Berry Corp (bry) - FORM 10-Q - August 23, 2018

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EX-32.1 - EXHIBIT 32.1 - Berry Corp (bry)ex321q22018.htm
EX-31.2 - EXHIBIT 31.2 - Berry Corp (bry)ex312q22018.htm
EX-31.1 - EXHIBIT 31.1 - Berry Corp (bry)ex311q22018.htm
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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 June 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)
5201 Truxtun Avenue
Bakersfield, California 93309
(661) 616-3900
(Address of principal executive offices, including zip code
Registrant’s telephone number, including area code):

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 ¨    No ý

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post 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 July 31, 2018                        81,336,762


TABLE OF CONTENTS







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

BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share amounts)
 
Berry Corp. (Successor)
 
June 30, 2018
December 31, 2017
ASSETS


Current assets:


Cash and cash equivalents
$
3,600

$
33,905

Accounts receivable, net of allowance for doubtful accounts of $950 at June 30, 2018 and $970 at December 31, 2017
56,860

54,720

Restricted cash
19,710

34,833

Other current assets
14,981

14,066

Total current assets
95,151

137,524

Noncurrent assets:


Oil and natural gas properties
1,382,777

1,342,453

Accumulated depletion and amortization
(88,548
)
(54,785
)
 
1,294,229

1,287,668

Other property and equipment
112,618

104,879

Accumulated depreciation
(8,928
)
(5,356
)
 
103,690

99,523

Other noncurrent assets
22,086

21,687

Total assets
$
1,515,156

$
1,546,402

LIABILITIES AND EQUITY


Current liabilities:


Accounts payable and accrued expenses
$
113,170

$
97,877

Derivative instruments
11,447

49,949

Liabilities subject to compromise
19,710

34,833

Total current liabilities
144,327

182,659

Noncurrent liabilities:


Long-term debt
457,333

379,000

Derivative instruments
3,563

25,332

Deferred income taxes
—

1,888

Asset retirement obligation
88,575

94,509

Other noncurrent liabilities
12,862

3,704

Commitments and Contingencies-Note 5



Equity:


Series A Preferred Stock ($.001 par value, 250,000,000 shares authorized and 37,669,805 shares issued at June 30, 2018 and 35,845,001 shares issued at December 31, 2017)
335,000

335,000

Common stock ($.001 par value, 750,000,000 shares authorized and 33,087,889 shares issued at June 30, 2018 and 32,920,000 issued at December 31, 2017
33

33

Additional paid-in-capital
536,188

545,345

Treasury stock, at cost
(20,006
)
—

Accumulated deficit
(42,719
)
(21,068
)
Total equity
808,496

859,310

Total liabilities and equity
$
1,515,156

$
1,546,402

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

3

BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)
 
Berry Corp.
(Successor)
Berry LLC
(Predecessor)
 
Three Months Ended
Three Months Ended
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
June 30, 2017
 
June 30, 2018
June 30, 2017
February 28, 2017
Revenues and other:




 






Oil, natural gas and natural gas liquids sales
$
137,385

$
101,884

 
$
263,010

$
135,562

$
74,120

Electricity sales
5,971

5,712

 
11,423

6,603

3,655

(Losses) gains on oil and natural gas derivatives
(78,143
)
23,962

 
(112,787
)
48,085

12,886

Marketing revenues
518

809

 
1,302

1,090

633

Other revenues
251

2,355

 
317

3,037

1,424


65,982

134,722

 
163,265

194,377

92,718

Expenses and other:
 
 
 
 
 
 
Lease operating expenses
41,517

45,726

 
85,819

58,790

28,238

Electricity generation expenses
3,135

4,465

 
7,725

5,613

3,197

Transportation expenses
2,343

9,404

 
5,321

13,059

6,194

Marketing expenses
407

730

 
987

1,000

653

General and administrative expenses
12,482

22,257

 
24,466

31,800

7,964

Depreciation, depletion, amortization and accretion
21,859

20,549

 
40,288

27,571

28,149

Taxes, other than income taxes
8,715

10,249

 
16,972

13,330

5,212

(Gains) losses on sale of assets and other, net
123

5

 
123

5

(183
)

90,581

113,385

 
181,701

151,168

79,424

Other income and (expenses):
 
 
 
 
 
 
Interest expense
(9,155
)
(4,885
)
 
(16,951
)
(6,600
)
(8,245
)
Other, net
(239
)
2,916

 
(212
)
2,916

(63
)

(9,394
)
(1,969
)
 
(17,163
)
(3,684
)
(8,308
)
Reorganization items, net
456

713

 
9,411

(593
)
(507,720
)
Income (loss) before income taxes
(33,537
)
20,081

 
(26,188
)
38,932

(502,734
)
Income tax expense (benefit)
(5,476
)
7,961

 
(4,537
)
15,435

230

Net income (loss)
(28,061
)
12,120

 
(21,651
)
23,497

$
(502,964
)
Dividends on Series A Preferred Stock
(5,650
)
(5,404
)
 
(11,301
)
(7,196
)
n/a

Net income (loss) attributable to common stockholders
$
(33,711
)
$
6,716

 
$
(32,952
)
$
16,301

n/a

Net income (loss) per share attributable to common stockholders:
 
 
 
 
 
 
Basic
$
(0.84
)
$
0.17

 
$
(0.82
)
$
0.41

n/a

Diluted
$
(0.84
)
$
0.16

 
$
(0.82
)
$
0.31

n/a

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

4

BERRY PETROLEUM CORPORATION (Successor)
CONDENSED CONSOLIDATED STATEMENT OF EQUITY
(in thousands)
(Unaudited)




Series A Preferred Stock
Common stock
Additional Paid-in Capital
Accumulated Deficit
Treasury Stock
Total equity
Balance, December 31, 2017
$
335,000

$
33

$
545,345

$
(21,068
)
$
—

$
859,310

Stock-based compensation
—

—

2,320

—

—

2,320

Share repurchase for payment of taxes on equity awards
—

—

(176
)
—

—

(176
)
Cash dividends declared on Series A Preferred Stock
—

—

(11,301
)
—

—

(11,301
)
Purchase of rights to common stock
—

—

—

—

(20,006
)
(20,006
)
Net (loss) income
—

—

—

(21,651
)
—

(21,651
)
Balance, June 30, 2018
$
335,000

$
33

$
536,188

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




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

5

BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
 
Berry Corp.
Berry LLC
 
(Successor)
(Predecessor)
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
June 30, 2017
February 28, 2017
Cash flow from operating activities:
 
 
 
Net income (loss)
$
(21,651
)
$
23,497

$
(502,964
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
Depreciation, depletion, amortization and accretion
40,288

27,571

28,149

Amortization of debt issuance costs
2,651

7

416

Stock-based compensation expense
2,320

—

—

Deferred income taxes
(4,537
)
14,268

9

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

—

Derivative activities:
 
 
 
  Total (gains) losses
112,787

(48,085
)
(12,886
)
     Cash settlements
(46,110
)
5,856

534

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

—

(Gains) losses on sale of assets and other, net
123

(25
)
(25
)
Reorganization items, net
(10,763
)
(1,385
)
501,872

Changes in assets and liabilities:
 
 
 
  (Increase) decrease in accounts receivable
(2,120
)
16,543

(9,152
)
  (Increase) decrease in other assets
(1,859
)
(5,657
)
(2,842
)
  Increase (decrease) in accounts payable and accrued expenses
8,421

2,461

18,330

  Increase (decrease) in other liabilities
(2,129
)
9,886

990

Net cash (used in) provided by operating activities
(49,548
)
44,937

22,431

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures:
 
 
 
  Development of oil and natural gas properties
(37,609
)
(23,258
)
(859
)
  Purchases of other property and equipment
(7,760
)
(9,620
)
(2,299
)
  Proceeds from sale of property, plant, equipment and other
3,022

—

25

     Deposit on acquisition of properties
—

(39,450
)
—

Net cash used in investing activities
(42,347
)
(72,328
)
(3,133
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from sale of Series A Preferred Stock
—

—

335,000

Repayments on pre-emergence credit facility
—

—

(497,668
)
Borrowings on emergence credit facility
—

36,000

—

Repayments on emergence credit facility
—

(51,000
)
—

Proceeds from issuance of senior unsecured notes
400,000

—

—

Repayments on new credit facility
(409,800
)
—

—

Borrowings on new credit facility
96,800

—

—

Dividends paid on Series A Preferred Stock
(11,301
)
—

—

Purchase of treasury stock
(20,006
)
—

—

Share repurchase for payment of taxes on equity awards
(176
)
—

—

Debt issuance costs
(9,050
)
—

—

Net cash provided by (used in) financing activities
46,467

(15,000
)
(162,668
)
Net decrease in cash, cash equivalents and restricted cash
(45,428
)
(42,391
)
(143,370
)
Cash, cash equivalents and restricted cash:
 
 
 
Beginning
68,738

85,034

228,404

Ending
$
23,310

$
42,643

$
85,034

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

6


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.
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 should not necessarily be taken as indicative of results that may be expected for the entire year. 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, 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

7

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.
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. Any changes in these assumptions resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
The 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 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 primarily impact other assets and other liabilities 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 are currently evaluating the impact of the adoption of these rules on our consolidated financial statements and related disclosures.
Note 2 - Emergence from Voluntary Reorganization under Chapter 11
On December 16, 2013, an affiliate of LINN Energy, LinnCo, LLC (“LinnCo”), acquired all the outstanding common shares of Berry Petroleum Company and contributed Berry Petroleum Company to LINN Energy in exchange for LINN Energy units. In connection with its acquisition by LINN Energy, Berry Petroleum Company was converted from a Delaware corporation into a Delaware limited liability company and changed its name to “Berry Petroleum Company, LLC.” Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, became Berry LLC’s sole member.

8

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




On May 11, 2016 (the “Petition Date”), the LINN entities ("LINN Entities") and, consequently, Berry LLC (collectively, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 (“Chapter 11”) of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040 (collectively, the “Chapter 11 Proceedings”). During the pendancy of the Chapter 11 Proceedings, the debtors in the Chapter 11 Proceedings (the “Debtors”), operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
In December 2016, Berry LLC and Linn Acquisition Company, LLC, on the one hand, and LINN Energy and its other affiliated debtors, on the other hand, filed separate plans of reorganization with the Bankruptcy Court. The “Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC” (the “Plan”) was filed on December 13, 2016. On January 27, 2017, the Bankruptcy Court entered its confirmation order (the “Confirmation Order”) approving and confirming the Plan.
On February 28, 2017, the Plan became effective and was implemented in accordance with its terms. Among other transactions, Linn Acquisition Company, LLC transferred 100% of Berry LLC’s outstanding membership interests to Berry Corp. As a result, Berry LLC emerged from bankruptcy as a wholly-owned subsidiary of Berry Corp., separate from LINN Energy and its affiliates, effective February 28, 2017 (the “Effective Date”).
Plan of Reorganization
On the Effective Date, the Company consummated the following reorganization transactions in accordance with the Plan:
•
Linn Acquisition Company, LLC transferred 100% of the outstanding membership interests in Berry LLC to Berry Corp. pursuant to an assignment agreement, dated February 28, 2017 between Linn Acquisition Company, LLC and Berry Corp. (the “Assignment Agreement”). Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.
•
The holders of claims under the Company’s Second Amended and Restated Credit Agreement, dated November 15, 2010, by and among Berry LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and certain lenders, (as amended, the “Pre-Emergence Credit Facility”), received (i) their pro rata share of a cash paydown and (ii) pro rata participation in the new facility (the “Emergence Credit Facility”). As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated.
•
Berry LLC, as borrower, entered into the Emergence Credit Facility with the holders of claims under the Pre-Emergence Credit Facility, as lenders, and Wells Fargo Bank, N.A, as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments.
•
The holders of Berry LLC’s 6.75% senior notes due 2020, issued by Berry LLC pursuant to a Second Supplemental Indenture, dated November 1, 2010, and 6.375% senior notes due 2022, issued by Berry LLC pursuant to a Third Supplemental Indenture, dated March 9, 2012 (collectively, the “Unsecured Notes”), received a right to their pro rata share of either (i) 32,920,000 shares of common stock in Berry Corp. or, for those non-accredited investors holding the Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Cash Distribution Pool”) and (ii) specified rights to participate in a two-tranche offering of rights to purchase Series A Preferred Stock at an aggregate purchase price of $335 million (as further defined in the Plan, the “Berry Rights Offerings”). As a result, all outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements governing these obligations were terminated.
•
The holders of unsecured claims against Berry LLC, other than the Unsecured Notes, (the “Unsecured Claims”) received a right to their pro rata share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. As a result, all outstanding obligations under the Unsecured Notes and the indentures governing such obligations were canceled and the obligations arising from the Unsecured Claims were extinguished.
•
Berry LLC settled all intercompany claims against LINN Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the Confirmation Order. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy which Berry LLC has fully-reserved.





9

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018





Liabilities Subject to Compromise

Liabilities subject to compromise decreased from approximately $35 million as of December 31, 2017 to approximately $20 million as of June 30, 2018. Activity for our liabilities subject to compromise for the six months ended June 30, 2018 included the return of $9 million in undistributed funds from restricted cash, approximately $6 million in settlement payments to general unsecured creditors and other payments of professional fees incurred to settle these claims.
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 proceedings since the Petition Date, 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
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
June 30, 2017
June 30, 2018
June 30, 2017
February 28, 2017
 
(in thousands)
 
 
Return of undistributed funds from Cash Distribution Pool
$
—

$
—

$
9,000

$
—

$
—

Refund of pre-emergence prepaid costs
—

—

579

—

—

Gain on settlement of liabilities subject to compromise
—

—

—

—

421,774

Fresh start valuation adjustments
—

—

—

—

(920,699
)
Legal and other professional advisory fees
(1,178
)
713

(1,802
)
112

(19,481
)
Gain on resolution of pre-emergence liabilities
1,634

—

1,634

—

—

Other
—

—

—

(705
)
10,686

Reorganization items, net
$
456

$
713

$
9,411

$
(593
)
$
(507,720
)

In August 2018, we received an additional return of undistributed funds from the Cash Distribution Pool of approximately $14 million.


