Exhibit 99.1

 

Bonanza Creek Energy Announces Fourth Quarter and Full Year 2017

Financial and Operating Results

 

·                  Quarterly GAAP cash flow from operating activities of $16.2 million; adjusted EBITDAX(1) of $21.6 million; GAAP net loss of $0.28 per diluted share; adjusted net income(1) of $0.40 per diluted share

 

·                  2017 all-in finding and development costs of $7.46 per Boe

 

·                  Slick-water completion test is outperforming offset wells and expectations

 

(1)   Non-GAAP measure, see attached Reconciliation Schedules.

 

DENVER, March 14, 2018 — Bonanza Creek Energy, Inc. (NYSE: BCEI) (the “Company”) today announces its fourth quarter and full year 2017 financial and operating results.

 

Fourth Quarter 2017 Results

 

For the fourth quarter of 2017, the Company reported quarterly and annual production volumes of 14.8 MBoe per day and 16.0 MBoe per day, respectively.  As previously announced, these production figures exceeded the high end of the Company’s guidance range. As the Company brought online new wells in the back half of the year, the product mix became increasingly oil-weighted as new wells with enhanced completions and choke management increased oil cuts. The oil-weighted growth from these wells along with increased commodity prices resulted in a 6% increase in quarterly revenues, despite the 19% decrease in production volumes from the prior year. The table below provides production data for the quarter and year ended December 31, 2017.

 

 

 

Three Months Ended

 

Twelve Months Ended

 

Avg. Daily Sales Volumes:

 

12/31/2017

 

12/31/2016

 

% Change

 

12/31/2017

 

12/31/2016

 

% Change

 

Crude oil (Bbls/d)

 

8,350

 

9,058

 

(8

)%

8,442

 

11,776

 

(28

)%

Natural gas (Mcf/d)

 

22,176

 

29,664

 

(25

)%

25,408

 

33,419

 

(24

)%

Natural gas liquids (Bbls/d)

 

2,705

 

4,237

 

(36

)%

3,319

 

4,336

 

(23

)%

Crude oil equivalent (Boe/d)

 

14,750

 

18,239

 

(19

)%

15,995

 

21,682

 

(26

)%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product Mix

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

57

%

50

%

 

 

53

%

54

%

 

 

Natural gas

 

25

%

27

%

 

 

26

%

26

%

 

 

Natural gas liquids

 

18

%

23

%

 

 

21

%

20

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Sales Prices (before derivatives):

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

52.00

 

$

41.86

 

24

%

$

47.56

 

$

35.31

 

35

%

Natural gas (per Mcf)

 

$

2.23

 

$

2.32

 

(4

)%

$

2.39

 

$

1.76

 

36

%

Natural gas liquids (per Bbl)

 

$

21.56

 

$

14.40

 

50

%

$

18.06

 

$

12.39

 

46

%

Crude oil equivalent (per Boe)

 

$

36.73

 

$

27.90

 

32

%

$

32.65

 

$

24.36

 

34

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product Revenue (in thousands)

 

$

49,850

 

$

46,823

 

6

%

$

190,617

 

$

193,335

 

(1

)%

 

1



 

Upon emerging from bankruptcy, the Company focused on reducing operating expenses to right-size its cost structure with the current environment. The table below provides selected cash operating expenses comparatively on a quarterly and annual year-over-year basis.

 

 

 

Three Months Ended

 

Twelve Months Ended

 

Operating Expenses

 

12/31/2017

 

12/31/2016

 

% Change

 

12/31/2017

 

12/31/2016

 

% Change

 

Lease operating expense

 

$

10,066

 

$

9,743

 

3

%

$

38,990

 

$

43,671

 

(11

)%

Gas plant and midstream operating expense

 

$

3,314

 

$

2,628

 

26

%

$

11,882

 

$

12,826

 

(7

)%

Severance and ad valorem taxes

 

$

4,748

 

$

3,773

 

26

%

$

15,261

 

$

15,304

 

%

General and Administrative

 

$

11,356

 

$

27,474

 

(59

)%

$

57,768

 

$

77,065

 

(25

)%

 

On an annual basis, the Company reduced its cash operating costs substantially as a result of various cost-saving measures that were implemented during 2017. While annual costs were reduced year over year, fourth quarter expenses increased compared to 2016. These increased costs resulted from increased well servicing expenses in the Mid-Continent region and implementation costs of compressor swaps that occurred in the Company’s Rocky Mountain region. During the fourth quarter, the Company began a program to swap out existing compressors in the Wattenberg field to reduce its future rental fees. Compressor exchanges will continue into 2018 and the associated costs are reflected in the Company’s lease operating expense guidance, provided on January 29, 2018. The Company expects its operating expenses to be reduced on a per-unit basis in 2018 as production volumes grow and field-level infrastructure capacity is optimally utilized.

 

The table below provides a regional breakout of the Company’s lease operating expense and gas plant and midstream operating expenses.

