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NATCHEZ, Miss., Nov. 4, 2015 /PRNewswire/ — Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three and nine month periods ended September 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.

Highlights for the third quarter of 2015 include:

  • Net daily production of 9,739 barrels of oil equivalent per day (“BOE/d”), an increase of 73% compared to the third quarter of 2014, comprised of 77% oil volume
  • Adjusted EBITDA, a non-GAAP financial measure(i), of $30.2 million, representing a margin of approximately 70% of Adjusted Total Revenues, a non-GAAP financial measure(i)
  • Adjusted Income available to common shareholders, a non-GAAP financial measure(i), of $0.05 per diluted share based on total average diluted shares outstanding of 66.3 million shares
  • Discretionary cash flow per share, a non-GAAP financial measure(i), of $0.38 per diluted share based on total average diluted shares outstanding of 66.3 million shares
  • Acceleration of operational plan, and related infrastructure investment, to dedicate both horizontal rigs to the Central Midland Basin, primarily targeting the Lower Spraberry shale

“We continue to focus on improving our operating cost structure and capital efficiency in the current environment,” commented Fred Callon, Chairman and Chief Executive Officer. “In order to advance our goal of funding our drilling program with internally generated cash flows by mid-2016, we made the decision in August to modify our operational plans and focus our two horizontal drilling rigs on our Central Midland acreage. We will focus on Lower Spraberry shale development through 2016, and will continue to monitor opportunities to develop the Wolfcamp A and Middle Spraberry as those zones are further delineated. Callon was able to quickly pivot in the current environment due to a property base that is entirely held by production, with no drilling commitments that would prevent us from targeting our highest return opportunities. We believe this unique flexibility will continue to benefit our operations in a volatile commodity price environment, and also create optionality to pursue acquisition and partnership opportunities that require near-term drilling to hold acreage.”

Operations Update

Callon currently has 78 gross (67.6 net) horizontal wells located in the Central and Southern Midland Basin, producing from five established zones, including a Middle Spraberry well placed on production in late October 2015. During the third quarter, the Company accelerated a planned shift in operational focus to its Central Midland Basin properties, with a particular focus on Lower Spraberry drilling. Callon dedicated its two horizontal rigs to the Carpe Diem and Casselman-Bohannon fields in early September and plans to operate both rigs on its Central Midland acreage through 2016. Based on its operational plan for this new drilling program, the Company has established a preliminary operational capital budget, including facilities, of $110 million for 2016 assuming its current well cost of $5.9 million for a 7,500′ lateral. This program currently contemplates the drilling of approximately 17.1 net horizontal wells, with 15.6 net wells targeting the Lower Spraberry. The Company anticipates announcing a formal capital budget plan approved by the Board of Directors and accompanying guidance metrics in early 2016.

The following table summarizes the Company’s drilling activity for the period indicated:

 

For the Three Months Ended September 30, 2015

Drilled

Completed (a)

Awaiting Completion

Gross

Net

Gross

Net

Gross

Net

Southern Midland Basin horizontal wells

1

1.0

2

2.0

1

1.0

Central Midland Basin horizontal wells

7

4.1

7

5.0

2

0.4

   Total Midland Basin horizontal wells

8

5.1

9

7.0

3

1.4

(a)

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

 

Operational Capital Budget and Third Quarter Summary

In order to facilitate its tactical shift to the Central Midland area, the Company recently increased its 2015 operational capital budget by approximately 10% to $180 million (on an accrual, or GAAP, basis), with the increase primarily related to the facilities and infrastructure investment required to accommodate an increased level of activity. Part of the increase was also attributable to longer completed lateral lengths, enhanced completion designs, and non-consenting partner capital, offset in part by continued achieved reductions in well costs throughout the year. A reconciliation of the revised capital budget to the original plan is provided below (in millions):

2015 Operational Capital Budget

Drilling and Completion

Facilities

Total

Original operational capital budget (a)

$

150.5

$

12.0

$

162.5

Enhanced completions/Longer laterals/Non-consents

7.5

7.5

Central Midland: Accelerated facilities investments

6.0

6.0

East Bloxom: Tank battery upgrade and repairs

4.0

4.0

   Revised operational capital budget

$

158.0

$

22.0

$

180.0

(a) 

Based on the midpoint of guidance.

