Exhibit 99.1



Callon Petroleum Company Announces Fourth Quarter 2016 Results



Natchez, MS (February 27, 2017) - Callon Petroleum Company (NYSE: CPE) (Callon or the Company) today reported results of operations for the three months and full-year ended December 31, 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 full-year and fourth quarter 2016,  and other recent data points include:



·

Full-year 2016 production of 15.2 MBOE/d  (77% oil), an increase of 59% over 2015 volumes

·

Fourth quarter 2016 production of 18.4 MBOE/d (76% oil), a sequential quarterly increase of 11%

·

Year-end proved reserves of 91.6 MMBOE (78% oil), a yearly increase of 69%

·

Organic reserve replacement(i)  of  311% of 2016 production at a Drill-Bit finding and development cost concept(i) of $8.77 per BOE on a two-stream basis

·

GAAP loss per diluted common share of $0.02 and Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), of  $0.08

·

Entered into agreements for multiple acquisitions during 2016,  forming two new core operating areas and increasing our total acreage footprint by approximately 41,000 net acres

·

Currently operating three horizontal rigs, including two in WildHorse and one in Monarch

·

Increased full-year 2017 production guidance to a range of 22.5 – 25.5 MBOE/d, an increase of approximately 60% over 2016 based on the midpoint of guidance



Callon delivered exceptional growth in our producing assets in 2016, with a nearly 60% increase in daily production and 70% increase in proved reserves, commented Fred Callon, Chairman and Chief Executive Officer. The strength of a  capital efficient operational base, combined with our solid financial position, allowed us to stay on our front foot throughout the year and ultimately enter into acquisition agreements that tripled our acreage position in the Permian Basin on an accretive basis. We are now entering a period that will be characterized by drill-bit growth, planning to increase our horizontal development program to five rigs in both the Midland and Delaware Basins by early 2018. Our 2017 drilling program will be active in all four of our core operating areas as we prioritize top-tier cash returns in our portfolio, without the need to manage onerous drilling obligations. In the near-term, we are on the cusp of unlocking the value of our newly acquired WildHorse position after investing in facilities for efficient development and adding a second rig to this position last month. We look forward to accelerating the value proposition in a similar manner in the Spur area with a rig starting by mid-year. Overall, we currently expect our operations to produce another year of production growth approaching 60% in 2017 while maintaining the financial strength required to navigate any potential headwinds in 2017 and beyond. With our existing portfolio of delineated locations in core, unconventional shale plays, Callon is well-positioned to deliver leading production and cash flow growth per share, as well as additional upside in emerging zones across the entire Permian Basin.



Operations Update



At December 31, 2016,  we had 148 gross (112.5 net) horizontal wells producing from  six established flow units in the Midland Basin.  Net daily production for the three months ended December 31, 2016 grew approximately 73%  to 18.4 thousand barrels of oil equivalent per day (MBOE/d)  (approximately 76% oil) as compared to the same period of 2015.  Sequentially, we grew production by approximately 11% compared to the third quarter of 2016.



For the three months ended December 31, 2016, we operated two horizontal drilling rigs, drilling 10 gross (7.4 net) horizontal wells in both the Monarch and WildHorse areas. We placed 10 gross (6.9 net) horizontal wells on production in the quarter, all of which were located in our Monarch area.




i.

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

 

 


 

Well Activity Summary



The following table details well-related activity for the quarter by operating area:





 

 

 

 

 

 

 

 

 

 

 

 



 

For the Three Months Ended December 31, 2016



 

 

 

 

 

Completed/

 

 

 

 



 

Drilled

 

On Production(a)

 

Awaiting Completion



 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Monarch horizontal wells

 

 

2.9 

 

10 

 

6.9 

 

 

1.4 

WildHorse horizontal wells

 

 

4.5 

 

 

 

 

2.8 

  Total Midland Basin wells

 

10 

 

7.4 

 

10 

 

6.9 

 

 

4.2 





(a)

Wells turned to production batteries. Includes wells drilled prior to the fourth quarter of 2016.



