Callon Petroleum Company Announces Second Quarter 2016 Results

NATCHEZ, Miss., Aug. 8, 2016 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months ended June 30, 2016.

Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located on the "Presentations" page within the Investors section of the site.

Financial and operational highlights for the second quarter of 2016 and other recent data points include:

  • Net daily production of 13,451 barrels of oil equivalent per day ("BOE/d"), an increase of 8% compared to the first quarter of 2016, comprised of 77% oil volume
  • Estimated July 2016 net daily production of over 16,000 BOE/d after a prolonged period of production downtime in June 2016 caused by offsetting completions activity at the Carpe Diem field, compounded by the impact of electrical outages
  • Lease operating expense, including workovers, of $5.97 per barrel of oil equivalent ("BOE"), a decrease of 3% from the first quarter of 2016
  • GAAP loss per diluted common share of $0.61 and Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), of $0.05
  • Closed two Midland Basin transactions for a total purchase price of $362.6 million, including the establishment of a new core operating area in Howard County
  • Completed first Callon-operated Wolfcamp A well (completed lateral length of 7,363') in northern Howard County which has produced approximately 48,600 BOE (90% oil) in the first 30 days after being placed on production in early July 2016
  • Borrowing base increased 28% from $300 million to $385 million following the closing of recent transactions
  • Recently added second horizontal rig to be focused in the WildHorse area in Howard County
  • Signed purchase and sale agreement for the acquisition of an incremental 4% working interest in the Casselman and Bohannon fields (the "CaBo area")

"It was an important quarter for our organization, demonstrating our ability to manage through periods of commodity price weakness by living within our cash flow while delivering capital efficient production growth. This solid operating and financial position also allowed us to complete two acquisitions that almost doubled our surface acreage in the Midland Basin, expanding our inventory of investments that we expect will deliver solid returns on capital through all phases of commodity cycles." commented Fred Callon, Chairman and Chief Executive Officer. "With a strong balance sheet and low cost operating structure, we have returned our second horizontal rig to service in August 2016 and are planning to add a third horizontal rig in early 2017 with continued signs of rebalancing in the oil markets. A large portion of this increased drilling activity will be focused in Howard County, a rapidly emerging core area which has produced encouraging well results from three delineated zones to date, including our recent Wolfcamp A well." 

Operations Update

At June 30, 2016, Callon had 118 gross (93.0 net) horizontal wells producing from five established zones. Our net daily production for the three months ended June 30, 2016, grew approximately 41% to 13,451 BOE/d (approximately 77% oil) as compared to the same period of 2015. Sequentially, we grew production more than 8% compared to the first quarter of 2016.

For the three months ended June 30, 2016, we drilled 6 gross (3.7 net) horizontal wells, completed 5 gross (3.4 net) horizontal wells, and placed 5 gross (3.4 net) horizontal wells on production. As of June 30, 2016, we had 6 gross (4.2 net) horizontal wells awaiting completion, including 2 gross drilled, uncompleted wells recently acquired as part of our western Reagan County transaction.

Monarch

Production from the Monarch areas was adversely impacted during most of the month of June 2016 by production disruptions at our largest producing field, Carpe Diem. Several wells in the field experienced hydraulic interference from two offsetting completions being performed by other operators offsetting the eastern side of Carpe Diem. The situation was compounded by power outages caused by adverse weather conditions which hindered our efforts to de-water the wells in order to restore normalized production levels. We estimate that this unexpected downtime negatively impacted total net production volumes in the quarter by approximately 425 BOE/d.

 

For the Three Months Ended June 30, 2016

Drilled

Completed

Placed on Production

Awaiting Completion

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Monarch

6

3.7

4

2.4

5

3.4

4

3.1

 

During the second quarter, we continued our focus on development of the Lower Spraberry on our Monarch assets in Midland County. For the three months ended June 30th, we drilled 6 gross (3.7 net) wells, completed 4 gross (2.4 net) wells and placed 5 gross (3.4 net) wells on production. Since placing our first two Lower Spraberry wells on production in November 2014, we now have 28 gross wells producing from two levels of this zone across our asset base, including 25 at Monarch, with drilled lateral lengths ranging from 5,000' to 10,000'.

