Callon Petroleum Company Announces First Quarter 2019 Results

Callon Petroleum Company Announces Third Quarter 2018 Results

HOUSTON, May 6, 2019 /PRNewswire/ — Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three months ended March 31, 2019.

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.

Highlights

  • Increased production to 40.3 Mboe/d (79% oil), an increase of 52% year-over-year
  • Generated an operating margin of $32.57 per Boe
  • Recently completed a five-well pad in the southern portion of WildHorse, developing an entire half section in the Wolfcamp A
  • Initial 2nd Bone Spring shale well placed on production in the Delaware and showing positive early performance
  • Continued strong production from a Middle Spraberry well drilled at Monarch as part of multi-well, co-development of three flow units
  • Improved completion efficiency, measured in stages per day, by more than 25% compared to the same period in 2018
  • Reduced average drilling and completion costs by 15% sequentially, resulting in an average cost per lateral foot below $1,000
  • Announced the pending sale of certain non-core assets in the southern Midland Basin for estimated gross proceeds of $260 million, with potential contingency payments of up to $60 million based upon average annual commodity prices over a three-year period
  • Reaffirmed a borrowing base of $1.1 billion, pro forma for the pending non-core asset sale

“We are ahead of our plan to build out an inventory of drilled, uncompleted wells to extend our usage of a larger pad development model, applying this concept to the Delaware Basin as we continue to build upon our success in the Midland Basin. Capitalizing on the efficiencies of larger development, we delivered a sequential decrease in average drilling and completion cost per lateral foot of 15% in the first quarter. Our drilling plan is quickly progressing to the point where we will decrease to four drilling rigs and start larger Delaware Basin pad completions towards the end of the second quarter.” commented Joe Gatto, President and Chief Executive Officer. He continued, “The previously announced sale of our Ranger properties will streamline our operations with a focus on three core operating areas with well-established infrastructure. Since we did not have any planned Ranger activity in 2019, the divestiture will not impact our base 2019 activity levels, but will allow us to optimize our 2020 capital allocation with the removal of Ranger drilling obligations. Upon closing, all cash proceeds will be directed to bolstering our financial position. We remain focused on executing our 2019 plan within our previously announced budget range, with the benefit of incremental cash flow from commodity realizations above our planning case flowing to the bottom line and the benefit our shareholders.”

Operations Update

At March 31, 2019, we had 524 gross (395.4 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended March 31, 2019 grew 52% to 40.3 Mboe/d (79% oil) as compared to the same period of 2018.

For the three months ended March 31, 2019, we drilled 21 gross (16.4 net) horizontal wells, and placed a combined 13 gross (11.2 net) horizontal wells on production. Wells placed on production during the quarter were completed in the Lower Spraberry, Middle Spraberry, Wolfcamp A and Wolfcamp B within the Midland Basin and the Lower Wolfcamp A within the Delaware Basin.

Midland Basin

We brought 11 gross (9.2 net) wells on production in the Midland Basin during the first quarter with the majority of activity coming from our Monarch area. Our Middle Spraberry well, the Kendra Amanda PSA 33 MS, an 8,000 foot lateral, which was completed as part of a multi-well pad project, has achieved a 30-day average production rate of approximately 110 Boe per thousand lateral feet (90% oil) and continues to perform well.

Near the end of the quarter, in the WildHorse area in Howard County, we began flowback on a five-well pad that employed half section development in the Wolfcamp A. While not all wells have reached 30 days of production, the combined five-well average for current accumulated production includes an average peak rate of over 1,500 Boe per day (92% oil) or approximately 175 Boe per thousand lateral feet.

The previously disclosed outage at a third party gas processing facility in Martin County has been resolved and we currently do not forecast any impact to second quarter production.

Delaware Basin

At our Spur area in Ward County, we placed on production the Wally World A1 01LA and A2 02LA, both Lower Wolfcamp A wells, which together have achieved cumulative production of over 100,000 Boe (84% oil) during their first 30 days of production. Recently, a two-well pad featuring 2nd Bone Spring shale and Lower Wolfcamp A co-development at Spur, was completed and placed on production. Both wells have performed as expected during their limited time on production and we will continue to monitor and compare to third party offsets in the area.

The field optimization project that was initiated during the first quarter of 2019 is progressing and is expected to be completed near the end of the second quarter.  We currently expect deferred production related to wells shut in for repairs to average 1,600 Boe per day (79% oil) for the second quarter.

