Document
Filed Pursuant to Rule 424(b)(3)
Registration No. 333-228740

PROSPECTUS SUPPLEMENT NO. 1
(to prospectus dated March 12, 2019)

51,819,725 Shares
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12893107&doc=6
Common Stock
 
This prospectus supplement is being filed to update and supplement information contained in the prospectus dated March 12, 2019, as amended and supplemented from time to time, covering the offer and resale of our common stock by the selling stockholders identified in the prospectus, or their permitted transferees, with information contained in our Current Report on Form 10-Q, filed with the Securities and Exchange Commission on May 9, 2019.
This prospectus supplement updates and supplements the information in the prospectus and is not complete without, and may not be delivered or utilized except in combination with, the prospectus, including any amendments or supplements thereto. This prospectus supplement should be read in conjunction with the prospectus and if there is any inconsistency between the information in the prospectus and this prospectus supplement, you should rely on the information in this prospectus supplement.
Investing in our common stock involves risks. Please see “Risk Factors” beginning on page 5 of the prospectus.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
The date of this prospectus supplement is May 9, 2019





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 March 31, 2019
OR
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from_______________ to _______________
Commission file number 001-38606


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


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

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

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


Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, par value $0.001 per share
Trading Symbol
BRY
Name of Each Exchange on Which Registered
Nasdaq Global Select Market


Shares of common stock outstanding as of April 30, 2019                     81,879,170



Table of Contents

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

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




Table of Contents

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

BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
March 31, 2019
 
December 31, 2018
 
(in thousands, except share amounts)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,662

 
$
68,680

Accounts receivable, net of allowance for doubtful accounts of $1,377 at March 31, 2019 and $950 at December 31, 2018
63,061

 
57,379

Derivative instruments
16,445

 
88,596

Other current assets
16,634

 
14,367

Total current assets
97,802

 
229,022

Noncurrent assets:
 
 
 
Oil and natural gas properties
1,509,933

 
1,461,993

Accumulated depletion and amortization
(143,959
)
 
(123,217
)
Total oil and natural gas properties, net
1,365,974

 
1,338,776

Other property and equipment
121,283

 
119,710

Accumulated depreciation
(18,130
)
 
(15,778
)
Total other property and equipment, net
103,153

 
103,932

Derivative instruments
18

 
3,289

Other non-current assets
16,256

 
17,244

Total assets
$
1,583,203

 
$
1,692,263

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
108,028

 
$
144,118

Derivative instruments
6,602

 

Total current liabilities
114,630

 
144,118

Noncurrent liabilities:
 
 
 
Long-term debt
391,947

 
391,786

Deferred income taxes
32,737

 
45,835

Asset retirement obligation
85,620

 
89,176

Other noncurrent liabilities
19,140

 
14,902

Commitments and Contingencies - Note 4

 


Equity:
 
 
 
Common stock ($.001 par value; 750,000,000 shares authorized; and 81,879,170 and 81,202,437 shares outstanding, at March 31, 2019 and December 31, 2018, respectively)
85

 
82

Additional paid-in-capital
895,500

 
914,540

Treasury stock, at cost, (2,648,823 shares at March 31, 2019 and 448,661 shares at December 31, 2018)
(28,328
)
 
(24,218
)
Retained earnings
71,872

 
116,042

Total equity
939,129

 
1,006,446

Total liabilities and equity
$
1,583,203

 
$
1,692,263



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

1

Table of Contents

BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended
March 31,
 
2019
 
2018
 
(in thousands, except per share amounts)
Revenues and other:
 
 
 
Oil, natural gas and natural gas liquids sales
$
131,102

 
$
125,624

Electricity sales
9,729

 
5,453

Gains (losses) on oil derivatives
(65,239
)
 
(34,644
)
Marketing revenues
830

 
785

Other revenues
117

 
66

Total revenues and other
76,539

 
97,284

Expenses and other:
 
 
 
