Document


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2018
OR
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from_______________ to _______________
Commission file number 001-38606


BERRY PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation or organization)
 
81-5410470
(I.R.S. Employer Identification Number)
16000 Dallas Parkway, Suite 500
Dallas, Texas 75248
(661) 616-3900
(Address of principal executive offices, including zip code
Registrant’s telephone number, including area code):

5201 Truxtun Avenue
Bakersfield, California 93309
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý    No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
 
 
 
 
 
 
 
Large accelerated filer ¨
 
Accelerated filer ¨
 
Non-accelerated filer x
 
Smaller reporting company ¨
         Emerging Growth Company ý
 
 
 
 
 
 
     
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ¨
   
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨    No ý


Shares of common stock outstanding as of October 31, 2018                        81,642,953



TABLE OF CONTENTS

 
 
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
Item 1.
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
 
 
Item 1.
Item 1A.
Item 5.
Item 6.
 
 

The financial information and certain other information presented in this Form 10-Q have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables. In addition, certain percentages presented here reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not sum due to rounding.





PART I – FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)


BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
Berry Corp. (Successor)
 
September 30, 2018
December 31, 2017
 
(in thousands, except share amounts)
ASSETS
 
 
Current assets:
 
 
Cash and cash equivalents
$
23,856

$
33,905

Accounts receivable, net of allowance for doubtful accounts of $950 at September 30, 2018 and $970 at December 31, 2017
65,757

54,720

Restricted cash
57

34,833

Other current assets
13,233

14,066

Total current assets
102,903

137,524

Noncurrent assets:
 
 
Oil and natural gas properties
1,419,589

1,342,453

Accumulated depletion and amortization
(106,128
)
(54,785
)
Total oil and natural gas properties, net
1,313,461

1,287,668

Other property and equipment
116,149

104,879

Accumulated depreciation
(11,244
)
(5,356
)
Total other property and equipment, net
104,905

99,523

Other noncurrent assets
18,338

21,687

Total assets
$
1,539,607

$
1,546,402

LIABILITIES AND EQUITY
 
 
Current liabilities:
 
 
Accounts payable and accrued expenses
$
117,801

$
97,877

Derivative instruments
26,409

49,949

Liabilities subject to compromise
57

34,833

Total current liabilities
144,267

182,659

Noncurrent liabilities:
 
 
Long-term debt
391,512

379,000

Derivative instruments
4,664

25,332

Deferred income taxes
5,033

1,888

Asset retirement obligation
89,404

94,509

Other noncurrent liabilities
15,617

3,704

Commitments and Contingencies - Note 5



Equity:
 
 
Series A preferred stock ($.001 par value, 250,000,000 shares authorized and none outstanding at September 30, 2018 and 35,845,001 shares outstanding at December 31, 2017)

335,000

Common stock ($.001 par value, 750,000,000 shares authorized and 81,364,933 shares outstanding at September 30, 2018 and 32,920,000 outstanding at December 31, 2017)
81

33

Additional paid-in-capital
915,028

545,345

Treasury stock, at cost
(20,265
)

Retained earnings (Accumulated deficit)
(5,734
)
(21,068
)
Total equity
889,110

859,310

Total liabilities and equity
$
1,539,607

$
1,546,402


The accompanying notes are an integral part of these condensed consolidated financial statements.

1


BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Berry Corp.
(Successor)
 
Berry LLC
(Predecessor)
 
Three Months Ended
Three Months Ended
 
Nine Months Ended
Seven Months Ended
 
Two Months Ended
 
September 30, 2018
September 30, 2017
 
September 30, 2018
September 30, 2017
 
February 28, 2017
 
(in thousands, except per share amounts)
Revenues and other:
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
147,004

$
101,763

 
$
410,013

$
237,324

 
$
74,120

Electricity sales
14,268

8,914

 
25,691

15,517

 
3,655

Gains (losses) on oil derivatives
(18,994
)
(42,443
)
 
(131,781
)
5,642

 
12,886

Marketing revenues
486

811

 
1,788

1,901

 
633

Other revenues
183

865

 
500

3,902

 
1,424

Total revenues and other
142,947

69,910

 
306,211

264,286

 
92,718

Expenses and other:
 
 
 
 
 
 
 
Lease operating expenses
51,649

46,224

 
137,468

105,014

 
28,238

Electricity generation expenses
6,130

4,580

 
13,855

10,193

 
3,197

Transportation expenses
2,318

5,586

 
7,640

18,645

 
6,194

Marketing expenses
437

674

 
1,424

1,674

 
653

General and administrative expenses
13,429

11,729

 
37,896

43,529

 
7,964

Depreciation, depletion, amortization and accretion
21,729

20,822

 
62,017

48,393

 
28,149

Taxes, other than income taxes
8,317

11,782

 
25,288

25,112

 
5,212

(Gains) losses on natural gas derivatives
(1,879
)

 
(1,879
)

 

(Gains) losses on sale of assets and other, net
400

(20,692
)
 
522

(20,687
)
 
(183
)
Total expenses and other
102,530

80,705

 
284,231

231,873

 
79,424

Other income (expenses):
 
 
 
 
 
 
 
Interest expense
(9,877
)
(5,882
)
 
(26,828
)
(12,482
)
 
(8,245
)
Other, net
347

1,155

 
135

4,071

 
(63
)
Total other income (expenses)
(9,530
)
(4,727
)
 
(26,693
)
(8,411
)
 
(8,308
)
Reorganization items, net
13,781

(408
)
 
23,192

(1,001
)
 
(507,720
)
Income (loss) before income taxes
44,668

(15,930
)
 
18,479

23,001

 
(502,734
)
Income tax expense (benefit)
7,683

(6,246
)
 
3,145

9,189

 
230

Net income (loss)
36,985

(9,684
)
 
15,334

13,812

 
$
(502,964
)
Series A preferred stock dividends and conversion to common stock
(86,642
)
(5,485
)
 
(97,942
)
(12,681
)
 
n/a

Net income (loss) attributable to common stockholders
$
(49,657
)
$
(15,169
)
 
$
(82,608
)
$
1,131

 
n/a

Net income (loss) per share attributable to common stockholders:
 
 
 
 
 
 
 
Basic
$
(0.66
)
$
(0.38
)
 
$
(1.59
)
$
0.03

 
n/a

Diluted
$
(0.66
)
$
(0.38
)
 
$
(1.59
)
$
0.03

 
n/a


The accompanying notes are an integral part of these condensed consolidated financial statements.

2


BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)



 
Berry Corp. (Successor)
 
Nine-Month Period Ended September 30, 2018
 
Series A
Common
Additional
Treasury
Retained Earnings
Total
 
Preferred Stock
Stock
Paid in Capital
Stock
(Accumulated Deficit)
Equity
 
(in thousands)
December 31, 2017
$
335,000

$
33

$
545,345

$

$
(21,068
)
$
859,310

Stock based compensation


1,042



1,042

Cash dividends declared on Series A preferred stock, $0.158/share


(5,650
)


(5,650
)
Net income




6,410

6,410

March 31, 2018
335,000

33

540,737


(14,658
)
861,112

Stock based compensation


1,278



1,278

Shares withheld for payment of taxes on equity awards


(176
)


(176
)
Cash dividends declared on Series A preferred stock, $0.15/share


(5,651
)


(5,651
)
Purchase of rights to common stock



(20,006
)

(20,006
)
Net loss




(28,061
)
(28,061
)
June 30, 2018
335,000

33

536,188

(20,006
)
(42,719
)
808,496

Conversion of Series A preferred stock into common stock
(335,000
)
40

334,960




Cash payment to Series A preferred stockholders


(60,273
)


(60,273
)
Issuance of common stock in initial public offering

10

134,352



134,362

Repurchase of common stock

(2
)
(23,710
)


(23,712
)
Shares withheld for payment of taxes on equity awards


(246
)


(246
)
Stock based compensation


1,188



1,188

Purchase of rights to common stock



(259
)

(259
)
Dividends declared on common stock, $0.09/share


(7,431
)


(7,431
)
Net income




36,985

36,985

September 30, 2018
$

$
81

$
915,028

$
(20,265
)
$
(5,734
)
$
889,110


The accompanying notes are an integral part of these condensed consolidated financial statements.



3



BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)


 
Nine-Month Period Ended September 30, 2017,
including Successor and Predecessor Periods
 
Series A Preferred Stock
Common Stock
Additional
Paid in Capital
Treasury Stock
Retained Earnings
(Accumulated Deficit)
Total Equity
December 31, 2016
$

$

$
2,798,713

$

$
(2,295,750
)
$
502,963

Net loss




(502,964
)
(502,964
)
Other


1



1

Cancellation of Predecessor Equity


(2,798,714
)

2,798,714


Predecessor February 28, 2017






Issuance of Series A convertible preferred stock
335,000





335,000

Issuance of common stock

33

527,794



527,827

Fresh start ad valorem tax reclassification


15,700



15,700

Successor February 28, 2017
335,000

33

543.494



878,527

Net income




11,377

11,377

March 31, 2017
335,000

33

543,494


11,377

889,904

Net income




12,119

12,119

June 30, 2017
335,000

33

543,494


23,496

902,023

Stock based compensation


902



902

Net loss




(9,684
)
(9,684
)
September 30, 2017
$
335,000

$
33

$
544,396

$

$
13,812

$
893,241


The accompanying notes are an integral part of these condensed consolidated financial statements.