During the fourth quarter, we continued to focus on the development of two flow units within the Lower Spraberry in the Monarch area, and also expanded our development to include the Wolfcamp A zone which was placed on production in early October 2016. The following table highlights wells that achieved peak rates during the period, expressed in absolute barrels of oil equivalent per day (BOE/d) and production rates per 1,000 feet of completed lateral: 





 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

Focus Area

 

Completed

 

24-Hour

 

Production

 

Lateral

 

30-Day

 

Production

 

Lateral

Date

 

Well

 

(Zone)

 

Lateral (ft)

 

IP

 

(% oil)

 

Feet

 

IP

 

(% oil)

 

Feet

11/20/2016

 

Casselman 40-6LL

 

Monarch (LLS)

 

4,473

 

987

 

76%

 

221

 

760

 

78%

 

170

11/20/2016

 

Casselman 40-8LL

 

Monarch (LLS)

 

4,623

 

968

 

78%

 

209

 

760

 

82%

 

164

11/22/2016

 

Pecan Acres 23
PSA 2 09SH

 

Monarch (LLS)

 

9,206

 

1,411

 

88%

 

153

 

1,142

 

86%

 

124

12/01/2016

 

Casselman 40 07UL

 

Monarch (ULS)

 

4,473

 

1,030

 

86%

 

230

 

883

 

86%

 

198

12/05/2016

 

Pecan Acres 23
PSA 2 16AH

 

Monarch (WCA)

 

9,234

 

1,440

 

89%

 

156

 

1,352

 

89%

 

146

12/06/2016

 

Kendra-Kristen 4 24SH

 

Monarch (LLS)

 

9,642

 

1,797

 

93%

 

186

 

1,255

 

92%

 

130

12/16/2016

 

Kendra-Kristen 3 23SH

 

Monarch (ULS)

 

9,678

 

1,296

 

93%

 

134

 

1,101

 

92%

 

114

12/25/2016

 

Kendra-Kristen 5 25SH

 

Monarch (ULS)

 

9,402

 

1,500

 

93%

 

160

 

1,167

 

92%

 

124

01/05/2017

 

Kendra PSA 1 216LL

 

Monarch (LLS)

 

10,061

 

1,747

 

90%

 

174

 

1,381

 

90%

 

137

01/05/2017

 

Kendra PSA 1 218LL

 

Monarch (LLS)

 

10,343

 

1,517

 

89%

 

147

 

1,289

 

90%

 

125



(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 are encouraged with the performance of the first Wolfcamp A well in the Monarch focus area. The Pecan Acres PSA 2 16AH was drilled from a stacked two-well pad with a ULS well and achieved a Peak 30-Day IP of over 1,350 BOE/d (89% oil), further demonstrating the high quality of targeted flow units for multi-zone development in the future. This well represents our fifth producing flow unit in the Monarch area, inclusive of the Upper and Lower benches of the Lower Spraberry (the ULS and LLS, respectively), the Middle Spraberry and the Wolfcamp B. Additionally, we drilled and completed our longest laterals to date in our Carpe Diem field targeting the LLS with drilled laterals averaging nearly 11,500 ft. and average Peak 30-Day IPs of approximately 1,350 BOE (90% oil).



We also drilled five gross wells in WildHorse in the fourth quarter as we commenced our program development of this new core operating unit. We recently completed our first four wells during January 2017, including a two-well, staggered Wolfcamp A and Lower Spraberry pad in the Sidewinder field in northwest Howard County, and a stacked Wolfcamp A and Lower Spraberry pad located approximately 10 miles south of Sidewinder in the Maverick field. These four wells are in various stages of flowback and continue to climb towards peak rates. 



Callon is currently operating three horizontal rigs, two of which are running in the WildHorse area. We initiated our pad development program in this area in late 2016 and recently accelerated our activity with the addition of a second rig in January 2017 after making substantial progress on our infrastructure investment plan. Both rigs are currently drilling in the Fairway field located in central Howard County. The rig on the western side of Fairway is drilling a three-well, stacked pad targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B zones, which we expect to complete in March 2017. The rig on the eastern side of Fairway is drilling a two-well pad


i.