10

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




Note 3 - Debt
The following table summarizes our outstanding debt:
 
(in thousands)
 
 
 
 
June 30, 2018
December 31, 2017
Interest Rate
Maturity
Security
RBL Facility
$
66,000

$
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
466,000

379,000

 
 
 
Less: Debt Issuance Costs
(8,667
)
—

 
 
 
Long-Term Debt, net
$
457,333

$
379,000

 
 
 

 
At June 30, 2018 and December 31, 2017, debt issuance costs for the RBL Facility reported in "non current assets" on the balance sheet were approximately $18 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 $408 million at June 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, 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 (as defined below). 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 June 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 June 30, 2018, our actual ratios were 2.63 to 1.00 and 3.18 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 June 30, 2018.
As of June 30, 2018, we had approximately $327 million of available borrowing capacity under the RBL Facility.
As of June 30, 2018 and December 31, 2017, we had letters of credit outstanding of approximately $7 million and $21 million, respectively, under our revolving credit facilities. 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). On August 20, 2018, we had approximately $388 million of available borrowing capacity under the RBL Facility and approximately $36 million of cash on hand.
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

11

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




deducting expenses 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 production to reduce exposure to fluctuations in oil and natural gas prices and we target covering our operating expenses and fixed charges 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 consist of primarily oil swap contracts and deferred premium purchased put options, though in the past we have also used collars and three-way collars and hedged our exposure to natural gas and natural gas liquids (NGL) price changes. We enter into these transactions with respect to a portion of our projected production to provide an economic hedge against the risk related to the future commodity prices received. 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.
As part of our hedging program, we entered into a number of derivative transactions that resulted in the following crude oil contracts as of June 30, 2018:  
 
Q3 2018
Q4 2018
FY 2019
FY 2020
Sold Oil Calls (ICE Brent):
 
 
 
 
  Hedged volume (MBbls)
186

—

—

—

  Weighted average price ($/Bbl)
$
81.67

$
—

$
—

$
—

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

—

2,835

455

  Weighted average price ($/Bbl)
—

$
—

$
65.00

$
65.00

Fixed Price Swaps (ICE Brent):
 
 
 
 
  Hedged volume (MBbls)
966

966

900

—

  Weighted average price ($/Bbl)
$
75.13

$
75.13

$
75.66

$
—

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

92

182.5

—

  Weighted average price ($/Bbl)
$
1.29

$
1.29

$
1.29

$
—

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. The purchased put options contain deferred premiums of approximately $17.9 million and are reflected in the mark-to-market valuation of the derivatives on the balance sheet at June 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 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.

12

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




 
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 and WTI is below the indicated weighted-average price per barrel.

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 June 30, 2018 and December 31, 2017:
 
 
Berry Corp. (Successor)
 
June 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
$
(11,447
)
$
—

$
(11,447
)
  Commodity Contracts
Non-current liabilities
(3,563
)
—

(3,563
)
Total derivatives
 
$
(15,010
)
$
—

$
(15,010
)



 
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 hedged pricing more in line with current market pricing.


13

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018





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 our plan of reorganization in the Chapter 11 Proceeding. On the Effective Date the plan became effective and was implemented. The Chapter 11 Proceeding will, however, remain pending until final resolution of all outstanding claims. For further information, see Note 2.
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 June 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 June 30, 2018, purchase obligations of approximately $13 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 June 30, 2018, we had entered into agreements to purchase natural gas for our operations in 2018 for approximately $7 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 June 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 June 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
$
676

2019
1,170

2020
157

2021
159

2022
160

Thereafter
36

Total minimum lease payments
$
2,358

 
 
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 sold 10,497,849 shares and the selling stockholders sold 2,545,630

14

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




shares at a price of $14.00 per share. We used a portion of our proceeds to repurchase 1,802,196 shares of our common stock owned by Benefit Street Partners and Oaktree Capital Management. After giving effect to the IPO and the share repurchase, the number of shares of our common stock outstanding increased by 8,695,653. We and the selling stockholders have granted the underwriters the option to purchase up to an additional 1,534,895 shares and 421,626 shares of common stock, respectively, on the same terms and conditions set forth above.
The Company received approximately $136 million in net proceeds from the offering after deducting underwriting discounts and offering expenses payable by us. We did not receive any proceeds from the sale by the selling stockholders. We used approximately $24 million of the net proceeds to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the offering) from funds affiliated with Benefit Street Partners and Oaktree Capital Management.
Of the remaining approximately $112 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 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, 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.
Shares Issued and Outstanding
As of July 31, 2018, there were 81,336,762 shares of common stock issued and outstanding including 167,889 common shares that have vested as of June 30, 2018 relating to the Company's Omnibus Incentive Plan. An additional 1,447,998 unvested restricted stock units and performance restricted stock units were outstanding under the Company's Omnibus Incentive Plan as of July 31, 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. In July 2018, all shares our of 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 will result in a payment of $0.09 per share.
Purchase of Common Stock
In connection with our IPO, we entered into stock purchase agreements with funds affiliated with each of Benefit Street Partners and Oaktree Capital Management pursuant to which we purchased an aggregate of 1,802,196 shares of our common stock at a price equal to the net proceeds per share received from the IPO of our common stock before expenses. The stock purchase agreement with funds affiliated with Benefit Street Partners requires us to purchase additional shares at the same price if the underwriters exercise their option to purchase additional shares in the IPO.
Treasury Stock Purchase
In March and April 2018, we entered into settlement agreements with two 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. We do not yet know the final amount of shares out of the 7,080,000 set aside that we will issue to third parties with respect to the unsecured claims. 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.

15

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




 
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 estimate of the fair value of 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 as in effect immediately prior to the adoption of the Restated Incentive Plan (the "Prior 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 8.3 million.
Included in lease operating expenses and general and administrative expenses is stock-based compensation expense of $44,000 and $1.3 million, respectively, for the three months ended June 30, 2018, and $67,000 and $2.3 million, respectively, for the six months ended June 30, 2018. For the three and six months ended June 30, 2017, including the successor and predecessor periods, there were no such expenses. For the six months ended June 30, 2018, stock-based compensation had an immaterial associated income tax benefit.
The table below summarizes the activity relating to restricted stock units ("RSUs") issued under the 2017 Plan during the six months ended June 30, 2018. The RSUs vest ratably over three years. Unrecognized compensation cost associated with the RSUs at June 30, 2018 is approximately $6.8 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
205

$
11.50

Vested
(166
)
$
11.68

Forfeited
(26
)
$
10.12

June 30, 2018
696

$
10.20



16

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




The table below summarizes the activity relating to the performance-based restricted stock units ("PRSUs") issued under the 2017 Plan during the six months ended June 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 June 30, 2018 is approximately $3.8 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

$
7.49

Vested
—

$
—

Forfeited
(2
)
$
7.09

June 30, 2018
752

$
7.11

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. 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 percent to 21 percent 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 16% and 17% in the three and six months ended June 30, 2018, respectively.  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 six months ended June 30, 2018. There were no current income taxes during the six months ended June 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 percent to 21 percent 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 quarter the analysis is complete.

17

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




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)
 
June 30, 2018
December 31, 2017
 
(in thousands)
Prepaid expenses
$
6,692

$
6,901

Oil inventories, materials and supplies
7,062

5,938

Other
1,227

1,227

 
$
14,981

$
14,066

The major classes of inventory were not material and therefore not stated separately. Other non-current assets at June 30, 2018 and December 31, 2017, included approximately $18 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)
 
June 30, 2018
December 31, 2017
 
(in thousands)
Accounts payable-trade
$
10,698

$
15,469

Accrued expenses
57,531

34,359

Royalties payable
18,811

25,793

Greenhouse gas liability
5,732

10,446

Taxes other than income tax liability
9,428

8,437

Accrued interest
10,970

—

Other
—

3,373

 
$
113,170

$
97,877


18

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018





Supplemental Cash Flow Information
Supplemental disclosures to the statements of cash flows are presented below:
 
Berry Corp.
Berry LLC
 
(Successor)
(Predecessor)
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
June 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
$
8,614

$
1,172

$
2,249

Supplemental Disclosures of Cash Payments/(Receipts):
 
 
 
  Interest
$
3,298

$
5,261

$
8,057

  Income taxes
$
—

$
1,168

$
—

  Reorganization items, net
$
1,352

$
(792
)
$
11,838

 
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)
(in thousands)
Six Months Ended
Four Months Ended
Two Months Ended
Beginning of Period
June 30, 2018
June 30, 2017
February 28, 2017
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
$
3,600

$
3,735

$
32,049

Restricted cash
19,710

38,908

52,860

Restricted cash in other noncurrent assets
—

—

125

Cash, cash equivalents and restricted cash
$
23,310

$
42,643

$
85,034



Restricted cash is primarily associated with cash reserved to settle claims with the 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.

19

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018





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. Pursuant to the TSSA, (i) LINN Energy continued to provide, or cause to be provided, certain administrative, management, operating, and other services and support to the Company during a transitional period following the Effective Date (the “Transition Services”), (ii) the LINN Energy debtors and Berry LLC separated their previously combined enterprise and (iii) the LINN Energy debtors transferred to Berry LLC certain assets that relate to Berry LLC’s properties or its business, in each case under the terms and conditions specified in the TSSA.
Under the TSSA, Berry LLC reimbursed LINN Energy for any and all reasonable, third-party out-of-pocket costs and expenses, without markup, actually incurred by LINN Energy, to the extent documented, in connection with providing the 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 functions. The Transition Period under the TSSA ended April 30, 2017, and the Accounting Period ended June 30, 2017.
For the four months ended June 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 from LINN Energy Holdings, LLC two leases 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 over a 5-year term and would assume a further minimum 40 well drilling commitment if we exercise our option; but otherwise we paid no consideration. 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.
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 six months ended June 30, 2018, the three months ended June 30, 2017, and the four months ended June 30, 2017. The actual amount of our common stock that will be issued from the 7,080,000 shares reserved for Unsecured Claims and included in the 40 million shares above, cannot be known until all claims are settled, adjustments have been made based on the stock to be received by Unsecured Claims and claims under the Unsecured Notes and, the final number of shares of common stock to be received per dollar of Unsecured Claims, is known. However, while we do not yet know the final amount of shares that we will issue to third parties, we have entered into agreements in March and April 2018 that materially reduced that number.
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 were included in the diluted EPS

20

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




calculation for the three and six months ended June 30, 2018, as their effect was antidilutive under the “if-converted” method. However, the convertible preferred stock may potentially dilute basic earnings per share in the future.
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).
 
Berry Corp. (Successor)
Berry LLC
 
(Predecessor)
 
Three Months Ended
Three Months Ended
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
June 30, 2017
 
June 30, 2018
June 30, 2017
February 28, 2017
 
(in thousands except per share amounts)
Basic EPS calculation


 



Net income (loss)
$
(28,061
)
$
12,120

 
$
(21,651
)
23,497

n/a
   less: Dividends on Series A Preferred Stock
(5,650
)
(5,404
)
 
(11,301
)
(7,196
)
n/a
Net income (loss) available to common stockholders
$
(33,711
)
$
6,716

 
$
(32,952
)
$
16,301

n/a
Weighted-average shares of common stock outstanding
33,010

32,920

 
32,971

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
40,090

40,000

 
40,051

40,000

n/a
Basic Earnings (loss) per share
$
(0.84
)
$
0.17

 
$
(0.82
)
$
0.41

n/a
Diluted EPS calculation


 
 
 
 
Net income (loss)
$
(28,061
)
$
12,120

 
$
(21,651
)
$
23,497

n/a
  less: Dividends on Series A Preferred Stock
(5,650
)
(5,404
)
 
(11,301
)
(7,196
)
n/a
Net income (loss) available to common stockholders
$
(33,711
)
$
6,716

 
$
(32,952
)
$
16,301

n/a
Weighted-average shares of common stock outstanding
33,010

32,920

 
32,971

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
40,090

40,000

 
40,051

40,000

n/a
Dilutive effect of potentially dilutive securities
—

35,845

 
—

35,845

n/a
Weighted-average common shares outstanding-diluted
40,090

75,845

 
40,051

75,845

n/a
Diluted Earnings (loss) per share
$
(0.84
)
$
0.16

 
$
(0.82
)
$
0.31

n/a

Note 12- Pro Forma Financial Data

PRO FORMA FINANCIAL DATA
The following unaudited pro forma condensed consolidated financial information of Berry Corp. gives effect to the issuance of the 2026 Notes, the Series A Preferred Stock Conversion and the IPO including the application of net proceeds from the IPO. The unaudited pro forma condensed consolidated statement of operations is presented for the six months ended June 30, 2018. The unaudited pro forma condensed consolidated balance sheet is presented as of June 30, 2018. This unaudited pro forma condensed consolidated financial information should be read in conjunction with Berry Corp.’s historical consolidated financial statements as of and for the six months ended June 30, 2018.
The unaudited pro forma condensed consolidated statement of operations gives effect to the issuance of the 2026 Notes, the Series A Preferred Stock Conversion and the IPO, including the application of net proceeds from the offering, as if each had

21

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




been completed as of January 1, 2017. The unaudited pro forma condensed consolidated balance sheet gives effect to the same transactions as if each had been completed on June 30, 2018.
The unaudited pro forma condensed consolidated financial statements are for informational and illustrative purposes only and are not necessarily indicative of the financial results that would have been had the events and transactions occurred on the dates assumed, nor are such financial statements necessarily indicative of the results of operations in future periods. The pro forma adjustments, as described in the accompanying notes, are based upon currently available information. The historical financial information has been adjusted to give effect to pro forma adjustments that are (i) directly attributable to the 2026 Notes, the Series A Preferred Stock Conversion, the IPO and the application of net proceeds from the offering, (ii) factually supportable, and (iii) expected to have a continuing impact on the Company’s consolidated results.
Background
2026 Notes
In February 2018, we completed a private issuance of $400 million in aggregate principal amount of 7.00% senior unsecured notes due 2026, which resulted in net proceeds of approximately $391 million after deducting expenses and the initial purchasers' discount. A portion of these proceeds were used to repay borrowings under the RBL Facility and the remainder for general corporate purposes.
Series A Preferred Stock Conversion and Common Stock Offering
In connection with our IPO, we amended the Series A Preferred Stock certificate of designation to provide for the automatic conversion of all outstanding shares of Series A Preferred Stock. Pursuant to the amendment, each outstanding share of Series A Preferred Stock was automatically converted into (i) 1.05 shares of common stock and (ii) the right to receive $1.75, minus the amount of any cash dividend paid by the Company on such share of Series A Preferred Stock in respect of any period commencing on or after April 1, 2018.
We received approximately $136 million of net proceeds from the IPO after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We did not receive any proceeds from the sale of shares by the selling stockholders. We used approximately $24 million of the net proceeds to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the offering) from funds affiliated with Benefit Street Partners and Oaktree Capital Management. Of the remaining approximately $112 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 amounts we borrowed in July on the RBL Facility to make the payment 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.