4


BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Berry Corp.
Berry LLC
 
(Successor)
(Predecessor)
 
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net income (loss)
$
15,334

$
13,812

$
(502,964
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
Depreciation, depletion, amortization and accretion
62,017

48,393

28,149

Amortization and write-off of deferred financing fees
4,042

926

416

Stock-based compensation expense
3,502

902


Deferred income taxes
3,146

7,196

9

(Decrease) increase in allowance for doubtful accounts
(20
)
970


Derivative activities:
 
 
 
  Total (gains) losses
129,902

(5,642
)
(12,886
)
     Cash settlements
(47,161
)
9,902

534

  Cash settlements on early-terminated derivatives
(126,949
)


(Gains) losses on sale of assets and other, net
522

(20,687
)
(25
)
Reorganization items, net
(24,199
)
1,376

501,872

Changes in assets and liabilities:
 
 
 
  (Increase) decrease in accounts receivable
(11,546
)
(3,095
)
(9,152
)
  (Increase) decrease in other assets
(774
)
(11,397
)
(2,842
)
Increase (decrease) in accounts payable and accrued expenses
5,574

11,416

18,330

  Increase (decrease) in other liabilities
(6,056
)
16,433

990

Net cash provided by (used in) operating activities
7,334

70,505

22,431

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures:
 
 
 
Development of oil and natural gas properties
(74,447
)
(38,445
)
(859
)
Purchases of other property and equipment
(11,305
)
(11,497
)
(2,299
)
Proceeds from sale of property, plant, equipment and other
3,377

234,823

25

Acquisition of properties

(259,444
)

Net cash used in investing activities
(82,375
)
(74,563
)
(3,133
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Repayments on new credit facility
(576,210
)
(11,800
)

Borrowings under new credit facility
197,210

390,800


IPO proceeds net of issuance costs
134,362



Repurchase of common stock
(23,712
)


Payment to preferred stockholders in conversion
(60,273
)


Issuance of 2026 Senior Unsecured Notes
400,000



Dividends paid on Series A preferred stock
(11,301
)


Purchase of treasury stock
(20,265
)


Shares withheld for payment of taxes on equity awards
(422
)


Debt issuance costs
(9,173
)
(22,049
)

Borrowings on emergence credit facility

51,000


Repayments on emergence credit facility

(451,000
)

Proceeds from sale of Series A preferred stock


335,000

Repayments on pre-emergence credit facility


(497,668
)
Net cash provided by (used in) financing activities
30,216

(43,049
)
(162,668
)
Net decrease in cash, cash equivalents and restricted cash
(44,825
)
(47,107
)
(143,370
)
Cash, cash equivalents and restricted cash:
 
 
 
Beginning
68,738

85,034

228,404

Ending
$
23,913

$
37,927

$
85,034


The accompanying notes are an integral part of these condensed consolidated financial statements.

5


BERRY PETROLEUM CORPORATION
Notes to Condensed Financial Statements (Unaudited)
Note 1 - Basis of Presentation
“Berry Corp.” refers to Berry Petroleum Corporation, a Delaware corporation which, on and after February 28, 2017 is the sole member of Berry Petroleum Company, LLC.
“Berry LLC” refers to Berry Petroleum Company, LLC, a Delaware limited liability company.
As the context may require, the “Company”, “we”, “our” or similar words refer to (i) Berry Corp. (the "Successor”) and Berry LLC, its consolidated subsidiary, as of and after February 28, 2017, as a whole or (ii) either Berry Corp. or Berry LLC on an individual basis as of and after February 28, 2017. References to historical activities of the “Company” prior to February 28, 2017, refer to activities of Berry LLC (the "Predecessor”).
“Linn Energy” refers to Linn Energy, LLC, a Delaware limited liability company of which Berry LLC was formerly a wholly-owned, indirect subsidiary and LinnCo, LLC (“LinnCo” and, together with Linn Energy, the “Linn Entities”).
Nature of Business
Berry Corp. is an independent oil and natural gas company that was incorporated under Delaware law on February 13, 2017. Berry Corp. operates through its wholly-owned subsidiary, Berry LLC. Our properties are located in the United States (“U.S.”), in California (in the San Joaquin and Ventura Basins), Utah (in the Uinta Basin), Colorado (in the Piceance Basin) and east Texas.
In July, we completed the initial public offering ("IPO") of our common stock and as a result, on July 26, 2018, our common stock began trading on the NASDAQ Global Select Market under the ticker symbol BRY.
Principles of Consolidation and Reporting
The information reported herein reflects all adjustments (consisting of normal recurring adjustments) that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations. The results reported in these unaudited condensed consolidated financial statements may not accurately forecast results for future periods. This report should be read in conjunction with the financial statements and notes in the Company's audited financial statements for the year ended December 31, 2017 presented in our final prospectus dated July 25, 2018 as filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on July 27, 2018 (the "prospectus").
The condensed consolidated financial statements have been prepared in conformity with GAAP and include the accounts of the Successor and its wholly owned subsidiary after February 28, 2017 and the accounts of the Predecessor prior to February 28, 2017. All significant intercompany transactions and balances have been eliminated upon consolidation. For oil and gas exploration and production joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements.
Bankruptcy Accounting
Upon emergence from bankruptcy on February 28, 2017, we adopted fresh start accounting which resulted in Berry Corp. becoming the financial reporting entity. As a result of the application of fresh start accounting and the effects of the implementation of the Plan (see Note 2 for definition), the condensed consolidated financial statements on or after February 28, 2017 are not comparable to the condensed consolidated financial statements prior to that date.
Use of Estimates
The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP required management of the Company to make informed estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.

6






As fair value is a market-based measurement, it was determined based on the assumptions that we believe market participants would use. We based these assumptions on management's best estimates and judgment. Management evaluates its assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, that management believes to be reasonable under the circumstances. Such assumptions are adjusted when management determines that facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates.
Estimates that are particularly significant to our financial statements include estimates of our reserves of oil and gas, future cash flows from oil and gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. In addition, as part of fresh-start accounting, we made estimates and assumptions related to our reorganization value, liabilities subject to compromise and the fair value of assets and liabilities recorded.
Accounting and Disclosure Changes
Recently Adopted Accounting Standards
In August 2018, the SEC issued a final rule requiring registrants to analyze and disclose changes in stockholders' equity in the form of a reconciliation for the current and comparative year-to-date interim periods with subtotals for each interim period. We adopted this rule in the quarter ended September 30, 2018 and modified our statements of equity accordingly.
In March 2016, the Financial Accounting Standards Board (“FASB”) issued rules to improve the accounting for share-based payment transactions. We early-adopted these rules retrospectively on April 1, 2018 and as a result are reporting cash paid to tax authorities when we withhold shares from an employee's award as a cash outflow for financing activities on the statement of cash flows. There was no change to the other financial statements as a result of adopting these rules.
In November 2016, the FASB issued rules intended to address the diversity in practice in classification and presentation of changes in restricted cash on the statement of cash flows. We adopted these rules retrospectively on January 1, 2018, as a result of which we included restricted cash amounts in our beginning and ending cash balances on the statement of cash flows and included a disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statement of cash flows.
New Accounting Standards Issued, But Not Yet Adopted
In February 2016, the FASB issued rules requiring lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers which is for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We expect the adoption of these rules to increase other assets and other liabilities on our balance sheet and do not expect a material impact on our consolidated results of operations.
During 2016, the FASB issued rules clarifying the new revenue recognition standard issued in 2014. The new rules are intended to improve and converge the financial reporting requirements for revenue from contracts with customers. We are an emerging growth company and have elected to delay adoption of these rules until they are applicable to non-SEC issuers which is for fiscal years beginning after December 31, 2018. We do not expect the adoption of these rules to materially change our reporting of revenue, however, we expect that certain amounts currently reported as expense will be reported as offsets to revenue.

7






Note 2 - Emergence from Voluntary Reorganization under Chapter 11
On May 11, 2016 our predecessor company filed bankruptcy. Our bankruptcy case was jointly administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et al., Case No. 16–60040 (the "Chapter 11 Proceeding"). On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter 11 Proceeding (the "Plan"). On February 28, 2017, the Effective Date occurred and the Plan became effective and was implemented. A final decree closing the Chapter 11 Proceeding was entered September 28, 2018, with the Court retaining jurisdiction as described in the confirmation order and without prejudice to the request of any party–in–interest to reopen the case including with respect to certain, immaterial remaining matters.
Reorganization Items, Net
We have incurred and continue to incur expenses associated with the reorganization. Reorganization items, net represent costs and gains directly associated with the Chapter 11 Proceeding, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined. The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations:
 
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Three Months
Ended
Three Months Ended
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
September 30, 2017
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands)
Return of undistributed funds from Cash Distribution Pool (1)
$
13,799

$

$
22,799

$

$

Refund of pre-emergence prepaid costs


579



Gain on resolution of pre-emergence liabilities


1,634



Linn Energy bankruptcy claim receipt
1,500


1,500



Gain on settlement of liabilities subject to compromise




421,774

Fresh start valuation adjustments




(920,699
)
Legal and other professional advisory fees
(713
)
(408
)
(2,515
)
(296
)
(19,481
)
Other
(805
)

(805
)
(705
)
10,686

Reorganization items, net
$
13,781

$
(408
)
$
23,192

$
(1,001
)
$
(507,720
)

 
 
 
 
 
(1)
Among other things, the holders of our Predecessor's Unsecured Notes (as defined below) received a right to their pro rata share of either 32,920,000 shares of common stock in Berry Corp. or, for those non-accredited investors holding our Predecessor's unsecured notes (the "Unsecured Notes") that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Cash Distribution Pool”).
Liabilities Subject to Compromise
Liabilities subject to compromise related to our 2017 emergence from bankruptcy decreased from approximately $35 million as of December 31, 2017 to approximately $0.1 million as of September 30, 2018. Activity for our liabilities subject to compromise for the nine months ended September 30, 2018 included the return of $23 million in undistributed funds from restricted cash and approximately $12 million in settlement payments to general unsecured creditors and other payments of professional fees incurred to settle these claims.