 

30-Day Average

24-Hour Peak IP

Peak IP

(BOE/d; Two-stream) (a)

(BOE/d; Two-stream)

24-Hour

Peak

Per 1,000'

Peak

Per 1,000'

IP

Completed

24-Hour

Production

Lateral

30-Day

Production

Lateral

Date

Well

County

 Lateral (ft)

IP

(% oil)

Feet

IP

(% oil)

Feet

06/21/2016

Pecan Acres 22A2 09SH

Midland

4,652'

729

87%

157

745

85%

160

06/21/2016

Pecan Acres 22A3 10SH

Midland

4,432'

719

87%

162

741

87%

167

06/02/2016

Casselman 8 18SH

Midland

4,675'

839

85%

180

674

84%

144

05/29/2016

Casselman 8 16SH

Midland

4,671'

867

79%

186

638

86%

137

05/25/2016

Kendra-Annie 10 21SH

Midland

8,178'

935

89%

114

697

89%

85

05/04/2016

Casselman 8 17SH

Midland

4,903'

923

83%

188

668

87%

136

04/17/2016

Kendra-Amanda 29SH

Midland

8,432'

1,242

89%

147

926

89%

110

04/01/2016

Casselman 10 09SH

Midland

4,182'

674

90%

161

562

87%

134

(a)     

24-Hour Peak IPs correspond to the rates filed with the Railroad Commission of Texas and are captured using well tests on the specified date, which may result in an understated rate as the production typically varies more widely during the early days of production. The 30-Day Average Peak IP is calculated using allocated production, and is occasionally greater than the reported 24-Hour Peak IP if the well test on that date captured a lower rate than the average for the period.

 

We continue to deliver strong, consistent well results and capital efficiency from our Monarch development program. As detailed in the table above, eight Lower Spraberry wells, all in the lower bench of the zone (or, "LLS"), achieved 24-hour peak initial production ("IP") rates during the quarter. The LLS wells averaged a 24-hour peak IP of 866 Boe/d (or 162 Boepd per 1,000') and a 30-day average peak IP of 706 Boe/d (or 134 Boepd per 1,000'). 

At our Pecan Acres field, we placed 3 gross (1.4 net) LLS wells on production. While one of the wells continues to build towards its 30-day average peak IP, the other two wells yielded an average 30-day average peak IP of 743 BOE/d (86% oil) or 164 BOE/d per 1,000' from an average drilled lateral length of approximately 5,000'. We also plan to commence completion operations on our first Wolfcamp A well in the Monarch area in August 2016 which is being developed as a stacked lateral with a LLS well. Each of the wells was drilled to a lateral length of approximately 10,000'.

We are currently completing a three-well pad with an average drilled lateral length of approximately 9,750' in our Carpe Diem field with two of the wells targeting the upper section of the Lower Spraberry ("ULS") and the third well targeting the LLS. This pad was drilled on 11 wells-per-section spacing, supported by long-term production and pressure data from our previous well density tests. In addition, we plan to drill an additional two LLS wells at Carpe Diem in the third quarter with planned drilled lateral lengths of 10,000' that were increased from a previous planned lateral length of 5,000' after a recently completed partnership agreement with an offset operator.

We continue to build upon our well density tests of the Lower Spraberry in the Monarch area which have been focused on the Carpe Diem field to date. The next step in our progression of this initiative will be a 13 wells-per-section test in the CaBo area that was spud in July 2016, with two wells landed in the LLS and the third landed in the ULS.

Callon recently signed a purchase agreement for the acquisition of an incremental 4% working interest in the CaBo area, increasing our working interest in the area to approximately 75%. The purchase price for the acquired interest is $13 million with an effective date of August 1, 2016. Completion of the acquisition is subject to customary closing conditions. 

WildHorse

 

For the Three Months Ended June 30, 2016

Drilled

Completed

Placed on Production

Awaiting Completion

Gross

Net

Gross

Net

Gross

Net

Gross

Net

WildHorse

1

1.0

 

During the second quarter, we began our first operated completion in the recently acquired WildHorse area in Howard County, Texas. The well (Silver City Unit A #1H; 100% WI) was completed in the Wolfcamp A with a lateral length of 7,363'. It is the northernmost Wolfcamp A completion to date on our operated acreage, located in our Sidewinder field in northwest Howard County. After a first oil production date on July 3, 2016, the well has produced approximately 48,600 BOE (90% oil) during the first 30 days of production.