 

 

 

Three Months Ended December 31, 2017

 

Regional Breakout

 

Rocky Mountain

 

Mid-Continent

 

Total Company

 

 

 

($M)

 

($/Boe)

 

($M)

 

($/Boe)

 

($M)

 

($/Boe)

 

Lease operating expense

 

$

6,728

 

$

6.11

 

$

3,338

 

$

13.04

 

$

10,066

 

$

7.42

 

Gas plant and midstream operating expense

 

1,802

 

1.64

 

1,512

 

5.90

 

3,314

 

2.44

 

Total

 

$

8,530

 

$

7.75

 

$

4,850

 

$

18.94

 

$

13,380

 

$

9.86

 

 

Reported net loss for the fourth quarter of 2017 was $5.8 million, or $0.28 per diluted share, compared to a net loss of $67.3 million, or $1.37 per diluted share, for the fourth quarter of 2016.  Adjusted net income for the fourth quarter of 2017 was $8.3 million, or $0.40 per diluted share, compared to adjusted net loss of $27.9 million, or $0.57 per diluted share, for the fourth quarter of 2016. The increase in GAAP and adjusted net income over the prior year was driven by improved cost structure, greater oil-weighted production and an increase in commodity prices over the prior period.

 

Adjusted EBITDAX for the fourth quarter of 2017 was $21.6 million, a 49% increase compared to $14.5 million for the fourth quarter of 2016.

 

2



 

Adjusted net income (loss) and adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures.

 

The table below summarizes the Company’s annual results as compared to previously provided guidance.

 

 

 

Twelve Months Ended December 31, 2017

 

Guidance vs Actual Summary

 

Guidance

 

Actual

 

Production (MBoe/d)

 

15.7 – 15.9

 

16.0

 

Lease operating expense ($/Boe)

 

$6.50 – $7.00

 

$

 

 6.68

 

Midstream ($/Boe)

 

$1.90 – $2.10

 

$

 

 2.04

 

Cash G&A ($MM)*

 

$41 – $43

 

$

 

 44

 

Production taxes (% of pre-derivative realization)

 

7% – 8%

 

8.0

%

CAPEX ($MM)

 

$108 – $115

 

$

 

110

 

 


* Cash G&A guidance is a non-GAAP measure that is exclusive of the Company’s stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. Please refer to the non-GAAP disclosure at the end of this release for information regarding cash G&A.

 

The Company reported annual production above the high-end of guidance. With the exception of cash G&A, costs and capital were reported within the guided range. The Company’s cash G&A expense for the year was above the high end of the Company’s 2017 guidance range as a result of higher than expected advisory fees in the fourth quarter related to the previously proposed merger with SandRidge Energy, Inc.

 

2017 Proved Reserves, Costs Incurred, and Finding and Development Costs

 

As previously reported, Bonanza Creek’s year-end 2017 proved reserves were 102.0 MMBoe, which represented a 13% increase from 2016. The Company’s year-end 2017 proved reserves were comprised of 52.9 MMBbls of oil, 22.8 MMBbls of NGLs, and 157.7 Bcf of natural gas and were 53% proved developed.  At year end the Company’s proved reserves PV-10 utilizing SEC pricing was $598 million. If SEC pricing for oil and gas increased by 10% to $56.47 per barrel WTI and $3.28 per Mcf Henry Hub, the Company’s proved reserves PV-10 would increase by 27% to $760 million. If, rather than flat pricing, 2017 year-end strip pricing is used, the Company’s PV-10 value for its proved reserves would be $656 million. Please see Schedule 9 at the end of this release for information on SEC pricing and a reconciliation from PV-10 to the GAAP figure “Standardized Measure of Oil and Gas.” All-in finding and development costs for 2017 were $7.46 per Boe, based on the Company’s 2017 costs incurred of $127.5 million and all-in additions of 17,090 MBoe. A breakout of the Company’s costs incurred are provided in the table below.

 

3



 

Costs Incurred

 

(in thousands)

 

For the Year Ended 
December 31, 2017

 

 

 

 

 

Acquisition(1)

 

$

5,828

 

Development(2)

 

117,229

 

Exploration

 

4,440

 

Total(3)

 

$

127,497

 

 


(1)         Acquisition costs for unproved properties were $5.8 million. There were no acquisition costs for proved properties in 2017.

(2)         Development costs include workover costs of $6.1 million.

(3)         Includes amounts relating to asset retirement obligations of $8.3 million.