22

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
JUNE 30, 2018
(in thousands)
 
Berry Corp. (Successor) June 30, 2018
Series A Preferred Stock Conversion and Common Stock Offering
 
Berry Corp. (Successor) Pro Forma
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
$
3,600

$
—

(a) (b)
$
3,600

Accounts receivable, net
56,860

 
 
56,860

Restricted cash
19,710

 
 
19,710

Other current assets
14,981

 
 
14,981

Total current assets
95,151

—

 
95,151

Noncurrent assets:
 
 
 
 
Oil and natural gas properties (successful efforts method)
1,382,777

 
 
1,382,777

Less accumulated depletion and amortization
(88,548)

 
 
(88,548)

 
1,294,229

 
 
1,294,229

Other property and equipment
112,618

 
 
112,618

Less accumulated depreciation
(8,928)

 
 
(8,928)

 
103,690

 
 
103,690

Other noncurrent assets
22,086

 
 
22,086

Total assets
$
1,515,156

$
—

 
$
1,515,156

LIABILITIES AND EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable and accrued
expenses
$
113,170

$
—

 
$
113,170

Derivative instruments
11,447

 
 
11,447

Liabilities subject to compromise
19,710

 
 
19,710

Total current liabilities
144,327

—

 
144,327

Noncurrent liabilities:
 
 
 
 
Long-term debt
457,333

(51,538
)
(a)
405,795

Derivative instruments
3,563

 
 
3,563

Asset retirement obligation
88,575

 
 
88,575

Other noncurrent liabilities
12,862

 
 
12,862

 
 
 
 
 
Equity:
 
 
 
 
Successor Series A Preferred Stock ($.001 par value, 250,000,000 shares authorized and 37,669,805 shares issued at June 30, 2018)
335,000

(335,000)

(b)
—

Successor common stock ($.001 par value, 750,000,000 shares authorized and 33,087,889 shares issued at June 30, 2018)
33

48

(a)(b)
81

Additional paid-in-capital
536,188

386,490

(a)(b)
922,678

Treasury stock, at cost
(20,006
)
 
 
(20,006
)
Accumulated deficit
(42,719)

 
 
(42,719)

 
 
 
 
 
Total equity
808,496

51,538

 
860,034

Total liabilities and equity
$
1,515,156

$
—

 
$
1,515,156


23

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR SIX MONTHS ENDED JUNE 30, 2018
(in thousands, except per share amounts)
 
Berry Corp. (Successor) Six Months Ended June 30, 2018
Issuance of 2026 Notes
Series A Preferred Stock Conversion and Common Stock Offering
 
Berry Corp. (Successor) Pro Forma
Revenues and other:
 
 
 
 
 
Oil, natural gas and NGL sales
$
263,010

 
 
 
$
263,010

Electricity sales
11,423

 
 
 
11,423

Gains (losses) on oil and natural gas derivatives
(112,787
)
 
 
 
(112,787
)
Marketing revenues
1,302

 
 
 
1,302

Other revenues
317

 
 
 
317

 
163,265

—

—

 
163,265

Expenses and other:
 
 
 
 
 
Lease operating expenses
85,819

 
 
 
85,819

Electricity generation expenses
7,725

 
 
 
7,725

Transportation expenses
5,321

 
 
 
5,321

Marketing expenses
987

 
 
 
987

General and administrative expenses
24,466

 
 
 
24,466

Depreciation, depletion and amortization
40,288

 
 
 
40,288

Taxes, other than income taxes
16,972

 
 
 
16,972

Gains on sale of assets and other, net
123

 
 
 
123

 
181,701

—

—

 
181,701

Other income and (expenses):
 
 
 
 
 
Interest expense, net of amounts capitalized
(16,951
)
(854
)
 
(c)
(17,805
)
Other, net
(212
)
 
 
 
(212
)
 
(17,163
)
(854
)
—

(c)
(18,017
)
Reorganization items, net
9,411

 
 
 
9,411

(Loss) income before income taxes
(26,188
)
(854
)
—

(c)
(27,042
)
Income tax expense (benefit)
(4,537
)
(147
)
 
(c)
(4,684
)
Net income (loss)   
(21,651
)
(707
)
—

 
(22,358
)
Dividends on Series A Preferred Stock
(11,301
)
 
11,301

(f)
—

Net income (loss) available to common stockholders   
$
(32,952
)
$
(707
)
$
11,301

 
$
(22,358
)
Net income (loss) per share of common stock:
 
 
 
 
 
Basic
$
(0.82
)
 
 
 
$
(0.26
)
Diluted
$
(0.82
)
 
 
 
$
(0.26
)
Weighted average common shares outstanding
 
 
 
 
 
Basic (g)
40,051

 
46,333

(d) (e)
86,384

Diluted (g)
40,051

 
46,333

(d) (e)
86,384

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION

1. Basis of Presentation

The accompanying unaudited pro forma condensed consolidated statement of operations presents the financial information of Berry Corp. assuming the events and transactions had occurred on January 1, 2017. The consolidated balance sheet presents the information assuming the transactions occurred on June 30, 2018. Issuance of 2026 Notes Adjustments represent

24

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




adjustments to give effect to the Company's issuance and net proceeds from the 2026 Notes to the condensed consolidated statement of operations as of the date assumed. Series A Preferred Stock Conversion and Common Stock Offering Adjustments represent adjustments to give effect to the conversion of preferred stock into common stock, including the payment of cash dividends and the common stock offering to the condensed consolidated financial statements as of the date assumed.

2. Pro Forma Balance Sheet Adjustments

(a) Reflects the issuance of 8,695,653 additional net shares of common stock in the offering, the receipt of approximately $112 million of net proceeds, after the repurchase of 1,802,196 shares for approximately $24 million, from funds affiliated with Benefit Street Partners and Oaktree Capital Management in connection with the IPO and the usage of a portion of the net proceeds to pay down the outstanding balance on the RBL Facility. The number of shares and net proceeds does not include a number of shares issued by us equal to the number of shares purchased by us from funds affiliated with Benefit Street Partners and Oaktree Capital Management in connection with the IPO.

(b) Reflects the conversion of the outstanding shares of Series A Preferred Stock into (1) approximately 39.6 million shares of common stock and (2) the cash payment from the IPO net proceeds of $1.60 on each pre-conversion share of Series A Preferred Stock, or approximately $60 million.

3. Pro Forma Statement of Operations Adjustments

Issuance of 2026 Notes Adjustments
 
(c) The issuance of the 2026 Notes was assumed to have occurred on January 1, 2017 for pro forma purposes and to have resulted in net proceeds of $391 million. As a result, borrowings under the RBL Facility would not have been necessary during this period.

The Company calculated the pro forma adjustment to increase interest expense as a result of the higher interest rate on the 2026 Notes and reversing the interest expense and other fees associated with the RBL Facility for the six months ended June 30, 2018 as follows:
(in thousands)
 
Reversal of interest expense, unused fee and LOC fee on the RBL Facility
$
(3,251
)
Reversal of 2026 Notes interest expense
(10,970
)
Pro Forma- RBL Facility letter of credit fee ($7.1 million outstanding at 2.625%)
93

Pro Forma-RBL Facility unused availability fee ($393 million availability at 0.5%)
982

Pro Forma 2026 Notes interest expense.
14,000

Pro Forma adjustment to increase interest expense
$
854


The effective tax rate applied to the increased interest expense was 17.3% for the six months ended June 30, 2018.

Series A Preferred Stock Conversion and Common Stock Offering Adjustments

(d) Reflects basic and diluted income per common share giving effect to the issuance of 8,695,653 shares of common stock in the IPO, assuming the IPO occurred January 1, 2017. The number of shares and net proceeds does not include shares purchased from the selling stockholders in the IPO or a number of shares issued by us equal to the number of shares purchased by us from funds affiliated with Benefit Street Partners and Oaktree Capital Management in connection with the IPO.

(e) Reflects the conversion of the outstanding shares of Series A Preferred Stock into approximately 37.7 million shares of common stock, assumed to occur on January 1, 2017.

(f) Reflects the effect of reversing the Series A Preferred Stock dividends, assuming the IPO and the Series A Preferred Stock Conversion occurred January 1, 2017.

(g) Share count includes 7 million shares reserved for issuance to the general unsecured creditors resulting from the bankruptcy process.

25


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 ("Linn Acquisition") and us (the "Plan"), 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 June 30, 2018, we had average production of approximately 26.5 MBoe/d, of which approximately 80% was oil. In California, our average production for the three months ended June 30, 2018 was 18.8 MBoe/d, of which approximately 100% was oil.






26



Chapter 11 Bankruptcy and Our Emergence

In 2013, the Linn Entities acquired our predecessor company in exchange for LinnCo shares and the assumption of debt with an aggregate value of $4.6 billion. A severe industry downturn, coupled with high leverage and significant fixed charges, led the Linn Entities and, consequently, our predecessor company to initiate the Chapter 11 Proceedings on May 11, 2016.

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. These improvements included:

• the elimination of approximately $1.3 billion of debt and more than $76 million of annualized interest expense;
• the termination of, or renegotiation of more favorable terms for, several firm transportation and oil sales contracts;
• the anticipated reduction in recurring general and administrative costs as a stand-alone company by following a lean operating model.

On the Effective Date, Berry LLC consummated the following reorganization transactions in accordance with the Plan:

• Linn Acquisition Company, LLC transferred 100% of the outstanding membership interests in Berry LLC to Berry Corp. pursuant to the Assignment Agreement. Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.

• The holders of claims under the Pre-Emergence Credit Facility, received (i) their pro rata share of a cash paydown and (ii) pro rata participation in the Emergence Credit Facility. As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated.

• Berry LLC, as borrower, entered into the Emergence Credit Facility with the holders of claims under the Pre-Emergence Credit Facility, as lenders, and Wells Fargo Bank, N.A., as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments.

• The holders of Berry LLC’s Unsecured Notes received a right to their pro rata share of either (i) 32,920,000 shares of common stock in Berry Corp. or, for those non-accredited investors that irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool and (ii) specified rights to participate the Berry Rights Offerings. As a result, all outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements governing these obligations were terminated.

• The holders of the Unsecured Claims received a right to their pro rata share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. The obligations arising from the Unsecured Claims were extinguished.

• Berry LLC settled all intercompany claims against LINN Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the Confirmation Order. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy which Berry LLC has fully reserved.

How We Evaluate Operations

Our management team uses 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; (f) production; and (g) levered free cash flow.

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; exploration expense; derivative gains or losses net of cash received or paid

27

for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring and reorganization costs.

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. 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. 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.

Levered free cash flow

Levered free cash flow reflects our financial flexibility; and we use it to plan our internal growth capital expenditures. We define levered free cash flow as Adjusted EBITDA less capital expenditures, interest expense and dividends. Levered free cash flow is our primary metric used in planning capital allocation for maintenance and internal growth opportunities as well as hedging needs and serves as a measure for assessing our financial performance and measuring our ability to generate excess cash from our operations after servicing indebtedness.

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 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) attributable to common stockholders 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 and reorganization costs and the income tax expense or benefit of these adjustments using our effective tax rate.

28


We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, amortization and accretion; exploration expense; 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 and reorganization costs. 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.
























29









The following tables present reconciliations of the non-GAAP financial measure Adjusted EBITDA and Levered Free Cash Flow to the GAAP financial measures of net income (loss) and net cash provided or used by operating activities for each of the periods indicated.
 