8






Note 3 - Debt
The following table summarizes our outstanding debt:
 
September 30, 2018
December 31, 2017
Interest Rate
Maturity
Security
 
(in thousands)
 
 
 
RBL Facility
$

$
379,000

variable rates of 4.5% (2018) and 4.8% (2017), respectively
June 29, 2022
Mortgage on 85% of Present Value of proven oil and gas reserves
2026 Notes
400,000


7.00%
February 15, 2026
Unsecured
Long-Term Debt - Principal Amount
400,000

379,000

 
 
 
Less: Debt Issuance Costs
(8,488
)

 
 
 
Long-Term Debt, net
$
391,512

$
379,000

 
 
 
At September 30, 2018 and December 31, 2017, debt issuance costs for the RBL Facility (as defined below) reported in "other noncurrent assets" on the balance sheet were approximately $17 million and $21 million net of amortization, respectively. The amortization of debt issuance costs is presented in interest expense on the condensed consolidated statements of operations.
Fair Value
Our debt is recorded at the carrying amount on the balance sheets. The carrying amount of the RBL Facility approximates fair value because the interest rates are variable and reflect market rates. The fair value of the 2026 senior unsecured notes was approximately $416 million at September 30, 2018.
Credit Facilities
On July 31, 2017, we entered into a credit agreement (“RBL Facility”), with Wells Fargo Bank, N.A. as administrative agent and certain lenders with up to $1.5 billion of commitments, subject to a reserves-based borrowing base. In connection with the issuance of the 2026 Notes (as defined below), the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25% of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination which reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the RBL Facility to $575 million with lender approval.
As of September 30, 2018, the financial performance covenants under our RBL Facility were (i) a leverage ratio of no more than 4.00 to 1.00 and (ii) a current ratio of at least 1.00 to 1.00. At September 30, 2018, our actual ratios were 1.85 to 1.00 and 4.21 to 1.00, respectively. In addition, the RBL Facility currently provides that to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. We were in compliance with all financial covenants as of September 30, 2018.
As of September 30, 2018, we had approximately $393 million of available borrowing capacity under the RBL Facility.
As of September 30, 2018 and December 31, 2017, we had letters of credit outstanding of approximately $7 million and $21 million, respectively, under our RBL facility. These letters of credit were issued to support ordinary course of business marketing, insurance, regulatory and other matters.
In July and August 2018, we paid down approximately $105 million on the RBL Facility from the net proceeds we received in the IPO of our common stock (see Note 6).
Senior Unsecured Notes Offering
In February 2018, we completed a private issuance of $400 million in aggregate principal amount of 7.00% senior unsecured notes due 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately $391 million after deducting expenses

9






and the initial purchasers’ discount. We used a portion of the net proceeds from the issuance of the 2026 Notes to repay borrowings under the RBL Facility and used the remainder for general corporate purposes.
Note 4 - Derivatives
We have hedged a portion of our forecasted oil production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices and we target covering our operating expenses and fixed charges, including maintenance capital expenditures, for up to two years out. We have hedged a portion of our exposure to differentials between Intercontinental Exchange ("ICE") Brent oil ("Brent") and New York Mercantile Exchange ("NYMEX") West Texas Intermediate oil ("WTI") as well. From time to time we have entered into agreements to purchase a portion of the natural gas we require for our operations that we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions.
Our current hedge positions primarily consist of swap contracts and deferred premium purchased put options. In addition, we recently acquired natural gas fixed price swaps to manage our exposure to increases in natural gas prices. We enter into these transactions with respect to a portion of our projected oil production and gas purchases to provide economic hedges against the risk related to the future commodity prices. We do not enter into derivative contracts for speculative trading purposes. We did not designate any of our contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. Gains (losses) on oil hedges are classified in the revenues and other section of the statement of operations and gains (losses) on natural gas hedges are presented in the expenses and other section of the statement of operations.
As of September 30, 2018, we have hedged crude oil production at the following approximate volumes and prices: 12.8 MBbl/d at $75 in the fourth quarter of 2018, 16.5 MBbl/d at $70 in 2019, and 1.2 MBbl/d at $65 in 2020, as outlined along with our natural gas derivative contracts in the following table:
 
Q4 2018
FY 2019
FY 2020
Sold Oil Calls (ICE Brent):
 
 
 
  Hedged volume (MBbls)
124



  Weighted-average price ($/Bbl)
$
80.00

$

$

Purchased Oil Put Options (ICE Brent):
 
 
 
  Hedged volume (MBbls)

3,385

455

  Weighted-average price ($/Bbl)
$

$
65.00

$
65.00

Fixed Price Oil Swaps (ICE Brent):
 
 
 
  Hedged volume (MBbls)
1,058

2,640


  Weighted-average price ($/Bbl)
$
74.82

$
75.40

$

Oil basis differential positions:
 
 
 
ICE Brent-NYMEX WTI basis swaps
 
 
 
  Hedged volume (MBbls)
92

182.5


  Weighted-average price ($/Bbl)
$
1.29

$
1.29

$

Fixed Price Gas Swaps (Kern, Delivered):
 
 
 
  Hedged volume (MMBtu)
1,380,000

4,560,000


  Weighted-average price ($/MMBtu)
$
2.65

$
2.65

$

We earn a premium on our sold oil calls at the time of sale. We make net settlement payments for prices above the indicated weighted-average price per barrel of Brent. If the calls expire unexercised, we make no payments.
For our purchased puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel of Brent. The purchased put options contain deferred premiums of approximately $20 million and are reflected in the mark-to-market valuation of the derivatives on the balance sheet at September 30, 2018. The premiums will be payable in conjunction with the monthly settlements of these contracts and thus have been deferred until payments begin in 2019.
For fixed-price Brent swaps, we make settlement payments for prices above the indicated weighted-average price per barrel of Brent and receive settlement payments for prices below the indicated weighted-average price per barrel of Brent.

10






For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the indicated weighted-average price per barrel of our contracts and receive settlement payments if the difference between Brent and WTI is below the indicated weighted-average price per barrel.
For fixed-price natural gas swaps, we are the buyer so we make settlement payments for prices below the weighted-average price per MMBtu and receive settlement payments for prices above the weighted-average price per MMBtu.
 Our commodity derivatives are measured at fair value using industry-standard models with various inputs including forward prices, and all are classified as Level 2 in the required fair value hierarchy for the periods presented. The following tables present the fair values (gross and net) of our outstanding derivatives as of September 30, 2018 and December 31, 2017:
 
Berry Corp. (Successor)
 
September 30, 2018
 
Balance Sheet
Classification
Gross Amounts
Recognized at
Fair Value
Gross Amounts
Offset in the
Balance Sheet
Net Fair Value
Presented in the
Balance Sheet
 
(in thousands)
Liabilities
 
 
 
 
  Commodity Contracts
Current liabilities
$
(26,409
)
$

$
(26,409
)
  Commodity Contracts
Non-current liabilities
(4,664
)

(4,664
)
Total derivatives
 
$
(31,073
)
$

$
(31,073
)

 
Berry Corp. (Successor)
 
December 31, 2017
 
Balance Sheet
Classification
Gross Amounts
Recognized at
Fair Value
Gross Amounts
Offset in the
Balance Sheet
Net Fair Value
Presented in the
Balance Sheet
 
(in thousands)
Liabilities
 
 
 
 
  Commodity Contracts
Current liabilities
$
(49,949
)
$

$
(49,949
)
  Commodity Contracts
Non-current liabilities
(25,332
)

(25,332
)
Total derivatives
 
$
(75,281
)
$

$
(75,281
)
In May 2018, we elected to terminate outstanding commodity derivative contracts for all WTI oil swaps and certain WTI/Brent basis swaps for July 2018 through December 2019 and all WTI oil sold call options for July 2018 through June 2020. Termination costs totaled approximately $127 million and were calculated in accordance with a bilateral agreement on the cost of elective termination included in these derivative contracts; the present value of the contracts using the forward price curve as of the date termination was elected. No penalties were charged as a result of the elective termination. Concurrently, Berry Corp. entered into commodity derivative contracts consisting of Brent oil swaps for July 2018 through March 2019 and Brent oil purchased put options for January 2019 through March 2020. These Brent oil swaps hedge 1.8 MMBbls in 2018 and 0.9 MMBbls in 2019 at a weighted-average price of $75.66. These Brent oil purchased put options provide a weighted-average price floor of $65.00 for 2.8 MMBbls in 2019 and 0.5 MMBbls in 2020. We effected these transactions to move from a WTI-based position to a Brent-based position as well as bring our hedge pricing more in line with market pricing at the time.