We anticipate initiating our operated drilling program in Howard County during the fourth quarter of 2016 with a dedicated one-rig program. The rig will initially drill two-well pads in the Wolfcamp A at our Fairway acreage in central Howard County, before expanding its scope to include our broader footprint and other prospective zones in 2017, including the Lower Spraberry and Wolfcamp B. We currently expect to place our first two-well pad from this program on production in mid-December 2016. Additionally, we are preparing to further increase our drilling activity in the WildHorse area should commodity prices warrant the addition of a third rig to our operated drilling program.

Ranger

 

30-Day Average

24-Hour Peak IP

Peak IP

(BOE/d; Two-stream)

(BOE/d; Two-stream)

Peak

Per 1,000'

Peak

Per 1,000'

Completed

24-Hour

Production

Lateral

30-Day

Production

Lateral

Well

County

 Lateral (ft)

IP

(% oil)

Feet

IP

(% oil)

Feet

Turner AR Unit B 08HK

Reagan

7,518'

1,716

86%

228

1,279

86%

170

Turner AR Unit C 13HK

Reagan

7,430'

1,758

86%

237

1,253

86%

169

 

The two wells listed in the table above were completed using a new generation completion design employed by the previous operator of our newly acquired Lonesome Draw field, which included shorter stage lengths and higher proppant volumes. We will continue to evaluate the longer-term performance of wells completed with this enhanced design, but early indications include 30-day average peak IPs trending approximately 50% higher versus older generation completions we used in the Ranger area. We plan to incorporate these enhanced completion techniques in two upcoming completions of drilled, uncompleted wells acquired at Lonesome Draw. These wells will be targeting the Wolfcamp A and Upper Wolfcamp B zones and are planned to commence completion operations in August 2016.

Capital expenditures

For the three months ended June 30, 2016, we accrued $21.3 million in operational capital expenditures, including facilities expenditures of $4.0 million, compared to $35.0 million in the first quarter of 2016. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):

 

Three Months Ended June 30, 2016

Operational Capital
Expenditures

Capitalized Interest

Capitalized G&A

Total Capital
Expenditures

Cash basis (a)

$

17,965

$

3,687

$

2,853

$

24,505

Timing adjustments (b)

3,309

(150)

3,159

Non-cash items

1,854

1,854

   Accrual (GAAP) basis

$

21,274

$

3,537

$

4,707

$

29,518

(a)     

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.

(b)    

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

June 30, 2016

March 31, 2016

June 30, 2015

Net production:

   Oil (MBbls)

948

892

685

   Natural gas (MMcf)

1,658

1,443

1,084

   Total production (MBOE)

1,224

1,132

866

   Average daily production (BOE/d)

13,451

12,440

9,516

   % oil (BOE basis)

77%

79%

79%

Oil and natural gas revenues (in thousands):

   Oil revenue

$

40,555

$

27,443

$

36,093

   Natural gas revenue

4,590

3,255

3,149

      Total revenue

$

45,145

$

30,698

$

39,242

   Impact of cash-settled derivatives

4,017

7,716

4,965

      Adjusted Total Revenue (i)

$

49,162

$

38,414

$

44,207

 

Total Revenue. For the quarter ended June 30, 2016, Callon reported total revenues of $45.2 million and total revenues including cash-settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure(i)) of $49.2 million, including the $4.0 million impact of settled derivative contracts. The table above reconciles to the related GAAP measure of the Company's revenue to Adjusted Total Revenue. Average daily production for the quarter was 13,451 BOE/d compared to average daily production of 12,440 BOE/d in the first quarter of 2016. Average realized prices, including and excluding the effects of hedging, are detailed below.