Capital Expenditures

For the three months ended March 31, 2019, we incurred $155.2 million in operational capital expenditures (including other items) on an accrual basis as compared to $141.2 million in the fourth quarter of 2018. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):

Three Months Ended March 31, 2019

Operational

Capitalized

Capitalized

Total Capital

Capital (a)

Interest

G&A

Expenditures

Cash basis (b)

$

164,277

$

18,589

$

10,345

$

193,211

Timing adjustments (c)

(9,109)

1,255

(7,854)

Non-cash items

354

354

   Accrual basis

$

155,168

$

19,844

$

10,699

$

185,711

(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.

Operating and Financial Results

The following table presents summary information for the periods indicated:

Three Months Ended

March 31, 2019

December 31, 2018

March 31, 2018

Net production

Oil (MBbls)

2,858

3,076

1,851

Natural gas (MMcf)

4,619

4,225

3,240

   Total (Mboe)

3,628

3,780

2,391

Average daily production (Boe/d)

40,311

41,087

26,567

   % oil (Boe basis)

79

%

81

%

77

%

Oil and natural gas revenues (in thousands)

   Oil revenue

$

141,098

$

150,398

$

115,286

   Natural gas revenue

11,949

11,497

12,154

      Total revenue

153,047

161,895

127,440

   Impact of settled derivatives

(290)

(1,594)

(8,459)

      Adjusted Total Revenue (i)

$

152,757

$

160,301

$

118,981

Average realized sales price
(excluding impact of settled derivatives)

   Oil (per Bbl)

$

49.37

$

48.89

$

62.28

   Natural gas (per Mcf)

2.59

2.72

3.75

   Total (per BOE)

42.18

42.83

53.30

Average realized sales price
(including impact of settled derivatives)

   Oil (per Bbl)

$

48.83

$

48.52

$

57.47

   Natural gas (per Mcf)

2.86

2.62

3.89

   Total (per BOE)

42.11

42.41

49.76

Additional per BOE data

   Sales price (a)

$

42.18

$

42.83

$

53.30

      Lease operating expense

6.63

6.47

5.45

      Production taxes

2.98

2.51

3.54

   Operating margin

$

32.57

$

33.85

$

44.31

   Depletion, depreciation and amortization

$

16.47

$

15.74

$

14.81

   Adjusted G&A (b)

      Cash component (c)

$

2.28

$

2.03

$

2.74

      Non-cash component

0.44

0.50

0.51

(a) 

Excludes the impact of settled derivatives.

(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) 

Excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization.

Total Revenue. For the quarter ended March 31, 2019, Callon reported total revenue of $153.0 million and total revenue including settled derivatives (“Adjusted Total Revenue,” a non-GAAP financial measure(i)) of $152.8 million, including the impact of a $0.3 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company’s total operating revenue. Average daily production for the quarter was 40.3 Mboe/d compared to average daily production of 41.1 Mboe/d in the fourth quarter of 2018. Average realized prices, including and excluding the effects of hedging, are detailed above.

Hedging impacts. For the quarter ended March 31, 2019, Callon recognized the following hedging-related items (in thousands, except per unit data):

Three Months Ended March 31, 2019

In Thousands

Per Unit

Oil derivatives

Net loss on settlements

$

(1,542)

$

(0.54)

Net loss on fair value adjustments

(66,826)

   Total loss on oil derivatives

$

(68,368)

Natural gas derivatives

Net gain on settlements

$

1,252

$

0.27

Net loss on fair value adjustments

(144)

   Total gain on natural gas derivatives

$

1,108

Total oil & natural gas derivatives

Net loss on settlements

$

(290)

$

(0.07)

Net loss on fair value adjustments

(66,970)

   Total loss on total oil & natural gas derivatives

$

(67,260)

Lease Operating Expenses, including workover (“LOE”). LOE per Boe for the three months ended March 31, 2019 was $6.63 per Boe, compared to LOE of $6.47 per Boe in the fourth quarter of 2018. The increase on a per unit basis was primarily attributed to a 1.9% decrease in daily production.

Production Taxes, including ad valorem taxes. Production taxes were $2.98 per Boe for the three months ended March 31, 2019, representing approximately 7.1% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization (“DD&A”). DD&A for the three months ended March 31, 2019 was $16.47 per Boe compared to $15.74 per Boe in the fourth quarter of 2018. The increase on a per unit basis was primarily attributable to an increase in our depreciable asset base and assumed future development costs related to undeveloped proved reserves relative to our estimated proved reserves as a result of additions made through our horizontal drilling efforts.