 

Proved Reserve Roll-Forward

 

 

 

MBoe

 

Balance as of December 31, 2016

 

90,651

 

Extensions, discoveries and infills

 

15,547

 

Revisions to previous estimates

 

1,543

 

Production

 

(5,719

)

Balance as of December 31, 2017

 

102,022

 

 

2018 Production, Capital, and Expense Guidance

 

The table below reiterates the Company’s previously provided 2018 guidance:

 

Guidance Summary

 

Three Months Ended 
March 31, 2018

 

Twelve Months Ended 
December 31, 2018

 

 

 

 

 

 

 

Production (MBoe/d)

 

16.0 - 16.6

 

17.7 - 18.7

 

LOE ($/Boe)

 

 

 

$5.00 - $6.00

 

Midstream expense ($/Boe)

 

 

 

$1.40 - $1.80

 

Recurring cash G&A ($MM)(1)

 

 

 

$32 - $34

 

Production taxes (% of pre-derivative realization)

 

 

 

7% - 8%

 

Total CAPEX ($MM)

 

 

 

$280 - $320

 

Rockies Oil Differential (2)

 

 

 

$5.85 off WTI

 

 

 

 


 

 

(1)         Recurring cash G&A guidance is a non-GAAP measure that is defined as GAAP G&A expense less stock based compensation and anticipated costs for permanent CEO compensation.  The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. Please refer to the Non-GAAP disclosure at the end of this release for information regarding Recurring cash G&A.

(2)         Assumes strip pricing as of January 23, 2018.

 

4



 

Operational Update

 

During the fourth quarter, the Company turned online two adjacent pads in its central legacy acreage, the J21 and T21, which now have approximately 120 days of production data. These two pads consisted of a total of five wells, two SRL, and three XRL, and tested an average of approximately 1,700 pounds of proppant per lateral foot. One of the SRL wells on the T21 pad utilized a slick-water completion design, which increased the fluid intensity by over 100%. While the wells on both of the pads are generally performing in line with expectations, the one slick-water well on the T21 pad stands out with significant outperformance when compared to the other wells on these adjacent pads. The slick-water SRL that was tested in the central acreage is tracking the performance of the 500 MBoe per well average of the North Platte 44-13 pad on the Company’s west acreage. The Company is very encouraged by the slick-water results and plans to test additional slick-water designs in the first half of the year in various portions of the Company’s Wattenberg acreage.

 

At the beginning of 2018, the Company turned online its 8-SRL F26 pad, which utilized an average of approximately 2,000 pounds of proppant per lateral foot and has also recently turned online its first French Lake well. The Company is currently drilling its four XRL B-28 pad on its eastern acreage and is completing its remaining seven French Lake wells. These remaining French Lake wells are expected to be turned online by the end of the second quarter.

 

The Company has provided an updated investor presentation to its website, under the “For Investors” section of its corporate website at www.bonanzacrk.com. Included in this presentation are updated production results and corresponding type curves.

 

Fourth Quarter Earnings Release and Conference Call

 

The Company announces that in conjunction with this release of it fourth quarter 2017 operating and financial results, it will host a conference call to discuss these results on March 15, 2018 at 9:00 a.m. Mountain Time. A live webcast and replay of this event will be available on the Investor Relations section of the Company’s website at www.bonanzacrk.com. A dial-in replay of the event will be available through March 29, 2018. Dial-in information for the conference call is included below.

 

Type

 

Phone Number

 

Passcode

Live participant

 

877-793-4362

 

1899728

Replay

 

855-859-2056

 

1899728

 

About Bonanza Creek Energy, Inc.

 

Bonanza Creek Energy, Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. The Company’s assets and operations are concentrated primarily in the Rocky Mountains in the Wattenberg Field, focused on the Niobrara and Codell formations, and in southern Arkansas, focused on oily Cotton Valley sands. The Company’s common shares are listed for trading on the NYSE under the symbol: “BCEI.” For more information about the Company, please visit www.bonanzacrk.com. Please note

 

5



 

that the Company routinely posts important information about the Company under the Investor Relations section of its website.

 

Forward-Looking Statements

 

This press 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. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These statements include statements regarding development and completion expectations and strategy; and decreasing operating and capital costs. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, that may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including the following: changes in natural gas, oil and NGL prices, including any impact on the Company’s asset carrying values or reserves arising from price declines; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; ability to acquire adequate supplies of water; risks related to derivative instruments; access to adequate gathering systems and pipeline take-away capacity; and pipeline and refining capacity constraints. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. We refer you to the discussion of risk factors in our Annual Report on Form 10-K for the year ended December 31, 2017, filed on March 14, 2018, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

 

For further information, please contact:

 

James R. Edwards

Director - Investor Relations

720-440-6136

jedwards@bonanzacrk.com

 

6



 

Schedule 1: Statement of Operations

(in thousands, expect for per share amounts, unaudited)

 

 

 

Successor

 

 

Predecessor

 

 

 

Three Months
Ended December
31, 2017

 

 

Three Months
Ended December
31, 2016

 

Operating net revenues:

 

 

 

 

 

 

Oil and gas sales

 

$

50,189

 

 

$

47,266

 

Operating expenses:

 

 

 

 

 

 

Lease operating expense

 

10,066

 

 

9,743

 

Gas plant and midstream operating expense

 

3,314

 

 

2,628

 

Severance and ad valorem taxes

 

4,748

 

 

3,773

 

Exploration

 

3,386

 

 

3

 

Depreciation, depletion and amortization

 