Hedging impacts. For the quarter ended June 30, 2016, Callon recognized the following hedging-related items:

 

In Thousands

Per Unit

Oil derivatives contracts

Net gain on settlements

$

3,707

$

3.91

Net loss on fair value adjustments

(18,466)

   Total net loss on oil derivatives contracts

$

(14,759)

Natural gas derivatives contracts

Net gain on settlements

$

310

$

0.19

Net gain on fair value adjustments

(1,035)

   Total net gain on natural gas derivatives contracts

$

(725)

Total derivatives contracts

Net gain on settlements

$

4,017

$

3.29

Net loss on fair value adjustments

(19,501)

   Total net loss on total derivatives contracts

$

(15,484)

 

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

 

Three Months Ended

June 30, 2016

Average realized sales price

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

$

42.78

      Impact of cash-settled derivatives

3.91

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

$

46.69

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

$

2.77

      Impact of cash-settled derivatives

0.19

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

$

2.96

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

$

36.88

      Impact of cash-settled derivatives

3.29

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

$

40.17

 

Three Months Ended

June 30, 2016

March 31, 2016

June 30, 2015

Additional per BOE data:

   Sales price, excluding impact of cash-settled derivatives

$

36.88

$

27.12

$

45.31

   Sales price, including impact of cash-settled derivatives

40.17

33.93

51.05

   Lease operating expense

$

5.97

$

6.15

$

7.59

   Production taxes

2.01

1.96

3.41

   Depletion, depreciation and amortization

13.31

13.89

20.31

   G&A

5.15

4.91

6.65

   Adjusted G&A - total (a)

3.55

4.10

4.53

   Adjusted G&A - cash component (b)

2.92

3.55

3.85

(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.

 

Lease Operating Expenses, including workover expense ("LOE"). LOE per BOE for the three months ended June 30, 2016 was $5.97 per BOE, compared to LOE of $6.15 per BOE in the first quarter of 2016.

Production Taxes, including ad valorem taxes. Production taxes were $2.01 per BOE in the second quarter of 2016, representing approximately 5.4% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended June 30, 2016 was $13.31 per BOE compared to $13.89 per BOE in the first quarter of 2016, 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 decrease in our depreciable base was primarily related to the write-down of oil and natural gas properties during 2015 and the first half of 2016.

General and Administrative ("G&A"). G&A for the second quarter of 2015 was $6.3 million, or $5.15 per BOE, compared to $5.6 million, or $4.91 per BOE, for the first quarter of 2016. 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 $3.55 per BOE, for the second quarter of 2016 compared to $4.6 million, or $4.10 per BOE, for the first quarter of 2016. The cash component of Adjusted G&A was $3.6 million, or $2.92 per BOE, for the second quarter of 2016 compared to $4.0 million, or $3.55 per BOE, for the first quarter of 2016.

For the second quarter of 2016, 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):

 

Cash

Non-Cash

Total

G&A expenses

   Cash G&A

$

3,578

$

$

3,578

   Restricted stock share-based compensation

655

655

   Change in the fair value of liability share-based awards

1,954

1,954

   Corporate depreciation & amortization

115

115

Total G&A expense:

$

3,578

$

2,724

$

6,302

Adjusted G&A (i)

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

$

(1,954)

Adjusted G&A – total

4,348

   Restricted stock share-based compensation

(655)

   Corporate depreciation & amortization

(115)

Adjusted G&A – cash component

$

3,578

 

Write-down of Oil and Natural Gas Properties. As a result of the ceiling test limitation, the Company recognized a write-down of oil and natural gas properties of $61.0 million in the second quarter of 2016.

Income (Loss) Available to Common Shareholders. The Company reported a net loss available to common shareholders of $71.9 million in the second quarter of 2016 and Adjusted Income available to common shareholders of $6.1 million, or $0.05 per diluted share.

Capital Budget Update

Following the closing of its recent Midland Basin acquisitions, the Company has completed a review of its operational plans for the balance of 2016. Callon recently returned a second horizontal rig to service after being idled in the first quarter of 2016. The rig will initially be focused on program development of the Wolfcamp A zone in the WildHorse area after drilling two 10,000' lateral wells targeting the LLS at the Carpe Diem field. In addition, the Company has budgeted for investments in facilities, seismic and land to support the longer-term development plans in each of our focus areas, including the potential addition of a third horizontal rig during the first half of 2017.