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 $9.9 million, or $2.72 per Boe, for the three months ended March 31, 2019 compared to $9.6 million, or $2.53 per Boe, for the fourth quarter of 2018. The cash component of Adjusted G&A was $8.3 million, or $2.28 per Boe, for the three months ended March 31, 2019 compared to $7.7 million, or $2.03 per Boe, for the fourth quarter of 2018.

For the three months ended March 31, 2019, 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
March 31, 2019

Total G&A expense

$

11,753

   Change in the fair value of liability share-based awards (non-cash)

(1,889)

Adjusted G&A – total

9,864

   Restricted stock share-based compensation (non-cash)

(1,500)

   Corporate depreciation & amortization (non-cash)

(88)

Adjusted G&A – cash component

$

8,276

Settled share-based awards. During the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in the $3.0 million recorded on the consolidated statements of operations as settled share-based awards.

Income tax expense. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. We recorded an income tax benefit of $5.1 million for the three months ended March 31, 2019, compared to income tax expense of $5.6 million for the three months ended December 31, 2018. The change in income tax is primarily related to the change in our tax position in 2018, when the Company’s tax position transitioned from a net deferred tax asset position to a net deferred tax liability position, thereby unwinding the valuation allowance balance to $0 as of December 31, 2018.

2019 Guidance

The Company is maintaining the current full year guidance until the announced sale of non-core assets closes, which is expected to occur during the second quarter. Upon closing, the Company will update applicable guidance categories, but does not expect any changes to the operational capital guidance for the year.

First Quarter

Full Year

2019 Actual

2019 Guidance

Total production (Mboe/d)

40.3

39.5 – 41.5

% oil

79%

77% – 78%

Income statement expenses (per Boe)

LOE, including workovers

$6.63

$5.50 – $6.50

Production taxes, including ad valorem (% unhedged revenue)

7%

7%

   Adjusted G&A: cash component (a)

$2.28

$2.00 – $2.50

   Adjusted G&A: non-cash component (b)

$0.44

$0.50 – $1.00

   Cash interest expense (c)

$0.00

$0.00

Effective income tax rate

21%

22%

Capital expenditures ($MM, accrual basis)

Total operational (d)

$155

$500 – $525

Capitalized interest and G&A expenses

$31

$100 – $105

Net operated horizontal wells placed on production

11

47 – 49

(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.

Hedge Portfolio Summary

The following tables summarize our open derivative positions as of March 31, 2019 for the periods indicated:

For the Remainder

For the Full Year

Oil contracts (WTI)

of 2019

of 2020

Puts

   Total volume (Bbls)

687,500

   Weighted average price per Bbl

$

65.00

$

Put spreads

Total volume (Bbls)

687,500

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)

3,484,000

915,000

Weighted average price per Bbl

Ceiling (short call)

$

67.56

$

65.02

Floor (long put)

$

56.58

$

55.00

Floor (short put)

$

43.62

$

45.00

Collar contracts (two-way collars)

Total volume (Bbls)

732,000

Weighted average price per Bbl

Ceiling (short call)

$

$

64.63

Floor (long put)

$

$

55.00

Oil contracts (Midland basis differential)

Swap contracts

Total volume (Bbls)

5,102,000

4,576,000

Weighted average price per Bbl

$

(3.95)

$

(1.29)

Natural gas contracts (Henry Hub)

Collar contracts (two-way collars)

   Total volume (MMBtu)

2,697,500

   Weighted average price per MMBtu

      Ceiling (short call)

$

3.68

$

      Floor (long put)

$

3.09

$

Swap contracts

   Total volume (MMBtu)

1,852,000

   Weighted average price per MMBtu

$

2.88

$

Natural gas contracts (Waha basis differential)

Swap contracts

   Total volume (MMBtu)

5,961,000

4,758,000

   Weighted average price per MMBtu

$

(1.19)

$

(1.12)

Income (Loss) Available to Common Shareholders. The Company reported net loss available to common shareholders of $21.4 million for the three months ended March 31, 2019 and Adjusted Income available to common shareholders of $35.4 million, or $0.16 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 prior period quarters 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(i), a non-GAAP financial measure, (in thousands):

Three Months Ended

March 31, 2019

December 31, 2018

March 31, 2018

Income (loss) available to common stockholders

$

(21,367)

$

154,370

$

53,937

   (Gain) loss on derivatives, net of settlements

66,970

(105,512)