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

 

 


 

targeting the Wolfcamp A, which we expect to complete in April 2017. Our third horizontal rig continues to be focused in Monarch before moving to Reagan County in the Ranger unit in the second quarter.



We are also progressing our plans for program development in our recently acquired acreage in the Delaware Basin, which has been named the Spur operating area. We are currently flowing back a recently completed 10,000’ lateral well targeting the Lower Wolfcamp A, the Corbets 34-149 2WA, and early time performance is in-line with our type curve expectations. We are also preparing to complete a 10,000’ lateral well targeting the Wolfcamp B in an offsetting drilling unit. Following the completion of upgrades to existing infrastructure, we plan to add a dedicated horizontal drilling rig to the Spur operating area by mid-year 2017, with the potential for incremental drilling activity in the Delaware Basin in 2018.



Capital Expenditures



For the three months ended December 31, 2016, we accrued  $43.3  million in operational capital expenditures, including facilities expenditures of $11.4 million,  equal to $43.3 million accrued in the third quarter of 2016. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands): 





 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

Three Months Ended December 31, 2016



 

Operational Capital Expenditures

 

Seismic & Other

 

Capitalized Interest

 

Capitalized G&A

 

Total Capital Expenditures

Cash basis (a)

 

$

53,358 

 

$

3,625 

 

$

6,699 

 

$

3,652 

 

$

67,334 

Timing adjustments (b)

 

 

(10,030)

 

 

754 

 

 

 

 

 

 

(9,275)

Non-cash items

 

 

 

 

 

 

 

 

1,352 

 

 

1,352 

  Accrual (GAAP) basis

 

$

43,328 

 

$

4,379 

 

$

6,700 

 

$

5,004 

 

$

59,411 



(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

 

 

December 31, 2016

 

September 30, 2016

 

December 31, 2015

Net production

 

 

 

 

 

 

 

 

 

  Oil (MBbls)

 

 

1,287 

 

 

1,153 

 

 

777 

  Natural gas (MMcf)

 

 

2,413 

 

 

2,244 

 

 

1,188 

  Total production (MBOE)

 

 

1,689 

 

 

1,527 

 

 

975 

  Average daily production (BOE/d)

 

 

18,359 

 

 

16,598 

 

 

10,598 

  % oil (BOE basis)

 

 

76% 

 

 

76% 

 

 

80% 

Oil and natural gas revenues (in thousands)

 

 

 

 

 

 

 

 

 

  Oil revenue

 

$

60,559 

 

$

49,095 

 

$

30,582 

  Natural gas revenue

 

 

8,522 

 

 

6,832 

 

 

2,981 

     Total revenue

 

$

69,081 

 

$

55,927 

 

$

33,563 

  Impact of cash-settled derivatives

 

 

2,079 

 

 

4,091 

 

 

9,918 

     Adjusted Total Revenue (i)

 

$

71,160 

 

$

60,018 

 

$

43,481 





Total Revenue. For the quarter ended December 31, 2016, Callon reported total revenues of $69.1 million and total revenues including cash-settled derivatives (Adjusted Total Revenue, a non-GAAP financial measure(i))  of $71.2 million, including the $2.1 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 18,359 BOE/d compared to average daily production of 16,598 BOE/d in the third quarter of 2016. Average realized prices, including and excluding the effects of hedging, are detailed below.




i.

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

 

 


 

Hedging impacts. For the quarter ended December 31, 2016, Callon recognized the following hedging-related items (in thousands, except per unit data): 





 

 

 

 

 

 



 

In Thousands

 

Per Unit

Oil derivatives contracts

 

 

 

 

 

 

Net gain on settlements

 

$

2,334 

 

$

1.82 

Net loss on fair value adjustments

 

 

(10,639)

 

 

 

  Total net loss on oil derivatives contracts

 

$

(8,305)

 

 

 



 

 

 

 

 

 

Natural gas derivatives contracts

 

 

 

 

 

 

Net loss on settlements

 

$

(255)

 

$

(0.10)

Net loss on fair value adjustments

 

 

(392)

 

 

 

  Total net loss on natural gas derivatives contracts

 

$

(647)

 

 

 



 

 

 

 

 

 

Total derivatives contracts

 