Berry Corp. (Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
March 31, 2018
June 30, 2017
 
June 30, 2018
June 30, 2017
February 28, 2017
 
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
 
 
 
 
 
 
 
Net income (loss)
$
(28,061
)
$
6,410

$
12,120

 
$
(21,651
)
$
23,497

$
(502,964
)
Add (Subtract):
 
 
 
 
 
 
 
Depreciation, depletion, amortization and accretion
21,859

18,429

20,549

 
40,288

27,571

28,149

Interest expense
9,155

7,796

4,885

 
16,951

6,600

8,245

Income tax expense (benefit)
(5,476
)
939

7,961

 
(4,537
)
15,435

230

Derivative (gain) loss
78,143

34,644

(23,962
)
 
112,787

(48,085
)
(12,886
)
Net cash received (paid) for scheduled derivative settlements
(28,261
)
(17,849
)
4,725

 
(46,110
)
5,856

534

(Gain) loss on sale of assets and other
123

—

5

 
123

5

(183
)
Stock compensation expense
1,278

1,042

—

 
2,320

—

—

Non-recurring restructuring and other costs
1,714

2,047

16,846

 
3,761

24,442

—

Reorganization items, net
(456
)
(8,955
)
(713
)
 
(9,411
)
593

507,720

Adjusted EBITDA
50,018

44,503

42,416

 
94,521

55,914

28,845

Net cash (received) paid for scheduled derivative settlements
28,261

17,849

(4,725
)
 
46,110

(5,856
)
(534
)
Adjusted EBITDA unhedged
$
78,279

$
62,352

$
37,691

 
$
140,631

$
50,058

$
28,311










30





 
Berry Corp. (Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
March 31, 2018
June 30, 2017
 
June 30, 2018
June 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
$
(77,394
)
$
27,846

$
20,703

 
$
(49,548
)
$
44,937

$
22,431

Add (Subtract):
 
 
 
 
 
 
 
Cash interest payments
644

2,654

4,860

 
3,298

5,261

8,057

Cash income tax payments
—

—

1,168

 
—

1,168

—

Cash reorganization item (receipts) payments
1,047

305

(1,384
)
 
1,352

(792
)
11,838

Non-recurring restructuring and other costs
1,714

2,047

16,846

 
3,761

24,442

—

Derivative early termination payment
126,949

—

—

 
126,949

—

—

Other changes in operating assets and liabilities
(2,942
)
11,651

223

 
8,709

(19,102
)
(13,323
)
Other, net
—

—

—

 
—

—

(158
)
Adjusted EBITDA
50,018

44,503

42,416

 
94,521

55,914

28,845

Subtract:
 
 
 
 
 
 
 
Capital expenditures
(39,196
)
(15,732
)
(24,697
)
 
(54,928
)
(34,050
)
(5,407
)
Interest expense
(9,155
)
(7,796
)
(4,885
)
 
(16,951
)
(6,600
)
(8,245
)
Dividends
(5,650
)
(5,650
)
(5,404
)
 
(11,301
)
(7,196
)
—

Levered Free Cash Flow
(3,983
)
15,325

7,430

 
11,341

8,068

15,193

Net cash (received) paid for scheduled derivative settlements
28,261

17,849

(4,725
)
 
46,110

(5,856
)
(534
)
Levered Free Cash Flow unhedged
$
24,278

$
33,174

$
2,705

 
$
57,451

$
2,212

$
14,659















31






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) attributable to common stockholders.
 
Berry Corp. (Successor)
Berry LLC (Predecessor)
 
Three Months Ended
Three Months Ended
Three Months Ended
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
March 31, 2018
June 30, 2017
June 30, 2018
June 30, 2017
February 28, 2017
Adjusted Net Income (Loss) reconciliation to Net income (loss) attributable to common stockholders
(in thousands)
Net income (loss) attributable to common stockholders
$
(33,711
)
$
760

$
6,716

$
(32,952
)
$
16,301

$
(502,964
)
 
 
 
 
 
 
 
Add (Subtract):
 
 
 
 
 
 
Losses (gains) on oil and natural gas derivatives
78,143

34,644

(23,962
)
112,787

(48,085
)
(12,886
)
Net cash received (paid) for scheduled derivative settlements
(28,261
)
(17,849
)
4,725

(46,110
)
5,856

534

Losses (gains) on sale of assets and other, net
123

—

5

123

5

(183
)
Non-recurring restructuring and other costs
1,714

2,047

16,846

3,761

24,442

—

Reorganization items, net
(456
)
(8,955
)
(713
)
(9,411
)
593

507,720

 
51,263

9,887

(3,099
)
61,150

(17,189
)
495,185

Income tax (expense) benefit of adjustments at effective tax rate
(8,370
)
(1,263
)
1,229

(10,594
)
6,815

 n/a

Adjusted Net Income (Loss)
$
9,182

$
9,384

$
4,846

$
17,604

$
5,927

$
(7,779
)

32

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
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
March 31, 2018
June 30, 2017
 
June 30, 2018
June 30, 2017
February 28, 2017
 
(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
 
 
 
 
 
 
 
General and administrative expenses
$
12,482

$
11,985

$
22,257

 
$
24,466

$
31,800

$
7,964

Subtract:
 
 
 
 
 
 
 
Non-recurring restructuring and other costs
(1,714
)
(2,047
)
(16,846
)
 
(3,761
)
(24,442
)
—

Non-cash stock compensation expense
(1,260
)
(1,019
)
—

 
(2,279
)
—

—

Adjusted General and Administrative Expenses
$
9,508

$
8,919

$
5,411

 
$
18,426

$
7,358

$
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 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 "-Chapter 11 Bankruptcy and our Emergence" and below in "Liquidity and Capital Resources."
 

33

Capital Expenditures and Capital Budget

For the three and six months ended June 30, 2018, our capital expenditures were approximately $39 million and $54 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 second half of 2018;
• drill approximately 180 to 190 gross development wells in 2018, of which we expect at least
175 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

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 completed the Chevron North Midway-Sunset Acquisition. We assumed a drilling commitment for the 214 acres of approximately $34.5 million to drill 115 wells, of which none have been drilled, on or before April 1, 2020, which has been extended to April 1, 2022, and 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.

Commodity Derivatives
Recently, we have utilized swaps, puts and calls to hedge a portion of our forecasted production and reduce exposure to fluctuations in oil and natural gas prices. 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

34

payments if the difference between Brent 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. Currently, our hedging program mainly consists of swaps and put options.
Our open derivative positions as of June 30, 2018 were as follows:
 
2018
2019
2020
Sold Oil Calls (ICE Brent):
 
 
 
  Hedged volume (MBbls)
186

—

—

  Weighted average price ($/Bbl)
$
81.67

$
—

$
—

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

2,835

455

  Weighted average price ($/Bbl)
$
—

$
65.00

$
65.00

Fixed Price Swaps (ICE Brent)
 
 
 
  Hedged volume (MBbls)
1,932

900

—

  Weighted average price ($/Bbl)
$
75.13

$
75.66

$
—

Oil basis differential positions:
 
 
 
ICE Brent - NYMEX WTI basis swaps
 
 
 
  Hedged volume (MBbls)
184

182.5

—

  Weighted average price ($/Bbl)
$
1.29

$
1.29

$
—

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
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
March 31, 2018
June 30, 2017
June 30, 2018
June 30, 2017
February 28, 2017
Crude Oil (per Bbl):
 
 
 
 
 
 
Realized price, before the effects of derivative settlements
$
67.93

$
62.14

$
44.27

$
65.06

$
44.34

$
46.94

Effects of derivative settlements
$
(14.71
)
$
(9.40
)
$
2.70

$
(12.08
)
$
2.50

$
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 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 hedged pricing more in line with current market pricing.
       


35

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 percent to 21 percent 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 16% and 17% in the three and six months ended June 30, 2018, respectively.  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 six months ended June 30, 2018. There were no current income taxes during the six months ended June 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 percent to 21 percent 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 quarter the analysis 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 $100.16 per Bbl on June 24, 2014 to a low of $40.67 per Bbl on January 20, 2016. The Henry Hub 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 Intercontinental Exchange Brent oil ("Brent"), New York Mercantile Exchange ("NYMEX") WTI oil and NYMEX Henry Hub natural gas prices for the three months ended June 30, 2018, March 31, 2018 and June 30, 2017, the six months ended June 30, 2018, the four months ended June 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
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
March 31, 2018
June 30, 2017
June 30, 2018
June 30, 2017
February 28, 2017
ICE (Brent) oil ($/Bbl)
$
74.87

$
67.16

$
50.90

$
71.01

$
51.31

$
55.72

NYMEX (WTI) oil ($/Bbl)
$
67.76

$
62.87

$
48.28

$
65.32

$
48.63

$
53.04

NYMEX Henry Hub natural gas ($MMBtu)
$
2.80

$
3.00

$
3.18

$
2.90

$
3.05

$
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

36

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.
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.
Seasonality
Seasonal weather conditions and lease stipulations can limit our drilling and producing 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.
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.

37

 
Berry Corp.
(Successor)
 
Three Months Ended
Three Months Ended
Three Months Ended
Variance
Variance
 
June 30, 2018
March 31, 2018
June 30, 2017
Q2 2018 vs. Q1 2018
Q2 2018 vs. Q2 2017
Average daily production:
 
 
 
 
 
Oil (MBbl/d)
21.1

21.1

19.2

—

1.9

Natural Gas (MMcf/d)
28.0

27.6

73.1

0.4

(45.1
)
NGL (MBbl/d)
0.7

0.5

2.9

0.2

(2.2
)
Total (MBoe/d)(1)
26.5

26.2

34.4

0.3

(7.9
)
Total Production:
 
 
 
 
 
Oil (MBbl)
1,920

1,897

1,752

23

168

Natural gas (MMcf)
2,551

2,481

6,656

70

(4,105
)
NGLs (MBbl)
62

45

267

17

(205
)
Total combined production (MBoe)(1)
2,408

2,356

3,128

52

(720
)
Weighted average realized prices:
 
 
 
—

—

Oil with hedges (Bbl)
$
53.22

$
52.74

$
46.97

$
0.48

$
6.25

Oil without hedges (Bbl)
$
67.93

$
62.14

$
44.27

$
5.79

$
23.66

Natural gas (Mcf)
$
2.12

$
2.64

$
2.74

$
(0.52
)
$
(0.62
)
NGL (Bbl)
$
24.38

$
25.56

$
22.72

$
(1.18
)
$
1.66

Average Benchmark prices:
 
 
 
$
—

$
—

Oil (Bbl) – Brent
$
74.87

$
67.16

$
50.90

$
7.71

$
23.97

Oil (Bbl) – WTI
$
67.76

$
62.87

$
48.28

$
4.89

$
19.48

Natural gas (MMBtu) – NYMEX Henry Hub
$
2.80

$
3.00

$
3.18

$
(0.20
)
$
(0.38
)
Average costs per Boe(2):
 
 
 
 
 
Lease operating expenses
$
17.24

$
18.80

$
14.62

$
(1.56
)
$
2.62

Electricity generation expenses
$
1.30

$
1.94

$
1.43

$
(0.64
)
$
(0.13
)
Electricity sales (2)
$
(2.48
)
$
(2.31
)
$
(1.83
)
$
(0.17
)
$
(0.65
)
Transportation expenses
$
0.97

$
1.26

$
3.01

$
(0.29
)
$
(2.04
)
Transportation sales (2)
$
(0.09
)
$
—

$
—

$
(0.09
)
$
(0.09
)
Marketing expenses
$
0.17

$
0.25

$
0.23

$
(0.08
)
$
(0.06
)
Marketing revenues (2)
$
(0.22
)
$
(0.33
)
$
(0.26
)
$
0.11

$
0.04

Total operating expenses
$
16.89

$
19.61

$
17.20

$
(2.72
)
$
(0.31
)
General and administrative expenses (3)
$
5.18

$
5.09

$
7.11

$
0.09

$
(1.93
)
Depreciation, depletion and amortization
$
9.08

$
7.82

$
6.57

$
1.26

$
2.51

Taxes, other than income taxes
$
3.62

$
3.50

$
3.28

$
0.12

$
0.34

(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $54.82 per Bbl and $3.11 per Mcf, respectively, resulting in an oil-to-gas ratio of over 17 to 1.

(2) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party

38

gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales, reported in "Other Revenues", relates to water and other liquids that we transport on our systems on behalf of third parties.

(3) Includes non-recurring restructuring and other costs and non-cash stock compensation expense, in aggregate, of approximately $1.24, $1.31 and $5.39 per Boe for the three months ended June 30, 2018, March 31, 2018 and June 30, 2017, respectively.
The following table sets forth average daily production by operating area for the periods indicated:
 
Berry Corp.
(Successor)
 
Three Months Ended
Three Months Ended
Three Months Ended
 
June 30, 2018
March 31, 2018
June 30, 2017
Average daily production (MBoe/d):
 
 
 
California(1)
18.8

18.8

16.3

Hugoton basin(2)
—

—

8.6

Uinta basin
5.3

5.0

5.9

Piceance basin
1.6

1.6

2.5

East Texas
0.8

0.8

1.1

 
26.5

26.2

34.4

    
(1)
On July 31, 2017, we purchased the remaining approximately 84% working interest of our South Belridge Hill property, located in Kern County, California.
(2)
On July 31, 2017, we sold our 78% working interest in the Hugoton natural gas field located in southwest Kansas and the Oklahoma Panhandle. Our Hugoton assets represented approximately 24% of our average net daily production for the year ended December 31, 2016.
Average daily production volumes decreased to approximately 26.5 MBoe/d or 23% for the three months ended June 30, 2018 from approximately 34.4 MBoe/d for the three months ended June 30, 2017. The decrease primarily reflected the decreased natural gas and NGL volumes from the sale of an approximately 78% non-operating, working interest in the Hugoton natural gas field (the "Hugoton Disposition") in July 2017, partially offset by the additional oil volumes from the acquisition of an approximately 84% non-operating, working interest in a South Belridge Hill property, (the "Hill Acquisition") in July 2017. Also contributing to the decrease to a lesser degree was the delay between our increase in capital spending in late 2017 to arrest production declines due to reduced capital spending in 2016 and early 2017, and the effectiveness of the increase which we began to observe in early and mid 2018.
Average daily production volumes increased for the three months ended June 30, 2018 compared to the three months ended March 31, 2018 due to the increased development capital spending in late 2017 and early 2018.
The following tables set forth information regarding total production, average daily production, average prices and average costs for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods. The information for the six months ended June 30, 2017 are reflected in the tables and narrative discussion that follows in two distinct periods, the four months ended June 30, 2017 and the two months ended February 28, 2017, as a result of our emergence from bankruptcy on February 28, 2017. References in these results of operations to the six months ended June 30, 2017 are used to provide comparable periods. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for comparing the periods presented.


