Callon Petroleum Company Announces Third Quarter 2017 Results – iCrowdNewswire
 
x

RSS Newsfeeds

See all RSS Newsfeeds

Global Regions

United States ( XML Feed )

Nov 7, 2017 6:10 AM ET

Callon Petroleum Company Announces Third Quarter 2017 Results

Disclosure NewswireTM

iCrowdNewswire - Nov 7, 2017

NATCHEZ, Miss. — Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three months ended September 30, 2017.

Presentation slides accompanying this earnings release are available on the Company’s website at www.callon.comlocated on the “Presentations” page within the Investors section of the site.

 

Financial and operational highlights for the third quarter of 2017, and other recent data points include:

  • Increased production by 36% year-over-year, with an increased percentage of oil volumes
  • Reduced lease operating expense by 9% on a sequential basis to $5.08 per BOE, contributing to a total reduction of 23% since the first quarter of 2017
  • Generated a third quarter operating margin of $32.58 per BOE
  • First operated Delaware Basin Lower Wolfcamp A well had a 24 hour peak flowing rate of 238 BOE/d per 1,000′ (82% oil)
  • Successful return to Ranger drilling program with two Lower Wolfcamp B wells outperforming previous type curves

Joe Gatto, Chief Executive Officer and President commented, “This quarter’s results speak to our team’s commitment to generating strong returns by focusing on driving down costs while extracting the best well results possible from our premier asset base. Consistent improvement in our already strong cash margins, despite production deferrals during the quarter, is evidence that we are taking the correct steps to create shareholder value. Our goal is to manage growth as a function of creating returns on our capital investment. We have been consistent in our focus on these priorities and will continue to be into 2018.” He continued, “Callon’s well results were strong across all four of our operations areas during the third quarter, including our first operated well in the Delaware Basin. Early well results in the fourth quarter have been equally strong and we are excited about our prospects for 2018.”

Operations Update

At September 30, 2017, we had 218 gross (161.2 net) horizontal wells producing from seven established flow units in the Permian Basin. Net daily production for the three months ended September 30, 2017 grew approximately 36% to 22.5 thousand barrels of oil equivalent per day (approximately 77% oil) as compared to the same period of 2016.

For the three months ended September 30, 2017, we operated four horizontal drilling rigs, drilling 13 gross (10.3 net) horizontal wells in the Spur, WildHorse, Ranger and Monarch areas. We placed a combined 11 gross (10.1 net) horizontal wells on production in the quarter in these areas.

In the Delaware Basin, we drilled and completed our first operated Lower Wolfcamp A well, the Sleeping Indian A1 #1LA well.  The well is currently outperforming the 7,500 foot type curve, with an oil cut of approximately 82%. We recently completed our second operated well, the Saratoga A1 #7LA and have placed the well on flowback. We expect to commence multi-well pad development prior to the end of this year with co-development of the Upper and Lower Wolfcamp A.

In the Midland Basin, we were active across all three focus areas: WildHorse, Ranger and Monarch. In Howard County at our WildHorse area, we placed multiple Wolfcamp A wells on production during the second half of the quarter. The wells are cleaning up and have shown similar productivity to our previous wells in the area on an early time basis. Our plans are to continue program development of multiple zones across our footprint and we also expect to test tighter Wolfcamp A spacing, at 10 wells per section, in 2018.

In Reagan County at our Ranger area, our first operated Lower Wolfcamp B wells since 2015 are outperforming the type curve by more than 20%. During the quarter, we drilled our first Wolfcamp C well in this area, which is scheduled for completion during the fourth quarter along with two additional Lower Wolfcamp B wells. We currently do not account for any Wolfcamp C locations in our delineated inventory.

At our Monarch area in Midland County, we drilled a three-well pad consisting of our longest wells to date at an average of over 21,000 feet true measured depth. The completed lateral length for these wells averaged approximately 10,600 feet and the wells are entering their fourth week of flowback.

