Callon Petroleum Company Announces Second Quarter 2015 Results and Increases Annual Production Guidance

Aug 05, 2015, 16:15 ET from Callon Petroleum Company

NATCHEZ, Miss., Aug. 5, 2015 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and six month periods ended June 30, 2015. Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located within the Investors (Events and Presentations) section of the site.

Key highlights for the second quarter of 2015 include:

  • Net daily production of 9,516 barrels of oil equivalent per day ("BOE/d"), an increase of 11% compared to the first quarter of 2015, comprised of 79% oil volume
  • Lease operating costs, including workovers, of $7.59 per barrel of oil equivalent ("BOE"), a decrease of 16% compared to the first quarter of 2015
  • Adjusted EBITDA, a non-GAAP financial measure(i), of $31.7 million, an increase of 14% compared to the first quarter of 2015
  • Adjusted income available to common shareholders, a non-GAAP financial measure(i), of $0.04 per diluted share based on total average diluted shares outstanding of 66.0 million shares
  • Increased annual production guidance midpoint by 6% to 9,600 BOE/d and established third quarter 2015 production guidance midpoint at 9,800 BOE/d

"Our results for the quarter reflected improvements across all aspects of the business," commented Fred Callon, Chairman and Chief Executive Officer. "We delivered double-digit production growth, while posting meaningful decreases in both our operating cost structure and level of capital expenditures. In addition to these important contributors to capital efficiency, the productivity of our drilling program has benefitted from ongoing completion enhancements and increasing capital allocation to the Lower Spraberry. We believe that the strength of our asset base, combined with our liquidity position and financial discipline, position us to generate continued production and reserve gains while progressing to a free cash flow neutral position in 2016."

Recent Well Performance

Callon currently has 70 gross (61.9 net) horizontal wells located in the Central and Southern Midland Basin, producing from four established zones including the Lower Spraberry, the Wolfcamp A, and the Upper and Lower Wolfcamp B. The Company's 2015 production has exceeded expectations primarily due to the extended time performance of its Lower Spraberry drilling program, and sustained improvement of Wolfcamp B wells in the Garrison Draw field.

24-Hour Peak Rate (BOE/d; Two-stream)

180-Day Cumulative Production (BOE; Two-stream)

Well

County

Completed Lateral (ft)

Production  (% oil)

Per 1,000'  Lateral Feet

Production (% oil)

Per  1,000' Lateral Feet

Lower Spraberry

Pecan Acres 22A1 4SH

Midland

4,646

1,114 (89%)

240

T.B.D.

T.B.D.

Casselman 40 4 LS

Midland

4,398

1,035 (89%)

235

84,233 (81%)

19,153

Kendra Annie 15SH

Midland

4,966

746 (88%)

150

92,332 (83%)

18,593

ST W 701LS

Midland

7,102

1,564 (86%)

220

145,507 (88%)

20,488

Neal 6522SH

Upton

6,632

788 (88%)

119

T.B.D.

T.B.D.

Garrison Draw Wolfcamp B

University 27-34 1LH

Reagan

7,482

1,131 (88%)

151

80,107 (89%)

10,707

University 27-34 2LH

Reagan

7,366

795 (82%)

108

70,604 (88%)

9,585

University 27-34 3LH

Reagan

7,602

722 (82%)

95

73,852 (87%)

9,715

Operating and Financial Results

The following table presents summary information for the periods indicated, and are followed by the Company's financial statements.