Lease operating expenses
57,928

 
44,303

Electricity generation expenses
7,760

 
4,590

Transportation expenses
2,173

 
2,978

Marketing expenses
851

 
580

General and administrative expenses
14,340

 
11,985

Depreciation, depletion, and amortization
24,585

 
18,429

Taxes, other than income taxes
8,086

 
8,256

(Gains) losses on natural gas derivatives
(2,115
)
 

(Gains) losses on sale of assets and other, net
1,245

 

Total expenses and other
114,853

 
91,121

Other income (expenses):
 
 
 
Interest expense
(8,805
)
 
(7,796
)
Other, net
154

 
27

Total other income (expenses)
(8,651
)
 
(7,769
)
Reorganization items, net
(231
)
 
8,955

Income (loss) before income taxes
(47,196
)
 
7,349

Income tax expense (benefit)
(13,098
)
 
939

Net income (loss)
(34,098
)
 
6,410

Series A preferred stock dividends

 
(5,650
)
Net income (loss) attributable to common stockholders
$
(34,098
)
 
$
760

 
 
 
 
Net income (loss) per share attributable to common stockholders:
 
 
 
Basic
$
(0.42
)
 
$
0.02

Diluted
$
(0.42
)
 
$
0.02



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

2

Table of Contents

BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)

 
Three-Month Period Ended March 31, 2018
 
Series A Preferred Stock
 
Common Stock
 
Additional Paid-in Capital
 
Treasury Stock
 
Retained Earnings (Accumulated Deficit)
 
Total Equity
 
(in thousands)
December 31, 2017
$
335,000

 
$
33

 
$
545,345

 
$

 
$
(21,068
)
 
$
859,310

Stock based compensation

 

 
1,042

 

 

 
1,042

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

 

 
(5,650
)
 

 

 
(5,650
)
Net income (loss)

 

 

 

 
6,410

 
6,410

March 31, 2018
$
335,000

 
$
33

 
$
540,737

 
$

 
$
(14,658
)
 
$
861,112

 
Three-Month Period Ended March 31, 2019
 
Series A Preferred Stock
 
Common Stock
 
Additional Paid-in Capital
 
Treasury Stock
 
Retained Earnings (Accumulated Deficit)
 
Total Equity
 
(in thousands)
December 31, 2018
$

 
$
82

 
$
914,540

 
$
(24,218
)
 
$
116,042

 
$
1,006,446

Shares withheld for payment of taxes on equity awards and other

 

 
(270
)
 

 

 
(270
)
Stock based compensation

 

 
1,498

 

 

 
1,498

Purchases of treasury stock

 

 

 
(24,375
)
 

 
(24,375
)
Purchase of rights to common stock(1)

 

 
(20,265
)
 
20,265

 

 

Common stock issued to settle unsecured claims

 
3

 
(3
)
 

 

 

Dividends declared on common stock, $0.12/share

 

 

 

 
(10,072
)
 
(10,072
)
Net income (loss)

 

 

 

 
(34,098
)
 
(34,098
)
March 31, 2019
$

 
$
85

 
$
895,500

 
$
(28,328
)
 
$
71,872

 
$
939,129

__________
(1) In 2018, we entered into several settlement agreements with general unsecured creditors from our bankruptcy process. We paid approximately $20 million to purchase their claims to our common stock. These claims were settled in February 2019 with no shares issued.

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








3

Table of Contents

BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Three Months Ended
March 31,
 
2019
 
2018
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net income (loss)
$
(34,098
)
 
$
6,410

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
Depreciation, depletion and amortization
24,585

 
18,429

Amortization of debt issuance costs
1,255

 
1,223

Stock-based compensation expense
1,474

 
1,042

Deferred income taxes
(13,098
)
 
939

(Decrease) increase in allowance for doubtful accounts
427

 
(2
)
(Gains) losses on sale of assets and other, net
1,245

 

Reorganization expenses, net (non-cash)

 
(9,000
)
Derivative activities:
 
 
 
Total (gains) losses
63,124

 
34,644

Cash settlements on derivatives
14,904

 
(17,849
)
Changes in assets and liabilities:
 
 
 
(Increase) decrease in accounts receivable
(6,084
)
 
