Callon Petroleum Company Announces Fourth Quarter and Full-Year 2015 Results

02 Mar, 2016, 16:45 ET from Callon Petroleum Company

NATCHEZ, Miss., March 2, 2016 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and twelve month periods ended December 31, 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.

Financial and operational highlights for the fourth quarter of 2015 and other recent datapoints include:

  • Net daily production of 10,598 barrels of oil equivalent per day ("BOE/d"), an increase of 9% compared to the third quarter of 2015, comprised of 80% oil volume
  • Lease operating expense, including workovers, of $6.47 per barrel of oil equivalent ("BOE"), a decrease of 19% from the third quarter of 2015
  • Adjusted EBITDA, a non-GAAP financial measure(i), of $31.8 million, representing a margin of approximately 73% 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 73.0 million shares
  • "Drill-bit" finding and development costs(i) of $8.98 per BOE for the year ended December 31, 2015 related to a 22 million BOE ("MMBOE") increase in total proved reserves from extensions and discoveries, net of revisions
  • "All-sources" reserve replacement(i) of 711% of 2015 production volumes
  • Increased total hedging portfolio to 64% and 36% of expected 2016 oil and natural gas volumes, respectively, based on the midpoint of current estimates
  • Exchanged 719,000 common shares for 120,000 shares of Series A cumulative preferred stock with a total liquidation value of $6 million

(i)

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

 

"We continue to deliver top-line growth while also achieving meaningful reductions in both our operating cost structure and capital expenditures per well," commented Fred Callon, Chairman and Chief Executive Officer. "We have proactively modified our operational plans over the last year with the goal of living within our means to provide us a high degree of flexibility in the current commodity price environment. As a result of these operational moves, combined with strong well performance and capital efficiency, we believe we are positioned to achieve this goal in the second quarter of 2016, ahead of our previous forecasted timing."

Operations Update

At December 31, 2015, Callon had 83 gross (73 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. Our net daily production for calendar year 2015 grew approximately 70% year-over-year to 9,610 BOE/d (approximately 80% oil).

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

For the Three Months Ended December 31, 2015

Drilled

Completed (a)

Awaiting Completion

Gross

Net

Gross

Net

Gross

Net

Southern Midland Basin horizontal wells

1

1.0

Central Midland Basin horizontal wells

9

6.6

5

2.7

6

4.3

   Total Midland Basin wells

9

6.6

6

3.7

6

4.3

(a)

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

 

Capital Expenditures

For the three months ended December 31, 2015, we accrued $36.4 million in operational capital expenditures, including facilities, compared to $47.1 million in the third quarter of 2015. Approximately $2 million of the operational capital expenditures accrued in the fourth quarter of 2015 was attributed to incremental operational capital expenditures related to our working interest acquisition in November 2015. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):

Three Months Ended December 31, 2015

Operational Capital Expenditures

Capitalized Interest

Capitalized G&A

Total Capital Expenditures

Cash basis

$

42,718

$

2,456

$

3,221

$

48,395

Timing adjustments (a)

(6,328)

34

(6,294)

Non-cash items

2,027

2,027

   Accrual (GAAP) basis

$

36,390

$

2,490

$

5,248

$

44,128

(a) 

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

 

For the year ended December 31, 2015, we accrued a total of $186 million for operational capital expenditures.

In January 2016, we announced an operational capital budget for 2016 in the range of $75 to $80 million, a reduction of over 50% from the 2015 level noted above, both on an accrual basis. The current budget reflects the transition from a two-rig to a one-rig program starting in March 2016. The following table details the 2016 horizontal wells we expect to place on production, all of which are located in the Central Midland Basin and planned to be completed from two to three well pads:

Lateral

Horizontal Wells

Target Zones

Lengths

Gross

Net

Lower Spraberry

5,000' - 10,000'

20

13.9

Wolfcamp A

10,000'

1

0.2

21

14.1

 

Proved Reserves

The Company recently completed the reserve audit for the year ended December 31, 2015 with its independent reserve auditor, DeGolyer and MacNaughton. As of December 31, 2015, Callon's estimated total proved reserves were 54.3 million BOE, a 65% increase over the previous year-end. The proved reserves estimate is comprised of 80% oil and 53% proved developed volumes. Included in total proved reserve estimates are 60 (gross) horizontal proved undeveloped locations.