39

 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
June 30, 2017
February 28, 2017
 
 
 
 
Average Daily Production:
 
 
 
Oil (MBbl/d)
21.1

19.2

19.5

Natural Gas (MMcf/d)
27.8

72.8

71.7

NGL (MBbl/d)
0.6

3.1

5.2

Total (MBoe/d)(1)
26.3

34.4

36.6

Total Production:
 
 
 
Oil (MBbl)
3,818

2,338

1,153

Natural gas (MMcf)
5,032

8,877

4,232

NGLs (MBbl)
108

379

304

Total combined production (MBoe)(1)
4,764

4,196

2,162

Weighted average realized prices:
 
 
 
Oil with hedges (Bbl)
$
52.98

$
46.84

$
47.40

Oil without hedges (Bbl)
$
65.06

$
44.34

$
46.94

Natural gas (Mcf)
$
2.38

$
2.67

$
3.42

NGL (Bbl)
$
24.88

$
21.64

$
18.20

Average benchmark prices:
 
 
 
Oil (Bbl) – Brent
$
71.01

$
51.31

$
55.72

Oil (Bbl) – WTI
$
65.32

$
48.63

$
53.04

Natural gas (MMBtu) – NYMEX Henry Hub
$
2.90

$
3.05

$
3.66

Average costs per Boe (2):
 
 
 
Lease operating expenses
$
18.01

$
14.01

$
13.06

Electricity generation expenses
$
1.62

$
1.34

$
1.48

Electricity sales (2)
$
(2.40
)
$
(1.57
)
$
(1.69
)
Transportation expenses
$
1.12

$
3.11

$
2.86

Transportation sales (2)
$
(0.05
)
$
—

$
—

Marketing expenses
$
0.21

$
0.24

$
0.30

Marketing revenues (2)
$
(0.27
)
$
(0.26
)
$
(0.29
)
Total operating expenses
$
18.24

$
16.87

$
15.72

General and administrative expenses (3)
$
5.14

$
7.58

$
3.68

Depreciation, depletion and amortization
$
8.46

$
6.57

$
13.02

Taxes, other than income taxes
$
3.56

$
3.18

$
2.41

(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years.

(2) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party

40

gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales, reported in "Other Revenues", relate to water and other liquids that we transport on our systems on behalf of third parties.

(3) Includes non-recurring restructuring and other costs and non-cash stock compensation expense, in aggregate, of approximately $1.28, $5.83 and none per Boe for the six months ended June 30, 2018, the four months ended June 30, 2017 and the two months ended February 28, 2017, respectively.
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
June 30, 2017
February 28, 2017
Average daily production (MBoe/d):
 
 
 
California (San Joaquin) (1)
18.8

16.3

17.0

Hugoton basin(2)
—

8.9

10.8

Uinta basin
5.1

5.7

5.4

Piceance basin
1.6

2.5

2.3

East Texas
0.8

1.0

1.1

 
26.3

34.4

36.6

Average daily production volumes decreased to approximately 26.3 MBoe/d for the six months ended June 30, 2018 from approximately 35.1 MBoe/d for the six months ended June 30, 2017, including the successor and predecessor periods. The decrease primarily reflected the decreased natural gas and NGL volumes from the sale of the approximately 78% non-operating, working interest in the Hugoton natural gas field in July 2017, partially offset by the additional oil volumes from the Hill Acquisition. Also contributing to the decrease, to a lesser degree, was the delayed impact of increasing capital after our emergence from bankruptcy in early 2017 following the reduced development capital spending in 2016 and early 2017.

41

Balance Sheet Analysis

The changes in our balance sheet from December 31, 2017 to June 30, 2018 are discussed below.
 
Berry Corp. (Successor)
 
June 30, 2018
 
December 31, 2017
 
(in thousands)
Cash and cash equivalents
$
3,600

 
$
33,905

Accounts receivable, net
$
56,860

 
$
54,720

Restricted cash
$
19,710

 
$
34,833

Other current assets
$
14,981

 
$
14,066

Property, plant & equipment, net
$
1,397,919

 
$
1,387,191

Other noncurrent assets
$
22,086

 
$
21,687

Accounts payable and accrued liabilities
$
113,170

 
$
97,877

Derivative instruments-current and long term
$
15,010

 
$
60,165

Liabilities subject to compromise
$
19,710

 
$
34,833

Long term debt
$
457,333

 
$
379,000

Asset retirement obligation
$
88,575

 
$
94,509

Other noncurrent liabilties
$
12,862

 
$
3,704

Equity
$
808,496

 
$
859,310


See “Liquidity and Capital Resources” for a discussion about the changes in cash and cash equivalents, as well as long term debt.

Restricted cash at June 30, 2018 and December 31, 2017 represents funds set aside to settle the general unsecured creditors claims resulting from our bankruptcy process. The decrease in restricted cash, and the corresponding decrease in liabilities subject to compromise, represents the settlement of these claims, the return of undistributed funds in the amount of $9 million and professional fees related to the settlement of these claims.

The increase in accounts payable and accrued liabilities is largely the result of the new interest payment obligations on our 2026 Notes, issued in February of 2018 of $11 million.

The decrease in the derivative liability reflects the early termination and replacement of certain hedge contracts to move from a WTI-based position to a Brent-based position and to align our hedging program with higher current commodity prices.

The increase in long term debt represents the issuance of our 2026 Notes in February 2018 in the principal amount of $400 million and the usage of the proceeds to pay down the $379 million balance on our RBL Facility, partially offset by $66 million of additional RBL Facility borrowings in the second quarter of 2018.

The increase in other noncurrent liabilities represents an additional greenhouse gas liability of $9 million for production during the six months ended June 30, 2018 and which is due for payment more than one year from June 30, 2018.

The decrease in equity reflects the $20 million repurchase from certain general unsecured creditors of the right to receive shares of our common stock in settlement of their claims, the declaration of approximately $11 million in dividends on our Series A Preferred Stock and our results of operations.






42

Results of Operations
Results of Operations - Three Months Ended June 30, 2018 compared to Three Months Ended March 31, 2018.
 
Berry Corp.
(Successor)
 
 
Three Months Ended
Three Months Ended
 
 
(in thousands)
June 30, 2018
March 31, 2018
$ Change
% Change
Revenues and other:
 
 
 
 
Oil, natural gas and NGL sales
$
137,385

$
125,624

$
11,761

9
 %
Electricity sales
5,971

5,453

518

9
 %
(Losses) gains on oil and natural gas derivatives
(78,143
)
(34,644
)
(43,499
)
126
 %
Marketing and other revenues
769

851

(82
)
(10
)%
 
65,982

97,284

(31,302
)
(32
)%
Expenses and other:
 
 
 
 
Lease operating expenses
41,517

44,303

(2,786
)
(6
)%
Electricity generation expenses
3,135

4,590

(1,455
)
(32
)%
Transportation expenses
2,343

2,978

(635
)
(21
)%
Marketing expenses
407

580

(173
)
(30
)%
General and administrative expenses
12,482

11,985

497

4
 %
Depreciation, depletion, amortization and accretion
21,859

18,429

3,430

19
 %
Taxes, other than income taxes
8,715

8,256

459

6
 %
(Gains) losses on sale of assets and other, net
123

—

123

 
 
90,581

91,121

(540
)
(1
)%
Other income and (expenses):
 
 
 
 
Interest expense
(9,155
)
(7,796
)
(1,359
)
17
 %
Other, net
(239
)
27

(266
)
(985
)%
Reorganization items, net
456

8,955

(8,499
)
(95
)%
Income (loss) before income taxes
(33,537
)
7,349

(40,886
)
(556
)%
Income tax expense (benefit)
(5,476
)
939

(6,415
)
(683
)%
Net income (loss)
(28,061
)
6,410

(34,471
)
(538
)%
Dividends on Series A Preferred Stock
(5,650
)
(5,650
)
—

—
 %
Net income (loss) available to common stockholders
$
(33,711
)
$
760

$
(34,471
)
(4,536
)%
 
 
 
 
 
Revenues and Other
Oil, natural gas and NGL sales increased $12 million, or 9% to approximately $137 million for the three months ended June 30, 2018 compared to the three months ended March 31, 2018. The increase reflects improved oil prices and a slight increase in production.
Electricity sales represent sales to utilities and increased by approximately $0.5 million, or 9%, to approximately $6 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018. The increase was primarily due to higher seasonal prices.
 
Losses on oil and natural gas derivatives were approximately $78 million for the three months ended June 30, 2018 compared to losses of approximately $35 million for the three months ended March 31, 2018. The increase represents improved commodity prices relative to the fixed prices of our derivative contracts.

43

Marketing and other revenues for the three months ended June 30, 2018 were comparable to the three months ended March 31, 2018. Marketing revenues in these periods primarily represent sales of third-party natural gas and were comparable for these periods.
Expenses and other
We report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales, reported in "Other Revenues", relate to water and other liquids that we transport on our systems on behalf of third parties.
Operating expenses, as defined above, decreased to $16.89 per Boe for the quarter ended June 30, 2018 from $19.61 per Boe for the quarter ended March 31, 2018, for the reasons noted below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $3 million, or 6%, to approximately $42 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018. The decrease was primarily due to lower well servicing activity, lower fuel gas costs and increased oil inventory caused by market disruptions in Utah in the quarter ended June 30, 2018. For the same reasons, lease operating expenses per Boe decreased to $17.24 per Boe for the three months ended June 30, 2018 from $18.80 per Boe for the three months ended March 31, 2018.
Electricity generation expenses decreased by approximately $1.5 million or 32% for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to lower fuel gas costs and reduced cogen operating costs due to replacement of a third party service provider with internal staffing.
Transportation expenses decreased by approximately $0.6 million, or 21%, to approximately $2 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018, primarily due to reduced costs for use of certain third-party systems.
Marketing expenses for the three months ended June 30, 2018 were comparable to the three months ended March 31, 2018.
General and administrative expenses increased by approximately $0.5 million, or 4%, to approximately $12 million for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to increased costs related to preparing to be a public company. The increase in absolute dollars incurred resulted in slightly higher general and administrative expenses of $5.18 per Boe for the three months ended June 30, 2018, compared to $5.09 per Boe for the three months ended March 31, 2018. For the three months ended June 30, 2018 and March 31, 2018, general and administrative expenses included non-recurring restructuring and other costs of approximately $1.7 million and $2.0 million, respectively, and non-cash stock compensation costs of approximately $1.3 million and $1.0 million, respectively.
Depreciation, depletion and amortization ("DD&A") increased by approximately $3 million, or 19%, to approximately $22 million for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to increased DD&A rates, slightly higher production and increased asset retirement accretion expense.








44


Taxes, Other Than Income Taxes
 
Berry Corp. (Successor)
 
Three Months Ended
Three Months Ended
 
 
June 30, 2018
March 31, 2018
Variance
(in thousands)
 
 
 
Severance taxes
$
2,997

$
2,764

$
233

Ad valorem and property taxes
3,141

3,417

(276
)
Greenhouse gas allowances
2,577

2,075

502

 
$
8,715

$
8,256

$
459

 
 
 
 
 
 
 
 
For the three months ended June 30, 2018 compared to the three months ended March 31, 2018, greenhouse gas allowance costs increased due to the higher unit cost and increased activity.
Other income and (expenses)
 
Berry Corp.
(Successor)
 
Three Months Ended
Three Months Ended
 
 
June 30, 2018
March 31, 2018
Variance
(in thousands)
 
 
 
Interest expense, net of amounts capitalized
$
(9,155
)
$
(7,796
)
$
(1,359
)
Other, net
(239
)
27

(266
)
 
$
(9,394
)
$
(7,769
)
$
(1,625
)
Interest expense increased for the three months ended June 30, 2018 by $1.4 million or 17%, compared to the three months ended March 31, 2018, due to increased borrowings on the RBL Facility and three months of the interest on the 2026 Notes in the second quarter versus one and a half months in the first quarter.
The following table summarizes the components of reorganization items included in the statement of operations:
 
Berry Corp. (Successor)
 
Three Months Ended
Three Months Ended
 
(in thousands)
June 30, 2018
March 31, 2018
Variance
Return of Undistributed Funds from Cash Distribution Pool
$
—

$
9,000

$
(9,000
)
Refund of pre-emergence prepaid costs
—

579

(579
)
Legal and other professional advisory fees
(1,178
)
(624
)
(554
)
Gain on resolution of pre-emergence liabilities
1,634

—

1,634

 
$
456

$
8,955

$
(8,499
)
Reorganization items, net consisted of a gain of approximately $0.5 million for the three months ended June 30, 2018. The gain was primarily due to the resolution of certain pre-emergence liabilities, partially offset by legal and other professional fees. For the three months ended March 31, 2018, the gain of $9 million reflected the return of undistributed funds reserved for settlement of claims of general unsecured creditors.

45

Income taxes
The three months ended June 30, 2018 had a $5.5 million tax benefit compared to income tax expense of $0.9 million for the three months ended March 31, 2018. The effective tax rate was 16% for the three months ended June 30, 2018 and 13% for the three months ended March 31, 2018.
         
Results of Operations - Three Months Ended June 30, 2018 compared to Three Months Ended June 30, 2017.
 