9,126

 

 

26,613

 

Abandonment and impairment of unproved properties

 

 

 

229

 

Unused commitments

 

 

 

4,226

 

Contract settlement expense

 

 

 

21,000

 

General and administrative (including $1,035 and $1,643, respectively, of stock compensation)

 

11,356

 

 

27,474

 

Total operating expenses

 

41,996

 

 

95,689

 

Income (loss) from operations

 

8,193

 

 

(48,423

)

Other income (expense):

 

 

 

 

 

 

Derivative gain (loss)

 

(12,603

)

 

490

 

Interest expense

 

(313

)

 

(15,842

)

Other income (loss)

 

(1,421

)

 

(3,559

)

Total other income (expense)

 

(14,337

)

 

(18,911

)

Loss from operations before taxes

 

(6,144

)

 

(67,334

)

Income tax benefit (expense)

 

376

 

 

 

Net loss

 

$

(5,768

)

 

$

(67,334

)

 

 

 

 

 

 

 

Net loss per basic common share

 

$

(0.28

)

 

$

(1.37

)

 

 

 

 

 

 

 

Net loss per diluted common share

 

$

(0.28

)

 

$

(1.37

)

 

 

 

 

 

 

 

Basic weighted-average common shares outstanding

 

20,454

 

 

49,388

 

Diluted weighted-average common shares outstanding

 

20,454

 

 

49,388

 

 

·      The Predecessor Company followed the two-class method when computing the basic and diluted loss per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net loss per share. Please refer to Note 14 — Earnings per Share in the Form 10-K, for a detailed calculation.

 

7



 

 

 

Successor

 

 

Predecessor

 

 

 

April 29, 2017 
through 

December 31, 

2017

 

 

January 1, 

2017 through 
April 28, 2017

 

Twelve 
Months Ended 
December 31, 

2016

 

Operating net revenues:

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

123,535

 

 

$

68,589

 

$

195,295

 

Operating expenses:

 

 

 

 

 

 

 

 

Lease operating expense

 

25,862

 

 

13,128

 

43,671

 

Gas plant and midstream operating expense

 

8,341

 

 

3,541

 

12,826

 

Severance and ad valorem taxes

 

9,590

 

 

5,671

 

15,304

 

Exploration

 

3,745

 

 

3,699

 

946

 

Depreciation, depletion and amortization

 

21,312

 

 

28,065

 

111,215

 

Impairment of oil and gas properties

 

 

 

 

10,000

 

Abandonment and impairment of unproved properties

 

 

 

 

24,692

 

Unused commitments

 

 

 

993

 

7,686

 

Contract settlement expense

 

 

 

 

21,000

 

General and administrative (including $11,630, $2,116, and $8,892, respectively, of stock compensation)

 

42,676

 

 

15,092

 

77,065

 

Total operating expenses

 

111,526

 

 

70,189

 

324,405

 

Income (loss) from operations

 

12,009

 

 

(1,600

)

(129,110

)

Other income (expense):

 

 

 

 

 

 

 

 

Derivative gain (loss)

 

(15,365

)

 

 

(11,234

)

Interest expense

 

(773

)

 

(5,656

)

(62,058

)

Reorganization items, net

 

 

 

8,808

 

 

Gain on termination fee

 

 

 

 

6,000

 

Other income (loss)

 

(1,267

)

 

1,108

 

(2,548

)

Total other income (expense)

 

(17,405

)

 

4,260

 

(69,840

)

Income (loss) from operations before taxes

 

(5,396

)

 

2,660

 

(198,950

)

Income tax benefit (expense)

 

376

 

 

 

 

Net income (loss)

 

$

(5,020

)

 

$

2,660

 

$

(198,950

)

 

 

 

 

 

 

 

 

 

Net income (loss) per basic common share

 

$

(0.25

)

 

$

0.05

 

$

(4.04

)

 

 

 

 

 

 

 

 

 

Net income (loss) per diluted common share

 

$

(0.25

)

 

$

0.05

 

$

(4.04

)

 

 

 

 

 

 

 

 

 

Basic weighted-average common shares outstanding

 

20,427

 

 

49,559

 

49,268

 

Diluted weighted-average common shares outstanding

 

20,427

 

 

50,971

 

49,268

 

 

·      The Predecessor Company followed the two-class method when computing the basic and diluted loss per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net loss per share. Please refer to Note 14 — Earnings per Share in the Form 10-K, for a detailed calculation.