The following table presents the progression of our estimated net proved oil and natural gas reserves from December 31, 2014 to 2015, and in each case, prepared in accordance with the rules and regulations of the SEC.

Oil

Natural Gas

Total

Proved developed and undeveloped reserves

(MBbls)

(MMcf)

(MBOE)

As of December 31, 2014

25,733

42,548

32,824

Revisions to previous estimates

(1,632)

4,870

(820)

Extensions and discoveries

19,127

19,621

22,397

Purchases, net of sale, of reserves in place

2,909

2,810

3,377

Production

(2,789)

(4,312)

(3,508)

As of December 31, 2015

43,348

65,537

54,271

 

Callon added a total of 25 MMBOE in 2015 from drilling activity and acquisitions, replacing 711% of 2015 production as calculated by the sum of reserve extensions, discoveries, net purchases and revisions (including all price-related revisions), divided by annual production ("All-sources reserve replacement"). The Company's finding and development from extensions and discoveries ("Drill-bit F&D") costs were $8.98 per BOE calculated as cash costs incurred for exploration and development divided by the sum of extensions and discoveries, and revisions to previous estimates. See "Non-GAAP Financial Measures and Reconciliations" included within this release for related disclosures and calculations.

First Quarter and Annual 2016 Guidance

First Quarter

Annual

2016

2016

Total production (BOE/d)

11,600 - 11,800

11,500 - 12,000

   % oil

77% - 79%

77% - 79%

   % oil hedged (a)

58%

64%

Expenses (per BOE)

LOE, including workovers

$7.00 - $7.50

$6.75 - $7.25

Production taxes, including ad valorem

$2.00 - $2.25

$2.00 - $2.50

Adjusted G&A (b)

$4.35 - $4.65

$3.80 - $4.20

   Adjusted G&A - cash component (c)

$3.85 - $4.15

$3.30 - $3.70

Operational Capital Expenditures

   Accrual basis ($MM)

$75 - $80

(a) 

Based on the midpoint of guidance. Includes swaps, three-way collars and two-way collars tied to the WTI NYMEX benchmark pricing.

(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.

 

Liquidity

As of December 31, 2015, Callon had $40 million of outstanding borrowings under its credit facility.

Based on current commodity strip prices, Callon projects that its incremental borrowing requirements under the facility will be approximately $50 to $55 million for 2016, with almost all of those borrowings expected to be incurred in the first quarter of 2016, including amounts paid for the working interest acquisitions in the Cassleman-Bohannon fields completed in January 2016. This estimated borrowing amount excludes the net impact of any potential acquisitions. Following the reduction in drilling activity that recently occurred in March 2016, Callon believes it will essentially be net cash flow neutral beginning in the second quarter of 2016 based on current estimates, including commodity price levels.

Operating and Financial Results

The following table presents summary information for the periods indicated:

Three Months Ended

December 31, 2015

September 30, 2015

December 31, 2014

Net production

   Oil (MBbls)

777

689

529

   Natural gas (MMcf)

1,188

1,239

839

   Total production (MBOE)

975

896

669

   Average daily production (BOE/d)

10,598

9,739

7,272

   % oil (BOE basis)

80%

77%

79%

Oil and natural gas revenues (in thousands)

   Oil revenue

$

30,582

$

30,582

$

34,409

   Natural gas revenue

2,981

3,734

4,009

      Total revenue

$

33,563

$

34,316

$

38,418

   Impact of cash-settled derivatives

9,918

9,789

7,068

      Adjusted Total Revenue (i)

$

43,481

$

44,105

$

45,486

 