 

 

 

 

 

Net gain on settlements

 

$

2,079 

 

$

1.23 

Net loss on fair value adjustments

 

 

(11,031)

 

 

 

  Total net loss on total derivatives contracts

 

$

(8,952)

 

 

 



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





 

 

 



 

Three Months Ended



 

December 31, 2016

Average realized sales price

 

 

 

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

 

$

47.05 

     Impact of cash-settled derivatives

 

 

1.82 

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

 

$

48.87 



 

 

 

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

 

$

3.53 

     Impact of cash-settled derivatives

 

 

(0.10)

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

 

$

3.43 



 

 

 

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

 

$

40.90 

     Impact of cash-settled derivatives

 

 

1.23 

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

 

$

42.13 







 

 

 

 

 

 

 

 

 



 

Three Months Ended



 

December 31, 2016

 

September 30, 2016

 

December 31, 2015

Additional per BOE data

 

 

 

 

 

 

 

 

 

  Sales price, excluding impact of cash-settled derivatives

 

$

40.90 

 

$

36.63 

 

$

34.42 

  Sales price, including impact of cash-settled derivatives

 

 

42.13 

 

 

39.30 

 

 

44.60 



 

 

 

 

 

 

 

 

 

  Lease operating expense, including workover and gathering

 

$

8.36 

 

$

6.52 

 

$

6.47 

  Production taxes

 

 

2.20 

 

 

2.28 

 

 

2.04 

  Depletion, depreciation and amortization

 

 

13.06 

 

 

11.33 

 

 

17.29 

  Adjusted G&A(a)

 

 

 

 

 

 

 

 

 

     Cash component

 

 

2.84 

 

 

2.38 

 

 

3.80 

     Non-cash component

 

 

0.54 

 

 

0.58 

 

 

0.65 



(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.




i.

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

 

 


 

Lease Operating Expenses, including workover and gathering expense (LOE). LOE per BOE for the three months ended December 31, 2016 was $8.36 per BOE, compared to LOE of $6.52 per BOE in the third quarter of 2016.  The increase in this metric was primarily related to an increase in the number of workover activities in the quarter and higher fuel and power expenses related to assets acquired during 2016. We continue to make investments in infrastructure in these new operating areas to support our planned increases in drilling activity and expect these investments to reduce our LOE in these areas over time.

 

Production Taxes, including ad valorem taxes. Production taxes were $2.20 per BOE in the fourth 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 December 31, 2016 was $13.06 per BOE compared to $11.33 per BOE in the third quarter of 2016, attributable to increases in our depreciable asset base and assumed future development costs related to undeveloped proved reserves relative to the increase in proved reserves.



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 $5.7 million, or $3.38 per BOE, for the fourth quarter of 2016 compared to $4.5 million, or $2.96 per BOE, for the third quarter of 2016.  The cash component of Adjusted G&A was $4.8 million, or $2.84 per BOE, for the fourth quarter of 2016 compared to $3.6  million, or $2.38 per BOE, for the third quarter of 2016.



For the fourth 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):  



 

 

 

 

 

 

 

 

 

 



 

Recurring

 

 

 

 



 

Cash

 

Non-Cash

 

 

Total

G&A expenses

 

 

 

 

 

 

 

 

 

 

  Cash G&A

 

$

4,800 

 

$

 

 

$

4,800 

  Restricted stock share-based compensation

 

 

 

 

801 

 

 

 

801 

  Change in the fair value of liability share-based awards

 

 

 

 

857 

 

 

 

857 

  Corporate depreciation & amortization

 

 

 

 

104 

 

 

 

104 

Total G&A expense:

 

$

4,800 

 

$

1,762 

 

 

$

6,562 

Adjusted G&A

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

$

(857)

Adjusted G&A – total

 

 

 

 

 

 

 

 

 

5,705 

  Restricted stock share-based compensation (non-cash)

 

 

 

 

 

 

 

 

 

(801)

  Corporate depreciation & amortization (non-cash)

 

 

 

 

 

 

 

 

 

(104)

Adjusted G&A – cash component

 

 

 

 

 

 

 

 

$

4,800 



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 benefit of less than $0.1 million for the three months ended December 31, 2016. At December 31, 2016 we had a valuation allowance of $140.2 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 for the quarter as if the valuation allowance did not exist.




i.