 

For the three months ended September 30, 2015, the Company accrued $47.1 million in operational capital expenditures, including facilities, compared to $45.1 million in the second quarter of 2015. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):

Three Months Ended September 30, 2015

Operational Capital Expenditures

Capitalized Interest

Capitalized G&A

Total Capital Expenditures

Cash basis

$

42,831

$

2,311

$

2,559

$

47,701

Timing adjustments (a)

4,307

111

4,418

Non-cash items

506

506

   Accrual (GAAP) basis

$

47,138

$

2,422

$

3,065

$

52,625

(a) 

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

 

Fourth Quarter and Annual 2015 Guidance:

Fourth Quarter

Annual

2015

2015

Total production (BOE/d)

10,200 – 10,700

9,500 – 9,650

   % oil

76% – 78%

78% – 80%

   % oil hedged (a)

60%

   Weighted average oil swap price

$64.93

Expenses (per BOE)

LOE, including workovers

$7.75 – $8.25

$8.00 – $8.40

Production taxes, including ad valorem

$2.50 – $3.00

$2.75 – $3.25

Adjusted G&A (b)

$4.00 – $4.50

$4.75 – $5.00

   Adjusted G&A – cash component (c)

$3.50 – $3.75

$4.00 – $4.25

Operational Capital Expenditures

Accrual basis ($MM)

$30

$180

(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.

 

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

September 30, 2015

June 30, 2015

September 30, 2014

Net production:

   Oil (MBbls)

689

685

425

   Natural gas (MMcf)

1,239

1,084

565

   Total production (MBOE)

896

866

519

   Average daily production (BOE/d)

9,739

9,516

5,641

   % oil (BOE basis)

77%

79%

82%

Oil and natural gas revenues (in thousands):

   Oil revenue

$

30,582

$

36,093

$

36,346

   Natural gas revenue

3,734

3,149

3,311

      Total revenue

$

34,316

$

39,242

$

39,657

   Impact of cash-settled derivatives

9,789

4,965

(462)

      Adjusted Total Revenue (i)

$

44,105

$

44,207

$

39,195

 

Three Months Ended

September 30, 2015

June 30, 2015

September 30, 2014

Additional per BOE data:

   Sales price, excluding impact of cash-settled derivatives

$

38.30

$

45.31

$

76.41

   Sales price, including impact of cash-settled derivatives

49.22

51.05

75.52

   Lease operating expense

$

8.03

$

7.59

$

12.08

   Production taxes

2.88

3.41

4.33

   Depletion, depreciation and amortization

18.64

20.31

31.05

   Adjusted G&A – total (a)

4.63

4.53

8.98

   Adjusted G&A – cash component (b)

3.81

3.85

7.27

(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 September 30, 2015, Callon reported total revenues including cash-settled derivatives (“Adjusted Total Revenue,” a non-GAAP financial measure(i)) of $44.1 million, comprised of oil revenues of $30.6 million, natural gas revenues of $3.7 million and the $9.8 million impact of settled derivative contracts. The table above reconciles to the related GAAP measure the Company’s revenue to Adjusted Total Revenue. Average daily production for the quarter was 9,739 BOE/d compared to average daily production of 9,516 BOE/d in the second quarter of 2015. Average realized prices, including and excluding the effects of hedging, are detailed below.

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

In Thousands

Per Unit

Oil derivatives contracts

Net gain on settlements

$

9,399

$

13.64

Net gain on fair value adjustments

13,758

   Total net gain on oil derivatives contracts

$

23,157

Natural gas derivatives contracts

Net gain on settlements

$

390

$

0.32

Net loss on fair value adjustments

(264)

   Total net gain on natural gas derivatives contracts

$

126

Total derivatives contracts

Net gain on settlements

$

9,789

$

10.92

Net gain on fair value adjustments

13,494

   Total net gain on total derivatives contracts

$

23,283

 

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

Three Months Ended

September 30, 2015

Average realized sales price:

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

$

44.39

      Impact of cash-settled derivatives

13.64

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

$

58.03

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

$

3.01

      Impact of cash-settled derivatives

0.32

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

$

3.33

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

$

38.30

      Impact of cash-settled derivatives

10.92

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

$

49.22

 

Lease Operating Expenses, including workover expense (“LOE”). LOE for the three months ended September 30, 2015 was $8.03per BOE, compared to LOE of $7.59 per BOE in the second quarter of 2015.