11






Note 5 - Lawsuits, Claims, Commitments and Contingencies
In the normal course of business, we, or our subsidiary, are subject to lawsuits, environmental and other claims and other contingencies that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.
On May 11, 2016 our predecessor company filed the Chapter 11 Proceeding. Our bankruptcy case was jointly administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et al., Case No. 16-60040. On January 27, 2017, the Bankruptcy Court approved and confirmed the Plan. On February 28, 2017, the Effective Date occurred and the Plan became effective and was implemented. A final decree closing the Chapter 11 Proceeding was entered September 28, 2018, with the Court retaining jurisdiction as described in the confirmation order and without prejudice to the request of any party-in-interest to reopen the case including with respect to certain, immaterial remaining matters.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at September 30, 2018 and December 31, 2017. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.
We have certain commitments under contracts, including purchase commitments for goods and services. At September 30, 2018, purchase obligations of approximately $10 million included a commitment to invest at least $9 million to construct a new access road in connection with our Piceance assets or provide access to an existing road or to pay 50% of the difference between $12 million and the actual amount spent on such access road construction prior to the end of 2019. If we do not obtain extensions for the road obligation, provide access to an existing road or construct a new access road, we may trigger the payment obligation which, if we were unable to negotiate resolution, would reduce our capital available for investment. Also, as of September 30, 2018, we had entered into agreements to purchase natural gas for our operations in 2018 for approximately $4 million.
We, or our subsidiary, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of September 30, 2018, we are not aware of material indemnity claims pending or threatened against us.
We have entered into operating lease agreements mainly for office space. Lease payments are generally expensed as part of general and administrative expenses. At September 30, 2018, future net minimum lease payments for non-cancelable operating leases (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance and maintenance expense) totaled:
 
Amount
 
(in thousands)
2018
$
362

2019
1,290

2020
316

2021
321

2022
326

Thereafter
229

Total minimum lease payments
$
2,844

 
 

12






Note 6 - Equity
Initial Public Offering of Common Stock
In July, we completed our IPO and as a result, on July 26, 2018, our common stock began trading on the NASDAQ Global Select Market under the ticker symbol BRY. The Company received approximately $111 million of net proceeds for the 8,695,653 shares of common stock issued for our benefit in the IPO, net of the shares sold for the benefit of the Company's stockholders. The shares sold to the public at $14.00 per share. The Company received the net proceeds from the IPO after deducting underwriting discounts and offering expenses payable by us, and the proceeds from the sale of the shares for the benefit of our stockholders. See "Use of IPO proceeds" below for additional information.
In connection with the IPO, each of the 37.7 million shares of our Series A Preferred Stock was automatically converted into 1.05 shares of our common stock or 39.6 million shares in aggregate and the right to receive a cash payment of $1.75 ("Series A Preferred Stock Conversion"). The cash payment was reduced in respect of any cash dividend paid by the Company on such share of Series A Preferred Stock for any period commencing on or after April 1, 2018. Because we paid the second quarter preferred dividend of $0.15 per share in June, the cash payment for the conversion was reduced to $1.60 per share, or approximately $60 million. The additional 1.9 million common shares received by the preferred stockholders in the conversion were assigned a value of $14.00 per share in the IPO. This approximate $27 million value and the $60 million conversion cash payment reduced the income available to common stockholders by approximately $87 million for the three months ended September 30, 2018.
Shares Issued and Outstanding
As of September 30, 2018, there were 81,364,933 shares of common stock issued and outstanding including 210,400 common shares outstanding as a result of awards that have vested as of September 30, 2018 under the Company's Omnibus Incentive Plan. An additional 1,396,000 unvested restricted stock units and performance restricted stock units were outstanding under the Company's Omnibus Incentive Plan as of September 30, 2018. A further 7,080,000 common shares have been reserved for issuance to the general unsecured creditor group pending resolution of disputed claims.
In March 2018, the board of directors approved a cumulative paid-in-kind dividend on the Series A Preferred Stock for the periods through December 31, 2017. The cumulative dividend was 0.050907 per share and approximately 1,825,000 shares in total. Also in March 2018, the board approved a $0.158 per share, or approximately $5.6 million, cash dividend on the Series A Preferred Stock for the quarter ended March 31, 2018. In both cases, the payments were to stockholders of record as of March 15, 2018. In May 2018, the board of directors approved a $0.15 per share, or approximately $5.6 million cash dividend, on the Series A Preferred Stock for the quarter ended June 30, 2018. The payment was to stockholders of record as of June 7, 2018. As described above, in July 2018, all shares of our Series A Preferred Stock, approximately 37.7 million in total, were converted to approximately 39.6 million common shares and, as a result, there were no shares of our Series A Preferred Stock outstanding following the IPO.
On August 21, 2018, our board of directors approved a $0.12 per share quarterly cash dividend on our common stock on a pro-rata basis from the date of our IPO through September 30, 2018, which resulted in a payment of $0.09 per share in October 2018. On November 7, 2018, our board of directors approved a $0.12 per share quarterly cash dividend on our common stock for the fourth quarter.
Treasury Stock Purchase
In 2018, we entered into several settlement agreements with general unsecured creditors from our bankruptcy process. As a result, we paid approximately $20 million to purchase their claims to our common stock that we have reflected as treasury stock. The Plan required that we reserve 7,080,000 shares of our common stock to settle claims of unsecured creditors (the "Unsecured Claims"). We do not yet know the final amount of shares we will issue under these provisions. When all Unsecured Claims are settled, we will be able to assign a share count to the treasury stock. See Note 2 under "Plan of Reorganization" and Note 11 for further discussion of the common shares set aside to settle claims.

13






Stock-Based Compensation
In July 2018, we became a public company and our stock began trading on the NASDAQ Global Select Market. As a result, the fair value of our common stock underlying our stock-based compensation awards granted will no longer be based on complex models using inputs and assumptions, but will be based on the price of our stock at the date of grant.
On June 27, 2018, our board of directors adopted the Berry Petroleum Corporation 2017 Omnibus Incentive Plan, as amended and restated (our “Restated Incentive Plan”). This plan constitutes an amendment and restatement of the plan (the "Prior Plan") as in effect immediately prior to the adoption of the Restated Incentive Plan. The Prior Plan constituted an amendment and restatement of the plan originally adopted as of June 15, 2017 (the "2017 Plan"). The Restated Incentive Plan provides for the grant, from time to time, at the discretion of the board of directors or a committee thereof, of stock options, stock appreciation rights ("SARs"), restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards. The maximum number of shares of common stock that may be issued pursuant to an award under the Restated Incentive Plan is 10,000,000 inclusive of the number of shares of common stock previously issued pursuant to awards granted under the Prior Plan or the 2017 Plan. The maximum number of shares remaining that may be issued is approximately 8.4 million as of September 30, 2018.
Included in lease operating expenses and general and administrative expenses is stock-based compensation expense of $0.1 million and $1.1 million, respectively, for the three months ended September 30, 2018, and $0.1 million and $3.4 million, respectively, for the nine months ended September 30, 2018. For the three and nine months ended September 30, 2017, including the successor and predecessor periods, stock compensation expense included in lease operating expenses and general and administrative expenses was none and $0.9 million, respectively. For the nine months ended September 30, 2018, stock-based compensation had an income tax benefit of approximately $0.6 million.
The table below summarizes the activity relating to restricted stock units ("RSUs") issued under the 2017 Plan during the nine months ended September 30, 2018. The RSUs vest ratably over three years. Unrecognized compensation cost associated with the RSUs at September 30, 2018 is approximately $6.2 million which will be recognized over a weighted-average period of approximately two years.
 
Number of
shares
Weighted-average Grant Date Fair Value
 
(shares in thousands)
December 31, 2017
683

$
10.12

Granted
217

$
11.81

Vested
(210
)
$
10.12

Forfeited
(32
)
$
10.35

September 30, 2018
658

$
10.67

The table below summarizes the activity relating to the performance-based restricted stock units ("PRSUs") issued under the 2017 Plan during the nine months ended September 30, 2018. The PRSUs vest if the Company's stock price reaches certain levels over defined periods of time. Unrecognized compensation cost associated with the PRSUs at September 30, 2018 is approximately $3.4 million which will be recognized over a weighted-average period of approximately two years.
 
Number of
shares
Weighted-average Grant Date Fair Value
 
(shares in thousands)
December 31, 2017
622

$
7.09

Granted
132

$
7.65

Vested

$

Forfeited
(16
)
$
7.25

September 30, 2018
738

$
7.19


In October 2018, approximately 454,000 PRSUs under the Restated Incentive Plan vested.

14






Use of IPO Proceeds
Of the approximately $111 million of net proceeds received by us in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility. This included the $60 million we borrowed on the RBL Facility to make the payment due to the holders of our Series A Preferred Stock in connection with the conversion of preferred stock to common stock. We used the remainder for general corporate purposes.
In connection with the IPO, on July 17, 2018, the Company entered into stock purchase agreements with certain funds affiliated with Oaktree Capital Management and Benefit Street Partners, pursuant to which we purchased an aggregate of 410,229 and 1,391,967 shares of our common stock, respectively, or 1,802,196 in total. We simultaneously received $24 million for selling 1,802,196 shares and paid $24 million to purchase 1,802,196 shares under the stock purchase agreements. We purchased the shares immediately following the closing of the IPO and retired and returned them to the status of authorized but unissued shares.
The selling shareholders also directly sold an additional 2,545,630 shares at a price of $14.00 per share for which we did not receive any proceeds.
Note 7 - Income Taxes
Prior to the Effective Date, Berry LLC was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, Berry LLC was not a taxable entity, it did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of Berry LLC. Upon emergence from bankruptcy, Berry Corp. acquired the assets of Berry LLC in a taxable asset acquisition as part of the restructuring. Consequently, we are now taxed as a corporation and have no net operating loss carryforwards for the periods prior to February 28, 2017.
 On December 22, 2017, the U.S. Tax Cuts and Jobs Act (the “Act”) made significant changes to the Internal Revenue Code of 1986, including lowering the maximum federal corporate rate from 35% to 21% and imposing limitations on the use of net operating losses arising in taxable years ending after December 31, 2017.  This was the key contributor to the decrease in our effective rate from 40% in the 2017 Successor periods to 17% in each of the three and nine months ended September 30, 2018.  We anticipate earnings for fiscal year 2018, in part due to the termination and resetting of our hedge positions in May 2018. These earnings consequently allow for the release of our valuation allowance, described below, resulting in an effective tax rate less than the maximum federal and applicable state tax rate for the nine months ended September 30, 2018. There were no current income taxes during the nine months ended September 30, 2018.
Our accounting for the U.S. Tax Reform Act is incomplete. As noted at year-end, however, we were able to reasonably estimate certain effects and, therefore, recorded provisional adjustments to income tax expense for the revaluation of deferred tax assets and liabilities from 35% to 21% associated with the reduction in the U.S. corporate income tax rate, and for a valuation allowance on certain deferred tax assets impacted by the Act. We have not revised any of the 2017 provisional estimates. Any subsequent adjustments to these amounts will be recorded to income tax expense in the fourth quarter of 2018 after analysis of the filed 2017 income tax return is complete.
Note 8 - Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows
Other current assets reported on the condensed consolidated balance sheets included the following:  
 