 

8



 

Schedule 2: Statement of Cash Flows

(in thousands, unaudited)

 

 

 

Successor

 

 

Predecessor

 

 

 

Three Months
Ended December
31, 2017

 

 

Three Months
Ended December
31, 2016

 

Cash flows from operating activities:

 

 

 

 

 

 

Net loss

 

$

(5,768

)

 

$

(67,334

)

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

 

 

 

 

 

 

Depreciation, depletion and amortization

 

9,126

 

 

26,613

 

Abandonment and impairment of unproved properties

 

 

 

229

 

Well abandonment costs and dry hole expense

 

 

 

(33

)

Stock-based compensation

 

1,035

 

 

1,643

 

Amortization of deferred financing costs and debt premium

 

 

 

475

 

Derivative (gain) loss

 

12,603

 

 

(490

)

Derivative cash settlements

 

(1,464

)

 

2,584

 

Inventory write-off

 

1,758

 

 

4,390

 

Other

 

4

 

 

(450

)

Changes in current assets and liabilities:

 

 

 

 

 

 

Accounts receivable

 

(2,450

)

 

5,840

 

Prepaid expenses and other assets

 

(1,899

)

 

(791

)

Accounts payable and accrued liabilities

 

3,441

 

 

11,636

 

Settlement of asset retirement obligations

 

(231

)

 

(327

)

Net cash provided by (used in) operating activities

 

16,155

 

 

(16,015

)

Cash flows from investing activities:

 

 

 

 

 

 

Acquisition of oil and gas properties

 

(309

)

 

821

 

Exploration and development of oil and gas properties

 

(34,020

)

 

(4,853

)

(Increase) decrease in restricted cash

 

(4

)

 

5,094

 

Additions to property and equipment - non oil and gas

 

(207

)

 

(240

)

Net cash provided by (used in) investing activities

 

(34,540

)

 

822

 

Cash flows from financing activities:

 

 

 

 

 

 

Payments to predecessor credit facility

 

 

 

(37,666

)

Payment of employee tax withholdings in exchange for the return of common stock

 

 

 

(6

)

Net cash provided by (used in) financing activities

 

 

 

(37,672

)

Net change in cash and cash equivalents

 

(18,385

)

 

(52,865

)

Cash and cash equivalents:

 

 

 

 

 

 

Beginning of period

 

31,096

 

 

133,430

 

End of period

 

$

12,711

 

 

$

80,565

 

 

9



 

 

 

Successor

 

 

Predecessor

 

 

 

April 29,
2017
through
December
31, 2017

 

 

January 1,
2017
through
April 28,
2017

 

Twelve
Months
Ended
December
31, 2016

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(5,020

)

 

$

2,660

 

$

(198,950

)

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

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

21,312

 

 

28,065

 

111,215

 

Non-cash reorganization items

 

 

 

(44,160

)

 

Impairment of oil and gas properties

 

 

 

 

10,000

 

Abandonment and impairment of unproved properties

 

 

 

 

24,692

 

Well abandonment costs dry hole expense

 

75

 

 

2,931

 

872

 

Stock-based compensation

 

11,630

 

 

2,116

 

8,892

 

Amortization of deferred financing costs and debt premium

 

 

 

374

 

3,180

 

Derivative (gain) loss

 

15,365

 

 

 

11,234

 

Derivative cash settlements

 

(1,464

)

 

 

18,333

 

Inventory write-off

 

1,758

 

 

 

4,390

 

Other

 

11

 

 

18

 

(323

)

Changes in current assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable

 

(4,477

)

 

(6,640

)

35,282

 

Prepaid expenses and other assets

 

(1,979

)

 

963

 

(1,838

)

Accounts payable and accrued liabilities

 

(8,470

)

 

(5,880

)

(11,616

)

Settlement of asset retirement obligations

 

(1,167

)

 

(331

)

(800

)

Net cash provided by (used in) operating activities

 

27,574

 

 

(19,884

)

14,563

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

Acquisition of oil and gas properties

 

(5,383

)

 

(445

)

(98

)

Payments of contractual obligation

 

 

 

 

(12,000

)

Exploration and development of oil and gas properties

 

(76,375

)

 

(5,123

)

(52,344

)

(Increase) decrease in restricted cash

 

(16

)

 

118

 

(2,613

)

Additions to property and equipment - non oil and gas

 

(874

)

 

(454

)

(346

)

Net cash used in investing activities

 

(82,648

)

 

(5,904

)

(67,401

)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

Proceeds from predecessor credit facility

 

 

 

 

209,000

 

Payments to predecessor credit facility

 

 

 

(191,667

)

(96,333

)

Proceeds from sale of common stock

 

 

 

207,500

 

 

Payment of employee tax withholdings in exchange for the return of common stock

 

(2,398

)

 

(427

)

(289

)

Deferred financing costs

 

 

 

 

(316

)

Net cash provided by (used in) financing activities

 

(2,398

)

 

15,406

 

112,062

 

Net change in cash and cash equivalents

 

(57,472

)

 

(10,382

)

59,224

 

Cash and cash equivalents:

 

 

 

 

 

 

 

 

Beginning of period

 

70,183

 

 

80,565

 

21,341

 

End of period

 

$

12,711

 

 

$

70,183

 

$

80,565

 

 

10



 

Schedule 3: Balance Sheets

(in thousands, unaudited)

 

 

 

Successor

 

 

Predecessor

 

 

 

As of
December 31,
2017

 

 

As of
December 31,
2016

 