Production Taxes, including ad valorem taxes. Production taxes were $2.88 per BOE in the third 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 September 30, 2015 was $18.64 per BOE compared to $20.31 per BOE in the second 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 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 $4.1 million, or $4.63 per BOE, for the current period compared to $3.9 million, or $4.53 per BOE, for the second quarter of 2015. G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, for the third quarter of 2015 are calculated as follows (in thousands):

Recurring

Non-Recurring

Cash

Non-Cash

Cash

Non-Cash

Total

G&A expenses:

   Cash G&A

$

3,414

$

$

$

$

3,414

   Restricted stock share-based compensation

598

598

   Change in the fair value of liability share-based awards

57

57

   Corporate depreciation & amortization

133

133

   Threatened proxy contest

100

100

Total G&A expense:

$

3,414

$

788

$

100

$

$

4,302

Adjusted G&A:

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

$

(57)

   Less: Threatened proxy contest expenses

(100)

Adjusted G&A – total

4,145

   Restricted stock share-based compensation

(598)

   Corporate depreciation & amortization

(133)

Adjusted G&A – cash component

$

3,414

 

Write-down of Oil and Natural Gas Properties. During the third quarter of 2015, the Company recognized a write-down of oil and natural gas properties of $87.3 million as a result of the ceiling test limitation and the impact of lower commodity prices. No write-down of oil and natural gas properties was recognized during the comparable prior year periods.

Income (Loss) Available to Common Shareholders. The Company reported a net loss available to common shareholders of $113.8 million in the third quarter of 2015 and adjusted income available to common shareholders (“Adjusted Income”), a non-GAAP measure(i), of $3.1 million, or $0.05 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 (in thousands):

Three Months Ended

September 30, 2015

June 30, 2015

September 30, 2014

Income (loss) available to common stockholders

$

(113,779)

$

(6,940)

$

10,227

   Valuation allowance

68,818

   Write-down of oil and natural gas properties

56,746

   Net loss (gain) on derivatives, net of settlements

(8,771)

8,589

(6,764)

   Change in the fair value of share-based awards

37

1,045

(974)

   Withdrawn proxy contest expenses

65

150

65

Adjusted Income

$

3,116

$

2,844

$

2,554

Adjusted Income per fully diluted common share

$

0.05

$

0.04

$

0.06

 

Three Months Ended

September 30, 2015

June 30, 2015

September 30, 2014

Net income (loss)

$

(111,805)

$

(4,967)

$

12,201

   Write-down of oil and natural gas properties

87,301

   Net loss (gain) on derivatives, net of settlements

(13,494)

13,214

(10,405)

   Change in the fair value of share-based awards

655

2,086

(795)

   Withdrawn proxy contest expenses

100

230

100

   Acquisition expense

(3)

   Income tax expense (benefit)

45,667

(2,116)

7,161

   Interest expense

5,603

5,106

2,205

   Depreciation, depletion and amortization

16,026

18,011

16,517

   Accretion expense

142

134

202

Adjusted EBITDA

$

30,192

$

31,698

$

27,186

Adjusted EBITDA per diluted share

$

0.46

$

0.48

$

0.61

 

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the third quarter of 2015 was $25.1 million, or $0.38 per diluted share, and is reconciled to operating cash flow in the following table (in thousands):

Three Months Ended

September 30, 2015

June 30, 2015

September 30, 2014

Cash flows from operating activities:

Net income (loss)

$

(111,805)

$

(4,967)

$

12,201

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

   Depreciation, depletion and amortization

16,026

18,011

16,517

   Write-down of oil and natural gas properties

87,301

   Accretion expense

142

134

202

   Amortization of non-cash debt related items

781

780

196

   Deferred income tax (benefit) expense

45,667

(2,116)

7,161

   Net loss (gain) on derivatives, net of settlements

(13,494)

13,214

(10,405)

   Non-cash expense related to equity share-based awards

368

(754)

468

   Change in the fair value of liability share-based awards

64

1,607

(1,499)