Berry Corp. (Successor)
 
September 30, 2018
December 31, 2017
 
(in thousands)
Prepaid expenses
$
4,945

$
6,901

Oil inventories, materials and supplies
7,060

5,938

Other
1,228

1,227

Total
$
13,233

$
14,066


15






The major classes of inventory were not material and therefore not stated separately. Other non-current assets at September 30, 2018 and December 31, 2017, included approximately $17 million and $20 million of deferred financing costs, net of amortization, respectively.
Accounts payable and accrued expenses on the condensed consolidated balance sheets included the following:
 
Berry Corp. (Successor)
 
September 30, 2018
December 31, 2017
 
(in thousands)
Accounts payable-trade
$
10,483

$
15,469

Accrued expenses
54,969

34,359

Royalties payable
26,004

25,793

Greenhouse gas liability
4,364

10,446

Taxes other than income tax liability
11,021

8,437

Accrued interest
3,529


Dividends payable
7,431


Other

3,373

Total
$
117,801

$
97,877

Other non-current liabilities at September 30, 2018 included approximately $12 million of greenhouse gas liability.
Supplemental Cash Flow Information
Supplemental disclosures to the statements of cash flows are presented below:
 
Berry Corp.
Berry LLC
 
(Successor)
(Predecessor)
 
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
 
 
(Decrease) increase in accrued liabilities related to purchases of property and equipment
$
8,832

$
1,008

$
2,249

Supplemental Disclosures of Cash Payments/(Receipts):
 
 
 
  Interest
$
19,199

$
9,987

$
8,057

  Income taxes
$

$
1,994

$

  Reorganization items, net
$
1,007

$
(375
)
$
11,838


16






The following table provides a reconciliation of Cash, Cash Equivalents and Restricted Cash as reported in the Consolidated Statements of Cash Flows to the line items within the Consolidated Balance Sheets:
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Nine months ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands)
Beginning of Period
 
 
 
Cash and cash equivalents
$
33,905

$
32,049

$
30,483

Restricted cash
34,833

52,860

197,793

Restricted cash in other noncurrent assets

125

128

Cash, cash equivalents and restricted cash
$
68,738

$
85,034

$
228,404

 
 
 
 
Ending of Period
 
 
 
Cash and cash equivalents
$
23,856

$
2,927

$
32,049

Restricted cash
57

35,000

52,860

Restricted cash in other noncurrent assets


125

Cash, cash equivalents and restricted cash
$
23,913

$
37,927

$
85,034

Restricted cash is associated with cash reserved to settle claims with general unsecured creditors resulting from implementation of the Plan. Cash and cash equivalents consists primarily of highly liquid investments with original maturities of three months or less and are stated at cost, which approximates fair value.
Note 9 - Certain Relationships and Related Party Transactions
In connection with our emergence from bankruptcy, we entered into agreements with certain of our affiliates and with parties who received shares of our common stock and Series A Preferred Stock in exchange for their claims. See Note 6 - Equity for further details.
Transition Services and Separation Agreement (“TSSA”)
On the Effective Date, Berry LLC entered into the TSSA with Linn Energy and certain of its subsidiaries to facilitate the separation of Berry LLC’s operations from Linn Energy’s operations. Under the TSSA, Berry LLC reimbursed Linn Energy for third-party out-of-pocket costs and expenses actually incurred by Linn Energy in connection with providing certain transition services. Additionally, Berry LLC paid to Linn Energy a management fee equal to $6 million per month, prorated for partial months, during the period from the Effective Date through the last day of the second full calendar month after the Effective Date (the “Transition Period”) and $2.7 million per month, prorated for partial months, from the first day following the Transition Period through the last day of the second full calendar month thereafter (the “Accounting Period”). During the Accounting Period, the scope of the transition services was reduced to specified accounting and administrative services. The Transition Period under the TSSA ended April 30, 2017, and the Accounting Period ended June 30, 2017. For the seven months ended September 30, 2017, we incurred management fee expenses of approximately $17 million under the TSSA. Since the agreement commenced on the Effective Date, no expenses were incurred for the period ended February 28, 2017.
Note 10 - Acquisitions and Divestitures
Chevron North Midway-Sunset Acquisition
In April 2018, we acquired two leases from a third party on an aggregate of 214 acres and a lease option on 490 acres (the "Chevron North Midway-Sunset Acquisition") of land owned by Chevron U.S.A. in the north Midway-Sunset field immediately adjacent to assets we currently operate. We assumed a drilling commitment of approximately $34.5 million to drill 115 wells on or before April 1, 2020. We have not drilled any of these wells as of September 30, 2018. We extended the commitment to April

17






1, 2022. We would assume an additional 40 well drilling commitment if we exercise our option on the 490 acres. We paid no other consideration for the acquisition. Our drilling commitment will be tolled for a month for each consecutive 30-day period for which the posted price of WTI is less than $45 per barrel. This transaction is consistent with our business strategy to investigate areas beyond our known productive areas.
Disposition of East Texas Properties
On October 17, 2018, we signed an agreement to sell our non-core oil and gas properties and related assets located in the East Texas Basin for approximately $7 million. Production comprised approximately 0.7 MBoe per day of natural gas in the third quarter of 2018. We anticipate closing this sale in the fourth quarter of 2018.
Note 11 - Earnings Per Share
The Predecessor was organized as a limited liability company and, as such, did not issue any stock. Accordingly, we have not presented earnings per share calculations for the predecessor company periods.
We calculate basic earnings (loss) per share by dividing net income (loss) available to common stockholders by the weighted-average number of common shares outstanding during each period. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, such as those shares contemplated by the Plan, are considered common shares outstanding and are included in the computation of net income (loss) per share. Accordingly, the 40 million shares of common stock contemplated by the Plan, without regard to actual issuance dates, were included in the computation of net income (loss) per share for the three and nine months ended September 30, 2018, and the three and seven months ended September 30, 2017. The Plan required that we reserve 7,080,000 shares of our common stock to settle claims of unsecured creditors. The final amount of shares we will issue under these provisions cannot be known until all claims are settled, adjustments have been made based on the stock to be received by Unsecured Claims including those of holders of Unsecured Notes. However, while we do not yet know the final amount of shares that we will issue to third parties, we entered into agreements in 2018 that have materially reduced that number. The 40 million shares above will be reduced to the extent we issue fewer than 7,080,000 shares.
The Series A Preferred Stock was not a participating security, therefore, we calculated diluted EPS using the “if-converted" method under which the preferred dividends are added back to the numerator and the convertible preferred stock is assumed to be converted at the beginning of the period. No incremental shares of Series A Preferred Stock or RSUs were included in the diluted EPS calculation for the three and nine months ended September 30, 2018, nor the three months ended September 30, 2017 as their effect was anti-dilutive under the “if-converted” method. No PRSU's were included in the EPS calculations for any of the periods presented due to their contingent nature.
In July 2018, all outstanding shares of our Series A Preferred Stock were converted to common shares in connection with the IPO of our common stock (see Note 6). The conversion was characterized as an induced conversion that required a deduction in our EPS calculation, from net income, of approximately $87 million in determining income available to common stockholders. This deduction represents the excess of fair value of the total consideration given to preferred stockholders in the transaction over the fair value of the common stock issuable under the original conversion terms. Included in the $87 million is a $60 million cash payment and approximately $27 million of value from the 1.9 million additional common shares received by preferred stockholders as a result of the automatic conversion that occurred in conjunction with our IPO.