Three Months Ended

December 31, 2015

September 30, 2015

December 31, 2014

Additional per BOE data

   Sales price, excluding impact of cash-settled derivatives

$

34.42

$

38.30

$

57.43

   Sales price, including impact of cash-settled derivatives

44.60

49.22

67.99

   Lease operating expense

$

6.47

$

8.03

$

11.22

   Production taxes

2.04

2.88

3.80

   Depletion, depreciation and amortization

17.29

18.64

27.04

   Adjusted G&A - total (a)

4.45

4.63

5.88

   Adjusted G&A - cash component (b)

3.80

3.81

4.34

(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 December 31, 2015, Callon reported total revenues including cash-settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure(i)) of $43.5 million, comprised of oil revenues of $40.0 million, and natural gas revenues of $3.5 million including the $9.9 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 10,598 BOE/d compared to average daily production of 9,739 BOE/d in the third quarter of 2015. Average realized prices, including and excluding the effects of hedging, are detailed below.

Hedging impacts. For the quarter ended December 31, 2015, Callon recognized the following hedging-related items:

In Thousands

Per Unit

Oil derivatives contracts

Net gain on settlements

$

9,436

$

12.14

Net gain on fair value adjustments

1,384

   Total net gain on oil derivatives contracts

$

10,820

Natural gas derivatives contracts

Net gain on settlements

$

482

$

0.41

Net loss on fair value adjustments

(407)

   Total net gain on natural gas derivatives contracts

$

75

Total derivatives contracts

Net gain on settlements

$

9,918

$

10.17

Net gain on fair value adjustments

977

   Total net gain on total derivatives contracts

$

10,895

 

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

Three Months Ended

December 31, 2015

Average realized sales price

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

$

39.36

      Impact of cash-settled derivatives

12.14

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

$

51.50

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

$

2.51

      Impact of cash-settled derivatives

0.41

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

$

2.91

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

$

34.42

      Impact of cash-settled derivatives

10.17

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

$

44.60

 

Lease Operating Expenses, including workover expense ("LOE"). LOE for the three months ended December 31, 2015 was $6.47 per BOE, compared to LOE of $8.03 per BOE in the third quarter of 2015.

Production Taxes, including ad valorem taxes. Production taxes were $2.04 per BOE in the fourth quarter of 2015, representing approximately 5.9% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended December 31, 2015 was $17.29 per BOE compared to $18.64 per BOE in the third 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. The increase in our depreciable base was offset by a decrease related to the write-down of oil and natural gas properties in the third quarter of 2015.

General and Administrative, net of amounts capitalized ("G&A"). G&A excluding certain non-cash incentive share-based compensation valuation adjustments ("Adjusted G&A", a non-GAAP measure(i)) was $4.3 million, or $4.45 per BOE, for the current period compared to $4.1 million, or $4.63 per BOE, for the third quarter of 2015. The cash component of Adjusted G&A was $3.7 million, or $3.80 per BOE, for the current period compared to $3.4 million, or $3.81 per BOE, for the third quarter of 2015.

For the fourth 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, are calculated as follows (in thousands):

Recurring

Cash

Non-Cash

Total

G&A expenses

   Cash G&A

$

3,709

$

$

3,709

   Restricted stock share-based compensation

512

512

   Change in the fair value of liability share-based awards

1,842

1,842

   Corporate depreciation & amortization

117

117

Total G&A expense:

$

3,709

$

2,471

$

6,180

Adjusted G&A

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

$

(1,842)

Adjusted G&A – total

4,338

   Restricted stock share-based compensation

(512)

   Corporate depreciation & amortization

(117)

Adjusted G&A – cash component

$

3,709

 

Write-down of Oil and Natural Gas Properties. During the fourth quarter of 2015, the Company recognized a write-down of its oil and natural gas properties for a total of $121 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 period.

Income (Loss) Available to Common Shareholders. The Company reported a net loss available to common shareholders of $115.1 million in the fourth quarter of 2015 and adjusted income available to common shareholders ("Adjusted Income"), a non-GAAP measure(i), of $3.8 million, or $0.05 per diluted share.