Discretionary cash flow

$

25,050

$

25,909

$

24,841

   Changes in working capital

1,639

438

(927)

   Payments to settle asset retirement obligations

(1,142)

(2,163)

(1,814)

   Payments to settle vested liability share-based awards

(326)

Net cash provided by operating activities

$

25,547

$

23,858

$

22,100

Weighted average dilutive shares outstanding

66,277

66,038

44,211

Discretionary cash flow per diluted share

$

0.38

$

0.39

$

0.56

 

Hedge Portfolio Summary

For the Three Months Ended

December 31,

March 31,

June 30,

September 30,

December 31,

Oil contracts

2015

2016

2016

2016

2016

Swap contracts (NYMEX):

   Total volume (MBbls)

442

182

182

184

184

   Weighted average price per Bbl

$

64.93

$

58.23

$

58.23

$

58.23

$

58.23

Swap contracts (Midland basis

differentials):

   Volume (MBbls)

327

364

364

368

368

   Weighted average price per Bbl

$

(2.38)

$

0.17

$

0.17

$

0.17

$

0.17

Collar contracts combined with

short puts (WTI, three-way collar):

   Volume (MBbls)

182

182

184

184

    Weighted average price per Bbl

      Ceiling (short call)

$

$

65.00

$

65.00

$

65.00

$

65.00

      Floor (long put)

$

$

55.00

$

55.00

$

55.00

$

55.00

      Short put

$

$

40.33

$

40.33

$

40.33

$

40.33

For the Three Months Ended

December 31,

March 31,

June 30,

September 30,

December 31,

Natural gas contracts

2015

2016

2016

2016

2016

Collar contracts combined with

short puts (three-way collar):

   Volume (BBtu)

161

   Weighted average price per

   MMBtu

      Ceiling (short call)

$

4.32

$

$

$

$

      Floor (long put)

$

3.85

$

$

$

$

      Short put

$

3.25

$

$

$

$

Swap contracts:

   Total volume (BBtu)

228

   Weighted average price per

   MMBtu

$

3.96

$

$

$

$

Short call contracts:

   Short call volume (BBtu)

111

   Short call price per MMBtu

$

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 such as “discretionary cash flow,” “Adjusted Income,” “Adjusted G&A” and “Adjusted EBITDA,” and “Adjusted Total Revenues.” 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.
  • We believe that the non-GAAP measure of Adjusted Total Revenues 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 affects in revenue. We believe Adjusted Total Revenue is also useful to investors as a measure of the actual cash inflows generated during the period.

Callon Petroleum Company

Consolidated Balance Sheets

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

September 30, 2015

December 31, 2014

ASSETS

Current assets:

Cash and cash equivalents

$

1,922

$

968

Accounts receivable

39,385

30,198

Fair value of derivatives

16,763

27,850

Other current assets

1,410

1,441

Total current assets

59,480

60,457

Oil and natural gas properties, full cost accounting method:

   Evaluated properties

2,251,993

2,077,985

   Less accumulated depreciation, depletion and amortization

(1,618,027)

(1,478,355)

   Net oil and natural gas properties

633,966

599,630

   Unevaluated properties

141,581

142,525

Total oil and natural gas properties

775,547

742,155

Other property and equipment, net

7,905

7,118

Restricted investments

3,305

3,810

Deferred tax asset

44,688

Deferred financing costs

15,858

18,200

Fair value of derivatives

2,203

Other assets, net

426

342

Total assets

$

864,724

$

876,770

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable and accrued liabilities

$

76,162

$

76,753

Accrued interest

6,066

5,993

Cash-settled restricted stock unit awards

8,025

3,856

Asset retirement obligations

827

4,747

Deferred tax liability

6,214

Fair value of derivatives

1,249

Total current liabilities

91,080

98,812

Senior secured revolving credit facility

99,000

35,000

Secured second lien term loan

300,000

300,000

Asset retirement obligations

3,856

1,927

Cash-settled restricted stock unit awards

3,487

7,175

Other long-term liabilities

220

121

Total liabilities

497,643

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; 66,279,074 and 55,225,288 shares outstanding, respectively

663

552

Capital in excess of par value

592,287

526,162

Accumulated deficit

(225,885)