1,163

(Increase) decrease in other assets
(2,703
)
 
554

(Decrease) in accounts payable and accrued expenses
(29,854
)
 
(7,323
)
(Decrease) in other liabilities
(2,066
)
 
(2,638
)
Net cash provided by operating activities
19,111

 
27,592

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures:
 
 
 
Development of oil and natural gas properties
(49,386
)
 
(14,727
)
Purchases of other property and equipment
(1,419
)
 
(5,149
)
Net cash (used in) investing activities
(50,805
)
 
(19,876
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Repayments on RBL credit facility
(15,350
)
 
(379,000
)
Borrowings under RBL credit facility
15,350

 

Issuance of 2026 Senior Unsecured Notes

 
400,000

Dividends paid on common stock
(9,813
)
 
 
Purchase of treasury stock
(25,241
)
 

Shares withheld for payment of taxes on equity awards and other
(270
)
 

Debt issuance costs

 
(8,815
)
Net cash (used in) provided by financing activities
(35,324
)
 
12,185

Net decrease in cash, cash equivalents and restricted cash
(67,018
)
 
19,901

Cash, cash equivalents and restricted cash:
 
 
 
Beginning
68,680

 
68,738

Ending
$
1,662

 
$
88,639


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

4

Table of Contents
BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)






Note 1 - Basis of Presentation
“Berry Corp.” refers to Berry Petroleum Corporation, a Delaware corporation, which is the sole member of Berry Petroleum Company, LLC ("Berry LLC").
As the context may require, the “Company”, “we”, “our” or similar words refer to (i) Berry Corp. and Berry LLC, its consolidated subsidiary, as a whole or (ii) either Berry Corp. or Berry LLC.
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 (the “U.S.”), in California (in the San Joaquin and Ventura basins), Utah (in the Uinta basin), and Colorado (in the Piceance basin).
Principles of Consolidation and Reporting
The condensed consolidated financial statements were prepared in conformity with U.S. generally accepted accounting principles ("GAAP"), which requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. In management’s opinion, the accompanying financial statements contain all normal, recurring adjustments that are necessary to fairly present our interim unaudited condensed consolidated financial statements for the three months ended March 31, 2019 and 2018. We eliminated all significant intercompany transactions and balances 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.
    
We prepared this report pursuant to the rules and regulations of the U.S. Security and Exchange Commission ("SEC") applicable to interim financial information, which permit the omission of certain disclosures to the extent they have not changed materially since the latest annual financial statements. We believe our disclosures are adequate to make the disclosed information not misleading. The results reported in these unaudited condensed consolidated financial statements may not accurately forecast results for future periods. This Form 10-Q should be read in conjunction with the consolidated financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2018.
Recently Adopted Accounting Standards
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 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. As such, we adopted these rules in the first quarter of 2019 and applied the modified retrospective approach, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We have performed an analysis of existing contracts and determined adoption did not have a material impact on our condensed consolidated financial statements. In addition, we have evaluated the changes to relevant business practices, accounting policies and control activities and we did not experience a material change in our revenue accounting as a result of the adoption of these rules. Refer to Note 8 for additional disclosure information.
New Accounting Standards Issued, But Not Yet Adopted

In June 2016, the FASB issued rules that change how entities will measure credit losses for certain financial assets and other instruments that are not measured at fair value. These rules are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact of these rules on our consolidated financial statements.
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

5

Table of Contents
BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

December 15, 2019, including interim periods within those fiscal years. We expect the adoption of these rules to increase other assets and other liabilities on our balance sheet and do not expect a material impact on our consolidated results of operations.
Note 2 - Debt
The following table summarizes our outstanding debt:
 
March 31, 2019
 
December 31, 2018
 
Interest Rate
 
Maturity
 
Security
 
(in thousands)
 
 
 
 
 
 
RBL Facility
$

 
$

 
variable rates of 6.25% (2019) and 4.5% (2018), respectively
 
June 29, 2022
 
Mortgage on 85% of Present Value of proven oil and gas reserves and lien on other assets
2026 Senior Unsecured Notes
400,000