Three Months Ended

June 30, 2015

March 31, 2015

June 30, 2014

Net production:

   Oil (MBbls)

685

638

405

   Natural gas (MMcf)

1,084

801

452

   Total production (MBOE)

866

771

480

   Average daily production (BOE/d)

9,516

8,567

5,275

   % oil (BOE basis)

79%

83%

84%

Oil and natural gas revenues (in thousands):

   Oil revenue

$

36,093

$

27,909

$

37,710

   Natural gas revenue

3,149

2,482

2,792

      Total, excluding impact of cash-settled derivatives

$

39,242

$

30,391

$

40,502

   Impact of cash-settled derivatives

4,965

10,343

(1,646)

      Total, including impact of cash-settled derivatives

$

44,207

$

40,734

$

38,856

Three Months Ended

Additional per BOE data:

June 30, 2015

March 31, 2015

June 30, 2014

   Sales price, excluding impact of cash-settled derivatives

$

45.31

$

39.42

$

84.38

   Sales price, including impact of cash-settled derivatives

51.05

52.83

80.95

   Lease operating expense

$

7.59

$

9.03

$

9.09

   Production taxes

3.41

2.94

4.72

   Depletion, depreciation and amortization

20.31

23.48

24.96

   Adjusted G&A - total (a)

4.53

6.15

10.25

   Adjusted G&A - cash component (b)

3.85

5.37

8.19

(a)   

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.

(b)  

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

Total Revenue. For the quarter ended June 30, 2015, Callon reported total revenues of $39.2 million, excluding the $5.0 million impact of settled derivative contracts, comprised of oil revenues of $36.1 million and natural gas revenues of $3.1 million. Average daily production for the quarter was 9,516 BOE/d compared to average daily production of 8,567 BOE/d in the first quarter of 2015. Average realized prices, including and excluding the effects of hedging, are detailed below.

Hedging impacts. For the quarter ended June 30, 2015, Callon recognized the following hedging-related items:

In Thousands

Per Unit

Oil derivatives

Net gain on settlements

$

4,511

$

6.59

Net loss on fair value adjustments

(12,755)

   Total loss

$

(8,244)

Natural gas derivatives

Net gain on settlements

$

454

$

0.42

Net loss on fair value adjustments

(459)

   Total loss

$

(5)

Total derivatives

Net gain on settlements

$

4,965

$

5.74

Net loss on fair value adjustments

(13,214)

   Total loss on derivative contracts

$

(8,249)

Average realized prices, including and excluding the impact of cash settled derivatives during the second quarter, were as follows:

Three Months Ended

June 30, 2015

Average realized sales price:

   Oil (per Bbl) (excluding impact of cash-settled derivatives)

$

52.69

      Impact of cash-settled derivatives

6.59

   Oil (per Bbl) (including impact of cash-settled derivatives)

$

59.28

   Natural gas (perMcf) (excluding impact of cash-settled derivatives)

$

2.90

      Impact of cash-settled derivatives

0.42

   Natural gas (per Mcf) (including impact of cash-settled derivatives)

$

3.32

   Total (per BOE) (excluding impact of cash-settled derivatives)

$

45.31

      Impact of cash-settled derivatives

5.74

   Total (per BOE) (including impact of cash-settled derivatives)

$

51.05

Lease Operating Expenses, including workover expense ("LOE"). LOE for the three months ended June 30, 2015 was $7.59 per BOE, compared to LOE of $9.03 per BOE in the first quarter of 2015. Higher production volumes and lower workover expenses contributed to the 16% per BOE decrease in the second quarter.

Production Taxes, including ad valorem taxes. Production taxes were $3.41 per BOE in the second quarter of 2015, representing approximately 7.5% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended June 30, 2015 was $20.31 per BOE compared to $23.48 per BOE in the first quarter of 2015, with the decrease in per unit DD&A being attributable to increases in proved reserves relative to our depreciable asset base and reductions in assumed future development costs related to undeveloped proved reserves.

General and Administrative, net of amounts capitalized ("G&A"). G&A excluding certain non-recurring items and non-cash incentive share-based compensation valuation adjustments ("Adjusted G&A", a non-GAAP measure(i)) was $3.9 million, or $4.53 per BOE, for the current period compared to $4.7 million, or $6.15 per BOE, for the first quarter of 2015. The cash component of Adjusted G&A, which excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization, was $3.3 million, or $3.85 per BOE, compared to $4.1 million or $5.37 per BOE for the first quarter of 2015. G&A and Adjusted G&A for the second quarter of 2015 are calculated as follows:

Recurring

Non-Recurring

G&A expenses:

Cash

Non-Cash

Cash

Non-Cash

Total

   Cash G&A

$

3,332

$

$

$

$

3,332

   Restricted stock share-based compensation

479

479

   Change in the fair value of liability share-based awards

1,607

1,607

   Corporate depreciation & amortization

115

115

   Threatened proxy contest

230

230

Total G&A expense:

$

3,332

$

2,201

$

230

$

$

5,763

Adjusted G&A:

   Less: Change in the fair value of liability share-based awards

$

(1,607)

   Less: Threatened proxy contest expenses

(230)

Adjusted G&A - total

3,926

   Restricted stock share-based compensation

(479)

   Corporate depreciation & amortization

(115)

Adjusted G&A - cash component

$

3,332

Income (Loss) Available to Common Shareholders. The Company reported a net loss available to common shareholders of $6.9 million in the second quarter of 2015 and Adjusted income available to common shareholders ("Adjusted Income"), a non-GAAP measure(i), of $2.8 million, or $0.04 per diluted share.

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:

Three Months Ended

June 30, 2015

March 31, 2015

June 30, 2014

Income (loss) available to common stockholders

$

(6,940)

$

(12,171)

$

2,767

   Net loss on derivatives, net of settlements

8,590

5,144

1,975

   Rig termination fee

2,367

   Change in the fair value of share-based awards

1,045

1,676

2,982

   Early retirement expenses

3,034

   Withdrawn proxy contest expenses

150

72

85

   Gain on early redemption of debt

(2,083)

Adjusted income

$

2,844

$

122

$

5,726

Adjusted income per fully diluted common share

$

0.04

$

0.00

$

0.14

Three Months Ended

June 30, 2015

March 31, 2015

June 30, 2014

Net income (loss)

$

(4,967)

$

(10,197)

$

4,740

   Net loss on derivatives, net of settlements

13,214

7,914

3,039

   Change in the fair value of share-based awards

2,086

3,058

5,397

   Early retirement expenses

4,668

   Rig termination fee

3,641

   Gain on early redemption of debt

(3,205)

   Withdrawn proxy contest expenses

230

111

130

   Acquisition expense

3

   Income tax expense (benefit)

(2,116)

(5,077)

4,128

   Interest expense

5,106

4,858

1,825

   Depreciation, depletion and amortization

18,011

18,546

12,378

   Accretion expense

134

209

173

Adjusted EBITDA

$

31,698

$

27,734

$

28,605

Adjusted EBITDA per diluted share

$

0.48

$

0.48

$

0.69

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the second quarter of 2015 was $25.9 million or $0.39 per diluted share, and is reconciled to operating cash flow in the following table:

Three Months Ended

June 30, 2015

March 31, 2015

June 30, 2014

Cash flows from operating activities:

Net income (loss)

$

(4,967)

$

(10,197)

$

4,740

Adjustments to reconcile net income (loss) to cash provided by operating activities:

   Depreciation, depletion and amortization

18,011

18,546

12,378

   Accretion expense

134

209

173

   Amortization of non-cash debt related items

780

781

179

   Amortization of deferred credit

   Deferred income tax (benefit) expense

(2,116)

(5,077)

4,128

   Net loss on derivatives, net of settlements

13,214

7,914

3,038

   Gain on early debt extinguishment

(3,205)

   Rig termination fee

3,641

   Non-cash expense related to equity share-based awards

(754)

86

(1,032)

   Change in the fair value of liability share-based awards

1,607

3,088

4,587

Discretionary cash flow

$

25,909

$

18,991

$

24,986

Discretionary cash flow per diluted share

$

0.39

$

0.33

$

0.60

Weighted average dilutive shares outstanding

66,038

57,479

41,605

   Changes in working capital

438

(5,988)

(6,113)

   Payments to settle asset retirement obligations

(2,163)

258

(1,443)

   Payments to settle vested liability share-based awards

   related to early retirements

(3,538)

(1,417)

   Payments to settle vested liability share-based awards

(326)

(3,599)

(383)