(92,995)

Total stockholders’ equity

367,081

433,735

Total liabilities and stockholders’ equity

$

864,724

$

876,770

 

Callon Petroleum Company

Consolidated Statements of Operations

(in thousands, except per share data)

Three Months Ended September 30,

Nine Months Ended September 30,

2015

2014

2015

2014

Operating revenues:

   Oil sales

$

30,582

$

36,346

$

94,584

$

104,965

   Natural gas sales

3,734

3,311

9,365

8,479

Total operating revenues

34,316

39,657

103,949

113,444

Operating expenses:

   Lease operating expenses

7,194

6,270

20,728

14,863

   Production taxes

2,583

2,247

7,800

6,429

   Depreciation, depletion and amortization

16,704

16,115

52,395

38,635

   General and administrative

4,302

3,261

22,167

23,707

   Accretion expense

142

202

485

603

   Write-down of oil and natural gas properties

87,301

87,301

   Rig termination fee

3,641

   Gain on sale of other property and equipment

(1,080)

Total operating expenses

118,226

28,095

194,517

83,157

   Income (loss) from operations

(83,910)

11,562

(90,568)

30,287

Other income:

   Interest expense

5,603

2,205

15,567

5,007

   Gain on early extinguishment of debt

(3,205)

   Gain on derivative contracts

(23,283)

(9,944)

(17,463)

(2,746)

   Other income

(92)

(61)

(177)

(203)

Total other income

(17,772)

(7,800)

(2,073)

(1,147)

   Income (loss) before income taxes

(66,138)

19,362

(88,495)

31,434

      Income tax expense

45,667

7,161

38,474

12,630

      Net income (loss)

(111,805)

12,201

(126,969)

18,804

      Preferred stock dividends

(1,974)

(1,974)

(5,921)

(5,921)

  Income (loss) available to common stockholders

$

(113,779)

$

10,227

$

(132,890)

$

12,883

  Income (loss) per common share:

   Basic

$

(1.72)

$

0.24

$

(2.10)

$

0.31

   Diluted

$

(1.72)

$

0.23

$

(2.10)

$

0.30

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

   Basic

66,277

43,187

63,265

41,370

   Diluted

66,277

44,211

63,265

42,510

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(in thousands)

Nine Months Ended September 30,

2015

2014

Cash flows from operating activities:

Net income (loss)

$

(126,969)

$

18,804

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

   Depreciation, depletion and amortization

52,583

39,493

   Write-down of oil and natural gas properties

87,301

   Accretion expense

485

603

   Amortization of non-cash debt related items

2,342

494

   Amortization of deferred credit

(433)

   Deferred income tax expense

38,474

12,630

   Net loss (gain) on derivatives, net of settlements

7,635

(5,728)

   Gain on sale of other property and equipment

(1,080)

   Non-cash gain for early debt extinguishment

(3,205)

   Non-cash expense (benefit) related to equity share-based awards

(300)

432

   Change in the fair value of liability share-based awards

4,759

6,571

   Payments to settle asset retirement obligations

(3,047)

(3,283)

   Changes in current assets and liabilities:

      Accounts receivable

(7,278)

(8,016)

      Other current assets

31

802

      Current liabilities

6,455

3,449

   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

421

(367)

      Net cash provided by operating activities

55,529

57,697

Cash flows from investing activities:

Capital expenditures

(178,548)

(188,793)

Deposit on acquisition

(10,629)

Proceeds from sales of mineral interests and equipment

348

1,991

     Net cash used in investing activities

(178,200)

(197,431)

Cash flows from financing activities:

Borrowings on credit facility

130,000

200,000

Payments on credit facility

(66,000)

(169,610)

Payment of deferred financing costs

(3,068)

Issuance of common stock

65,546

122,514

Payment of preferred stock dividends

(5,921)

(5,921)

      Net cash provided by financing activities

123,625

143,915

Net change in cash and cash equivalents

954

4,181

   Balance, beginning of period

968

3,012

   Balance, end of period

$

1,922

$

7,193

 

Earnings Call Information

The Company will host a conference call on Thursday, November 5, 2015 to discuss third quarter 2015 financial and operating results.

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

Date/Time:  

Thursday, November 5, 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 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 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