Infrastructure investment continued to be a key focus in the third quarter. We realized an impressive reduction in lease operating expenses this quarter, and we expect this infrastructure investment to continue to improve operating margins as well as position Callon as an environmentally-responsible operator for the long term. We continued to invest in saltwater disposal wells in the Midland Basin and Delaware Basin, resulting in increased disposal capacity and reduced disposal costs.  In addition, we have begun utilizing recycled water volumes in the Midland Basin and are currently preparing infrastructure at our Spur asset to implement water recycling for our planned two rig program in 2018. Importantly, after developing a substantial base of Callon-owned infrastructure, we are now positioned to selectively monetize portions of our asset base while ensuring reliable operations. As an initial step in this initiative, we expect to complete at least $20 million of such transactions in the fourth quarter, with other identified transactions expected to close by the end of the first quarter of 2018.

 

Capital Expenditures

 

For the three months ended September 30, 2017, we incurred $112.7 million in cash operational capital expenditures (excluding other items) compared to $64.0 million in the second quarter of 2017. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):

 
  

Three Months Ended September 30, 2017

  

Operational

   

Capitalized

 

Capitalized

 

Total Capital

  

Capital

 

Other (a)

 

Interest

 

G&A

 

Expenditures

Cash basis (b)

 

$

112,667

  

$

3,767

  

$

479

  

$

4,215

  

$

121,128

 

Timing adjustments (c)

 

711

  

  

9,119

  

  

9,830

 

Non-cash items

 

  

  

  

1,133

  

1,133

 

   Accrual (GAAP) basis

 

$

113,378

  

$

3,767

  

$

9,598

  

$

5,348

  

$

132,091

 

 

  

(a)

Includes seismic, land and other items.

(b)

Cash basis is a non-GAAP measure that we believe helps users of the financial information reconcile amounts to the cash flow statement and to account for timing related operational changes such as our development pace and rig count.

(c)

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

 

Operating and Financial Results

 

The following table presents summary information for the periods indicated:

 
  

Three Months Ended

  

September 30, 2017

 

June 30, 2017

 

September 30, 2016

Net production:

      

Oil (MBbls)

 

1,591

  

1,596

  

1,153

 

Natural gas (MMcf)

 

2,900

  

2,550

  

2,244

 

Total production (MBOE)

 

2,074

  

2,021

  

1,527

 

Average daily production (BOE/d)

 

22,543

  

22,209

  

16,598

 

   % oil (BOE basis)

 

77

%

 

79

%

 

76

%

Oil and natural gas revenues (in thousands):

      

   Oil revenue

 

$

73,349

  

$

72,885

  

$

49,095

 

   Natural gas revenue

 

11,265

  

9,398

  

6,832

 

      Total revenue

 

84,614

  

82,283

  

55,927

 

   Impact of cash-settled derivatives

 

(1,214)

  

(267)

  

4,091

 

      Adjusted Total Revenue (i)

 

$

83,400

  

$

82,016

  

$

60,018

 

Average realized sales price:

      

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

 

$

46.10

  

$

45.67

  

$

42.58

 

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

 

45.24

  

45.47

  

46.27

 

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

 

$

3.88

  

$

3.69

  

$

3.04

 

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

 

3.94

  

3.70

  

2.97

 

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

 

$

40.80

  

$

40.71

  

$

36.63

 

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

 

40.21

  

40.58

  

39.30

 

Additional per BOE data:

      

   Sales price (excluding impact of cash settled derivatives)

 

$

40.80

  

$

40.71

  

$

36.63

 

      Lease operating expense (excluding gathering and treating

      

      expense)

 

5.08

  

5.56

  

6.16

 

      Gathering and treating expense

 

0.52

  

0.45

  

0.36

 

      Production taxes

 

2.62

  

2.38

  

2.28

 

   Operating margin

 

$

32.58

  

$

32.32

  

$

27.83

 
       

   Depletion, depreciation and amortization

 

$

13.75

  

$

12.97

  

$

11.33

 

   Adjusted G&A (a)

      

      Cash component (b)

 

$

2.50

  

$

2.67

  

$

2.38

 

      Non-cash component

 

0.65

  

0.53

  

0.58

 

 

  

(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, 2017, Callon reported total revenue of $84.6 million and total revenue including cash-settled derivatives (“Adjusted Total Revenue,” a non-GAAP financial measure(i)) of $83.4 million, including the impact of a $1.2 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company’s revenue. Average daily production for the quarter was 22.5 MBOE/d compared to average daily production of 22.2 MBOE/d in the second quarter of 2017. Average realized prices, including and excluding the effects of hedging, are detailed below.