Net cash provided by operating activities

$

23,858

$

6,124

$

15,630

Operations Update

The following table summarizes the Company's drilling activity for the three months ended June 30, 2015:

For the Three Months Ended June 30, 2015

Drilled

Completed (a)

Awaiting Completion

Gross

Net

Gross

Net

Gross

Net

Southern Midland Basin

Horizontal wells

5

5.0

5

5.0

2

2.0

   Total

5

5.0

5

5.0

2

2.0

Central Midland Basin

Vertical wells

Horizontal wells

4

2.6

3

2.0

2

1.3

   Total

4

2.6

3

2.0

2

1.3

Total vertical wells

Total horizontal wells

9

7.6

8

7.0

4

3.3

   Total

9

7.6

8

7.0

4

3.3

(a)    

  Completions include wells drilled prior to the second quarter of 2015.

For the three months ended June 30, 2015, the Company accrued $45.1 million in operational capital expenditures, including facilities, compared to $57.3 million in the first quarter of 2015. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis:

Three Months Ended June 30, 2015

Operational Capital Expenditures

Capitalized Interest

Capitalized G&A

Total Capital Expenditures

Cash basis

$

54,738

$

2,803

$

2,525

$

60,066

Timing adjustments (a)

(9,623)

(89)

(9,712)

Non-cash items

1,523

1,523

Accrual (GAAP) basis

$

45,115

$

2,714

$

4,048

$

51,877

(a)   

Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period.

Full-Year 2015 Updated Guidance:

Full-Year 2015

Previous

Updated

Total production (BOE/d)

8,800 - 9,300

9,450 - 9,750

% oil

79% - 81%

78% - 80%

% oil hedged (a)

66%

64%

Weighted average oil swap price

$69.04

$69.05

Expenses (per BOE)

LOE, including workovers

$8.50 - $9.50

$8.00 - $8.50

Production taxes, including ad valorem

$2.75 - $3.25

$2.75 - $3.25

Adjusted G&A (b)

$5.50 - $5.75

$4.75 - $5.25

   Adjusted G&A - cash component (c)

$4.00 - $4.75

$4.00 - $4.50

Third Quarter 2015 Guidance:

Second Quarter

Third Quarter

2015 Actual

2015 Guidance

Total production (BOE/d)

9,516

9,600 - 10,000

% oil

79%

76% - 80%

% oil hedged (a)

60%

76%

Weighted average oil swap price

$70.79

$67.22

Expenses (per BOE)

LOE, including workovers

$7.59

$8.00 - $8.75

Production taxes, including ad valorem

$3.41

$2.75 - $3.25

Adjusted G&A (b)

$4.53

$4.50 - $4.75

   Adjusted G&A - cash component (c)

$3.85

$3.75 - $4.00

(a)   

Based on the midpoint of guidance.

(b)   

Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within the Non-GAAP financial measures and reconciliations section of this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(c)    

Excludes stock-based compensation and corporate depreciation and amortization.

Hedge Portfolio Summary:

For the Three Months Ended

September 30,

December 31,

March 31,

June 30,

September 30,

December 31,

Oil contracts

2015

2015

2016

2016

2016

2016

Swap contracts (NYMEX):

   Total volume (MBbls)

520

442

91

91

92

92

   Weighted average price per Bbl

$

67.22

$

64.93

$

63.50

$

63.50

$

63.50

$

63.50

Swap contracts (Midland basis

Differentials):

   Volume (MBbls)

382

327

   Weighted average price per Bbl

$

(2.39)

$

(2.38)

$

$

$

$

Collar contracts combined with

short puts (three-way collar):

   Volume (MBbls)

91

91

92

92

    Weighted average price per Bbl

      Ceiling (short call)

$

$

$

70.00

$

70.00

$

70.00

$

70.00

      Floor (long put)

$

$

$

60.00

$

60.00

$

60.00

$

60.00

      Short put

$

$

$

45.00

$

45.00

$

45.00

$

45.00

For the Three Months Ended

September 30,

December 31,

March 31,

June 30,

September 30,

December 31,

Natural gas contracts

2015

2015

2016

2016

2016

2016

Collar contracts combined with

short puts (three-way collar):