18






 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
 
Three Months Ended
Three Months Ended
 
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
September 30, 2017
 
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands except per share amounts)
Basic EPS calculation


 



Net income (loss)
$
36,985

$
(9,684
)
 
$
15,334

13,812

n/a
less: Series A preferred stock dividends and conversion to common stock
(86,642
)
(5,485
)
 
(97,942
)
(12,681
)
n/a
Net income (loss) available to common stockholders
$
(49,657
)
$
(15,169
)
 
$
(82,608
)
$
1,131

n/a
Weighted-average shares of common stock outstanding
68,131

32,920

 
44,820

32,920

n/a
Shares of common stock distributable to holders of Unsecured Claims
7,080

7,080

 
7,080

7,080

n/a
Weighted-average common shares outstanding-basic
75,211

40,000

 
51,900

40,000

n/a
Basic Earnings (loss) per share (2)
$
(0.66
)
$
(0.38
)
 
$
(1.59
)
$
0.03

n/a
Diluted EPS calculation


 
 
 
 
Net income (loss)
$
36,985

$
(9,684
)
 
$
15,334

$
13,812

n/a
less: Series A preferred stock dividends and conversion to common stock
(86,642
)
(5,485
)
 
(97,942
)
(12,681
)
n/a
Net income (loss) available to common stockholders
$
(49,657
)
$
(15,169
)
 
$
(82,608
)
$
1,131

n/a
Weighted-average shares of common stock outstanding
68,131

32,920

 
44,820

32,920

n/a
Shares of common stock distributable to holders of Unsecured Claims
7,080

7,080

 
7,080

7,080

n/a
Weighted-average common shares outstanding-basic
75,211

40,000

 
51,900

40,000

n/a
Dilutive effect of potentially dilutive securities (1)
$

$

 
$

$
602

n/a
Weighted-average common shares outstanding-diluted
75,211

40,000

 
51,900

40,602

n/a
Diluted Earnings (loss) per share (2)
$
(0.66
)
$
(0.38
)
 
$
(1.59
)
$
0.03

n/a
 
 
 
 
 
(1)
No potentially dilutive securities were included in computing earnings (loss) per share for the three and nine months ended September 30, 2018 and for the three months ended September 30, 2017 because the effect of inclusion would have been anti-dilutive.
(2)
Per share amounts are stated net of tax.




19


Item 2.
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes presented in this Quarterly Report on form 10-Q, as well as our audited consolidated financial statements for the year ended December 31, 2017 included in the prospectus. When we use the terms “we,” “us,” “our,” the “Company” or similar words, unless the context otherwise requires, on or prior to the Effective Date (see below), we are referring to Berry LLC, our predecessor company and following February 28, 2017, the effective date ("Effective Date") of the Amended Joint Chapter 11 Plan of Linn Acquisition Company, LLC and us, we are referring to Berry Corp. and its subsidiary, Berry LLC, together, the successor company, as applicable.
Our Company
We are a California-based independent upstream energy company engaged primarily in the development and production of conventional oil reserves located onshore in the western United States. Our long-lived, predictable and high margin asset base is uniquely positioned to support our objectives of generating top-tier corporate-level returns and positive free cash flow through commodity price cycles. We believe that executing our strategy across our low-declining production base and extensive inventory of identified drilling locations will result in long-term, capital efficient production growth as well as the ability to return excess free cash flow to stockholders.

We target onshore, low-cost, low-risk, oil-rich reservoirs in the San Joaquin basin of California and the Uinta basin of Utah, and, to a lesser extent, the low geologic risk natural gas resource play in the Piceance basin in Colorado. In the aggregate, the Company’s assets are characterized by:

• high oil content, which makes up more than 80% of our production;
• favorable Brent-influenced crude oil pricing dynamics;
• long-lived reserves with low and predictable production decline rates;
• stable and predictable development and production cost structures;
• a large inventory of low-risk identified development drilling opportunities with attractive full-cycle economics; and
• potential in-basin organic and strategic opportunities to expand our existing inventory with new locations of
substantially similar geology and economics.

California is and has been one of the most productive oil and natural gas regions in the world. Our asset base is concentrated in the oil-rich San Joaquin basin in California, which has more than 100 years of production history and substantial remaining oil in place. As a result of these attributes, we have a strong understanding of many of the basin’s geologic and reservoir characteristics, leading to predictable, repeatable, low-risk development opportunities.

In California, we focus on conventional, shallow reservoirs, the drilling and completion of which are relatively low-cost in contrast to modern unconventional resource plays. Our decades-old proven completion techniques in these reservoirs include steamflood and low-volume fracture stimulation.

We own additional assets in the Uinta basin in Utah, a stacked, multi-bench, light-oil-prone play with significant undeveloped resources where we have high operational control and additional behind pipe potential, as well as in the Piceance basin in Colorado, a prolific low geologic risk natural gas play where we produce from a conventional, tight sandstone reservoir using proven slick water fracture stimulation techniques to increase recoveries.

Using SEC Pricing as of December 31, 2017, we had estimated total proved reserves of 141,384 MBoe. For the three months ended September 30, 2018, we had average production of approximately 27.4 MBoe/d, of which approximately 81% was oil. In California, our average production for the three months ended September 30, 2018 was 19.5 MBoe/d, of which approximately 100% was oil.
How We Plan and Evaluate Operations

We use levered free cash flow to plan our capital allocation for maintenance and internal growth opportunities as well as hedging needs. We define levered free cash flow as Adjusted EBITDA less capital expenditures, interest expense and dividends.


20


We use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA; (b) operating expenses; (c) environmental, health & safety (“EH&S”) results; (d) taxes, other than income taxes; (e) general and administrative expenses; and (f) production.

Adjusted EBITDA
Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business. We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, amortization and accretion; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items.

Operating expenses
We define operating expenses as lease operating expenses, electricity expenses, transportation expenses, and marketing expenses, offset by the third-party revenues generated by electricity, transportation and marketing activities, as well as the effect of cash received or paid for gas purchase derivatives. Taxes other than income taxes are excluded from operating expenses. The electricity, transportation and marketing activity related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the economics of development projects and the efficiency of our hydrocarbon recovery. Overall, operating expense is used by management as a measure of the efficiency with which operations are performing.

Environmental, health & safety
We are committed to good corporate citizenship in our communities, operating safely and protecting the environment and our employees. We monitor our EH&S performance through various measures, holding our employees and contractors to high standards. Meeting corporate EH&S metrics is a part of our incentive programs for all employees.

Taxes, other than income taxes
Taxes, other than income taxes includes severance taxes, ad valorem and property taxes, greenhouse gas (GHG) allowances, and other taxes not based on income. We include these taxes when analyzing the economics of development projects and the efficiency of our hydrocarbon recovery; however, we do not include these taxes in our operating expenses.

General and administrative expenses
We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities. Such expenses are a key component of the appropriate level of support our corporate and professional team provides to the development of our assets and our day-to-day operations.

Production
Oil and gas production is a key driver of our operating performance, an important factor to the success of our business, and used in forecasting future development economics. We measure and closely monitor production on a continuous basis, adjusting our property development efforts in accordance with the results. We track production by commodity type and compare it to prior periods and expected results.

Emergence from Chapter 11 Bankruptcy

On February 28, 2017, Berry LLC emerged from bankruptcy as a stand-alone company and wholly-owned subsidiary of Berry Corp. with new management, a new board of directors and new ownership. Through the Chapter 11 Proceedings, the Company significantly improved its financial position from that of Berry LLC while it was owned by the Linn Entities. A final decree closing the Chapter 11 Proceeding was entered September 28, 2018, with the Court retaining jurisdiction as described in the confirmation order and without prejudice to the request of any party-in-interest to reopen the case including with respect to certain, immaterial remaining matters.


21


Non-GAAP Financial Measures

Adjusted EBITDA, Levered Free Cash Flow and Adjusted Net Income (Loss)
Adjusted EBITDA and Adjusted Net Income (Loss) are not measures of net income (loss) and Levered Free Cash Flow is not a measure of cash flow, in all cases, as determined by GAAP. Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.

Adjusted Net Income (Loss) excludes the impact of unusual, out-of-period and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items and the income tax expense or benefit of these adjustments using our effective tax rate.

We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, amortization and accretion; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends.

Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. Levered Free Cash Flow is used by management as a primary metric to plan capital allocation for maintenance and internal growth opportunities, as well as hedging needs. It also serves as a measure for assessing our financial performance and our ability to generate excess cash from operations to service debt and pay dividends.

While Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

Adjusted General and Administrative Expenses
Adjusted General and Administrative Expenses is a supplemental non-GAAP financial measure that is used by management. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-recurring restructuring and other costs and non-cash stock compensation expense. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period.

We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature. Adjusted General and Administrative Expenses should not be considered as an alternative to, or more meaningful than, general and administrative expenses as determined in accordance with GAAP. Our computations of Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures of other companies.


22


The following tables present reconciliations of the non-GAAP financial measures Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow to the GAAP financial measures of net income (loss) and net cash provided or used by operating activities, as applicable, for each of the periods indicated.
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
 
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
June 30, 2018
September 30, 2017
 
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)
$
36,985

$
(28,061
)
$
(9,684
)
 
$
15,334

$
13,812

$
(502,964
)
Add (Subtract):
 
 
 
 
 
 
 
Interest expense
9,877

9,155

5,882

 
26,828

12,482

8,245

Income tax expense (benefit)
7,683

(5,476
)
(6,246
)
 
3,145

9,190

230

Depreciation, depletion, amortization and accretion
21,729

21,859

20,822

 
62,017

48,392

28,149

Derivative (gain) loss
17,115

78,143

42,443

 
129,902

(5,642
)
(12,886
)
Net cash received (paid) for scheduled derivative settlements
(1,052
)
(28,261
)
4,045

 
(47,161
)
9,902

534

(Gain) loss on sale of assets and other
400

123

(20,692
)
 
522

(20,687
)
(183
)
Stock compensation expense
1,182

1,278

902

 
3,502

902


Non-recurring restructuring and other costs
1,598

1,714

2,979

 
5,359

27,421


Reorganization items, net
(13,781
)
(456
)
408

 
(23,192
)
1,001

507,720

Adjusted EBITDA (1)
81,736

50,018

40,859

 
176,256

96,773

28,845

 
 
 
 
 
(1)
Adjusted EBITDA includes cash paid for scheduled derivative settlements of $1 million for the three months ended September 30, 2018, $28 million for the three months ended June 30, 2018, and $47 million for the nine months ended September 30, 2018; and includes cash received for scheduled derivative settlements of $4 million for the three months ended September 30, 2017, $10 million for the seven months ended September 30, 2017, and $1 million for the two months ended February 28, 2017.