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," "Adjusted EBITDA," "Adjusted Total Revenues," "Drill-bit F&D costs" and "All-sources reserve replacement." These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

  • Callon believes that the non-GAAP measure of discretionary cash flow is useful as an indicator of an oil and 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 above were computed in accordance with GAAP.
  • We calculate Adjusted Earnings before Interest, Income Taxes, Depreciation, Depletion and Amortization ("Adjusted EBITDA") as Adjusted Income plus interest expense, income tax expense (benefit) and depreciation, depletion and amortization expense. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, we believe that Adjusted EBITDA provides additional information with respect to our performance or ability to meet 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.
  • We believe "Drill-bit F&D costs" and "All-sources reserve replacement" ratios are non-GAAP metrics commonly used by Callon and other companies in our industry, as well as analysts and investors, to measure and evaluate the cost of replenishing annual production and adding proved reserves. The Company's definitions of drill-bit F&D costs and all-sources reserve replacement may differ significantly from definitions used by other companies to compute similar measures and as a result may not be comparable to similar measures provided by other companies. Consequently, we provided the detail of our calculation within the included tables.

The following tables reconcile to the related GAAP measure the Company's income (loss) available to common stockholders to Adjusted Income and the Company's net income (loss) to Adjusted EBITDA (in thousands):

Three Months Ended

December 31, 2015

September 30, 2015

December 31, 2014

Income (loss) available to common stockholders

$

(115,144)

$

(113,779)

$

16,988

   Valuation allowance

40,025

68,818

   Write-down of oil and natural gas properties

78,737

56,746

   Net gain on derivatives, net of settlements

(635)

(8,771)

(14,249)

   Rig termination fee

(368)

   Change in the fair value of share-based awards

1,197

37

(1,713)

   Early retirement expenses

   Withdrawn proxy contest expenses

65

65

   Gain on early redemption of debt

1,985

Adjusted Income

$

3,812

$

3,116

$

3,076

Adjusted Income per fully diluted common share

$

0.05

$

0.05

$

0.05

 

Three Months Ended

December 31, 2015

September 30, 2015

December 31, 2014

Net income (loss)

$

(113,170)

$

(111,805)

$

18,962

   Write-down of oil and natural gas properties

121,134

87,301

   Net gain on derivatives, net of settlements

(977)

(13,494)

(21,921)

   Change in the fair value of share-based awards

2,354

655

(1,941)

   Rig termination fee

(566)

   Gain on early redemption of debt

3,054

   Withdrawn proxy contest expenses

100

100

   Acquisition expense

27

(3)

668

   Income tax expense

45,667

10,504

   Interest expense

5,544

5,603

4,765

   Depreciation, depletion and amortization

17,308

16,026

18,521

   Accretion expense

175

142

223

Adjusted EBITDA

$

31,829

$

30,192

$

32,935

Adjusted EBITDA per diluted share

$

0.44

$

0.46

$

0.59

 

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the fourth quarter of 2015 was $27.1 million, or $0.37 per diluted share, and is reconciled to operating cash flow in the following table (in thousands):

Three Months Ended

December 31, 2015

September 30, 2015

December 31, 2014

Cash flows from operating activities:

Net income (loss)

$

(113,170)

$

(111,805)

$

18,962

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

   Depreciation, depletion and amortization

17,308

16,026

18,521

   Write-down of oil and natural gas properties

121,134

87,301

   Accretion expense

175

142

223

   Amortization of non-cash debt related items

781

781

778

   Amortization of deferred credit

(54)

   Deferred income tax expense

45,667

10,504

   Net gain on derivatives, net of settlements

(977)

(13,494)

(21,922)

   Gain on early debt extinguishment

3,054

   Rig termination fee

(566)

   Non-cash expense related to equity share-based awards

521

368

694

   Change in the fair value of liability share-based awards

1,853

64

(2,635)