ASSETS

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

12,711

 

 

$

80,565

 

Accounts receivable:

 

 

 

 

 

 

Oil and gas sales

 

28,549

 

 

14,479

 

Joint interest and other

 

3,831

 

 

6,784

 

Prepaid expenses and other

 

6,555

 

 

5,915

 

Inventory of oilfield equipment

 

1,019

 

 

4,685

 

Derivative asset

 

488

 

 

 

Total current assets

 

53,153

 

 

112,428

 

Property and equipment (successful efforts method):

 

 

 

 

 

 

Proved properties

 

555,341

 

 

2,525,587

 

Less: accumulated depreciation, depletion and amortization

 

(17,032

)

 

(1,694,483

)

Total proved properties, net

 

538,309

 

 

831,104

 

Unproved properties

 

183,843

 

 

163,369

 

Wells in progress

 

47,224

 

 

18,250

 

Other property and equipment, net of accumulated depreciation of $2,224 in 2017 and $11,206 in 2016

 

4,706

 

 

6,245

 

Total property and equipment, net

 

774,082

 

 

1,018,968

 

Long-term derivative asset

 

6

 

 

 

Other noncurrent assets

 

3,130

 

 

3,082

 

Total assets

 

$

830,371

 

 

$

1,134,478

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable and accrued expenses

 

$

62,129

 

 

$

61,328

 

Oil and gas revenue distribution payable

 

15,667

 

 

23,773

 

Derivative liability

 

11,423

 

 

 

Predecessor credit facility - current portion

 

 

 

191,667

 

Senior Notes - current portion

 

 

 

793,698

 

Total current liabilities

 

89,219

 

 

1,070,466

 

Long-term liabilities:

 

 

 

 

 

 

Ad valorem taxes

 

11,584

 

 

14,118

 

Long-term derivative liability

 

2,972

 

 

 

Asset retirement obligations for oil and gas properties

 

38,262

 

 

30,833

 

Total liabilities

 

142,037

 

 

1,115,417

 

Commitments and contingencies

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

Predecessor preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding as of December 31, 2016

 

 

 

 

Predecessor common stock, $.001 par value, 225,000,000 shares authorized, 49,660,683 issued and outstanding as of December 31, 2016

 

 

 

49

 

Successor preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding as of December 31, 2017

 

 

 

 

Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,453,549 issued and outstanding as of December 31, 2017

 

4,286

 

 

 

Additional paid-in capital

 

689,068

 

 

814,990

 

Retained deficit

 

(5,020

)

 

(795,978

)

Total stockholders’ equity

 

688,334

 

 

19,061

 

Total liabilities and stockholders’ equity

 

$

830,371

 

 

$

1,134,478

 

 

11



 

Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)

(unaudited)

 

 

 

Three Months Ended

 

 

 

December 31,

 

 

 

2017

 

2016

 

Wellhead Volumes and Prices

 

 

 

 

 

Crude Oil and Condensate Sales Volumes (Bbl/d)

 

 

 

 

 

Rocky Mountains

 

6,762

 

7,042

 

Mid-Continent

 

1,588

 

2,016

 

Total

 

8,350

 

9,058

 

Crude Oil and Condensate Realized Prices ($/Bbl)

 

 

 

 

 

Rocky Mountains

 

$

51.30

 

$

39.98

 

Mid-Continent

 

54.95

 

48.44

 

Composite (before derivatives)

 

52.00

 

41.86

 

Composite (after derivatives)

 

50.06

 

44.96

 

Natural Gas Liquids Sales Volumes (Bbl/d)

 

 

 

 

 

Rocky Mountains

 

2,311

 

3,695

 

Mid-Continent

 

394

 

542

 

Total

 

2,705

 

4,237

 

Natural Gas Liquids Realized Prices ($/Bbl)

 

 

 

 

 

Rocky Mountains

 

$

19.66

 

$

13.19

 

Mid-Continent

 

32.72

 

22.65

 

Composite (before derivatives)

 

21.56

 

14.40

 

Composite (after derivatives)

 

21.56

 

14.40

 

Natural Gas Sales Volumes (Mcf/d)

 

 

 

 

 

Rocky Mountains

 

17,397

 

23,061

 

Mid-Continent

 

4,779

 

6,603

 

Total

 

22,176

 

29,664

 

Natural Gas Realized Prices ($/Mcf)

 

 

 

 

 

Rocky Mountains

 

$

2.08

 

$

2.12

 

Mid-Continent

 

2.77

 

3.01

 

Composite (before derivatives)

 

2.23

 

2.32

 

Composite (after derivatives)

 

2.24

 

2.32

 

Crude Oil Equivalent Sales Volumes (Boe/d)

 

 

 

 

 

Rocky Mountains

 

11,972

 

14,581

 

Mid-Continent

 

2,778

 

3,658

 

Total

 

14,750

 

18,239

 

Crude Oil Equivalent Sales Prices ($/Boe)

 

 

 

 

 