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

 

 


 

A breakdown of the Company’s actual 2016 capital expenditures and anticipated 2017 operational plan and associated expenditures is presented below on an accrual, or GAAP, basis:







 

 

 

 

 

 



 

2016 Actual

 

2017 Forecast

Net operated horizontal well completions

 

 

 

 

 

 

  Midland Basin

 

 

23.7

 

 

30 - 32

  Delaware Basin

 

 

 

 

3 - 4



 

 

 

 

 

 

Average lateral length

 

 

6,510

 

 

~7,500

Average working interest

 

 

~74%

 

 

~75%



 

 

 

 

 

 

Gross horizontal well costs ($MM)

 

 

 

 

 

 

  Midland Basin (7,500' drilled lateral)

 

 

 

 

$

5.0 - 5.5

  Delaware Basin (10,000' drilled lateral)

 

 

 

 

$

8.5 - 9.5



 

 

 

 

 

 

Non-operated horizontal activity ($MM)

 

 

 

 

$

7.5 - 10.0



 

 

 

 

 

 

Capital expenditures ($MM, accrual basis)

 

 

 

 

 

 

  Drilling and completion

 

$

117.4 

 

$

240-255 

  Facilities and other

 

 

38.9 

 

 

85-95 

     Total operational capital expenditures

 

$

156.3 

 

$

325-350 



Proved Reserves



The Company recently completed the reserve audit for the year ended December 31, 2016 with its independent reserve auditor, DeGolyer and MacNaughton. As of December 31, 2016, Callon’s estimated total proved reserves were 91.6 million BOE, a 69% increase over the previous year-end. The proved reserves estimate is comprised of 78% oil of which our total proved developed estimated volumes are comprised of 76% oil. Included in total proved reserve estimates are  105 (gross) horizontal proved undeveloped locations. These estimates do not include the impact of our recently completed acquisition in the Delaware Basin.



The following table presents the progression of our estimated net proved oil and natural gas reserves from December 31, 2015 to 2016, 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, 2015

 

43,348 

 

65,537 

 

54,271 

Revisions to previous estimates

 

(5,738)

 

13,929 

 

(3,417)

Extensions and discoveries

 

14,479 

 

17,194 

 

17,345 

Purchases, net of sales, of reserves in place

 

23,336 

 

33,709 

 

28,954 

Production

 

(4,280)

 

(7,758)

 

(5,573)

As of December 31, 2016

 

71,145 

 

122,611 

 

91,580 



Callon added a total of 17.3 MMBOE in 2016 from  horizontal development of a portion of our properties, replacing 311% of 2016 production as calculated by the sum of reserve extensions, discoveries and revisions (including all price-related revisions), divided by annual production (Organic reserve replacement). The Company’s finding and development from extensions and discoveries Drill-Bit F&D costs  were $8.77 per BOE calculated as cash costs incurred for exploration and development divided by the sum of extensions and discoveries. See Non-GAAP Financial Measures and Reconciliations included within this release for related disclosures and calculations.










i.

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

 

 


 

2017  Guidance Update



 

 

 

 



 

First Quarter

 

Annual



 

2017

 

2017

Total production (BOE/d)

 

19,500 - 21,000

 

22,500 - 25,500

  % oil

 

75% - 77%

 

75% - 77%

Income Statement Expenses (per BOE)

 

 

 

 

  LOE, including workovers

 

$6.75 - $7.50

 

$6.00 - $6.50

  Gathering and treating

 

$0.40 - $0.50

 

$0.40 - $0.50

  Production taxes, including ad valorem (% unhedged revenue)

 

7%

 

7%

  Adjusted G&A: cash component (a)

 

$2.50 - $3.00

 

$2.00 - $2.50

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

 

$0.75 - $1.25

 

$0.50 - $1.00

  Interest expense (c)

 

$0.00 - $0.00

 

$0.00 - $0.00

  Effective income tax rate

 

0.0%

 

0.0%

Capital expenditures ($MM, accrual basis)

 

 

 

 

  Total operational capital expenditures (d)

 

$70 - $75

 

$325 - $350

  Capitalized expenses (cash component)

 

$10 - $12

 

$40 - $45



(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 fourth 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.