Berry Corp.
(Successor)
 
 
Three Months Ended
Three Months Ended
 
 
(in thousands)
June 30, 2018
June 30, 2017
$ Change
% Change
Revenues and other:
 
 
 
 
Oil, natural gas and NGL sales
$
137,385

$
101,884

$
35,501

35
 %
Electricity sales
5,971

5,712

259

5
 %
(Losses) gains on oil and natural gas derivatives
(78,143
)
23,962

(102,105
)
(426
)%
Marketing and other revenues
769

3,164

(2,395
)
(76
)%
 
65,982

134,722

(68,740
)
(51
)%
Expenses and other:
 
 


 
Lease operating expenses
41,517

45,726

(4,209
)
(9
)%
Electricity generation expenses
3,135

4,465

(1,330
)
(30
)%
Transportation expenses
2,343

9,404

(7,061
)
(75
)%
Marketing expenses
407

730

(323
)
(44
)%
General and administrative expenses
12,482

22,257

(9,775
)
(44
)%
Depreciation, depletion, amortization and accretion
21,859

20,549

1,310

6
 %
Taxes, other than income taxes
8,715

10,249

(1,534
)
(15
)%
(Gains) losses on sale of assets and other, net
123

5

118

2,360
 %
 
90,581

113,385

(22,804
)
(20
)%
Other income and (expenses):
 
 


 
Interest expense
(9,155
)
(4,885
)
(4,270
)
87
 %
Other, net
(239
)
2,916

(3,155
)
(108
)%
Reorganization items, net
456

713

(257
)
(36
)%
Income (loss) before income taxes
(33,537
)
20,081

(53,618
)
(267
)%
Income tax expense (benefit)
(5,476
)
7,961

(13,437
)
(169
)%
Net income (loss)
(28,061
)
12,120

(40,181
)
(332
)%
Dividends on Series A Preferred Stock
(5,650
)
(5,404
)
(246
)
5
 %
Net income (loss) available to common stockholders
$
(33,711
)
$
6,716

$
(40,427
)
(602
)%
 
 
 
 
 
Revenues and Other
Oil, natural gas and NGL sales increased $36 million, or 35% to approximately $137 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017. The increase reflects improved oil prices and an increased mix of oil production compared to gas production as a result of the Hill Acquisition and Hugoton Disposition, partially offset by decreased production on an oil-equivalent basis.

46

Electricity sales represent sales to utilities and increased by approximately $0.3 million, or 5%, to approximately $6 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. The increase was primarily due to higher volumes sold externally as a result of lower downtime at our cogens in the three months ended June 30, 2018 than the three months ended June 30, 2017.
Losses on oil and natural gas derivatives were approximately $78 million for the three months ended June 30, 2018 compared to approximately $24 million of gains for the three months ended June 30, 2017. Losses on oil and natural gas derivatives for the three months ended June 30, 2018 were primarily due to an increase in hedging activity, a portion of which was required by the RBL Facility at closing in July 2017, and improved commodity prices relative to the fixed prices of our derivative contracts.
Marketing and other revenues decreased by approximately $2 million, or 76%, to approximately $0.8 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. Marketing revenues in these periods primarily represent sales of third-party natural gas and were comparable for these periods. Other revenues in 2017 comprised mostly helium sales, all of which were derived from our Hugoton asset prior to its disposition in July 2017.
Expenses and Other
We report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.
Operating expenses, as defined above, decreased to $16.89 per Boe for the quarter ended June 30, 2018 from $17.20 per Boe for the quarter ended June 30, 2017, for the reasons noted below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $4 million, or 9%, to approximately $42 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. The decrease was primarily due to a decrease in the price of fuel gas used in operations. Further, lease operating expenses per Boe increased to $17.24 per Boe for the three months ended June 30, 2018 from $14.62 per Boe for the three months ended June 30, 2017, primarily due to increased oil production to 80% of total production from 56% of total production as a result of the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) which adversely impacted costs per Boe. Replacing low cost natural gas production with oil production in 2017 had a disproportionate impact (oil volume rose 10% and gas volume decreased 62% but cost per Boe rose 18%), on our costs per Boe when comparing these respective periods.
Electricity generation expenses decreased approximately $1 million or 30% to $3 million for the three months ended June 30, 2018 and the three months ended June 30, 2017, primarily due to a decrease in the price of natural gas.
Transportation expenses decreased by approximately $7 million, or 75%, to approximately $2 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017, primarily due to the Hugoton Disposition of gas properties, which required significant transportation expense because gas transportation is generally borne by the seller and oil transportation costs are borne by the buyer.
Marketing expenses decreased $0.3 million or 44% to $0.4 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the decrease in natural gas prices.
General and administrative expenses decreased by approximately $10 million, or 44%, to approximately $12 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the management change in conjunction with our emergence from bankruptcy. The reduction in absolute dollars spent, as well as lower production volumes resulted in lower general and administrative expenses of $5.18 per Boe for the three months ended June 30, 2018, compared to $7.11 per Boe for the three months ended June 30, 2017. For the three months ended June 30, 2018, general and administrative expenses included non-recurring restructuring and other costs of approximately $1.7 million and non-cash stock compensation costs of approximately $1.3 million. For the three months ended June 30, 2017, general and administrative expenses included non-recurring restructuring and other costs of approximately $17 million and no non-cash stock compensation costs.
DD&A increased by approximately $1 million, or 6%, to approximately $22 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the Hill Acquisition. The Hill property which had a higher depletion rate than the Hugoton field.



47


Taxes, Other Than Income Taxes
 
Berry Corp. (Successor)
 
Three Months Ended
Three Months Ended
 
 
June 30, 2018
June 30, 2017
Variance
(in thousands)
 
 
 
Severance taxes
$
2,997

$
2,466

$
531

Ad valorem and property taxes
3,141

4,498

(1,357
)
Greenhouse gas allowances
2,577

3,285

(708
)
 
$
8,715

$
10,249

$
(1,534
)
Taxes, other than income taxes decreased by approximately $1.5 million or 15% for the three months ended June 30, 2018 compared to the three months ended June 30, 2017 due to (i) an increase in gross sales revenue which is the basis for severance taxes, (ii) lower ad valorem and property taxes due to reduced tax assessments in 2018 and (iii) lower prices for greenhouse gas emission credits, partially offset by an increase in emissions in 2018.
Other income and (expenses)
 
Berry Corp. (Successor)
 
Three Months Ended
Three Months Ended
 
 
June 30, 2018
June 30, 2017
Variance
(in thousands)
 
 
 
Interest expense, net of amounts capitalized
$
(9,155
)
$
(4,885
)
$
(4,270
)
Other, net
(239
)
2,916

(3,155
)
 
$
(9,394
)
$
(1,969
)
$
(7,425
)
Interest expense increased for the three months ended June 30, 2018 by approximately $4 million or 87%, compared to the three months ended June 30, 2017, primarily due to the addition of interest expense on the 2026 Notes, which were issued in February 2018, partially offset by lower interest on the RBL Facility due to the decrease in borrowings period over period.
The following table summarizes the components of reorganization items included in the statement of operations:
 
Berry Corp. (Successor)
 
Three Months Ended
Three Months Ended
 
(in thousands)
June 30, 2018
June 30, 2017
Variance
Legal and other professional advisory fees
(1,178
)
(3,199
)
2,021

Gain on resolution of pre-emergence liabilities
1,634

3,912

(2,278
)
 
$
456

$
713

$
(257
)
Reorganization items, net consisted of a gain of approximately $0.5 million for the three months ended June 30, 2018, compared to the $0.7 million gain for the three months ended June 30, 2017. The second quarter 2018 gain was primarily due to the resolution of certain pre-emergence liabilities, partially offset by legal and other professional fees. The 2017 gain amount was primarily due to a resolution of certain pre-emergence liabilities of $3.9 million partially offset by legal and professional fees to resolve outstanding bankruptcy-related claims.
Income tax benefit was $5.5 million for the three months ended June 30, 2018, compared to the income tax expense of $8.0 million for the three months ended June 30, 2017 due to recording pre-tax loss in 2018 compared to pre-tax income in 2017. The decrease in the effective tax rates from 40% in 2017 to 16% in 2018 was primarily a result of the new tax laws for 2018.

48

Results of Operations - Six Months Ended June 30, 2018 compared to the Six Months ended June 30, 2017 , including the successor and predecessor periods.
Our results of operations for the six months ended June 30, 2017 are reflected in the tables and narrative discussion that follow in two distinct periods, the four months ended June 30, 2017 and the two months ended February 28, 2017, as a result of our emergence from bankruptcy on February 28, 2017. References in these results of operations to the six months ended June 30, 2017 are used to provide comparable periods. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for comparing the periods presented.
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
 
 
(a)
(b)
(c)
(a)-((b)+(c))
 
 
Six Months Ended
Four Months Ended
Two Months Ended
 
 
 
June 30, 2018
June 30, 2017
February 28, 2017
$ Change
% Change
(in thousands)
 
 
 
 
 
Revenues and other:
 
 
 
 
 
Oil, natural gas and NGL sales
$
263,010

$
135,562

$
74,120

$
53,328

25
 %
Electricity sales
11,423

6,603

3,655

1,165

11
 %
(Losses) gains on oil and natural gas derivatives
(112,787
)
48,085

12,886

(173,758
)
(285
)%
Marketing and other revenues
1,619

4,127

2,057

(4,565
)
(74
)%
 
163,265

194,377

92,718

(123,830
)
(43
)%
Expenses and other:
 
 
 
—

 
Lease operating expenses
85,819

58,790

28,238

(1,209
)
(1
)%
Electricity generation expenses
7,725

5,613

3,197

(1,085
)
(12
)%
Transportation expenses
5,321

13,059

6,194

(13,932
)
(72
)%
Marketing expenses
987

1,000

653

(666
)
(40
)%
General and administrative expenses
24,466

31,800

7,964

(15,298
)
(38
)%
Depreciation, depletion, amortization and accretion
40,288

27,571

28,149

(15,432
)
(28
)%
Taxes, other than income taxes
16,972

13,330

5,212

(1,570
)
(8
)%
(Gains) losses on sale of assets and other, net
123

5

(183
)
301

(169
)%
 
181,701

151,168

79,424

(48,891
)
(21
)%
Other income and (expenses):
 
 
 
—

 
Interest expense
(16,951
)
(6,600
)
(8,245
)
(2,106
)
14
 %
Other, net
(212
)
2,916

(63
)
(3,065
)
(107
)%
Reorganization items, net
9,411

(593
)
(507,720
)
517,724

(102
)%
Income (loss) before income taxes
(26,188
)
38,932

(502,734
)
437,614

(94
)%
Income tax expense (benefit)
(4,537
)
15,435

230

(20,202
)
(129
)%
Net income (loss)
(21,651
)
23,497

(502,964
)
457,816

(95
)%
Dividends on Series A Preferred Stock
(11,301
)
(7,196
)
—

(4,105
)
57
 %
Net income (loss) available to common stockholders
$
(32,952
)
$
16,301

$
(502,964
)
$
453,711

(93
)%

49

Revenues and Other
Oil, natural gas and NGL sales increased approximately $53 million, or 25% to approximately $263 million for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods. The increase reflects improved oil prices and an increased mix of oil production compared to gas production as a result of the Hill Acquisition and Hugoton Disposition, partially offset by decreased overall production, as well as slightly lower gas prices.
Electricity sales represent sales to utilities and increased by approximately $1 million, or 11%, to approximately $11 million for the six months ended June 30, 2018, compared to the six months ended June 30, 2017, including the successor and predecessor periods, primarily due to higher volumes sold externally as a result of lower downtime at our cogens.
Losses on oil and natural gas derivatives increased to approximately $113 million in the six months ended June 30, 2018, compared to gains of approximately $61 million in the six months ended June 30, 2017, including the successor and predecessor periods. Losses on oil and natural gas derivatives in 2018 were primarily due to an increase in hedging activity, a portion of which was required by the RBL Facility at closing in July 2017, and improved commodity prices relative to the fixed prices of our derivative contracts.
Marketing and other revenues decreased approximately $5 million or 74% for the six months ended June 30, 2018 when compared to the six months ended June 30, 2017, including successor and predecessor periods, primarily due to the lost helium sales revenue as a result of the Hugoton Disposition.
Expenses and other
We report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. Operating expenses increased to $18.24 per Boe for the six months ended June 30, 2018 from $15.78 for the six months ended June 30, 2017 including the successor and predecessor periods, for the reasons described below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses in absolute dollars for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods, reflected lower fuel gas costs offset by higher activity in 2018 compared to 2017. Lease operating expenses per Boe increased to $18.01 per Boe for the six months ended June 30, 2018, from $13.69 per Boe for the six months ended June 30, 2017, including the successor and predecessor periods. The increase in oil production to 80% of total production from 56% as a result of the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) adversely impacted costs per Boe in 2018 compared to 2017.
Electricity generation expenses were comparable for the six months ended June 30, 2018 and the six months ended June 30, 2017, including the successor and predecessor periods.
Transportation expenses decreased by approximately $14 million or 72% for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including successor and predecessor periods, primarily due to the Hugoton disposition of gas properties, which required significant transportation expense because gas transportation is generally borne by the seller and oil transportation costs are borne by the buyer.
Marketing expenses decreased $0.7 million or 40% for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including successor and predecessor periods, primarily due to the decrease in natural gas prices.
General and administrative expenses decreased by approximately $15 million for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including successor and predecessor periods, in terms of absolute dollars, primarily due to the reduced spending on non-recurring restructuring and other costs, slightly offset by increased headcount-related costs. This activity was consistent with our post-emergence efforts to build out our corporate structure while reducing restructuring costs. This also resulted in a decrease in general and administrative expenses per Boe to $5.14 in 2018 from $6.25 in 2017 For the six months ended June 30, 2018 and 2017, general and administrative expenses included non-recurring restructuring and other costs of approximately $4 million and $24 million, respectively, and non-cash stock compensation costs of approximately $2.3 million and none, respectively.
Depreciation, depletion and amortization decreased by approximately $15 million, or 28% for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including successor and predecessor periods, primarily due to the increase in oil and gas reserves in 2018, which resulted in lower DD&A rates and the fair market revaluation of our assets in fresh start accounting which resulted in a lower depreciable asset base in the periods following our emergence from bankruptcy.