A breakdown of the Company's anticipated 2016 operational plan and associated expenditures is presented below:

 

Estimated

1st Half 2016

2nd Half 2016

Total

Operational activity (gross / net)

   Drill wells

11 / 8.0

15 / 10.2

26 / 18.2

   Completed wells

14 / 10.5

15 / 10.3

29 / 20.8

   Wells placed on production

13 / 9.5

13 / 8.9

26 / 18.4

Capital expenditures (in millions, accrual basis)

   Drilling and completion

$

46.2

$

58.4

$

104.6

   Facilities

9.2

16.2

25.4

      Operational capital expenditures

55.4

74.6

130.0

   Seismic

0.8

2.5

3.3

   Land and other

6.7

6.7

      Total capital expenditures (excl. capitalized expenses)

$

56.2

$

83.8

$

140.0

 

2016 Guidance Update

 

Third Quarter

Updated Full Year

Full Year (a)

2016 Guidance

2016 Guidance

Guidance Change

Total production (BOE/d)

16,000 - 17,000

14,500 - 15,500

500

   % oil

75% - 77%

76% - 80%

(1%)

   % oil hedged (b)

49%

48%

   Average swap/long-put price (b)

$48.84

$50.04

Expenses (per BOE)

   LOE, including workovers

$5.75 - $6.25

$5.75 - $6.25

$(1.00)

   Production taxes, including ad valorem (% unhedged revenue)

7%

7%

   Adjusted G&A (c)

$3.25 - $3.75

$3.25 - $3.75

$(0.05)

   Adjusted G&A - cash component (d)

$2.50 - $3.00

$2.35 - $2.85

$(0.55)

Total capital expenditures

   Accrual basis ($MM)

$34 - $38

$140

$40

(a)     

Based on the midpoint of guidance.

(b)    

Volumes presented in the Updated Full Year 2016 Guidance column include volumes hedged and the average swap/long put price for the remainder of the year only.

(c)     

Excludes certain non-recurring expenses and non-cash valuation adjustments. The reconciliation above provides a reconciliation of second quarter 2016 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.

(d)    

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

 

Hedge Portfolio Summary

The following table summarizes our open derivative positions as of August 8, 2016:

 

For the Remainder of

For the Full Year of

Oil contracts

2016

2017

Swap contracts (WTI)

   Total volume (MBbls)

460

   Weighted average price per Bbl

$

58.10

$

Swap contracts combined with short puts (WTI, enhanced swaps)

   Total volume (MBbls)

730

   Weighted average price per Bbl

      Swap

$

$

44.50

      Short put option

$

$

30.00

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

   Volume (MBbls)

276

   Weighted average price per Bbl

      Ceiling (short call option)

$

63.33

$

      Floor (long put option)

$

53.33

$

      Short put option

$

38.77

$

Collar contracts (WTI, two-way collars)

   Total volume (MBbls)

368

438

   Weighted average price per Bbl

      Ceiling (short call)

$

46.50

$

59.05

      Floor (long put)

$

37.50

$

47.50

Call option contracts (short position)

   Total volume (MBbls)

670

   Weighted average price per Bbl

      Call strike price

$

$

50.00

Swap contracts (Midland basis differentials)

   Volume (MBbls)

736

   Weighted average price per Bbl

$

0.17

$

Natural gas contracts

Swap contracts (Henry Hub)

   Total volume (BBtu)

1,104

   Weighted average price per MMBtu

$

2.52

$

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

   Total volume (BBtu)

1,460

   Weighted average price per MMBtu

      Ceiling (short call option)

$

$

3.71

      Floor (long put option)

$

$

3.00

      Short put option

$

$

2.50

 

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

 

Three Months Ended

June 30, 2016

March 31, 2016

June 30, 2015

Loss available to common stockholders

$

(71,920)

$

(42,933)

$

(6,940)

   Valuation allowance

24,409

14,288

   Write-down of oil and natural gas properties

39,658

22,604

   Net loss (gain) on derivatives, net of settlements

12,676

5,621

8,590

   Change in the fair value of share-based awards

1,277

461

1,045

   Withdrawn proxy contest expenses

2

144

150

Adjusted Income

$

6,102

$

185

$

2,845

Adjusted Income per fully diluted common share

$

0.05

$

0.00

$

0.04

 

Three Months Ended

June 30, 2016

March 31, 2016

June 30, 2015

Net loss

$

(70,097)

$

(41,109)

$

(4,967)

   Write-down of oil and natural gas properties

61,012

34,776

   Net loss (gain) on derivatives, net of settlements

19,501

8,648

13,214

   Change in the fair value of share-based awards

2,628

1,225

2,086

   Withdrawn proxy contest expenses

3

221

230

   Acquisition expense

1,906

48

   Income tax benefit

(2,116)