(c)

All interest expense anticipated to be capitalized.

(d)

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




i.

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

 

 


 

Hedge Portfolio Summary



The following table summarizes our open derivative positions as of February 27, 2017: 







 

 

 

 

 

 



 

For the Full Year of

 

For the Full Year of

Oil contracts

 

2017

 

2018

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 

 

$

Deferred premium put option

 

 

 

 

 

 

  Total volume (MBbls)

 

 

498 

 

 

  Premium per Bbl

 

$

2.05 

 

$

  Weighted average price per Bbl

 

 

 

 

 

 

     Long put option

 

$

50.00 

 

$

Deferred premium put spread option

 

 

 

 

 

 

  Total volume (MBbls)

 

 

506 

 

 

  Premium per Bbl

 

$

2.45 

 

$

  Weighted average price per Bbl

 

 

 

 

 

 

     Long put option

 

$

50.00 

 

$

     Short put option

 

$

40.00 

 

$

Collar contracts (WTI, two-way collars)

 

 

 

 

 

 

  Total volume (MBbls)

 

 

1,351 

 

 

  Weighted average price per Bbl

 

 

 

 

 

 

     Ceiling (short call)

 

$

58.19 

 

$

     Floor (long put)

 

$

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 differential)

 

 

 

 

 

 

  Volume (MBbls)

 

 

2,004 

 

 

1,825 

  Weighted average price per Bbl

 

$

(0.52)

 

$

(1.02)

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

 

 

 

 

 

 

  Total volume (MBbls)

 

 

 

 

2,738 

  Weighted average price per Bbl

 

 

 

 

 

 

     Ceiling (short call option)

 

$

 

$

62.84 

     Floor (long put option)

 

$

 

$

50.00 

     Short put option

 

$

 

$

40.00 



 

 

 

 

 

 

Natural gas contracts

 

 

 

 

 

 

Collar contracts combined with short puts (Henry Hub, 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 

 

$

Collar contracts (Henry Hub, two-way collars)

 

 

 

 

 

 

  Total volume (Bbtu)

 

 

1,460 

 

 

  Weighted average price per MMBtu

 

 

 

 

 

 

     Ceiling (short call option)

 

$

3.68 

 

$

     Floor (long put option)

 

$

3.00 

 

$


i.

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

 

 


 

Income (Loss) Available to Common Shareholders. The Company reported a net loss available to common shareholders of $3.6 million in the fourth quarter of 2016 and Adjusted Income available to common shareholders of $13.1 million, or $0.08 per diluted share. The following tables reconcile to the related GAAP measure the Company’s income (loss) available to common stockholders to Adjusted Income and the Company’s net income (loss) to Adjusted EBITDA (in thousands):





 

 

 

 

 

 

 

 

 



 

For the Three Months Ended



 

December 31, 2016

 

September 30, 2016

 

December 31, 2015

Income (loss) available to common stockholders

 

$

(3,570)

 

$

19,315 

 

$

(115,144)

  Change in valuation allowance

 

 

559 

 

 

(7,907)

 

 

40,025 

  Write-down of oil and natural gas properties

 

 

 

 

 

 

78,737 

  Net loss (gain) on derivatives, net of settlements

 

 

7,170 

 

 

(679)

 

 

(635)

  Rig termination fee

 

 

 

 

 

 

(368)

  Change in the fair value of share-based awards

 

 

590 

 

 

2,192 

 

 

1,197 

  Loss on early extinguishment of debt

 

 

8,374 

 

 

 

 

Adjusted Income

 

$

13,123 

 

$

12,921 

 

$

3,812 

Adjusted Income per fully diluted common share

 

$

0.08 

 

$

0.09 

 

$

0.05 







 

 

 

 

 

 

 

 

 



 

 

For the Three Months Ended



 

December 31, 2016

 

September 30, 2016

 

December 31, 2015

Net income (loss)