 
400,000

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

 
400,000

 
 
 
 
 
 
Less: Debt Issuance Costs
(8,053
)
 
(8,214
)
 
 
 
 
 
 
Long-Term Debt, net
$
391,947

 
$
391,786

 
 
 
 
 
 

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At March 31, 2019 and December 31, 2018, debt issuance costs for the RBL Facility (as defined below) reported in "other noncurrent assets" on the balance sheet were approximately $15 million and $16 million net of amortization, respectively. The amortization of debt issuance costs is presented in interest expense on the condensed consolidated statements of operations. At March 31, 2019 and December 31, 2018, debt issuance costs for the 2026 Senior Unsecured Notes were $8 million and $8 million net of amortization, respectively.
For the three months ended March 31, 2019 and March 31, 2018, amortization expense of approximately $1 million and $1 million, respectively, was included in “interest expense” in 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 $399 million and $368 million at March 31, 2019 and December 31, 2018, respectively.
The RBL Facility
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 April 2019, we completed a borrowing base redetermination under our RBL Facility that resulted in our borrowing base being set at $750 million and we reaffirmed our elected commitment amount at $400 million. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.
We were in compliance with all financial covenants as of March 31, 2019.
As of March 31, 2019, we had approximately $391 million of available borrowing capacity under the RBL Facility.
As of March 31, 2019 and December 31, 2018, we had letters of credit outstanding of approximately $9 million and $7 million, respectively, under our RBL facility. These letters of credit were issued to support ordinary course of business marketing, insurance, regulatory and other matters.


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Table of Contents
BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Note 3 - Derivatives

We utilize derivatives, such as swaps, puts, and calls to hedge a portion of our forecasted oil production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices. We target covering our operating expenses and fixed charges, including maintenance capital expenditures, with the oil hedges for a period of up to two years out. We have hedged a portion of our exposure to differentials between ICE Brent oil (“Brent”) and NYMEX West Texas Intermediate oil (“WTI”) as well. Additionally, we target fixing the price for a large portion of our natural gas purchases used in our steam operations for up to two years. We also, from time to time, have entered into agreements to purchase a portion of the natural gas we require for our operations, which we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions.
As of March 31, 2019, our hedge position consisted of oil swaps, puts and calls, and natural gas swaps. We use oil swaps and puts to protect against decreases in the oil price and natural gas swaps to protect against increases in natural gas prices. We do not enter into derivative contracts for speculative trading purposes and have not accounted for our derivatives as cash-flow or fair-value hedges. We did not designate any of our contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. Gains (losses) on oil hedges are classified in the revenues and other section of the statement of operations and gains (losses) on natural gas hedges are presented in the expenses and other section of the statement of operations.
As of March 31, 2019, we had hedged crude oil production to protect against oil price decreases, at the following approximate volumes and weighted average prices: 19.0 MBbl/d at $65.99 in the second quarter of 2019, 12.0 MBbl/d at $65.33 in the third quarter of 2019 and 12.0 MBbl/d at $65.33 in the fourth quarter of 2019. We had also hedged gas purchases as noted below.
 
Q2 2019
 
Q3 2019
 
Q4 2019
Oil Calls Options (Brent):
 
 
 
 
 
Hedged volume (MBbls)
180

 
92

 
92

Weighted-average price ($/Bbl)
$
70.00

 
$
81.00

 
$
81.00

Oil Put Options (Brent):
 
 
 
 
 
  Hedged volume (MBbls)
1,092

 
460

 
460

  Weighted-average price ($/Bbl)
$
60.00

 
$
50.00

 
$
50.00

Fixed Price Oil Swaps (Brent):
 
 
 
 
 
  Hedged volume (MBbls)
637

 
644

 
644

  Weighted-average price ($/Bbl)
$
76.27

 
$
76.27

 
$
76.27

Oil basis differential positions (Brent-WTI basis swaps):
 
 
 
 
 
  Hedged volume (MBbls)
46

 
46

 
46

  Weighted-average price ($/Bbl)
$
(1.29
)
 