   Interest expense

4,180

5,491

5,106

   Depreciation, depletion and amortization

16,698

16,129

18,011

   Accretion expense

395

180

134

Adjusted EBITDA

$

36,226

$

25,609

$

31,698

 

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the second quarter of 2016 was $29.0 million and is reconciled to operating cash flow in the following table (in thousands):

 

Three Months Ended

June 30, 2016

March 31, 2016

June 30, 2015

Cash flows from operating activities:

Net loss

$

(70,097)

$

(41,109)

$

(4,967)

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

   Depreciation, depletion and amortization

16,698

16,129

18,011

   Write-down of oil and natural gas properties

61,012

34,776

   Accretion expense

395

180

134

   Amortization of non-cash debt related items

780

781

780

   Deferred income tax (benefit) expense

(2,116)

   Net loss (gain) on derivatives, net of settlements

19,501

8,648

13,214

   Non-cash expense related to equity share-based awards

(1,253)

392

(754)

   Change in the fair value of liability share-based awards

1,965

709

1,607

Discretionary cash flow

$

29,001

$

20,506

$

25,909

   Changes in working capital

(6,974)

5,582

438

   Payments to settle asset retirement obligations

(158)

(161)

(2,163)

   Payments to settle vested liability share-based awards

(493)

(9,807)

(326)

Net cash provided by operating activities

$

21,376

$

16,120

$

23,858

 

Callon Petroleum Company

Consolidated Balance Sheets

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

June 30, 2016

December 31, 2015

ASSETS

Unaudited

Current assets:

Cash and cash equivalents

$

207

$

1,224

Accounts receivable

44,460

39,624

Fair value of derivatives

5,537

19,943

Other current assets

1,766

1,461

Total current assets

51,970

62,252

Oil and natural gas properties, full cost accounting method:

   Evaluated properties

2,530,978

2,335,223

   Less accumulated depreciation, depletion, amortization and impairment

(1,883,806)

(1,756,018)

   Net oil and natural gas properties

647,172

579,205

   Unevaluated properties

379,605

132,181

Total oil and natural gas properties

1,026,777

711,386

Other property and equipment, net

9,971

7,700

Restricted investments

3,323

3,309

Deferred financing costs

3,076

3,642

Fair value of derivatives

60

Other assets, net

413

305

Total assets

$

1,095,590

$

788,594

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:

Accounts payable and accrued liabilities

$

71,960

$

70,970

Accrued interest

6,258

5,989

Cash-settleable restricted stock unit awards

5,168

10,128

Asset retirement obligations

3,933

790

Fair value of derivatives

7,491

Total current liabilities

94,810

87,877

Senior secured revolving credit facility

40,000

40,000

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

289,559

288,565

Asset retirement obligations

2,164

4,317

Cash-settleable restricted stock unit awards

4,141

4,877

Fair value of derivatives

6,313

Other long-term liabilities

286

200

Total liabilities

437,273

425,836

Stockholders' equity:

Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 and 1,578,948 shares outstanding, respectively

15

16

Common stock, $0.01 par value, 300,000,000 and 150,000,000 shares authorized, respectively; 131,090,644 and 80,087,148 shares outstanding, respectively

1,311

801

Capital in excess of par value

1,112,873

702,970

Accumulated deficit

(455,882)

(341,029)

Total stockholders' equity

658,317

362,758

Total liabilities and stockholders' equity

$

1,095,590

$

788,594

 

 

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)

Three Months Ended June 30,

Six Months Ended June 30,

2016

2015

2016

2015

Operating revenues:

   Oil sales

$

40,555

$

36,093

$

67,998

$

64,002

   Natural gas sales

4,590

3,149

7,845

5,631

Total operating revenues

45,145

39,242

75,843

69,633

Operating expenses:

   Lease operating expenses

7,311

6,575

14,268

13,534

   Production taxes

2,455

2,952

4,675

5,217

   Depreciation, depletion and amortization

16,293

17,587

32,015

35,691

   General and administrative

6,302

5,763

11,864

17,865

   Accretion expense

395

134

575

343

   Write-down of oil and natural gas properties

61,012

95,788

   Rig termination fee

3,641

   Acquisition expense

1,906

1,954

Total operating expenses

95,674

33,011

161,139

76,291

   Income (loss) from operations

(50,529)