   Volume (BBtu)

207

161

   Weighted average price per

   MMBtu

      Ceiling (short call)

$

4.32

$

4.32

$

$

$

$

      Floor (long put)

$

3.85

$

3.85

$

$

$

$

      Short put

$

3.25

$

3.25

$

$

$

$

Swap contracts:

   Total volume (BBtu)

219

228

   Weighted average price per

   MMBtu

$

3.98

$

3.96

$

$

$

$

Short call contracts:

   Short call volume (BBtu)

110

111

   Short call price per MMBtu

$

5.00

$

5.00

$

$

$

$

 

i.    

See "Non-GAAP Financial Measures and Reconciliations" included within this release for related disclosures and calculations

Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures as "discretionary cash flow," "Adjusted Income," "Adjusted G&A" and "Adjusted EBITDA." 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 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 and discretionary cash flow per diluted share are 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), remaining asset retirement obligations related to our divested offshore properties, 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 below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted Income and Adjusted Income per diluted share below 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 its 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.

 

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share values and share data)

June 30, 2015

December 31, 2014

ASSETS

Current assets:

Cash and cash equivalents

$

2,028

$

968

Accounts receivable

34,499

30,198

Fair value of derivatives

6,889

27,850

Other current assets

1,525

1,441

Total current assets

44,941

60,457

Oil and natural gas properties, full cost accounting method:

   Evaluated properties

2,207,999

2,077,985

   Less accumulated depreciation, depletion and amortization

(1,514,036)

(1,478,355)

   Net oil and natural gas properties

693,963

599,630

   Unevaluated properties

131,121

142,525

Total oil and natural gas properties

825,084

742,155

Other property and equipment, net

7,874

7,118

Restricted investments

3,299

3,810

Deferred tax asset

46,497

44,688

Deferred financing costs

16,639

18,200

Other assets, net

658

342

Total assets

$

944,992

$

876,770

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:

Accounts payable and accrued liabilities

$

65,792

$

76,753

Accrued interest

5,974

5,993

Cash-settled restricted stock unit awards

8,172

3,856

Asset retirement obligations

872

4,747

Deferred tax liability

830

6,214

Fair value of derivatives

1,622

1,249

Total current liabilities

83,262

98,812

Senior secured revolving credit facility

75,000

35,000

Secured second lien term loan

300,000

300,000

Asset retirement obligations

3,249

1,927

Cash-settled restricted stock unit awards

3,086

7,175

Other long-term liabilities

219

121

Total liabilities

464,816

443,035

Stockholders' equity:

Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively

16

16

Common stock, $0.01 par value, 110,000,000 shares authorized; 66,190,660 and 55,225,288 shares outstanding, respectively

662

552

Capital in excess of par value

591,604

526,162

Accumulated deficit

(112,106)

(92,995)

Total stockholders' equity

480,176

433,735

Total liabilities and stockholders' equity

$

944,992

$

876,770

 

Callon Petroleum Company

Consolidated Statements of Operations

(in thousands, except per share data)

Three Months Ended June 30,

Six Months Ended June 30,

2015

2014

2015

2014

Operating revenues:

   Oil sales

$

36,093

$

37,710

$

64,002

$

68,619

   Natural gas sales

3,149

2,792

5,631

5,168

Total operating revenues

39,242

40,502

69,633

73,787

Operating expenses:

   Lease operating expenses

6,575

4,363

13,534

8,593

   Production taxes

2,952

2,265

5,217

4,182

   Depreciation, depletion and amortization

17,587

11,982

35,691

22,520

   General and administrative

5,763

9,639

17,865

20,446

   Accretion expense

134

173

343

401

   Rig termination fee

3,641

   Gain on sale of other property and equipment

(1,080)

Total operating expenses

33,011

28,422

76,291

55,062

   Income (loss) from operations

6,231

12,080

(6,658)

18,725

Other (income) expenses:

   Interest expense

5,106

1,825

9,964

2,802

   Gain on early extinguishment of debt

(3,205)

(3,205)

   Loss on derivative contracts

8,249

4,685

5,820

7,198

   Other income

(41)

(93)

(85)

(142)

Total other expenses

13,314

3,212

15,699

6,653

   Income (loss) before income taxes

(7,083)

8,868

(22,357)

12,072

      Income tax expense (benefit)

(2,116)

4,128

(7,193)

5,469

      Net income (loss)

(4,967)

4,740

(15,164)

6,603

      Preferred stock dividends

(1,973)

(1,973)

(3,947)

(3,947)

  Income (loss) available to common stockholders

$

(6,940)

$

2,767

$

(19,111)

$

2,656

  Income (loss) per common share:

   Basic

$

(0.11)

$

0.07

$

(0.31)

$

0.07

   Diluted

$

(0.11)

$

0.07

$

(0.31)

$

0.06

   Shares used in computing income (loss) per common share:

   Basic

66,038

40,606

61,759

40,467

   Diluted

66,038

41,605

61,759

41,652

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(in thousands)

Six Months Ended June 30,

2015

2014

Cash flows from operating activities:

Net income (loss)

$

(15,164)

$

6,603

Adjustments to reconcile net income (loss) to cash provided by operating activities:

   Depreciation, depletion and amortization

36,557

22,976

   Accretion expense

343

401

   Amortization of non-cash debt related items

1,561

298

   Amortization of deferred credit

(433)

   Deferred income tax (benefit) expense

(7,193)

5,469

   Net loss on derivatives, net of settlements

21,129

4,677

   Gain on sale of other property and equipment

(1,080)

   Non-cash gain for early debt extinguishment

(3,205)

   Non-cash expense related to equity share-based awards

(668)

(36)

   Change in the fair value of liability share-based awards

4,695

8,070

   Payments to settle asset retirement obligations

(1,905)

(1,469)

   Changes in current assets and liabilities:

      Accounts receivable

(6,946)

(5,268)

      Other current assets

(85)

265

      Current liabilities

5,549

2,014

   Payments to settle vested liability share-based awards related to early retirements

(3,538)

(1,417)

   Payments to settle vested liability share-based awards

(3,925)

(2,052)

   Change in other long-term liabilities

100

   Change in other assets, net

(528)

(216)

      Net cash provided by operating activities

29,982

35,597

Cash flows from investing activities:

Capital expenditures

(130,847)

(127,219)

Proceeds from sales of mineral interests and equipment

326

2,267

     Net cash used in investing activities

(130,521)

(124,952)

Cash flows from financing activities:

Borrowings on credit facility

103,000

150,000

Payments on credit facility

(63,000)

(55,610)

Payment of deferred financing costs

(2,928)

Issuance of common stock

65,546

Payment of preferred stock dividends

(3,947)

(3,947)

      Net cash provided by financing activities

101,599

87,515

Net change in cash and cash equivalents

1,060

(1,840)

   Balance, beginning of period

968

3,012

   Balance, end of period

$

2,028

$

1,172

Earnings Call Information

The Company will host a conference call on Thursday, August 6, 2015 to discuss second quarter 2015 financial and operating results.

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

Date/Time:

Thursday, August 6, 2015, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)

Webcast:

Live webcast will be available at www.callon.com in the "Investors" section of the website.

Alternatively, you may join by telephone using the following numbers:

Toll Free:

1-888-349-0096

Canada Toll Free: 

1-855-669-9657

International:

1-412-902-0125

Request to join:

Callon Petroleum Company Earnings Call

An archive of the conference call webcast will also be available at www.callon.com in 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 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 projections and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include all statements, as well as statements including the words "believe," "expect," "plans" and words of similar meaning. These projections and 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 are 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.

For further information contact: Joe Gatto Chief Financial Officer, Senior Vice President and Treasurer 1-800-451-1294

 

SOURCE Callon Petroleum Company



RELATED LINKS

http://www.callon.com