 

$

(1,746)

 

$

21,139 

 

$

(113,170)

  Write-down of oil and natural gas properties

 

 

 

 

 

 

121,134 

  Net loss (gain) on derivatives, net of settlements

 

 

11,030 

 

 

(1,044)

 

 

(977)

  Change in the fair value of share-based awards

 

 

1,718 

 

 

4,150 

 

 

2,354 

  Rig termination fee

 

 

 

 

 

 

(566)

  Loss on early extinguishment of debt

 

 

12,883 

 

 

 

 

  Acquisition expense

 

 

1,263 

 

 

456 

 

 

27 

  Income tax (benefit) expense

 

 

48 

 

 

(62)

 

 

  Interest expense

 

 

1,369 

 

 

831 

 

 

5,544 

  Depreciation, depletion and amortization

 

 

22,512 

 

 

17,733 

 

 

17,308 

  Accretion expense

 

 

196 

 

 

187 

 

 

175 

Adjusted EBITDA

 

$

49,273 

 

$

43,390 

 

$

31,829 



Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the fourth quarter of 2016 was $44.4 million and is reconciled to operating cash flow in the following table (in thousands):



 

 

 

 

 

 

 

 

 



 

Three Months Ended



 

December 31, 2016

 

September 30, 2016

 

December 31, 2015

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(1,746)

 

$

21,139 

 

$

(113,170)

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

 

 

 

 

 

 

 

 

 

  Depreciation, depletion and amortization

 

 

22,512 

 

 

17,733 

 

 

17,308 

  Write-down of oil and natural gas properties

 

 

 

 

 

 

121,134 

  Accretion expense

 

 

196 

 

 

187 

 

 

175 

  Amortization of non-cash debt related items

 

 

744 

 

 

810 

 

 

781 

  Deferred income tax (benefit) expense

 

 

48 

 

 

(62)

 

 

  Net (gain) loss on derivatives, net of settlements

 

 

11,030 

 

 

(1,044)

 

 

(977)

  Loss on early extinguishment of debt

 

 

9,883 

 

 

 

 

  Rig termination fee

 

 

 

 

 

 

(566)

  Non-cash expense related to equity share-based awards

 

 

811 

 

 

608 

 

 

521 

  Change in the fair value of liability share-based awards

 

 

908 

 

 

3,371 

 

 

1,853 

Discretionary cash flow

 

$

44,386 

 

$

42,742 

 

$

27,059 



 

 

 

 

 

 

 

 

 

  Changes in working capital

 

 

(7,832)

 

 

2,927 

 

 

4,475 

  Payments to settle asset retirement obligations

 

 

(576)

 

 

(576)

 

 

(211)

Net cash provided by operating activities

 

$

35,978 

 

$

45,093 

 

$

31,323 




i.

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

 

 


 

 F&D and Reserve Replacement:



 

 

 

 

 

 



 

Calculation Parameters

 

2016 Metrics

Production (MBOE)

 

 

(A)

 

 

5,573 



 

 

 

 

 

 

Proved Reserve Data

 

 

 

 

 

 

Proved reserves (MBOE)

 

 

 

 

 

 

  Total (MBOE) extensions and discoveries

 

 

(B)

 

 

17,345 

PUD additions

 

 

(C)

 

 

12,035 

PUDs transferred to PDP

 

 

(D)

 

 

6,823 

Total annual reserve additions, net of revisions

 

 

(E)

 

 

42,882 



 

 

 

 

 

 

Capital Costs (in thousands)

 

 

 

 

 

 

Property acquisition costs

 

 

 

 

 

 

  Exploration costs

 

 

 

 

$

38,612 

  Development costs

 

 

 

 

 

151,735 

Unevaluated properties

 

 

 

 

 

 

  Exploration costs

 

 

(F)

 

 

8,631 

  Transfers to evaluated properties

 

 

 

 

 

(40,621)

  Leasehold and seismic

 

 

 

 

 

(6,220)

Total capital costs incurred

 

 

(G)

 

$

152,137 



 

 

 

 

 

 

Drill-Bit F&D costs per BOE (two-stream)

 

 

(G) / (B)

 

$

8.77 

PD F&D per BOE (two-stream)

 

 

(G - F) / (B - C + D)

 

$

11.83 



 

 

 

 

 

 

Organic reserve replacement ratio

 

 

(B) / (A)

 

$

311% 

All-sources reserve replacement ratio

 

 

(E) / (A)

 

$

769% 














i.