Hedging impacts. For the quarter ended September 30, 2017, Callon recognized the following hedging-related items (in thousands, except per unit data):

 

 

In Thousands

 

Per Unit

Oil derivatives

   

Net loss on settlements

$

(1,373)

  

$

(0.86)

 

Net loss on fair value adjustments

(12,811)

   

   Total loss on oil derivatives

$

(14,184)

   

Natural gas derivatives

   

Net gain on settlements

$

159

  

$

0.06

 

Net loss on fair value adjustments

(137)

   

   Total gain on natural gas derivatives

$

22

   

Total oil & natural gas derivatives

   

Net loss on settlements

$

(1,214)

  

$

(0.59)

 

Net loss on fair value adjustments

(12,948)

   

   Total loss on total oil & natural gas derivatives

$

(14,162)

   

Lease Operating Expenses, including workover and gathering expense (“LOE”). LOE per BOE for the three months ended September 30, 2017 was $5.60 per BOE, compared to LOE of $6.01 per BOE in the second quarter of 2017. The decrease in this metric resulted primarily from a decrease in the number of workovers period over period.

Production Taxes, including ad valorem taxes. Production taxes were $2.62 per BOE for the three months ended September 30, 2017, representing approximately 6.4% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization (“DD&A”). DD&A for the three months ended September 30, 2017 was $13.75per BOE compared to $12.97 per BOE in the second quarter of 2017. The increase on a per unit basis was primarily attributable to greater increases in our depreciable asset base and assumed future development costs related to undeveloped proved reserves as compared to the estimated total proved reserve base.

General and Administrative (“G&A”). G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, (“Adjusted G&A”, a non-GAAP measure(i)) was $6.5 million, or $3.15 per BOE, for the three months ended September 30, 2017 compared to $6.5 million, or $3.20 per BOE, for the second quarter of 2017. The cash component of Adjusted G&A was $5.2 million, or $2.50 per BOE, for the three months ended September 30, 2017 compared to $5.4 million, or $2.67 per BOE, for the second quarter of 2017.

For the three months ended September 30, 2017, G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands):

 

 

Three Months Ended
September 30, 2017

Total G&A expense

$

7,259

 

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

(731)

 

Adjusted G&A – total

6,528

 

   Less: Restricted stock share-based compensation (non-cash)

(1,198)

 

   Less: Corporate depreciation & amortization (non-cash)

(146)

 

Adjusted G&A – cash component

$

5,184

 

Income tax expense. Callon typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. We recorded an income tax expense of $0.2 million for the three months ended September 30, 2017 which relates to deferred State of Texas gross margin tax. At September 30, 2017 we had a valuation allowance of $109.8 million. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision of $6.1 million (or $0.03 per diluted share) for the quarter as if the valuation allowance did not exist.

 

2017 Guidance Update

 
  

Fourth Quarter

  

2017 Guidance

Total production (BOE/d)

 

24,000 – 25,500

% oil

 

77 %

Income Statement Expenses (per BOE)

  

LOE, including workovers

 

$5.75 – $6.25

Gathering and treating

 

$0.55 – $0.65

Production taxes, including ad valorem (% unhedged revenue)

 

7%

   Adjusted G&A: cash component (a)

 

$2.25 – $2.50

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

 

$0.55 – $0.65

   Interest expense (c)

 

$0.00

Effective income tax rate

 

0%

Capital expenditures ($MM, accrual basis)

  

Total Operational (net of monetizations) (d)

 

$108 – $112 ($88 – $92)

Capitalized expenses (cash component)

 

$13 – $17

Net operated horizontal well completions

  

Midland Basin

 

~12

Delaware Basin

 

~1

 

  

(a)

Excludes stock-based compensation and corporate depreciation and amortization. See the Non-GAAP related disclosures referenced in the footnote (b) below.

(b)

Excludes certain non-recurring expenses and non-cash valuation adjustments. The reconciliation above provides a reconciliation of third quarter 2017 G&A expense on a GAAP basis to Adjusted G&A expense, a non-GAAP measure. The Company is unable to present a quantitative reconciliation of this forward-looking non-GAAP financial measure without unreasonable effort because of the number of estimated variables that could affect the final value. Accordingly, investors are cautioned not to place undue reliance on this information.

(c)

All interest expense anticipated to be capitalized.