23


 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
 
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
June 30, 2018
September 30, 2017
 
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands)
Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided (used) by operating activities:
Net cash provided (used) by operating activities
$
56,880

$
(77,394
)
$
25,568

 
$
7,334

$
70,505

$
22,431

Add (Subtract):
 
 
 
 
 
 
 
Cash interest payments
15,902

644

4,726

 
19,199

9,987

8,057

Cash income tax payments


826

 

1,994


Cash reorganization item (receipts) payments
(345
)
1,047

417

 
1,007

(375
)
11,838

Non-recurring restructuring and other costs
1,598

1,714

2,979

 
5,359

27,421


Derivative early termination payment

126,949


 
126,949



Other changes in operating assets and liabilities
7,701

(2,942
)
6,343

 
16,408

(12,759
)
(13,323
)
Other, net



 


(158
)
Adjusted EBITDA
81,736

50,018

40,859

 
176,256

96,773

28,845

Subtract:
 
 
 
 
 
 
 
Capital expenditures - accrual basis
(40,243
)
(38,531
)
(16,902
)
 
(94,505
)
(50,953
)
(5,406
)
Interest expense
(9,877
)
(9,155
)
(5,882
)
 
(26,828
)
(12,482
)
(8,245
)
Cash dividends declared
(7,431
)
(5,651
)

 
(18,732
)


Levered Free Cash Flow (1)
24,185

(3,319
)
18,075

 
36,191

33,338

15,194

 
 
 
 
 
(1)
Levered Free Cash Flow includes cash paid for scheduled derivative settlements of $1 million for the three months ended September 30, 2018, $28 million for the three months ended June 30, 2018, and $47 million for the nine months ended September 30, 2018; and includes cash received for scheduled derivative settlements of $4 million for the three months ended September 30, 2017, $10 million for the seven months ended September 30, 2017, and $1 million for the two months ended February 28, 2017.


24


The following table presents a reconciliation of the non-GAAP financial measure Adjusted Net Income (Loss) to the GAAP financial measure of Net income (loss).
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
 
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
June 30, 2018
September 30, 2017
 
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands)
Adjusted Net Income (Loss) reconciliation to Net income (loss)
Net income (loss)
$
36,985

$
(28,061
)
$
(9,684
)
 
$
15,334

$
13,812

$
(502,964
)
Add (Subtract):
 
 
 
 
 
 
 
(Gains) losses on oil and natural gas derivatives
17,115

78,143

42,443

 
129,902

(5,642
)
(12,886
)
Net cash received (paid) for scheduled derivative settlements
(1,052
)
(28,261
)
4,045

 
(47,161
)
9,902

534

Gains (losses) on sale of assets and other, net
400

123

(20,692
)
 
522

(20,687
)
(183
)
Non-recurring restructuring and other costs
1,598

1,714

2,979

 
5,359

27,421


Reorganization items, net
(13,781
)
(456
)
408

 
(23,192
)
1,001

507,720

Total additions, net
4,280

51,263

29,183

 
65,430

11,995

495,185

Income tax (expense) benefit of adjustments at effective tax rate
(736
)
(8,371
)
(11,673
)
 
(11,137
)
(4,798
)

Adjusted Net Income (Loss)
$
40,529

$
14,831

$
7,826

 
$
69,627

$
21,009

$
(7,779
)

The following table presents a reconciliation of the non-GAAP financial measure Adjusted General and Administrative Expenses to the GAAP financial measure of general and administrative expenses for each of the periods indicated.
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
 
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
June 30, 2018
September 30, 2017
 
September 30, 2018
September 30, 2017
February 28, 2017
 
(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
General and administrative expenses
$
13,429

$
12,482

$
11,729

 
$
37,896

$
43,529

$
7,964

Subtract:
 
 
 
 
 
 
 
Non-recurring restructuring and other costs
(1,598
)
(1,714
)
(2,979
)
 
(5,359
)
(27,421
)

Non-cash stock compensation expense
(1,125
)
(1,260
)
(902
)
 
(3,404
)
(902
)

Adjusted General and Administrative Expenses
$
10,706

$
9,508

$
7,848

 
$
29,133

$
15,206

$
7,964


Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Basis of Presentation and Fresh-Start Accounting
Upon Berry LLC’s emergence from bankruptcy, we adopted fresh-start accounting, which, with the recapitalization upon emergence from bankruptcy, resulted in Berry Corp. becoming the financial reporting entity in our corporate group.

Unless otherwise noted or suggested by context, all financial information and data and accompanying financial statements and corresponding notes, as contained in this Quarterly Report on Form 10-Q, on or prior to the Effective Date, reflect the actual historical results of operations and financial condition of our predecessor company for the periods presented and do not give effect

25


to the Plan or any of the transactions contemplated thereby or the adoption of fresh-start accounting. Following the Effective Date, they reflect the actual historical results of operations and financial condition of Berry Corp. on a consolidated basis and give effect to the Plan and any of the transactions contemplated thereby and the adoption of fresh-start accounting. Thus, the financial information presented herein on or prior to the Effective Date is not comparable to Berry Corp.’s performance or financial condition after the Effective Date. As a result, “black-line” financial statements are presented to distinguish between Berry LLC as the predecessor and Berry Corp. as the successor.

Berry Corp.’s financial statements reflect the application of fresh-start accounting under GAAP. GAAP requires that the financial statements, for periods subsequent to the Chapter 11 Proceeding, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on Berry Corp.’s as well as Berry LLC’s statements of operations. In addition, Berry Corp.’s balance sheet classifies the cash distributions from the Cash Distribution Pool as “liabilities subject to compromise.” Prepetition unsecured and under-secured obligations that were impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on our balance sheet.

The main actions we took affecting comparability between periods presented include the reorganization of Berry LLC through bankruptcy, entry into the RBL Facility, issuance of the 2026 Notes, dividends on and conversion of Series A Preferred Stock and completion of the IPO. These actions are described above under "Emergence from Chapter 11 Bankruptcy" and below in "Liquidity and Capital Resources."
 
Capital Expenditures
For the three and nine months ended September 30, 2018, our capital expenditures were approximately $40 million and $95 million, respectively, on an accrual basis excluding acquisitions.

Following Berry LLC’s emergence from bankruptcy and separation from the Linn Entities, we increased our pace of development and have continued to do so in 2018. Our 2018 anticipated capital expenditure budget of approximately $140 to $160 million represents an increase of approximately 107% over our 2017 capital expenditures, including the successor and predecessor periods, of approximately $73 million. Based on current commodity prices and a drilling success rate comparable to our historical performance, we believe we will be able to fund our 2018 capital program exclusively with our levered free cash flow. We expect to:
• employ:
• three drilling rigs in California for the remainder of 2018;
• one additional drilling rig assigned to drilling opportunities in Utah in the fourth quarter of 2018;
• drill approximately 230 to 250 gross development wells in 2018, of which we expect at least 235 will be in California.

The table below sets forth the expected allocation of our 2018 capital expenditure budget by area as compared to the allocation of our 2017 capital expenditures.
 
Capital Expenditure by Area
 
2018 Budget
2017 Actual
 
(in millions)
California
$122-136


$71

Uinta
12-16

1

Piceance
1-2

1

East Texas


Corporate
5-6


Total
$140-160


$73



26


2019 Guidance
The table below sets forth our 2019 Guidance for certain metrics.
 
 
2019 Guidance
 
Low
 
High
Average daily production (MBoe/d)
 
29
 
32
% Oil
 
~86%
Operating expenses ($/Boe)
 
$17.00
 
$18.50
Taxes, other than income taxes ($/Boe)
 
$4.25
 
$4.75
Adjusted General & Administrative Expenses ($/Boe)
 
$4.00
 
$4.50
Capital Expenditures ($mm)
 
$230
 
$260
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and materially affect our business, financial condition and results of operations.
Chevron North Midway-Sunset Acquisition
In April 2018, we acquired two leases from a third party on an aggregate of 214 acres and a lease option on 490 acres of land owned by Chevron U.S.A. in the north Midway-Sunset field immediately adjacent to assets we currently operate. We assumed a drilling commitment of approximately $34.5 million to drill 115 wells on or before April 1, 2020. We have not drilled any of these wells as of September 30, 2018. We extended the commitment to April 1, 2022. We would assume an additional 40 well drilling commitment if we exercise our option on the 490 acres.We paid no other consideration for the acquisition. Our drilling commitment will be tolled for a month for each consecutive 30-day period for which the posted price of WTI is less than $45 per barrel. Our 2018 anticipated capital expenditure budget does not currently include funding for drilling wells against the assumed drilling commitment, but we have designated funds for drilling appraisal wells to determine whether to exercise the option. This transaction is consistent with our business strategy to investigate areas beyond our known productive areas.

Disposition of East Texas Properties
On October 17, 2018, we signed an agreement to sell our non-core oil and gas properties and related assets located in the East Texas Basin for approximately $7 million. Production comprised approximately 0.7 MBoe per day of natural gas in the third quarter of 2018. We anticipate closing this sale in the fourth quarter of 2018.

Commodity Derivatives
We utilize derivatives, such as swaps, puts and calls, to hedge a portion of our forecasted production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices and we target covering our operating expenses and fixed charges, including maintenance capital expenditures, for up to two years out. We have also hedged a portion of our exposure to differentials between Brent and WTI. We also, from time to time, have entered into agreements to purchase a portion of the natural gas we require for our operations that we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions.