$
(1.29
)
 
$
(1.29
)
Fixed Price Gas Purchase Swaps (Kern, Delivered):
 
 
 
 
 
  Hedged volume (MMBtu)
2,730,000

 
1,380,000

 
465,000

  Weighted-average price ($/MMBtu)
$
2.70

 
$
2.65

 
$
2.65

In April 2019, we acquired additional oil and gas hedges. For additional detail see "Liquidity and Capital Resources".
For our purchased puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel of Brent. For some of our put positions, we paid a premium at the time the positions were created and for others the premium payment is deferred until the time of settlement. We paid approximately $15 million of the deferred premium during the three months ended March 31, 2019. In order to mitigate the exposure to these deferred premiums, we entered into several offsetting put positions. We received approximately $4 million for the offsetting positions during the three months ended March 31, 2019. The remaining deferred premiums of approximately $7 million are reflected in the mark-to-market valuation and will be payable through the first quarter of 2020.
For fixed-price swaps, we make settlement payments for prices above the indicated weighted-average price per barrel of Brent or WTI and receive settlement payments for prices below the indicated weighted-average price per barrel of Brent or WTI.

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Table of Contents
BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the indicated weighted-average price per barrel of our contracts and receive settlement payments if the difference between Brent and WTI is below the indicated weighted-average price per barrel.
For fixed-price natural gas purchase swaps, we are the buyer so we make settlement payments for prices below the weighted-average price per MMBtu and receive settlement payments for prices above the weighted-average price per MMBtu.
 Our commodity derivatives are measured at fair value using industry-standard models with various inputs including publicly available underlying commodity prices and forward curves, and all are classified as Level 2 in the required fair value hierarchy for the periods presented. These commodity derivatives are subject to counterparty netting. The following tables present the fair values (gross and net) of our outstanding derivatives as of March 31, 2019 and December 31, 2018:
 
March 31, 2019
 
Balance Sheet
Classification
 
Gross Amounts
Recognized at Fair Value
 
Gross Amounts Offset
in the Balance Sheet
 
Net Fair Value Presented 
on the Balance Sheet
 
(in thousands)
Assets:
 
 
 
 
 
 
 
  Commodity Contracts
Current assets
 
$
21,987

 
$
(5,542
)
 
$
16,445

  Commodity Contracts
Non-current assets
 
18

 

 
18

Liabilities:
 
 
 
 
 
 
 
  Commodity Contracts
Current liabilities
 
(12,144
)
 
5,542

 
(6,602
)
Total derivatives
 
 
$
9,861

 
$

 
$
9,861


 
December 31, 2018
 
Balance Sheet
Classification
 
Gross Amounts
Recognized at Fair Value
 
Gross Amounts Offset
in the Balance Sheet
 
Net Fair Value Presented 
on the Balance Sheet
 
(in thousands)
Assets:
 
 
 
 
 
 
 
  Commodity Contracts
Current assets
 
$
89,981

 
$
(1,385
)
 
$
88,596

  Commodity Contracts
Non-current assets
 
3,289

 

 
3,289

Liabilities:
 
 
 
 
 
 
 
  Commodity Contracts
Current liabilities
 
(1,385
)
 
1,385

 

Total derivatives
 
 
$
91,885

 
$

 
$
91,885

By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We do not receive collateral from our counterparties.
We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, our 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 Standards & 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 which partially mitigates the counterparty nonperformance risk.