50

Taxes, Other Than Income Taxes
 
Berry Corp. (Successor)
Berry LLC (Predecessor)
 
 
Six Months Ended
Four Months Ended
Two Months Ended
 
 
June 30, 2018
June 30, 2017
February 28, 2017
Variance
 
(a)
(b)
(c)
(a)-((b)+(c))
(in thousands)
 
 
 
 
Severance taxes
$
5,761

$
3,611

$
1,540

$
610

Ad valorem and property taxes
6,558

5,572

2,108

(1,122
)
Greenhouse gas allowances
4,653

4,146

1,564

(1,057
)
 
$
16,972

$
13,329

$
5,212

$
(1,569
)
Taxes, other than income taxes decreased by approximately $1.5 million or 15% for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods, due to (i) an increase in gross sales revenue which is the basis for severance taxes (ii) lower ad valorem and property taxes due to reduced tax assessments in 2018 and (iii) lower prices for greenhouse gas emission credits, partially offset by an increase in emissions in 2018.
Other income and (expenses)
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
 
Six Months Ended
Four Months Ended
Two Months Ended
 
 
June 30, 2018
June 30, 2017
February 28, 2017
Variance
 
(a)
(b)
(c)
(a)-((b)+(c))
(in thousands)
 
 
 
 
Interest expense, net of amounts capitalized
$
(16,951
)
$
(6,600
)
$
(8,245
)
$
(2,106
)
Other, net
(212
)
2,916

(63
)
(3,065
)
 
$
(17,163
)
$
(3,684
)
$
(8,308
)
$
(5,171
)
Interest expense increased by $2 million or 14% for the six months ended June 30, 2018, compared to the six months ended June 30, 2017, including successor and predecessor periods, due to the additional 7% interest expense on the 2026 Notes which were issued in February 2018, partially offset by lower interest on the RBL Facility due to the decrease in borrowings from $385 million at June 30, 2017 to $66 million at June 30, 2018. Other, net for the four months ended June 30, 2017 primarily represents the refund of an overpayment on taxes from a prior year.











51


The following table summarizes the components of reorganization items included in the statement of operations:
 
Berry Corp. (Successor)
Berry LLC (Predecessor)
 
 
Six Months Ended
Four Months Ended
Two Months Ended
 
(in thousands)
June 30, 2018
June 30, 2017
February 28, 2017
Variance
 
(a)
(b)
(c)
(a)-((b)+(c))
Return of Undistributed Funds from Cash Distribution Pool
$
9,000

$
—

$
—

$
9,000

Legal and other professional advisory fees
(1,223
)
112

(19,481
)
18,146

Gain on resolution of pre-emergence suspended royalties
—

—

421,774

(421,774
)
Fresh-start valuation adjustments
—

—

(920,699
)
920,699

Gain on resolution of pre-emergence liabilities
1,634

—

—

1,634

Other
—

(705
)
10,686

(9,981
)
 
$
9,411

$
(593
)
$
(507,720
)
$
517,724

Reorganization items, net reflected a gain of approximately $9 million for the six months ended June 30, 2018, compared to an expense of approximately $507 million for the six months ended June 30, 2017, including successor and predecessor periods. The gain for the six months ended 2018 was primarily due to a return of $9 million from the funds reserved for the claims of the general unsecured creditors and the resolution of pre-emergence liabilities in the amount of $1.6 million offset by legal and professional fees of $1.2 million.
The loss for the two months ended February 28, 2017 was primarily due to the application of fresh-start accounting in conjunction with our emergence from bankruptcy, partially offset by the gain on settlement of liabilities subject to compromise. Reorganization items represent costs and income directly associated with the Chapter 11 Proceedings and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.
Income tax benefit was $4.5 million for the six months ended June 30, 2018, compared to an income tax expense of approximately $15.7 million for the six months ended June 30, 2017, including the successor and predecessor periods, due to recording pre-tax income in 2018 compared to a pre-tax loss in 2017. The decrease in the effective tax rates from 40% in 2017 to 17% in 2018 was primarily a result of the new tax laws for 2018.
For federal and state income tax purposes (with the exception of the State of Texas), the predecessor company was a limited liability company in which income tax liabilities and/or benefits were passed through to the Predecessor's unitholders. The Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the predecessor company resulting in an effective tax rate of zero for the two months ended February 28, 2017. The successor company was formed as a C Corporation.
Liquidity and Capital Resources
Currently, we expect our primary sources of liquidity and capital resources will be internally generated free cash flow from operations after debt service, or levered free cash flow, and as needed, borrowings under the RBL Facility. Depending upon market conditions and other factors, we have issued and may issue additional equity and debt securities; however, we expect our operations to continue to generate sufficient levered free cash flow at current commodity prices to fund maintenance operations and organic growth. We believe our liquidity and capital resources will be sufficient to conduct our business and operations for the next 12 months.
In February 2018, we issued our 2026 Notes, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds to repay borrowings under the RBL Facility and used the remainder for general corporate purposes.

52

In March 2018, our 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 made to stockholders of record as of June 7, 2018.
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 sold 10,497,849 shares and the selling stockholders sold 2,545,630 shares at a price of $14.00 per share. We used a portion of our proceeds to repurchase 1,802,196 shares of our common stock owned by Benefit Street Partners and Oaktree Capital Management. After giving effect to the IPO and the share repurchase, the number of shares of our common stock outstanding increased by 8,695,653. We and the selling stockholders have granted the underwriters the option to purchase up to an additional 1,534,895 shares and 421,626 shares of common stock, respectively, on the same terms and conditions set forth above.
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. 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 Company received approximately $136 million in net proceeds from the offering after deducting underwriting discounts and offering expenses payable by us. We did not receive any proceeds from the sale by the selling stockholders. We used approximately $24 million of the net proceeds to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the offering) from funds affiliated with Benefit Street Partners and Oaktree Capital Management.
Of the remaining approximately $112 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 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. On August 20, 2018, we had approximately $388 million of available borrowing capacity under the RBL Facility and approximately $36 million of cash on hand.
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 will result in a payment of $0.09 per share.
The RBL Facility contains certain financial covenants, including the maintenance of (i) a Leverage Ratio (as defined in the RBL Facility) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the RBL Facility) not to be less than 1.00:1.00. As of June 30, 2018, our Leverage Ratio and Current Ratio were 2.63:1.00 and 3.18:1.00, respectively. As of June 30, 2018 our borrowing base was approximately $400 million and we had $327 million available for borrowing under the RBL Facility. At June 30, 2018, we were in compliance with the financial covenants under the RBL Facility. In connection with the issuance of the 2026 Notes, 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 that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. Borrowing base redeterminations become effective on, or about, each May 1 and November 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations.
Historically, the Predecessor utilized funds from debt offerings, borrowings under its credit facility and net cash provided by operating activities, as well as funding from our former parent, for capital resources and liquidity, and the primary use of capital was for the development of oil and natural gas properties.
We have protected a significant portion of our anticipated cash flows through our commodity hedging program, including through fixed-price derivative contracts. As of June 30, 2018, we have hedged crude oil production of approximately 2.1 MMBbls for 2018, 3.7 MMBbls for 2019 and 0.5 MMBbls for 2020.
Future cash flows are subject to a number of variables discussed in "Risk Factors". Further, our capital investment budget for the year ended December 31, 2018, does not allocate any amounts for acquisitions of oil and natural gas properties. If we make acquisitions, we would be required to reduce the expected level of capital investments or seek additional capital. If we require additional capital we may seek such capital through borrowings under the RBL Facility, joint venture partnerships, production payment financings, asset sales, additional offerings of debt or equity securities or other means. We cannot be sure that needed

53

capital would be available on acceptable terms or at all. If we are unable to obtain funds on acceptable terms, we may be required to curtail our current development programs, which could result significant declines in our production.
See "-Capital Expenditures and Capital Budget" for a description of our 2018 capital expenditure budget.
Statements of Cash Flows
The following is a comparative cash flow summary:
 
Berry Corp. (Successor)
Berry LLC (Predecessor)
 
Six Months Ended
Four Months Ended
Two Months Ended
 
June 30, 2018
June 30, 2017
February 28, 2017
(in thousands)
 
 
 
Net cash:
 
 
 
  Provided by (used in) operating activities
$
(49,548
)
$
44,937

$
22,431

  Used in investing activities
(42,347
)
(72,328
)
(3,133
)
  Provided by (used in) financing activities
46,467

(15,000
)
(162,668
)
Net decrease in cash, cash equivalents and restricted cash
$
(45,428
)
$
(42,391
)
$
(143,370
)
 
 
 
 
Operating Activities
Cash used in operating activities was approximately $50 million for the six months ended June 30, 2018 compared to cash provided by operating activities of approximately $67 million for the six months ended June 30, 2017, including the successor and predecessor periods. The amounts used in 2018 included $127 million for early-terminated hedges which offset $77 million of cash provided by other operating activities. Aside from the impact of these early hedge terminations, the decrease in cash used in operating activities in the first six months of 2018 compared to 2017 reflected higher sales and lower costs, slightly offset by negative working capital effects.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
 
Berry Corp.
(Successor)
Berry LLC (Predecessor)
 
Six Months Ended
Four Months Ended
Two Months Ended
(in thousands)
June 30, 2018
June 30, 2017
February 28, 2017
Capital expenditures (1)
$
(45,369
)
$
(32,878
)
$
(3,158
)
Proceeds from sale of properties and equipment and other
3,022

—

25

Deposit on acquisition of properties
—

(39,450
)
—

Cash used in investing activities:
$
(42,347
)
$
(72,328
)
$
(3,133
)
(1) based on actual cash payments rather than accruals.
Cash used in investing activities was approximately $42 million for the six months ended June 30, 2018. The decrease in cash used for investing activities for the six months ended June 30, 2018 when compared to the same period in 2017 including the successor and predecessor periods, was primarily due to the deposit made for the acquisition of the Hill property in 2017 offset by increased capital spending in the six months ended June 30, 2018.
Financing Activities
Cash provided by financing activities was approximately $46 million for the six months ended June 30, 2018 and was due to receiving $391 million net proceeds from the issuance of our 2026 Notes offset by payments on our RBL Facility, additional net

54

borrowings of $313 million, the repurchase of a right to our shares of $20 million, which is reflected as treasury stock, cash dividends declared on our Series A Preferred Stock in the aggregate amount of $11 million and $9 million of debt issuance costs. For the six months ended June 30, 2017, including the successor and predecessor periods, net cash used in financing activities related to payments on our previous credit facilities of approximately $513 million offset by the receipt of proceeds from the issuance of our Series A Preferred Stock of $335 million.
Debt
2026 Notes Offering
In February 2018, we issued $400 million in aggregate principal amount of our 2026 Notes, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the issuance to repay the $379 million outstanding balance on the RBL Facility and used the remainder for general corporate purposes.
We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after February 15, 2021. We are also entitled to redeem up to 35% of the aggregate principal amount of the 2026 Notes before February 15, 2021, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107% of the principal amount of the 2026 Notes being redeemed, plus accrued and unpaid interest, if any. In addition, prior to February 15, 2021, we may redeem some or all of the 2026 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus any accrued and unpaid interest. If we experience certain kinds of changes of control, holders of the 2026 Notes may have the right to require us to repurchase their notes at 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any.
The 2026 Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The notes are fully and unconditionally guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries (other than Berry LLC). The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under the RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the 2026 Notes.
The indenture governing the 2026 Notes contains restrictive covenants that may limit our ability to, among other things:
•
incur or guarantee additional indebtedness or issue certain types of preferred stock;
•
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness
•
transfer, sell or dispose of assets;
•
make investments;
•
create certain liens securing indebtedness;
•
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
•
consolidate, merge or transfer all or substantially all of our assets; and
•
engage in transactions with affiliates.
The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain of our subsidiaries.
The RBL Facility

On July 31, 2017, Berry LLC, as borrower, entered into the RBL Facility. The RBL Facility provides for a revolving loan with up to $1.5 billion of commitments, subject to a reserve borrowing base, and provided an initial commitment of $500 million. The RBL Facility also provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the RBL Facility on a dollar for dollar basis. Borrowing base redeterminations become effective on or about each May 1 and November 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations. In connection with the issuance of the 2026 Notes, 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 that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. As of June 30, 2018, we had $66 million in borrowings and

55

approximately $7 million in letters of credit outstanding and borrowing availability of $327 million under the RBL Facility. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.
The outstanding borrowings under the revolving loan bear interest at a rate equal to either (i) a customary London interbank offered rate plus an applicable margin ranging from 2.50% to 3.50% per annum, and (ii) a customary base rate plus an applicable margin ranging from 1.50% to 2.50% per annum, in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.50% on the average daily unused amount of the borrowing availability under the RBL Facility. We have the right to prepay any borrowings under the RBL Facility with prior notice at any time without a prepayment penalty, other than customary “breakage” costs with respect to eurodollar loans.
Berry Corp. guarantees, and each future subsidiary of Berry Corp. (other than Berry LLC), with certain exceptions, is required to guarantee, our obligations and obligations of the other guarantors under the RBL Facility and under certain hedging transactions and banking services arrangements (the “Guaranteed Obligations”). In addition, pursuant to a Guaranty Agreement dated as of July 31, 2017 (the “Guaranty Agreement”), Berry LLC guarantees the Guaranteed Obligations. The lenders under the RBL Facility hold a mortgage on at least 85% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions. The RBL Facility, with certain exceptions, also requires that any future subsidiaries of Berry LLC will also have to grant mortgages, security interests and equity pledges.
The RBL Facility requires us to maintain on a consolidated basis as of September 30, 2017 and each quarter-end thereafter (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. The RBL Facility also contains customary restrictions that may limit our ability to, among other things:
•
incur or guarantee additional indebtedness;
•
transfer, sell or dispose of assets;
•
make loans to others;
•
make investments;
•
merge with another entity;
•
make or declare dividends;
•
hedge future production or interest rates;
•
enter into transactions with affiliates;
•
incur liens; and
•
engage in certain other transactions without the prior consent of the lenders.
The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights and remedies, including foreclosure on all of the collateral.
Lawsuits, Claims, Commitments, Contingencies and Contractual Obligations
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 entity 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 our plan of reorganization in the Chapter 11 Proceeding.  On the Effective Date the plan became effective and was implemented.  The Chapter 11 Proceeding will, however, remain pending until final resolution of all outstanding claims. 
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 June 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 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.

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For information related to Berry LLC’s emergence from bankruptcy and the terms of the RBL Facility, see “—Chapter 11 Bankruptcy and Our Emergence” and “Description of Other Indebtedness—The RBL Facility.”
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 June 30, 2018, we are not aware of material indemnity claims pending or threatened against us.