(d)

Includes seismic, land and other items. Excludes capitalized expenses.

 

Hedge Portfolio Summary

 

The following tables summarize our open derivative positions for the periods indicated:

 
 

For the Remainder of

 

For the Full Year of

Oil contracts (WTI)

2017

 

2018

Swap contracts combined with short puts (enhanced swaps)

   

Total volume (MBbls)

184

  

 

Weighted average price per Bbl

   

  Swap

$

44.50

  

$

 

  Short put option

$

30.00

  

$

 

Swap contracts

   

Total volume (MBbls)

184

  

1,825

 

Weighted average price per Bbl

$

45.74

  

$

51.42

 

Deferred premium put spread option

   

Total volume (MBbls)

253

  

 

Premium per Bbl

$

2.45

  

$

 

Weighted average price per Bbl

   

  Long put option

$

50.00

  

$

 

  Short put option

$

40.00

  

$

 

Collar contracts (two-way collars)

   

Total volume (MBbls)

340

  

 

Weighted average price per Bbl

   

  Ceiling (short call)

$

58.19

  

$

 

  Floor (long put)

$

47.50

  

$

 

Call option contracts

   

Total volume (MBbls)

169

  

 

 Premium per Bbl

$

1.82

  

$

 

Weighted average price per Bbl

   

   Short call strike price (a)

$

50.00

  

$

 

     Long call strike price (a)

$

50.00

  

$

 

Collar contracts combined with short puts (three-way collars)

   

Total volume (MBbls)

  

3,468

 

Weighted average price per Bbl

   

  Ceiling (short call option)

$

  

$

60.86

 

  Floor (long put option)

$

  

$

48.95

 

  Short put option

$

  

$

39.21

 

 

  

(a)

Offsetting contracts.

 

 

For the Remainder of

 

For the Full Year of

Oil contracts (Midland basis differential)

2017

 

2018

Swap contracts

   

Volume (MBbls)

552

  

5,109

 

Weighted average price per Bbl

$

(0.52)

  

$

(0.90)

 
        

 

 

For the Remainder of

 

For the Full Year of

Natural gas contracts (Henry Hub)

2017

 

2018

Collar contracts combined with short puts (three-way collars)

   

Total volume (BBtu)

368

  

 

Weighted average price per MMBtu

   

  Ceiling (short call option)

$

3.71

  

$

 

  Floor (long put option)

$

3.00

  

$

 

  Short put option

$

2.50

  

$

 

Collar contracts (two-way collars)

   

Total volume (BBtu)

856

  

720

 

Weighted average price per MMBtu

   

  Ceiling (short call option)

$

3.77

  

$

3.84

 

  Floor (long put option)

$

3.23

  

$

3.40

 

Swap contracts

   

Total volume (BBtu)

124

  

 

Weighted average price per MMBtu

$

3.39

  

$

 

Income (Loss) Available to Common Shareholders. The Company reported net income available to common shareholders of $15.3 million for the three months ended September 30, 2017 and Adjusted Income available to common shareholders of $18.1 million, or $0.09 per diluted share. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision for the quarter as if the valuation allowance did not exist. 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, 2017

 

June 30, 2017

 

September 30, 2016

Income available to common stockholders

$

15,257

  

$

31,566

  

$

19,315

 

   Change in valuation allowance

(6,064)

  

(11,194)

  

(7,907)

 

   Net (gain) loss on derivatives, net of settlements

8,416

  

(6,995)

  

(679)

 

   Change in the fair value of share-based awards

475

  

(315)

  

2,192

 

   Settled share-based awards

  

4,128

  

 

Adjusted Income

$

18,084

  

$

17,190

  

$

12,921

 

Adjusted Income per fully diluted common share

$

0.09

  

$

0.09

  

$

0.09

 
  
 

Three Months Ended

 

September 30, 2017

 

June 30, 2017

 

September 30, 2016

Net income

$

17,081

  

$

33,390

  

$

21,139

 

   Net (gain) loss on derivatives, net of settlements

12,947

  

(10,761)

  

(1,044)

 

   Non-cash stock-based compensation expense

1,952

  

499

  

4,150

 

   Settled share-based awards

  

6,351

  

 

   Acquisition expense

205

  

2,373

  

456

 

   Income tax (benefit) expense

237

  

322

  

(62)

 