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BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Note 4 - 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.
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 March 31, 2019 and December 31, 2018. 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, 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 March 31, 2019, we are not aware of material indemnity claims pending or threatened against us.
During the three months ended March 31, 2019, we entered into an 8-year office lease agreement for approximately $1.3 million annually for a total future commitment of approximately $10 million. This agreement begins in August 2019.
Note 5 - Equity
Common Stock
On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization (the “Plan”). The Plan contemplated the distribution of 40,000,000 shares of common stock in Berry Corp. On the Effective Date, 32,920,000 shares of common stock were distributed, pro rata, to holders of Unsecured Notes claims. On February 28, 2017 (the “Effective Date”), the Plan became effective and was implemented. The holders of Unsecured Claims received a right to receive 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. Since the Effective Date we have negotiated with claimants to settle their claims and in February 2019 we issued approximately 2,770,000 shares instead of 7,080,000 to resolve these claims.
Cash Dividends
On February 28, 2019, our board of directors approved a $0.12 per share quarterly cash dividend on our common stock for the first quarter of 2019, which was paid in April 2019. On May 8, 2019, our board of directors approved a $0.12 per share quarterly cash dividend on our common stock for the second quarter of 2019.
Stock Repurchase Program
In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of current market conditions for our common stock they authorized current repurchases of up to $50 million under the program. Purchases may be made from time to time in the open market, in privately negotiated transactions or otherwise. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Petroleum to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. For the three months ended March 31, 2019, we repurchased 2,200,162 shares at an average price of $11.08 per share for $24 million, which is reflected as treasury stock. The Company has repurchased a total of 2,648,823 shares under the stock repurchase program for $28 million as of March 31, 2019.

Stock-Based Compensation
In March 2019, the Company granted awards of 706,314 shares of restricted stock units ("RSUs"), which will vest annually in equal amounts over three years and 553,902 performance-based restricted stock units ("PSUs"), which will cliff vest at two or three years. The fair value of these awards was approximately $16 million.
The RSUs awarded are service based awards. The PSUs awarded include a market objective measured against both absolute total stockholder return (“Absolute TSR”) and total stockholder return relative (“Relative TSR”), to the Vanguard World Fund -

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BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Vanguard Energy ETF index (the “Index”) over the performance period, assuming the reinvestment of dividends. Depending on the results achieved during the two or three year performance period, the actual number of shares that a grant recipient receives at the end of the period may range from 0% to 200% of the Target Shares granted.

The fair value of the PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the Index over the performance periods. The expected volatility of the Company’s common stock at the date of grant was estimated based on blended historical average volatility rates for the Company and selected guideline public companies. The dividend yield assumption was based on the current annualized declared dividend. The risk-free interest rate assumption was based on observed interest rates consistent with the approximate two and three year performance measurement period.
Note 6 - 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:  
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Prepaid expenses
$
6,010

 
$
4,656

Oil inventories, materials and supplies
10,386

 
9,473

Other
238

 
238

Total
$
16,634

 
$
14,367

The major classes of inventory were not material and therefore not stated separately. Other non-current assets at March 31, 2019 and December 31, 2018, included approximately $15 million and $16 million of deferred financing costs, net of amortization, respectively.
Accounts payable and accrued expenses on the condensed consolidated balance sheets included the following:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Accounts payable-trade
$
7,996

 
$
13,564

Accrued expenses
53,753

 
66,417

Royalties payable
13,900

 
26,189

Taxes other than income tax liability
9,867

 
10,766

Accrued interest
4,050

 
10,500

Dividends payable
10,251

 
9,992

Other
8,212

 
6,689

Total
$
108,028

 
$
144,118

Other non-current liabilities at March 31, 2019 and December 31, 2018 included approximately $19 million and $15 million of greenhouse gas liability, respectively.

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BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Supplemental Cash Flow Information
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
Three Months Ended
March 31,
 
2019
 
2018
 
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
 
 
(Increase) decrease in accrued liabilities related to purchases of property and equipment
$
2,038

 
$
(4,144
)
Supplemental Disclosures of Cash Payments (Receipts):
 
 
 
  Interest, net of amounts capitalized
$
14,000

 
$
2,654

  Reorganization items, net
$

 
$
468

The following table provides a reconciliation of cash, cash equivalents and restricted cash as reported in the condensed consolidated statements of cash flows to the line items within the condensed consolidated balance sheets:
 
Three Months Ended
March 31,
 
2019
 
2018
 
(in thousands)
Beginning of Period
 
 
 
Cash and cash equivalents
$
68,680

 
$
33,905

Restricted cash

 
34,833

Cash, cash equivalents and restricted cash
$
68,680

 
$
68,738

 
 