Counterparty Credit Risk
We account for our commodity derivatives at fair value. We had three commodity derivative counterparties at June 30, 2018 and five at December 31, 2017. We did not receive collateral from any of our counterparties. We minimize the credit risk of our derivative instruments by limiting our exposure to any single counterparty. In addition, the RBL Facility prevents us from entering into hedging arrangements that are secured except with our lenders and their affiliates, that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Off-Balance Sheet Arrangements
During the six months ended June 30, 2018, there were no significant changes in our consolidated contractual obligations from those reported in the prospectus.

Recently Adopted Accounting and Disclosure Changes

See Note 1, Accounting and Disclosure Changes, in the Notes to Consolidated Condensed Financial Statements in Part I, Item 1 of this Form 10-Q.

Safe Harbor Statement Regarding Outlook and Forward-Looking Information

The information in this document includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and objectives for operations, maintenance capital requirements, expected production and costs, reserves, hedging activities, capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect our results of operations and financial position appear in Risk Factors in the prospectus.

Factors (but not necessarily all the factors) that could cause results to differ include among others:

•
volatility of oil, natural gas and NGL prices;
•
inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures and meet working capital requirements;
•
price and availability of natural gas;
•
our ability to use derivative instruments to manage commodity price risk;
•
impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;
•
uncertainties associated with estimating proved reserves and related future cash flows;
•
our inability to replace our reserves through exploration and development activities;
•
our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil and natural gas in commercially viable quantities;
•
effects of competition;

57

•
our ability to make acquisitions and successfully integrate any acquired businesses;
•
market fluctuations in electricity prices and the cost of steam;
•
asset impairments from commodity price declines;
•
large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;
•
geographical concentration of our operations;
•
our ability to improve our financial results and profitability following our emergence from bankruptcy and other risks and uncertainties related to our emergence from bankruptcy;
•
changes in tax laws;
•
impact of derivatives legislation affecting our ability to hedge;
•
ineffectiveness of internal controls;
•
concerns about climate change and other air quality issues;
•
catastrophic events;
•
litigation;
•
our ability to retain key members of our senior management and key technical employees;
•
information technology failures or cyber attacks:

We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.



Item 3. Quantitative and Qualitative Disclosures About Market Risk
For the three months ended June 30, 2018, there were no material changes in the information required to be provided under Item 305 of Regulation S-K included under the caption Management's Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A)- Quantitative and Qualitative Disclosures About Market Risk, in the prospectus.
Price Risk
Our most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of our oil and gas properties may be required if commodity prices experience a significant decline.
At June 30, 2018, the fair value of our hedge positions was a net liability of approximately $15 million, as determined from prices provided by external sources that are not actively quoted. A 10% increase in the oil and natural gas index prices above the June 30, 2018 prices would result in a net liability of approximately $57 million, which represents a decrease in the fair value of approximately $42 million; conversely, a 10% decrease in the oil and natural gas index prices below the June 30, 2018 prices would result in a net liability of approximately $4 million, which represents an increase in the fair value of approximately $11 million. For additional information about derivative activity, see Note 4.
Counterparty Credit Risk
We had three commodity derivative counterparties at June 30, 2018, which were all liability positions. We did not receive collateral from any of our counterparties. We minimize the credit risk of our derivative instruments by limiting our exposure to any single counterparty. In addition, the RBL Facility prevents us from entering into hedging arrangements that are secured except with our lenders and their affiliates, that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.


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Interest Rate Risk
Our RBL Facility has a variable interest rate on outstanding balances. As of June 30, 2018, there were $66 million outstanding borrowings under our RBL Facility which incurred interest at floating rates. See Note 3 for additional information regarding interest rates on outstanding debt. As of June 30, 2018, a 1% increase in the respective market rate would result in an estimated $0.7 million increase in annual interest expense. The 2026 Notes have a fixed interest rate and thus we are not exposed to interest rate risk on these.


Item 4. Controls and Procedures
Our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2018.

Part II – Other Information


Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 5 to the consolidated financial statements in Part I of this Form 10-Q and Note 7 to our consolidated financial statements for the year ended December 31, 2017 included in the prospectus.


Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading Risk Factors in the prospectus.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
During the quarter ended June 30, 2018, we issued 190,260 RSUs and 117,088 PRSUs to certain of our employees and directors in connection with services provided to us by such persons. As of August 21, 2018, 681,092 RSUs and 749,833 PRSUs remain outstanding. We also granted 1,566 shares of restricted stock to employees in connection with services provided to us by such persons.
The offers, sales and issuances of the securities described in the preceding paragraph were deemed to be exempt from registration either under Rule 701 promulgated under the Securities Act in that the transactions were under compensatory benefit plans and contracts relating to compensation, or under Section 4(a)(2) of the Securities Act in that the transactions were between an issuer and members of its senior executive management and did not involve any public offering within the meaning of Section 4(a)(2).

Use of Proceeds
    
On July 30, 2018, we completed our IPO of common stock pursuant to our registration statement on Form S-1 (File 333-226011), as amended and declared effective by the SEC on July 25, 2018. Goldman Sachs & Co. LLC, Wells Fargo Securities, LLC and BMO Capital Markets Corp. served as representatives of the several underwriters for the IPO. The offering did not terminate before all of the shares in the IPO that were registered in the registration statement were sold. Upon completion of the IPO, we and the selling stockholders sold 13,043,479 shares at a price to the public of $14.00 per share, raising approximately $183 million of gross proceeds, with gross proceeds to Berry of approximately $147 million and gross proceeds to the selling stockholders of approximately $36 million. Of the 13,043,479 shares sold to the public, 10,497,849 shares were issued and sold by us, and 2,545,630 shares were sold by the selling stockholders named in the prospectus. We incurred expenses in connection with the IPO of approximately $2.6 million as of July 30, 2018. After subtracting underwriting discounts and commissions of approximately $8.8 million and offering expenses, Berry received net proceeds of approximately $136 million. None of the expenses associated with our IPO were paid to directors, officers or persons owning ten percent or

59

more of our common stock or to their associates, or to our affiliates. We did not receive any proceeds from the sale of the shares by the selling stockholders. We and the selling stockholders granted the underwriters a 30-day option to purchase up to an additional 1,534,895 shares and 421,626 shares, respectively, of common stock at the IPO price, less underwriting discounts and commissions. We intend to use a portion of the proceeds we receive from any sale of any such option shares to purchase up to an additional 230,548 shares of common stock owned by Benefit Street.

We used approximately $24 million of the net proceeds from the IPO to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the IPO) from funds affiliated with Benefit Street Partners and Oaktree Capital Management, each of which owned more than ten percent of our common stock prior to the IPO and repurchase. Of the remaining approximately $112 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 amounts we borrowed on the RBL Facility to make the payment to the holders of our Series A Preferred Stock in connection with the conversion of the Series A Preferred Stock to common stock. We used the remainder for working capital.


Item 5. Other Disclosures

Amended and Restated Employment Agreements with Arthur T. Smith, Cary D. Baetz and Gary A. Grove
On August 22, 2018, Berry LLC, a wholly-owned subsidiary of the Company, entered into amended and restated employment agreements with its Chief Executive Officer, Arthur T. “Trem” Smith (the “Smith Agreement”), its Chief Financial Officer, Cary D. Baetz (the “Baetz Agreement”) and its Chief Operating Officer, Gary A. Grove (the “Grove Agreement” and, together with the Smith Agreement and the Baetz Agreement, the “Amended Agreements”), in each case, to replace the executive’s previous employment agreement with the Company (each, a “Prior Agreement”). The Amended Agreements became effective as of August 22, 2018.
Each Amended Agreement modifies certain terms of the corresponding Prior Agreement, including the following:
•
Each executive is eligible to receive an annual equity award, as determined by the board of directors of the Company or a committee thereof.
•
Upon a termination of each executive’s employment under certain circumstances, the executive is eligible to receive (a) any earned but unpaid annual bonus for the year prior to the year of termination, (b) a prorated annual bonus for the year of termination and (c) severance in an amount equal to 18 months’ worth, for Mr. Smith, and 12 months’ worth, for Messrs. Baetz and Grove (or, following a Qualifying Termination (as defined in the applicable Amended Agreement), 24 months’ worth for Mr. Smith and 18 months’ worth for Messrs. Baetz and Grove) of the sum of the applicable executive’s base salary and target annual bonus, and reimbursement of up to an equivalent number of months’ worth of health insurance premiums.
•
Modifies the definition of Good Reason in certain respects.
•
With respect to the Smith Agreement, Mr. Smith is eligible to receive an annual bonus in a target amount equal to 100% of his then-current base salary.

All other material terms contained in the Prior Agreements remain substantially unchanged in the Amended Agreements. Copies of the Smith Agreement, Baetz Agreement and Grove Agreement are attached hereto as Exhibits 10.14, 10.15 and 10.16, respectively, and are incorporated herein by reference. The description of the material changes to the Prior Agreements contained herein is qualified in its entirety by reference to the full text of the Amended Agreements.




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Item 6.    Exhibits
 
 
 
 
Exhibit Number
 
Description
3.1
 
3.2
 
3.3
 
3.4
 
3.5
 
10.1
 
10.2
 
10.3
 
10.4
 
10.5
 
10.6
 
10.7
 
10.8
 
10.9
 
10.10
 
10.11
 
10.12
 
10.13
 
10.14*
 
10.15*
 

61

*
Filed herewith.
**
Furnished herewith.


62

GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms that may be used in this report, which are commonly used in the oil and natural gas industry:
“API” gravity means the relative density, expressed in degrees, of petroleum liquids based on a specific gravity scale developed by the American Petroleum Institute.
“basin” means a large area with a relatively thick accumulation of sedimentary rocks.
“Bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
“Bcf” means one billion cubic feet, which is a unit of measurement of volume for natural gas.
“Boe” means barrel of oil equivalent, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.
“Boe/d” means Boe per day.
“Brent” means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea.
“Btu” means one British thermal unit-a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.
“Completion” means the installation of permanent equipment for the production of oil or natural gas.
“Condensate” means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“Development drilling or Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.
“Diatomite” means a sedimentary rock composed primarily of siliceous, diatom shells.
“Differential” means an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
“Downspacing” means additional wells drilled between known producing wells to better develop the reservoir.
“Enhanced oil recovery” means a technique for increasing the amount of oil that can be extracted from a field.
“EOR” means enhanced oil recovery.
“Estimated ultimate recovery” or “EUR” means the sum of reserves remaining as of a given date and cumulative production as of that date. EUR is shown on a combined basis for oil and natural gas.
“Exploration activities” means the initial phase of oil and natural gas operations that includes the generation of a prospect or play and the drilling of an exploration well.
“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
“Formation” means a layer of rock which has distinct characteristics that differ from those of nearby rock.
“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.

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“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.
“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working interest.
“Held by production” means acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.
“Henry Hub” is a distribution hub on the natural gas pipeline system in Erath, Louisiana.
“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability.
“Horizontal drilling” means a wellbore that is drilled laterally.
“ICE” means Intercontinental Exchange.
“Infill drilling” means drilling of an additional well or wells at less than existing spacing to more adequately drain a reservoir.
“Injection Well” means a well in which water, gas or steam is injected, the primary objective typically being to maintain reservoir pressure and/or improve hydrocarbon recovery.
“IOR” means improved oil recovery.
“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.
“MBbl” means one thousand barrels of oil, condensate or NGLs.
“MBoe” means one thousand barrels of oil equivalent.
“MBoe/d” means MBoe per day.
“Mcf” means one thousand cubic feet, which is a unit of measurement of volume for natural gas.
“MMBbl” means one million barrels of oil, condensate or NGLs.
“MMBoe” means one million barrels of oil equivalent.
“MMBtu” means one million Btus.
“MMcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.
“MMcf/d” means MMcf per day.
“MW” means megawatt.
“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.
“Net revenue interest” means all of the working interests, less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.
“NGL” means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
“NYMEX” means New York Mercantile Exchange.
“Oil” means crude oil or condensate.

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“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.
“PDNP” is an abbreviation for proved developed non-producing.
“PDP” is an abbreviation for proved developed producing.
“Permeability” means the ability, or measurement of a rock’s ability, to transmit fluids.
“Play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations.
“Porosity” means the total pore volume per unit volume of rock.
“PPA” is an abbreviation for power purchase agreement.
“Production costs” means costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
“Productive well” means a well that is producing oil, natural gas or NGLs or that is capable of production.
“Proppant” means sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.
“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved developed producing reserves” means reserves that are being recovered through existing wells with existing equipment and operating methods.
“Proved reserves” means the estimated quantities of oil, gas and gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“Proved undeveloped drilling location” means a site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“PV-10” is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. While this measure does not include the effect of income

65

taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.
“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.
 “Reasonable certainty” means a high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).
“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.
“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.
“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended on the given date.
“Seismic Data” means data produced by an exploration method of sending energy waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.
“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Steamflood” means cyclic or continuous steam injection.
“Standardized measure” means discounted future net cash flows estimated by applying year-end prices to the estimated future production of proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Strip Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules with the exception of pricing that is based on average annual forward-month ICE (Brent) oil and NYMEX Henry Hub natural gas contract pricing in effect on a given date to reflect the market expectations as of that date.
“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

66

“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Unproved reserves” means reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.
“Wellbore” means the hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.
“Workover” means maintenance on a producing well to restore or increase production.
“WTI” means West Texas Intermediate.


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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
 
 
 
BERRY PETROLEUM CORPORATION
 
(Registrant)
 
 
Date: August 23, 2018
/s/ Michael S. Helm
 
Michael S. Helm
 
Chief Accounting Officer
 
(Duly Authorized Officer and Principal Accounting Officer)
 
 
 
 
Date: August 23, 2018
/s/ Cary Baetz
 
Cary Baetz
 
Executive Vice President and Chief Financial Officer
 
(Principal Financial Officer)


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Berry Corp (bry) Reports