   Interest expense

444

  

589

  

831

 

   Depreciation, depletion and amortization

29,132

  

26,765

  

17,733

 

   Accretion expense

131

  

208

  

187

 

Adjusted EBITDA

$

62,129

  

$

59,736

  

$

43,390

 

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended September 30, 2017 was $61.9 million and is reconciled to operating cash flow in the following table (in thousands):

 

 

Three Months Ended

 

September 30, 2017

 

June 30, 2017

 

September 30, 2016

Cash flows from operating activities:

     

Net income

$

17,081

  

$

33,390

  

$

21,139

 

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

   Depreciation, depletion and amortization

29,132

  

26,765

  

17,733

 

   Accretion expense

131

  

208

  

187

 

   Amortization of non-cash debt related items

441

  

589

  

810

 

   Deferred income tax expense

237

  

323

  

(62)

 

   Net (gain) loss on derivatives, net of settlements

12,947

  

(10,761)

  

(1,044)

 

   Loss on sale of other property and equipment

  

62

  

 

   Non-cash expense related to equity share-based awards

1,219

  

4,865

  

608

 

   Change in the fair value of liability share-based awards

732

  

1,982

  

3,371

 

Discretionary cash flow

$

61,920

  

$

57,423

  

$

42,742

 

   Changes in working capital

$

(7,777)

  

$

(8,968)

  

$

2,927

 

   Payments to settle asset retirement obligations

(250)

  

(816)

  

(576)

 

   Payments to settle vested liability share-based awards

  

(4,511)

  

 

Net cash provided by operating activities

$

53,893

  

$

43,128

  

$

45,093

 

 

Callon Petroleum Company

Consolidated Balance Sheets

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

 
 

September 30, 2017

 

December 31, 2016

ASSETS

Unaudited

  

Current assets:

   

Cash and cash equivalents

$

61,609

  

$

652,993

 

Accounts receivable

81,973

  

69,783

 

Fair value of derivatives

3,333

  

103

 

Other current assets

2,583

  

2,247

 

Total current assets

149,498

  

725,126

 

Oil and natural gas properties, full cost accounting method:

   

Evaluated properties

3,283,985

  

2,754,353

 

Less accumulated depreciation, depletion, amortization and impairment

(2,026,809)

  

(1,947,673)

 

Net evaluated oil and natural gas properties

1,257,176

  

806,680

 

Unevaluated properties

1,173,614

  

668,721

 

Total oil and natural gas properties

2,430,790

  

1,475,401

 

Other property and equipment, net

18,626

  

14,114

 

Restricted investments

3,362

  

3,332

 

Deferred financing costs

5,209

  

3,092

 

Fair value of derivatives

1,121

  

 

Acquisition deposit

  

46,138

 

Prepaid

4,650

  

 

Other assets, net

827

  

384

 

Total assets

$

2,614,083

  

$

2,267,587

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

   

Current liabilities:

   

Accounts payable and accrued liabilities

$

147,338

  

$

95,577

 

Accrued interest

18,375

  

6,057

 

Cash-settleable restricted stock unit awards

4,158

  

8,919

 

Asset retirement obligations

1,841

  

2,729

 

Fair value of derivatives

6,380

  

18,268

 

Total current liabilities

178,092

  

131,550

 

Senior secured revolving credit facility

  

 

6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs

595,115

  

390,219

 

Asset retirement obligations

3,163

  

3,932

 

Cash-settleable restricted stock unit awards

2,626

  

8,071

 

Deferred tax liability

1,158

  

90

 

Fair value of derivatives

659

  

28

 

Other long-term liabilities

405

  

295

 

Total liabilities

781,218

  

534,185

 

Commitments and contingencies

   

Stockholders’ equity:

   

Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 1,458,948 shares outstanding

15

  

15

 

Common stock, $0.01 par value, 300,000,000 shares authorized; 201,827,995 and 201,041,320 shares outstanding, respectively

2,018

  

2,010

 

Capital in excess of par value

2,179,258

  

2,171,514

 

Accumulated deficit

(348,426)

  

(440,137)

 

Total stockholders’ equity

1,832,865

  

1,733,402

 

Total liabilities and stockholders’ equity

$

2,614,083

  

$

2,267,587

 

 

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)

 
 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

2017

 

2016

 

2017

 