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

 

 


 



Callon Petroleum Company

Consolidated Balance Sheets

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







 

 

 

 

 

 

December 31, 2016

 

December 31, 2015

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

$

652,993 

 

$

1,224 

Accounts receivable

 

69,783 

 

 

39,624 

Fair value of derivatives

 

103 

 

 

19,943 

Other current assets

 

2,247 

 

 

1,461 

Total current assets

 

725,126 

 

 

62,252 

Oil and natural gas properties, full cost accounting method:

 

 

 

 

 

  Evaluated properties

 

2,754,353 

 

 

2,335,223 

  Less accumulated depreciation, depletion, amortization and impairment

 

(1,947,673)

 

 

(1,756,018)

  Net evaluated oil and natural gas properties

 

806,680 

 

 

579,205 

  Unevaluated properties

 

668,721 

 

 

132,181 

Total oil and natural gas properties

 

1,475,401 

 

 

711,386 

Other property and equipment, net

 

14,114 

 

 

7,700 

Restricted investments

 

3,332 

 

 

3,309 

Deferred financing costs related to the senior secured revolving credit facility

 

3,092 

 

 

3,642 

Acquisition deposit

 

46,138 

 

 

Other assets, net

 

384 

 

 

305 

Total assets

$

2,267,587 

 

$

788,594 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

$

95,577 

 

$

70,970 

Accrued interest

 

6,057 

 

 

5,989 

Cash-settleable restricted stock unit awards

 

8,919 

 

 

10,128 

Asset retirement obligations

 

2,729 

 

 

790 

Fair value of derivatives

 

18,268 

 

 

Total current liabilities

 

131,550 

 

 

87,877 

Senior secured revolving credit facility

 

 

 

40,000 

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

 

 

 

288,565 

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

 

390,219 

 

 

Asset retirement obligations

 

3,932 

 

 

4,317 

Cash-settleable restricted stock unit awards

 

8,071 

 

 

4,877 

Deferred tax liability

 

90 

 

 

Fair value of derivatives

 

28 

 

 

Other long-term liabilities

 

295 

 

 

200 

Total liabilities

 

534,185 

 

 

425,836 

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 and 1,578,948 shares outstanding, respectively

 

15 

 

 

16 

Common stock, $0.01 par value, 300,000,000 and 150,000,000 shares authorized; 201,041,320 and 80,087,148 shares outstanding, respectively

 

2,010 

 

 

801 

Capital in excess of par value

 

2,171,514 

 

 

702,970 

Accumulated deficit

 

(440,137)

 

 

(341,029)

Total stockholders’ equity

 

1,733,402 

 

 

362,758 

Total liabilities and stockholders’ equity

$

2,267,587 

 

$

788,594 








































i.

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

 

 


 

Callon Petroleum Company

Consolidated Statements of Operations

(in thousands, except per share data)







 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended December 31,

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2016

 

 

2015

Operating revenues:

 

 

 

 

 

 

 

 

 

 

 

 

  Oil sales

 

$

60,559 

 

$

30,582 

 

$

177,652 

 

$

125,166 

  Natural gas sales

 

 

8,522 

 

 

2,981 

 

 

23,199 

 

 

12,346 

Total operating revenues

 

 

69,081 

 

 

33,563 

 

 

200,851 

 

 

137,512 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 

  Lease operating expenses

 

 

14,124 

 

 

6,308 

 

 

38,353 

 

 

27,036 

  Production taxes

 

 

3,717 

 

 

1,993 

 

 

11,870 

 

 

9,793 

  Depreciation, depletion and amortization

 

 

22,051 

 

 

16,854 

 

 

71,369 

 

 

69,249 

  General and administrative

 

 

6,562 

 

 

6,180 

 

 

26,317 

 

 

28,347 

  Accretion expense