Discretionary cash flow

$

27,059

$

25,050

$

28,125

Discretionary cash flow per diluted share

$

0.37

$

0.38

$

0.50

   Changes in working capital

4,475

1,639

9,090

   Payments to settle asset retirement obligations

(211)

(1,142)

(525)

Net cash provided by operating activities

$

31,323

$

25,547

$

36,690

Weighted average dilutive shares outstanding

73,036

66,277

56,257

 

Drill-bit F&D and Reserve Replacement

Calculation Parameters

2015 Metrics

Production (MBOE)

(A)

3,508

Proved reserves (MBOE)

   Revisions to previous estimates (including price-related)

(B)

(820)

   Purchases, net of sale, of reserves in place

(C)

3,377

   Extensions and discoveries

(D)

22,397

Total additions, net of sale

(E)

24,954

Capital costs incurred (in thousands)

   Property acquisition costs

$

32,246

   Exploration and development costs (a)

(F)

193,660

Total capital costs incurred

(G)

$

225,906

Drill-bit F&D per BOE

(F) / (B + D)

$

8.98

All-sources F&D per BOE

(G) / (E )

$

9.05

Organic reserve replacement ratio

(B + D) / (A)

615%

All-sources reserve replacement ratio

(E) / (A)

711%

(a) 

Includes $200 million in costs related to proved properties and $15 million related to unproved properties.

 

Callon Petroleum Company

Consolidated Balance Sheets

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

December 31, 2015

December 31, 2014

ASSETS

Current assets:

Cash and cash equivalents

$

1,224

$

968

Accounts receivable

39,624

30,198

Fair value of derivatives

19,943

27,850

Other current assets

1,461

1,441

Total current assets

62,252

60,457

Oil and natural gas properties, full cost accounting method:

   Evaluated properties

2,335,223

2,077,985

   Less accumulated depreciation, depletion and amortization

(1,756,018)

(1,478,355)

   Net oil and natural gas properties

579,205

599,630

   Unevaluated properties

132,181

142,525

Total oil and natural gas properties

711,386

742,155

Other property and equipment, net

7,700

7,118

Restricted investments

3,309

3,810

Deferred tax asset

44,688

Deferred financing costs

3,642

4,776

Other assets, net

305

342

Total assets

$

788,594

$

863,346

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:

Accounts payable and accrued liabilities

$

70,970

$

76,753

Accrued interest

5,989

5,993

Cash-settled restricted stock unit awards

10,128

3,856

Asset retirement obligations

790

4,747

Deferred tax liability

6,214

Fair value of derivatives

1,249

Total current liabilities

87,877

98,812

Senior secured revolving credit facility

40,000

35,000

Secured second lien term loan, net of unamortized deferred financing costs

288,565

286,576

Asset retirement obligations

4,317

1,927

Cash-settled restricted stock unit awards

4,877

7,175

Other long-term liabilities

200

121

Total liabilities

425,836

429,611

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, 150,000,000 and 110,000,000 shares authorized; 80,087,148 and 55,225,288 shares outstanding, respectively

801

552

Capital in excess of par value

702,970

526,162

Accumulated deficit

(341,029)

(92,995)

Total stockholders' equity

362,758

433,735

Total liabilities and stockholders' equity

$

788,594

$

863,346

 

Callon Petroleum Company

Consolidated Statements of Operations

(in thousands, except per share data)

Three Months Ended December 31,

Year Ended December 31,

2015

2014

2015

2014

Operating revenues:

   Oil sales

$

30,582

$

34,409

$

125,166

$

139,374

   Natural gas sales

2,981

4,009

12,346

12,488

Total operating revenues

33,563

38,418

137,512

151,862

Operating expenses:

   Lease operating expenses

6,308

7,509

27,036

22,372

   Production taxes

1,993

2,544

9,793

8,973

   Depreciation, depletion and amortization

16,854

18,089

69,249

56,724

   General and administrative

6,180

1,402

28,347

25,109

   Accretion expense

175

223

660

826

   Write-down of oil and natural gas properties

121,134

208,435

   Rig termination fee

(566)