2016

Operating revenues:

       

Oil sales

$

73,349

  

$

49,095

  

$

218,242

  

$

117,093

 

Natural gas sales

11,265

  

6,832

  

30,019

  

14,677

 

Total operating revenues

84,614

  

55,927

  

248,261

  

131,770

 

Operating expenses:

       

Lease operating expenses

11,624

  

9,961

  

36,708

  

24,229

 

Production taxes

5,444

  

3,478

  

16,168

  

8,153

 

Depreciation, depletion and amortization

28,525

  

17,303

  

79,172

  

49,318

 

General and administrative

7,259

  

7,891

  

18,894

  

19,755

 

Settled share-based awards

  

  

6,351

  

 

Accretion expense

131

  

187

  

523

  

762

 

Write-down of oil and natural gas properties

  

  

  

95,788

 

Acquisition expense

205

  

456

  

3,027

  

2,410

 

Total operating expenses

53,188

  

39,276

  

160,843

  

200,415

 

Income (loss) from operations

31,426

  

16,651

  

87,418

  

(68,645)

 

Other (income) expenses:

       

Interest expense, net of capitalized amounts

444

  

831

  

1,698

  

10,502

 

(Gain) loss on derivative contracts

14,162

  

(5,135)

  

(11,636)

  

11,281

 

Other income

(498)

  

(122)

  

(1,270)

  

(299)

 

Total other (income) expense

14,108

  

(4,426)

  

(11,208)

  

21,484

 

Income (loss) before income taxes

17,318

  

21,077

  

98,626

  

(90,129)

 

Income tax (benefit) expense

237

  

(62)

  

1,026

  

(62)

 

Net income (loss)

17,081

  

21,139

  

97,600

  

(90,067)

 

Preferred stock dividends

(1,824)

  

(1,824)

  

(5,471)

  

(5,471)

 

Income (loss) available to common stockholders

$

15,257

  

$

19,315

  

$

92,129

  

$

(95,538)

 

Income (loss) per common share:

       

Basic

$

0.08

  

$

0.14

  

$

0.46

  

$

(0.85)

 

Diluted

$

0.08

  

$

0.14

  

$

0.46

  

$

(0.85)

 

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

      

Basic

201,827

  

136,983

  

201,422

  

112,925

 

Diluted

202,337

  

137,483

  

201,995

  

112,925

 

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)

 
 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

2017

 

2016

 

2017

 

2016

Cash flows from operating activities:

       

Net income (loss)

$

17,081

  

$

21,139

  

$

97,600

  

$

(90,067)

 

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

Depreciation, depletion and amortization

29,132

  

17,733

  

80,829

  

50,560

 

Write-down of oil and natural gas properties

  

  

  

95,788

 

Accretion expense

131

  

187

  

523

  

762

 

Amortization of non-cash debt related items

441

  

810

  

1,695

  

2,371

 

Deferred income tax (benefit) expense

237

  

(62)

  

1,026

  

(62)

 

Net (gain) loss on derivatives, net of settlements

12,947

  

(1,044)

  

(15,608)

  

27,105

 

Loss on sale of other property and equipment

  

  

62

  

 

Non-cash expense related to equity share-based awards

1,219

  

778

  

7,014

  

1,954

 

Change in the fair value of liability share-based awards

732

  

3,371

  

2,423

  

6,045

 

Payments to settle asset retirement obligations

(250)

  

(576)

  

(1,831)

  

(895)

 

Changes in current assets and liabilities:

       

Accounts receivable

(4,338)

  

(11,608)

  

(12,148)

  

(16,444)

 

Other current assets

(38)

  

54

  

(336)

  

(251)

 

Current liabilities

1,854

  

15,702

  

7,534

  

19,815

 

Change in other long-term liabilities

1

  

  

121

  

86

 

Change in long-term prepaid

(4,650)

  

  

(4,650)

  

 

Change in other assets, net

(606)

  

(1,221)

  

(1,376)

  

(1,671)

 

Payments to settle vested liability share-based awards

  

  

(13,173)

  

(10,300)

 

Net cash provided by operating activities

53,893

  

45,263

  

149,705

  

84,796

 

Cash flows from investing activities:

       

Capital expenditures

(121,128)

  

(47,418)

  

(267,218)

  

(122,698)

 