6,231

(85,296)

(6,658)

Other (income) expense:

   Interest expense, net of capitalized amounts

4,180

5,106

9,671

9,964

   Loss on derivative contracts

15,484

8,249

16,416

5,820

   Other income, net

(96)

(41)

(177)

(85)

Total other expense

19,568

13,314

25,910

15,699

   Loss before income taxes

(70,097)

(7,083)

(111,206)

(22,357)

      Income tax benefit

(2,116)

(7,193)

      Net loss

(70,097)

(4,967)

(111,206)

(15,164)

      Preferred stock dividends

(1,823)

(1,973)

(3,647)

(3,947)

  Loss available to common stockholders

$

(71,920)

$

(6,940)

$

(114,853)

$

(19,111)

  Loss per common share:

   Basic

$

(0.61)

$

(0.11)

$

(1.14)

$

(0.31)

   Diluted

$

(0.61)

$

(0.11)

$

(1.14)

$

(0.31)

   Shares used in computing loss per common share:

   Basic

118,209

66,038

100,895

61,759

   Diluted

118,209

66,038

100,895

61,759

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)

Three Months Ended June 30,

Six Months Ended June 30,

2016

2015

2016

2015

Cash flows from operating activities:

Net loss

$

(70,097)

$

(4,967)

$

(111,206)

$

(15,164)

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

   Depreciation, depletion and amortization

16,698

18,011

32,827

36,557

   Write-down of oil and natural gas properties

61,012

95,788

   Accretion expense

395

134

575

343

   Amortization of non-cash debt related items

780

780

1,561

1,561

   Deferred income tax benefit

(2,116)

(7,193)

   Net loss on derivatives, net of settlements

19,501

13,214

28,149

21,129

   Non-cash expense related to equity share-based awards

(1,253)

(754)

(861)

(668)

   Change in the fair value of liability share-based awards

1,965

1,607

2,674

4,695

   Payments to settle asset retirement obligations

(158)

(2,163)

(319)

(1,905)

   Changes in operating assets and liabilities:

      Accounts receivable

(10,777)

(4,821)

(4,836)

(6,946)

      Other current assets

(885)

(536)

(305)

(85)

      Current liabilities

4,830

5,904

4,113

5,549

      Change in other long-term liabilities

75

100

86

100

      Change in other assets, net

(217)

(209)

(450)

(528)

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

   retirements

(3,538)

   Payments to settle vested liability share-based awards

(493)

(326)

(10,300)

(3,925)

      Net cash provided by operating activities

21,376

23,858

37,496

29,982

Cash flows from investing activities:

Capital expenditures

(24,505)

(60,067)

(75,280)

(129,050)

Acquisitions

(273,841)

(284,024)

(1,797)

Proceeds from sales of mineral interests and equipment

23,631

54

23,631

326

     Net cash used in investing activities

(274,715)

(60,013)

(335,673)

(130,521)

Cash flows from financing activities:

Borrowings on senior secured revolving credit facility

98,000

43,000

143,000

103,000

Payments on senior secured revolving credit facility

(58,000)

(5,000)

(143,000)

(63,000)

Payment of deferred financing costs

12

Issuance of common stock, net

205,858

300,807

65,546

Payment of preferred stock dividends

(1,823)

(1,973)

(3,647)

(3,947)

      Net cash provided by financing activities

244,035

36,039

297,160

101,599

Net change in cash and cash equivalents

(9,304)

(116)

(1,017)

1,060

   Balance, beginning of period

9,511

2,144

1,224

968

   Balance, end of period

$

207

$

2,028

$

207

$

2,028

 

Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures such as "discretionary cash flow," "Adjusted Income (Loss)," "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 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 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, August 9, 2016, to discuss second quarter 2016 financial and operating results.

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

Date/Time:            Tuesday, August 9, 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 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 the consummation of the pending transactions, wells anticipated to be drilled and placed on production, future levels of drilling activity and associated production, the Company's 2016 guidance, capital budget amounts and expected cash flows, 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. Without limiting the foregoing, forward-looking statements contained in this news release specifically include the expectation of total reserve potential and EUR. 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 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

 

__________________________

i.

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

 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-second-quarter-2016-results-300310672.html

SOURCE Callon Petroleum Company