3,075

   Gain on sale of other property and equipment

(1,080)

   Acquisition expense

27

668

27

668

Total operating expenses

152,105

30,435

346,622

113,592

   Income (loss) from operations

(118,542)

7,983

(209,110)

38,270

Other (income) expenses:

   Interest expense

5,544

4,765

21,111

9,772

   Gain on early extinguishment of debt

3,054

(151)

   Gain on derivative contracts

(10,895)

(28,990)

(28,358)

(31,736)

   Other income

(21)

(312)

(198)

(515)

Total other income

(5,372)

(21,483)

(7,445)

(22,630)

   Income (loss) before income taxes

(113,170)

29,466

(201,665)

60,900

      Income tax expense

10,504

38,474

23,134

      Net income (loss)

(113,170)

18,962

(240,139)

37,766

      Preferred stock dividends

(1,974)

(1,974)

(7,895)

(7,895)

  Income (loss) available to common stockholders

$

(115,144)

$

16,988

$

(248,034)

$

29,871

  Income (loss) per common share:

   Basic

$

(1.58)

$

0.31

$

(3.77)

$

0.67

   Diluted

$

(1.58)

$

0.30

$

(3.77)

$

0.65

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

   Basic

73,036

55,225

65,708

44,848

   Diluted

73,036

56,257

65,708

45,961

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(in thousands)

For the Year Ended December 31,

2015

2014

Cash flows from operating activities:

Net income (loss)

$

(240,139)

$

37,766

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

   Depreciation, depletion and amortization

69,891

58,014

   Write-down of oil and natural gas properties

208,435

   Accretion expense

660

826

   Amortization of non-cash debt related items

3,123

1,272

   Amortization of deferred credit

(487)

   Deferred income tax expense

38,474

23,134

   Net loss (gain) on derivatives, net of settlements

6,658

(27,650)

   Gain on sale of other property and equipment

(1,080)

   Non-cash gain on early debt extinguishment

(151)

   Non-cash expense related to equity share-based awards

221

1,126

   Change in the fair value of liability share-based awards

6,612

3,936

   Payments to settle asset retirement obligations

(3,258)

(3,808)

   Changes in current assets and liabilities:

      Accounts receivable

(4,761)

(7,915)

      Other current assets

(20)

622

      Current liabilities

8,001

12,805

   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

80

(106)

   Change in other assets, net

338

(448)

      Net cash provided by operating activities

86,852

94,387

Cash flows from investing activities:

Capital expenditures

(227,292)

(232,596)

Acquisitions

(32,245)

(222,883)

Proceeds from sales of mineral interest and equipment

377

2,978

     Net cash used in investing activities

(259,160)

(452,501)

Cash flows from financing activities:

Borrowings on senior secured revolving credit facility

181,000

132,500

Payments on senior secured revolving credit facility

(176,000)

(119,500)

Borrowings on term loans

382,500

Payments on term loans

(84,149)

Payment of deferred financing costs

(19,779)

Redemption of 13% senior notes

(50,057)

Issuance of common stock

175,459

122,450

Payment of preferred stock dividends

(7,895)

(7,895)

      Net cash provided by financing activities

172,564

356,070

Net change in cash and cash equivalents

256

(2,044)

   Balance, beginning of period

968

3,012

   Balance, end of period

$

1,224

$

968

 

Earnings Call Information

The Company will host a conference call on Thursday, March 3, 2016, to discuss fourth quarter 2015 financial and operating results.

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

Date/Time: 

Thursday, March 3, 2016, 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 and Results 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 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 production, the Company's 2016 guidance, capital budget amounts and expected cash flows, capital expenditure and other spending plans, ratios and other metrics, liquidity, commodity prices, reserve quantities and the present value thereof, the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "plans" and words of similar meaning. These statements reflect the Company's current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and gas prices, ability to drill and complete wells, operational, regulatory and environment risks, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K, 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