Acquisitions

(8,015)

  

(18,033)

  

(714,504)

  

(302,057)

 

Acquisition deposit

  

(32,700)

  

46,138

  

(32,700)

 

Proceeds from sales of mineral interests and equipment

  

(708)

  

  

22,923

 

Net cash used in investing activities

(129,143)

  

(98,859)

  

(935,584)

  

(434,532)

 

Cash flows from financing activities:

       

Borrowings on senior secured revolving credit facility

  

74,000

  

  

217,000

 

Payments on senior secured revolving credit facility

  

(114,000)

  

  

(257,000)

 

Issuance of 6.125% senior unsecured notes due 2024

  

  

200,000

  

 

Premium on the issuance of 6.125% senior unsecured notes due 2024

  

  

8,250

  

 

Issuance of common stock

  

421,908

  

  

722,715

 

Payment of preferred stock dividends

(1,824)

  

(1,824)

  

(5,471)

  

(5,471)

 

Payment of deferred financing costs

(401)

  

(640)

  

(7,166)

  

(640)

 

Tax withholdings related to restricted stock units

(65)

  

(170)

  

(1,118)

  

(2,207)

 

Net cash provided by financing activities

(2,290)

  

379,274

  

194,495

  

674,397

 

Net change in cash and cash equivalents

(77,540)

  

325,678

  

(591,384)

  

324,661

 

Balance, beginning of period

139,149

  

207

  

652,993

  

1,224

 

Balance, end of period

$

61,609

  

$

325,885

  

$

61,609

  

$

325,885

 

Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures such as “Discretionary Cash Flow,” “Adjusted G&A,” “Adjusted Income,” “Adjusted EBITDA,” and “Adjusted Total Revenue.” These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

  • Callon believes that the non-GAAP measure of discretionary cash flow is useful as an indicator of an oil and natural gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The Company also has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the company may not control and may not relate to the period in which the operating activities occurred. Discretionary cash flow is calculated using net income (loss) adjusted for certain items including depreciation, depletion and amortization, the impact of financial derivatives (including the mark-to-market effects, net of cash settlements and premiums paid or received related to our financial derivatives), 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 above. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted Income and Adjusted Income per diluted share above were computed in accordance with GAAP.
  • We calculate Adjusted Earnings before Interest, Income Taxes, Depreciation, Depletion and Amortization (“Adjusted EBITDA”) as Adjusted Income plus interest expense, income tax expense (benefit) and depreciation, depletion and amortization expense. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, we believe that Adjusted EBITDA provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDA we present may not be comparable to similarly titled measures of other companies.
  • We believe that the non-GAAP measure of Adjusted Total Revenue is useful to investors because it provides readers with a revenue value more comparable to other companies who account for derivative contracts and hedges and include their effects in revenue. We believe Adjusted Total Revenue is also useful to investors as a measure of the actual cash inflows generated during the period.

Earnings Call Information

The Company will host a conference call on Tuesday, November 7, 2017, to discuss third quarter 2017 financial and operating results.

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

 

Date/Time:

Tuesday, November 7, 2017, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)

Webcast:

Select “IR Calendar” under the “Investors” section of the website: www.callon.com.

Presentation Slides:

Select “Presentations” under the “Investors” section of the website: www.callon.com.

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

 

Toll Free:

1-888-317-6003

Canada Toll Free:

1-866-284-3684

International:

1-412-317-6061

Access code:

6326656

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

About Callon Petroleum

Callon Petroleum Company is an independent energy company focused on the acquisition, development, exploration, and operation of oil and natural gas properties in the Permian Basin in West Texas.

This news release is posted on the Company’s website at www.callon.com and will be archived there for subsequent review under the “News” link on the top of the homepage.

Cautionary Statement Regarding Forward Looking Statements

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; the Company’s 2017 guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; and the implementation of the Company’s business plans and strategy, as well as statements including the words “believe,” “expect,” “plans” and words of similar meaning. These statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on our website or the SEC’s website at www.sec.gov.

For further information contact:
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
[email protected]
1-800-451-1294

 

   

i)  

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

 

SOURCE Callon Petroleum Company

Related Links

http://www.callon.com

Contact Information:

Mark Brewer
Director of Investor Relations
Callon Petroleum Company
[email protected]
1-800-451-1294

View Related News >