 | $ | 91,158 | $ | 57,423 | |||||
Changes in working capital | 8,978 | 4,512 | (8,968 | ) | |||||||
Payments to settle asset retirement obligations | (207 | ) | (366 | ) | (816 | ) | |||||
Payments to settle vested liability share-based awards | (1,901 | ) | (3,089 | ) | (4,511 | ) | |||||
Net cash provided by operating activities | $ | 107,764 | $ | 92,215 | $ | 43,128 | |||||
i) See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations | ||
7
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)
June 30, 2018 | December 31, 2017 | |||||||
ASSETS | Unaudited | |||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 509,146 | $ | 27,995 | ||||
Accounts receivable | 111,964 | 114,320 | ||||||
Fair value of derivatives | 11,569 | 406 | ||||||
Other current assets | 7,689 | 2,139 | ||||||
Total current assets | 640,368 | 144,860 | ||||||
Oil and natural gas properties, full cost accounting method: | ||||||||
Evaluated properties | 3,814,242 | 3,429,570 | ||||||
Less accumulated depreciation, depletion, amortization and impairment | (2,158,225 | ) | (2,084,095 | ) | ||||
Net evaluated oil and natural gas properties | 1,656,017 | 1,345,475 | ||||||
Unevaluated properties | 1,144,138 | 1,168,016 | ||||||
Total oil and natural gas properties | 2,800,155 | 2,513,491 | ||||||
Other property and equipment, net | 21,514 | 20,361 | ||||||
Restricted investments | 3,393 | 3,372 | ||||||
Deferred tax asset | 26 | 52 | ||||||
Deferred financing costs | 5,749 | 4,863 | ||||||
Fair value of derivatives | 2,299 | — | ||||||
Acquisition deposit | 28,500 | 900 | ||||||
Other assets, net | 5,322 | 5,397 | ||||||
Total assets | $ | 3,507,326 | $ | 2,693,296 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 193,981 | $ | 162,878 | ||||
Accrued interest | 11,351 | 9,235 | ||||||
Cash-settleable restricted stock unit awards | 1,781 | 4,621 | ||||||
Asset retirement obligations | 2,284 | 1,295 | ||||||
Fair value of derivatives | 35,948 | 27,744 | ||||||
Total current liabilities | 245,345 | 205,773 | ||||||
Senior secured revolving credit facility | — | 25,000 | ||||||
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs | 595,552 | 595,196 | ||||||
6.375% senior unsecured notes due 2026, net of unamortized deferred financing costs | 392,907 | — | ||||||
Asset retirement obligations | 7,782 | 4,725 | ||||||
Cash-settleable restricted stock unit awards | 1,900 | 3,490 | ||||||
Deferred tax liability | 2,431 | 1,457 | ||||||
Fair value of derivatives | 11,136 | 1,284 | ||||||
Other long-term liabilities | 665 | 405 | ||||||
Total liabilities | 1,257,718 | 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; 227,507,031 and 201,836,172 shares outstanding, respectively | 2,275 | 2,018 | ||||||
Capital in excess of par value | 2,472,155 | 2,181,359 | ||||||
Accumulated deficit | (224,837 | ) | (327,426 | ) | ||||
Total stockholders’ equity | 2,249,608 | 1,855,966 | ||||||
Total liabilities and stockholders’ equity | $ | 3,507,326 | $ | 2,693,296 | ||||
8
Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited; in thousands, except per share data)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Operating revenues: | |||||||||||||||
Oil sales | $ | 122,613 | $ | 72,885 | $ | 237,898 | $ | 144,893 | |||||||
Natural gas sales | 14,462 | 9,398 | 26,617 | 18,754 | |||||||||||
Total operating revenues | 137,075 | 82,283 | 264,515 | 163,647 | |||||||||||
Operating expenses: | |||||||||||||||
Lease operating expenses | 13,141 | 12,145 | 26,179 | 25,084 | |||||||||||
Production taxes | 7,539 | 4,820 | 16,002 | 10,723 | |||||||||||
Depreciation, depletion and amortization | 38,733 | 26,213 | 74,151 | 50,646 | |||||||||||
General and administrative | 8,289 | 6,430 | 17,057 | 11,636 | |||||||||||
Settled share-based awards | — | 6,351 | — | 6,351 | |||||||||||
Accretion expense | 206 | 208 | 424 | 392 | |||||||||||
Acquisition expense | 1,767 | 2,373 | 2,315 | 2,822 | |||||||||||
Total operating expenses | 69,675 | 58,540 | 136,128 | 107,654 | |||||||||||
Income from operations | 67,400 | 23,743 | 128,387 | 55,993 | |||||||||||
Other (income) expenses: | |||||||||||||||
Interest expense, net of capitalized amounts | 594 | 589 | 1,053 | 1,254 | |||||||||||
(Gain) loss on derivative contracts | 16,554 | (10,494 | ) | 21,036 | (25,797 | ) | |||||||||
Other income | (703 | ) | (64 | ) | (914 | ) | (772 | ) | |||||||
Total other (income) expense | 16,445 | (9,969 | ) | 21,175 | (25,315 | ) | |||||||||
Income before income taxes | 50,955 | 33,712 | 107,212 | 81,308 | |||||||||||
Income tax expense | 481 | 322 | 976 | 789 | |||||||||||
Net income | 50,474 | 33,390 | 106,236 | 80,519 | |||||||||||
Preferred stock dividends | (1,824 | ) | (1,824 | ) | (3,647 | ) | (3,647 | ) | |||||||
Income available to common stockholders | $ | 48,650 | $ | 31,566 | $ | 102,589 | $ | 76,872 | |||||||
Income per common share: | |||||||||||||||