Rocky Mountains

 

$

35.79

 

$

26.01

 

Mid-Continent

 

40.81

 

35.47

 

Composite (before derivatives)

 

36.73

 

27.90

 

Composite (after derivatives)

 

35.66

 

29.44

 

Total Sales Volumes (MBoe)

 

1,357.0

 

1,678.0

 

 

12



 

Schedule 5: Per unit operating margins

(unaudited)

 

 

 

For the Three Months 
Ended December 31,

 

For the Twelve Months Ended 
December 31,

 

 

 

2017

 

2016

 

Percent 
Change

 

2017

 

2016

 

Percent 
Change

 

Per Unit Costs ($/Boe)

 

 

 

 

 

 

 

 

 

 

 

 

 

Realized price (before derivatives)

 

$

36.73

 

$

27.90

 

32

%

$

32.65

 

$

24.36

 

34

%

LOE

 

$

7.42

 

$

5.81

 

28

%

$

6.68

 

$

5.50

 

21

%

Midstream expense

 

$

2.44

 

$

1.57

 

55

%

$

2.04

 

$

1.62

 

26

%

Severance and Ad Valorem

 

$

3.50

 

$

2.25

 

56

%

$

2.61

 

$

1.93

 

35

%

Cash General and Administrative (1)

 

$

7.61

 

$

15.39

 

(51

)%

$

7.54

 

$

8.59

 

(12

)%

Total cash operating costs

 

$

20.97

 

$

25.02

 

(16

)%

$

18.87

 

$

17.64

 

7

%

Cash operating margin (before derivatives)

 

$

15.76

 

$

2.88

 

447

%

$

13.78

 

$

6.72

 

105

%

Derivative Cash Settlements

 

$

(1.07

)

$

1.54

 

(169

)%

$

(0.25

)

$

2.31

 

(111

)%

Cash operating margin (after derivatives)

 

$

14.69

 

$

4.42

 

232

%

$

13.53

 

$

9.03

 

50

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-cash items

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation Depletion and Amortization

 

$

6.72

 

$

15.86

 

(58

)%

$

8.46

 

$

14.01

 

(40

)%

Non-cash General and Administrative

 

$

0.76

 

$

0.98

 

(22

)%

$

2.35

 

$

1.12

 

110

%

 


(1) Cash general and administrative expense excludes stock based compensation of $1.0 million and $1.6 million for the three-month periods ended December 31, 2017 and 2016, respectively, and $13.7 million and $8.9 million for the twelve-month periods ended December 31, 2017 and 2016, respectively.

 

13



 

Schedule 6: Adjusted Net Income (Loss)

(in thousands, except per share amounts, unaudited)

 

Adjusted net income (loss) is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines adjusted net income (loss) as net income (loss) after adjusting first for (1) the impact of certain non-cash items, including unrealized gains and losses on unsettled derivative instruments, impairment of oil and gas properties, other similar non-cash charges (2) one-time transactions and then (3) the non-cash and one time items’ impact on taxes based on an applicable rate that approximates the Company’s effective tax rate in each period. Adjusted net income (loss) is not a measure of net income (loss) as determined by GAAP.

 

The following table provides a reconciliation of net loss (GAAP) to adjusted net income (loss) (non-GAAP):

 

 

 

Three Months Ended

 

Twelve Months Ended

 

 

 

December 31,

 

December 31,

 

 

 

2017

 

2016

 

2017

 

2016

 

Net loss

 

$

(5,768

)

$

(67,334

)

$

(2,360

)

$

(198,950

)

Adjustments to net loss:

 

 

 

 

 

 

 

 

 

Derivative (gain) loss

 

12,603

 

(490

)

15,365

 

11,234

 

Derivative cash settlements

 

(1,464

)

2,584

 

(1,464

)

18,333

 

Impairment of proved properties

 

 

 

 

10,000

 

Abandonment and impairment of unproved properties

 

 

229

 

 

24,692

 

Exploratory dry hole expense

 

 

(33

)

3,006

 

872

 

Stock-based compensation (1)

 

1,035

 

1,643

 

13,746

 

8,892

 

Advisor fees related to CEO transition and strategic alternatives (1)

 

2,774

 

14,457

 

2,774

 

20,375

 

Cash severance costs (1)

 

 

 

1,605

 

2,162

 

Pre-petition advisory fees(1)

 

 

 

683

 

 

Post-petition restructuring fees(1)

 

 

 

3,740

 

 

Reorganization items

 

 

 

(8,808

)

 

Gain on termination fee

 

 

 

 

6,000

 

Contract settlement expense

 

 

21,000

 

 

21,000

 

Total adjustments before taxes

 

14,948

 

39,390

 

30,647

 

123,560

 

Income tax effect

 

(912

)

 

(4,199

)

 

Total adjustments after taxes

 

$

14,036

 

$

39,390

 

$

26,448

 

$

123,560

 

 

 

 

 

 

 

 

 

 

 

Adjusted net income (loss)

 

$

8,268

 

$

(27,944

)

$

24,088

 

$

(75,390

)

Adjusted net income (loss) per diluted share (2)

 

$

0.40

 

$

(0.57

)

$

1.18

 

$

(1.53

)

 

 

 

 

 

 

 

 

 

 

Diluted weighted-average common shares outstanding (2)

 

20,454

 

49,388

 

20,427

 

49,268

 

 


(1) Included as a portion of general and administrative expense on the consolidated statement of operations.