(3,978)

   Change in the fair value of share-based awards

1,881

(1,053)

1,012

   Settled share-based awards

3,024

Tax effect on adjustments above

(15,094)

22,379

622

Change in valuation allowance

(30,281)

(11,753)

Adjusted Income (i)

$

35,414

$

39,903

$

39,840

Adjusted Income per fully diluted common share (i)

$

0.16

$

0.17

$

0.20

Three Months Ended

March 31, 2019

December 31, 2018

March 31, 2018

Net income (loss)

$

(19,543)

$

156,194

$

55,761

   (Gain) loss on derivatives, net of settlements

66,970

(105,512)

(3,978)

   Non-cash stock-based compensation expense

3,402

770

2,143

   Settled share-based awards

3,024

   Acquisition expense

157

1,333

548

   Income tax (benefit) expense

(5,149)

5,647

495

   Interest expense

738

735

460

   Depreciation, depletion and amortization

60,672

60,301

36,066

   Accretion expense

241

248

218

Adjusted EBITDA (i)

$

110,512

$

119,716

$

91,713

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended March 31, 2019 was $110.4 million and is reconciled to operating cash flow in the following table (in thousands):

Three Months Ended

March 31, 2019

December 31, 2018

March 31, 2018

Cash flows from operating activities:

Net income (loss)

$

(19,543)

$

156,194

$

55,761

Adjustments to reconcile net income to cash provided by operating activities:

   Depreciation, depletion and amortization

60,672

60,301

36,066

   Accretion expense

241

248

218

   Amortization of non-cash debt related items

738

734

453

   Deferred income tax (benefit) expense

(5,149)

5,647

495

   (Gain) loss on derivatives, net of settlements

66,970

(105,512)

(3,978)

   (Gain) loss on sale of other property and equipment

28

(64)

   Non-cash expense related to equity share-based awards

4,545

1,823

1,131

   Change in the fair value of liability share-based awards

1,881

(1,053)

1,012

Discretionary cash flow (i)

$

110,383

$

118,318

$

91,158

   Changes in working capital

(33,864)

33,710

4,512

   Payments to settle asset retirement obligations

(664)

(389)

(366)

   Payments to settle vested liability share-based awards

(1,296)

(3,089)

Net cash provided by operating activities

$

74,559

$

151,639

$

92,215

 

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share data)

March 31, 2019

December 31, 2018

ASSETS

Unaudited

Current assets:

   Cash and cash equivalents

$

10,482

$

16,051

   Accounts receivable

137,110

131,720

   Fair value of derivatives

11,372

65,114

   Other current assets

12,034

9,740

      Total current assets

170,998

222,625

Oil and natural gas properties, full cost accounting method:

   Evaluated properties

4,760,071

4,585,020

   Less accumulated depreciation, depletion, amortization and impairment

(2,333,589)

(2,270,675)

   Evaluated oil and natural gas properties, net

2,426,482

2,314,345

   Unevaluated properties

1,432,118

1,404,513

      Total oil and natural gas properties, net

3,858,600

3,718,858

Operating lease right-of-use assets

40,977

Other property and equipment, net

22,413

21,901

Restricted investments

3,450

3,424

Deferred financing costs

5,742

6,087

Fair value of derivatives

385

Other assets, net

6,269

6,278

   Total assets

$

4,108,834

$

3,979,173

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

   Accounts payable and accrued liabilities

$

230,990

$

261,184

   Operating lease liabilities

29,134

   Accrued interest

25,920

24,665

   Cash-settleable restricted stock unit awards

1,060

1,390

   Asset retirement obligations

3,771

3,887

   Fair value of derivatives

24,550

10,480

   Other current liabilities

8,512

13,310

      Total current liabilities

323,937

314,916

Senior secured revolving credit facility

330,000

200,000

6.125% senior unsecured notes due 2024

595,971

595,788

6.375% senior unsecured notes due 2026

393,896

393,685

Operating lease liabilities

11,751

Asset retirement obligations

10,189

10,405

Cash-settleable restricted stock unit awards

2,252

2,067

Deferred tax liability

4,415

9,564

Fair value of derivatives

6,983

7,440

Other long-term liabilities

995

100

   Total liabilities

1,680,389

1,533,965

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; 227,884,091 and 227,582,575 shares outstanding, respectively

2,279

2,276

   Capital in excess of par value

2,481,879

2,477,278

   Accumulated deficit

(55,728)