Basic | $ | 0.23 | $ | 0.16 | $ | 0.50 | $ | 0.38 | |||||||
Diluted | $ | 0.23 | $ | 0.16 | $ | 0.50 | $ | 0.38 | |||||||
Shares used in computing income per common share: | |||||||||||||||
Basic | 210,698 | 201,386 | 206,309 | 201,220 | |||||||||||
Diluted | 211,465 | 201,905 | 207,027 | 201,823 | |||||||||||
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Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Cash flows from operating activities: | |||||||||||||||
Net income | $ | 50,474 | $ | 33,390 | $ | 106,236 | $ | 80,519 | |||||||
Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||||||
Depreciation, depletion and amortization | 39,387 | 26,765 | 75,453 | 51,697 | |||||||||||
Accretion expense | 206 | 208 | 424 | 392 | |||||||||||
Amortization of non-cash debt related items | 588 | 589 | 1,041 | 1,254 | |||||||||||
Deferred income tax expense | 481 | 323 | 976 | 789 | |||||||||||
Net (gain) loss on derivatives, net of settlements | 8,572 | (10,761 | ) | 4,594 | (28,555 | ) | |||||||||
Loss on sale of other property and equipment | 22 | 62 | 22 | 62 | |||||||||||
Non-cash expense related to equity share-based awards | 1,627 | 4,865 | 2,758 | 5,795 | |||||||||||
Change in the fair value of liability share-based awards | (463 | ) | 1,982 | 549 | 1,691 | ||||||||||
Payments to settle asset retirement obligations | (207 | ) | (816 | ) | (573 | ) | (1,581 | ) | |||||||
Changes in current assets and liabilities: | |||||||||||||||
Accounts receivable | 10,447 | (3,744 | ) | 2,380 | (7,810 | ) | |||||||||
Other current assets | (5,611 | ) | (874 | ) | (5,550 | ) | (298 | ) | |||||||
Current liabilities | 4,123 | (4,223 | ) | 17,061 | 5,680 | ||||||||||
Other long-term liabilities | 200 | 120 | 287 | 120 | |||||||||||
Other assets, net | (181 | ) | (247 | ) | (689 | ) | (770 | ) | |||||||
Payments to settle vested liability share-based awards | (1,901 | ) | (4,511 | ) | (4,990 | ) | (13,173 | ) | |||||||
Net cash provided by operating activities | 107,764 | 43,128 | 199,979 | 95,812 | |||||||||||
Cash flows from investing activities: | |||||||||||||||
Capital expenditures | (187,040 | ) | (79,936 | ) | (298,370 | ) | (146,090 | ) | |||||||
Acquisitions | (6,469 | ) | (58,004 | ) | (45,392 | ) | (706,489 | ) | |||||||
Acquisition deposit | (28,500 | ) | — | (27,600 | ) | 46,138 | |||||||||
Proceeds from sale of assets | 3,077 | — | 3,077 | — | |||||||||||
Net cash used in investing activities | (218,932 | ) | (137,940 | ) | (368,285 | ) | (806,441 | ) | |||||||
Cash flows from financing activities: | |||||||||||||||
Borrowings on senior secured revolving credit facility | 85,000 | — | 165,000 | — | |||||||||||
Payments on senior secured revolving credit facility | (160,000 | ) | — | (190,000 | ) | — | |||||||||
Issuance of 6.125% senior unsecured notes due 2024 | — | 200,000 | — | 200,000 | |||||||||||
Premium on the issuance of 6.125% senior unsecured notes due 2024 | — | 8,250 | — | 8,250 | |||||||||||
Issuance of 6.375% senior unsecured notes due 2026 | 400,000 | — | 400,000 | — | |||||||||||
Issuance of common stock | 288,357 | — | 288,357 | — | |||||||||||
Payment of preferred stock dividends | (1,824 | ) | (1,823 | ) | (3,647 | ) | (3,647 | ) | |||||||
Payment of deferred financing costs | (8,664 | ) | (6,765 | ) | (8,664 | ) | (6,765 | ) | |||||||
Tax withholdings related to restricted stock units | (1,028 | ) | (974 | ) | (1,589 | ) | (1,053 | ) | |||||||
Net cash provided by financing activities | 601,841 | 198,688 | 649,457 | 196,785 | |||||||||||
Net change in cash and cash equivalents | 490,673 | 103,876 | 481,151 | (513,844 | ) | ||||||||||
Balance, beginning of period | 18,473 | 35,273 | 27,995 | 652,993 | |||||||||||
Balance, end of period | $ | 509,146 | $ | 139,149 | $ | 509,146 | $ | 139,149 | |||||||
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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” and “Adjusted Total Revenue.” 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. |
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Earnings Call Information
The Company will host a conference call on Tuesday, August 7, 2018, to discuss second quarter 2018 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: | Tuesday, August 7, 2018, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time) |
Webcast: | Select “IR Calendar” under the “Investors” section of the website: www.callon.com. |
Presentation Slides: | Select “Presentations” under the “Investors” section of the website: www.callon.com. |
Alternatively, you may join by telephone using the following numbers:
Toll Free: | 1-888-317-6003 |
Canada Toll Free: | 1-866-284-3684 |
International: | 1-412-317-6061 |
Access code: | 8210968 |
An archive of the conference call webcast will 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
1-281-589-5200
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