(2) For the twelve-month period ended December 31, 2017, the Company used the Successor’s diluted weighted average share count to calculate adjusted net income per diluted share.

 

14



 

Schedule 7: Adjusted EBITDAX

(in thousands, except per share amounts, unaudited)

 

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash and non-recurring charges. Adjusted EBITDAX is not a measure of net income or cash flows as determined by GAAP.

 

The following table presents a reconciliation of GAAP financial measures of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

 

 

 

Three Months Ended

 

Twelve Months Ended

 

 

 

December 31,

 

December 31,

 

 

 

2017

 

2016

 

2017

 

2016

 

Net Income (loss)

 

$

(5,768

)

$

(67,334

)

$

(2,360

)

$

(198,950

)

Exploration

 

3,386

 

3

 

7,444

 

946

 

Depreciation, depletion and amortization

 

9,126

 

26,613

 

49,377

 

111,215

 

Impairment of proved properties

 

 

 

 

10,000

 

Abandonment and impairment of unproved properties

 

 

229

 

 

24,692

 

Stock-based Compensation (1)

 

1,035

 

1,643

 

13,746

 

8,892

 

Cash severance costs (1)

 

 

 

1,605

 

2,162

 

Advisor fees related to CEO search and strategic alternatives(1)

 

2,774

 

14,457

 

2,774

 

20,375

 

Gain on termination fee

 

 

 

 

(6,000

)

Contract settlement expense

 

 

21,000

 

 

21,000

 

Pre-petition advisory fees(1)

 

 

 

683

 

 

Post-petition restructuring fees(1)

 

 

 

3,740

 

 

Reorganization items

 

 

 

(8,808

)

 

Interest expense

 

313

 

15,842

 

6,429

 

62,058

 

Derivative (gain) loss

 

12,603

 

(490

)

15,365

 

11,234

 

Derivative cash settlements

 

(1,464

)

2,584

 

(1,464

)

18,333

 

Income tax (benefit) expense

 

(376

)

 

(376

)

 

Adjusted EBITDAX

 

$

21,629

 

$

14,547

 

$

88,155

 

$

85,957

 

 


(1) Included as a portion of general and administrative expense on the consolidated statement of operations.

 

15



 

Schedule 9: PV-10 of Estimated Proved Reserves

 

PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our proved oil and natural gas reserves.

 

The following table presents a reconciliation of GAAP Standardized Measure to the non-GAAP financial measure of PV-10.

 

 

 

December 31,

 

(in thousands)

 

2017

 

 

 

 

 

PV-10 (1)

 

598,498

 

Present value of future income taxes discounted at 10% (2)

 

 

Standardized Measure

 

$

598,498

 

 


(1) The 12-month average benchmark pricing used to estimate SEC proved reserves and PV-10 value for crude oil and natural gas was $51.34 per Bbl of WTI crude oil and $2.98 per MMBtu of natural gas at Henry Hub before differential adjustments. Year-end 2017 benchmark prices for oil, and natural gas were both 20% higher from year-end 2016 SEC pricing. After differential adjustments, the Company’s SEC pricing realizations for year-end 2017 were $46.76 per Bbl of oil, $19.57 per Bbl of NGLs, and $2.45 per Mcf of natural gas. Please refer to the Non-GAAP Disclosure at the end of this release for information regarding PV-10

(2) The tax basis of the Company’s oil and gas properties as of December 31, 2017 provides more tax deduction than income generation when reserve estimates were prepared using 2017 SEC pricing.

 

16



 

Schedule 10: Cash G&A

(in thousands, unaudited)

 

Cash G&A is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines cash G&A as GAAP general and administrative expense exclusive of the Company’s stock based compensation and one-time charges, such as severance costs and advisor fees. The Company refers to cash G&A to provide typical cash G&A costs that are planned for in a given period. Cash G&A is not a fully inclusive measure of general and administrative expense as determined by GAAP.

 

The following table presents a reconciliation of GAAP financial measures of G&A expense to the non-GAAP financial measure of cash G&A.

 

 

 

Three Months Ended

 

Twelve Months Ended

 

 

 

12/31/2017

 

9/30/2017

 

12/31/2017

 

12/31/2016

 

General and Administrative Expense

 

$

11,356

 

$

15,181

 

$

57,768

 

$

77,065

 

Stock Compensation

 

(1,035

)

(2,646

)

(13,746

)

(8,892

)

Cash G&A

 

10,321

 

12,535

 

44,022

 

68,173

 

 

17


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