(34,361)

      Total stockholders’ equity

2,428,445

2,445,208

Total liabilities and stockholders’ equity

$

4,108,834

$

3,979,173

 

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)

Three Months Ended March 31,

2019

2018

Operating revenues:

Oil sales

$

141,098

$

115,286

Natural gas sales

11,949

12,154

Total operating revenues

153,047

127,440

Operating expenses:

Lease operating expenses

24,067

13,039

Production taxes

10,813

8,463

Depreciation, depletion and amortization

59,767

35,417

General and administrative

11,753

8,769

Settled share-based awards

3,024

Accretion expense

241

218

Acquisition expense

157

548

Total operating expenses

109,822

66,454

Income from operations

43,225

60,986

Other (income) expenses:

Interest expense, net of capitalized amounts

738

460

Loss on derivative contracts

67,260

4,481

Other income

(81)

(211)

Total other (income) expense

67,917

4,730

Income (loss) before income taxes

(24,692)

56,256

Income tax (benefit) expense

(5,149)

495

Net income (loss)

(19,543)

55,761

Preferred stock dividends

(1,824)

(1,824)

Income (loss) available to common stockholders

$

(21,367)

$

53,937

Income per common share:

Basic

$

(0.09)

$

0.27

Diluted

$

(0.09)

$

0.27

Weighted average common shares outstanding:

Basic

227,784

201,921

Diluted

227,784

202,588

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)

Three Months Ended March 31,

2019

2018

Cash flows from operating activities:

Net income (loss)

$

(19,543)

$

55,761

Adjustments to reconcile net income to cash provided by operating activities:

   Depreciation, depletion and amortization

60,672

36,066

   Accretion expense

241

218

   Amortization of non-cash debt related items

738

453

   Deferred income tax (benefit) expense

(5,149)

495

   (Gain) loss on derivatives, net of settlements

66,970

(3,978)

   Loss on sale of other property and equipment

28

   Non-cash expense related to equity share-based awards

4,545

1,131

   Change in the fair value of liability share-based awards

1,881

1,012

   Payments to settle asset retirement obligations

(664)

(366)

   Payments for cash-settled restricted stock unit awards

(1,296)

(3,089)

Changes in current assets and liabilities:

   Accounts receivable

(5,390)

(8,067)

   Other current assets

(2,294)

61

   Current liabilities

(26,003)

12,938

   Other

(177)

(420)

Net cash provided by operating activities

74,559

92,215

Cash flows from investing activities:

Capital expenditures

(193,211)

(111,330)

Acquisitions

(27,947)

(38,923)

Acquisition deposit

900

Proceeds from sale of assets

13,879

Net cash used in investing activities

(207,279)

(149,353)

Cash flows from financing activities:

Borrowings on senior secured revolving credit facility

220,000

80,000

Payments on senior secured revolving credit facility

(90,000)

(30,000)

Payment of preferred stock dividends

(1,824)

(1,824)

Tax withholdings related to restricted stock units

(1,025)

(560)

Net cash provided by financing activities

127,151

47,616

Net change in cash and cash equivalents

(5,569)

(9,522)

Balance, beginning of period

16,051

27,995

Balance, end of period

10,482

18,473

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 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.

Earnings Call Information

The Company will host a conference call on Tuesday, May 7, 2019, to discuss first quarter 2019 financial and operating results.

Please join Callon Petroleum Company via the Internet for a webcast of the conference call:

Date/Time:

Tuesday, May 7, 2019, 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:

3634060

An archive of the conference call webcast will be available at www.callon.com under the “Investors” section of the website.

About Callon Petroleum Company

Callon Petroleum Company is an independent energy company focused on the acquisition and development of unconventional onshore oil and natural gas reserves 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; Callon’s 2019 production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; and the implementation of Callon’s business plans and strategy, as well as statements including the words “believe,” “expect,” “plans,” “may,” “will,” “should,” “could,” and words of similar meaning. These statements reflect Callon’s current views with respect to future events and financial performance based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. 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. Any forward-looking statement speaks only as of the date on which such statement is made and Callon undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect Callon’s future results and could cause results to differ materially from those expressed in Callon’s forward-looking statements include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, cost and availability of equipment and labor, Callon’s ability to finance Callon’s activities and other risks more fully discussed in Callon’s filings with the Securities and Exchange Commission, including Callon’s Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on Callon’s 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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See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations  

 

Cision View original content:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-first-quarter-2019-results-300844478.html

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