Our current hedge positions primarily consist of swap contracts and deferred premium purchased put options. We also recently acquired natural gas fixed price swaps to hedge our exposure to price changes for natural gas purchases. We enter into these transactions with respect to a portion of our projected oil production and gas purchases to provide economic hedges against the risk related to the future commodity prices. We do not enter into derivative contracts for speculative trading purposes.

Swap contracts are designed to provide a fixed price. For fixed-price swaps, we make settlement payments for prices above the indicated weighted-average price per barrel of Brent and receive settlement payments for prices below the indicated weighted‑average price per barrel of Brent. For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the indicated weighted-average price per barrel and receive settlement payments if the difference between Brent

27


and WTI is below the indicated weighted-average price per barrel. We earn a premium on our sold oil calls at the time of sale. We make net settlement payments for prices above the indicated weighted-average price per barrel of Brent. If the calls expire unexercised, no payments are received. For our purchased puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel of Brent. For fixed-price natural gas swaps, we are the buyer so we make settlement payments for prices below the weighted-average price per MMBtu and receive settlement payments for prices above the weighted-average price per MMBtu.

As of September 30, 2018, we have hedged crude oil production at the following approximate volumes and prices: 12.8 MBbl/d at $75 in the fourth quarter of 2018, 16.5 MBbl/d at $70 in 2019, and 1.2 MBbl/d at $65 in 2020, as outlined along with our natural gas derivative contracts in the following table:
 
2018
2019
2020
Sold Oil Calls (ICE Brent):
 
 
 
 Hedged volume (MBbls)
124



 Weighted-average price ($/Bbl)
$
80.00

$

$

Purchased put options (ICE Brent):
 
 
 
  Hedged volume (MBbls)

3,385

455

  Weighted-average price ($/Bbl)
$

$
65.00

$
65.00

Fixed Price Swaps (ICE Brent):
 
 
 
  Hedged volume (MBbls)
1,058

2,640


  Weighted-average price ($/Bbl)
$
74.82

$
75.40

$

Oil basis differential positions:
 
 
 
ICE Brent - NYMEX WTI basis swaps
 
 
 
  Hedged volume (MBbls)
92

182.5


  Weighted-average price ($/Bbl)
$
1.29

$
1.29

$

Fixed Price Swaps (Kern):
 
 
 
Hedged volume (MMBtu)
1,380,000

4,560,000


Weighted-average price ($/MMBtu)
$
2.65

$
2.65

$

The following table summarizes the historical results of our hedging activities.
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
Nine Months Ended
Four Months Ended
Two Months Ended
 
September 30, 2018
June 30, 2018
September 30, 2017
September 30, 2018
September 30, 2017
February 28, 2017
Crude Oil (per Bbl):
 
 
 
 
 
 
Realized price, before the effects of derivative settlements
$
67.67

$
67.93

$
45.50

$
65.97

$
44.87

$
46.94

Effects of derivative settlements
$
(0.44
)
$
(14.71
)
$
2.07

$
(8.01
)
$
2.30

$
0.46

We expect our operations to generate substantial cash flows at current commodity prices. We have protected a portion of our anticipated cash flows through 2020 as part of our crude oil hedging program. Our low-decline production base, coupled with our stable operating cost environment, affords an ability to hedge a material amount of our future expected production.
 
In May 2018, we elected to terminate outstanding commodity derivative contracts for all WTI oil swaps and certain WTI/Brent basis swaps for July 2018 through December 2019 and all WTI oil sold call options for July 2018 through June 2020. Termination costs totaled approximately $127 million and were calculated in accordance with a bilateral agreement on the cost of elective termination included in these derivative contracts; the present value of the contracts using the forward price curve as of the date termination was elected. No penalties were charged as a result of the elective termination. Concurrently, Berry Corp. entered into commodity derivative contracts consisting of Brent oil swaps for July 2018 through March 2019 and Brent oil purchased put options for January 2019 through March 2020. These Brent oil swaps hedge 1.8 MMBbls in 2018 and 0.9 MMBbls in 2019 at a weighted-average price of $75.66. These Brent oil purchased put options provide a weighted-average price floor of $65.00 for 2.8 MMBbls

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in 2019 and 0.5 MMBbls in 2020. We effected these transactions to move from a WTI-based position to a Brent-based position as well as bring our hedge pricing more in line with current market pricing.
Income Taxes
Prior to the Effective Date, Berry LLC was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, Berry LLC was not a taxable entity, it did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of Berry LLC. Upon emergence from bankruptcy, Berry Corp. acquired the assets of Berry LLC in a taxable asset acquisition as part of the restructuring. Consequently, we are now taxed as a corporation and have no net operating loss carryforwards for the periods prior to February 28, 2017.
 
On December 22, 2017, the U.S. the Tax Cuts and Jobs Act (the “Act”) which made significant changes to the Internal Revenue Code of 1986, including lowering the maximum federal corporate rate from 35% to 21% and imposing limitations on the use of net operating losses arising in taxable years ending after December 31, 2017.  This was the key contributor to the decrease in our effective rate from 40% in the 2017 Successor periods to 17% in each of the three and nine months ended September 30, 2018. We anticipate earnings for fiscal year 2018, in part due to the termination and resetting of our hedge positions in May 2018. These earnings consequently allow for the release of our valuation allowance, resulting in an effective tax rate less than the maximum federal and applicable state tax rate for the nine months ended September 30, 2018. There were no current income taxes during the nine months ended September 30, 2018

Our accounting for the U.S. Tax Reform Act is incomplete. As noted at year-end, however, we were able to reasonably estimate certain effects and, therefore, recorded provisional adjustments to income tax expense for the revaluation of deferred tax assets and liabilities from 35% to 21% associated with the reduction in the U.S. corporate income tax rate, and for a valuation allowance on certain deferred tax assets impacted by the Act. We have not revised any of the 2017 provisional estimates. Any subsequent adjustments to these amounts will be recorded to income tax expense in the fourth quarter of 2018 after analysis of the filed 2017 income tax return is complete.
Business Environment and Market Conditions
The oil and gas industry is heavily influenced by commodity prices. Since the latter half of 2014, commodity prices have declined and remained at relatively low levels through the middle of 2017 but have generally risen since then. For example, the Brent crude oil futures contract prices declined from a high of over $108.19 per Bbl in July 2014 to a low of $31.93 per Bbl in January 2016. The NYMEX Henry Hub natural gas ("HH") spot price for natural gas has also declined since 2014, though reduced gas prices are a net benefit to our results of operations. While oil prices remain lower than the 2014 averages, they have improved since early 2016. Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production.
The following table presents the average Brent oil, WTI oil, and HH natural gas prices for the three months ended September 30, 2018, June 30, 2018 and September 30, 2017, the nine months ended September 30, 2018, the seven months ended September 30, 2017 and the two months ended February 28, 2017:
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
Nine Months Ended
Seven Months Ended
Two Months Ended
 
September 30, 2018
June 30, 2018
September 30, 2017
September 30, 2018
September 30, 2017
February 28, 2017
ICE Brent oil ($/Bbl)
$
75.93

$
74.87

$
52.21

$
72.67

$
51.70

$
55.72

NYMEX WTI oil ($/Bbl)
$
69.50

$
67.76

$
48.20

$
66.75

$
48.45

$
53.04

NYMEX HH natural gas ($MMBtu)
$
2.90

$
2.80

$
3.00

$
2.90

$
3.03

$
3.66

Oil prices and differentials will continue to be affected by a variety of factors, including worldwide and regional economic conditions, transportation costs, imports, political conditions in producing regions, exploration levels, inventory levels, the actions of the Organization of Petroleum Exporting Countries ("OPEC") and other state-controlled oil companies and significant producers, local pricing, gathering facility and transportation dynamics, exploration, development, production and transportation costs, the effects of conservation, weather, geophysical and technology, refining and processing disruptions, exchange rates, taxes and

29


regulations and other matters affecting the supply and demand dynamics for oil, technological advances, regional market conditions, transportation capacity and costs in producing areas and the effect of changes in these variables on market perceptions.
California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign sources. There is a closer correlation of prices in California to Brent pricing than to WTI. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low-cost transportation of crude, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California.
Utah oil prices have historically traded at a discount to WTI as the local refineries are designed for the oil's unique characteristics and the remoteness of the assets makes access to other markets logistically challenging.
Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify pricing volatility.
Natural gas prices and differentials are strongly affected by local market fundamentals, as well as availability of transportation capacity from producing areas. Higher natural gas prices have a net negative effect on our operating results. We use substantially more natural gas for our steamfloods and power generation, than we produce and sell. The negative impact of higher prices on our operating costs is, however, partially offset by higher natural gas sales.
Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses, we also sell electricity produced by three of our cogeneration facilities under long-term contracts. The most significant input and cost of the cogeneration facilities is natural gas. The price we receive from selling electricity to third–parties is closely tied to the price of natural gas and thus these operations effectively serve as a partial hedge against gas price increases.
Seasonality
Seasonal weather conditions can impact a portion of our drilling and production activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires.
Natural gas prices can fluctuate based on seasonal impacts. We purchase gas, significantly more than we sell, to generate steam in our cogeneration facilities for our producing activities. As a result, our key exposure to gas prices is in our costs. We effectively mitigate this exposure by selling excess electricity from our cogeneration operations to third parties. The prices of these electricity sales are closely tied to the purchase price of natural gas.
Production, Prices and Costs
The following table sets forth information regarding total production, average daily production, average prices and average costs for each of the periods indicated.

30


 
Berry Corp. (Successor)
 
Three Months Ended