 
 
Ending of Period
 
 
 
Cash and cash equivalents
$
1,662

 
$
67,090

Restricted cash

 
21,549

Cash, cash equivalents and restricted cash
$
1,662

 
$
88,639

Restricted cash is associated with cash reserved to settle claims with general unsecured creditors resulting from implementation of the Plan. Cash and cash equivalents consists primarily of highly liquid investments with original maturities of three months or less and are stated at cost, which approximates fair value.
Note 7 - Earnings Per Share
We calculate basic earnings (loss) per share by dividing net income (loss) attributable 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 expected to be issued under the Plan, are considered common shares outstanding and are included in the computation of net income (loss) per share. The Plan required that we reserve 7,080,000 shares of our common stock to settle claims of unsecured creditors. These shares were previously included in the 40 million shares of common stock contemplated by the Plan, without regard to actual issuance dates. As a result, prior to final issuance of these shares, the computation of net income (loss) per share included the 7,080,000 reserved shares. At the end of February 2019, we finalized settlement of these claims and issued approximately 2,770,000 shares. In all prior periods presented we retrospectively adjusted the weighted average shares in our earnings per share calculations for the ultimate shares issued, instead of the 7,080,000 shares that had been reserved.
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 calculation for the three months ended March 31, 2019, as all outstanding shares of our Series A Preferred Stock were converted to common shares in connection with the IPO of our common stock in July 2018. No Series A Preferred Stock were included in

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BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

the diluted EPS calculation for the three months ended March 31, 2018 as their affect was anti-dilutive under the "if converted" method. The RSUs are not a participating security as the dividends are forfeitable. No incremental RSU shares were included in the diluted EPS calculation for the three months ended March 31, 2019 as their effect was anti-dilutive under the "if converted" method. Incremental RSU shares of 225,000 were included in the diluted EPS calculation for the three months ended March 31, 2018, as their effect was dilutive under the "if-converted" method. No PSU's were included in the EPS calculations for any of the periods presented due to their contingent nature.
 
Three Months Ended
March 31,
 
2019
 
2018
 
(in thousands except per share amounts)
Basic EPS calculation

 

Net income (loss)
$
(34,098
)
 
$
6,410

less: Series A Preferred Stock dividends and conversion to common stock

 
(5,650
)
Net income (loss) attributable to common stockholders
$
(34,098
)
 
$
760

Weighted-average shares of common stock outstanding
81,765

 
38,602

Basic earnings (loss) per share(2)
$
(0.42
)
 
$
0.02

Diluted EPS calculation

 

Net income (loss)
$
(34,098
)
 
$
6,410

less: Series A Preferred Stock dividends and conversion to common stock

 
(5,650
)
Net income (loss) attributable to common stockholders
$
(34,098
)
 
$
760

Weighted-average shares of common stock outstanding
81,765

 
38,602

Dilutive effect of potentially dilutive securities(1)

 
225

Weighted-average common shares outstanding - diluted
81,765

 
38,827

Diluted earnings (loss) per share(2)
$
(0.42
)
 
$
0.02

__________
(1)
No potentially dilutive securities were included in computing earnings (loss) per share for the three months ended March 31, 2019, because the effect of inclusion would have been anti-dilutive.
(2)
Per share amounts are stated net of tax.

Note 8 - Revenue Recognition

We account for revenue in accordance with the Accounting Standards Codification 606, Revenue from Contracts with Customers, which we adopted on January 1, 2019, using the modified retrospective method, which was applied to all contracts that were not completed as of that date. Prior period results were not adjusted and continue to be reported under the accounting standards in effect for the prior period. The new standard did not affect the timing of our revenue recognition and did not impact net income; accordingly, we did not record an adjustment to the opening balance of retained earnings.

We adopted the practical expedient related to disclosing the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied at the end of the reporting period. The performance obligations that are unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these are wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation as well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation.

We derive substantially all of our revenue from sales of oil, natural gas and natural gas liquids ("NGL"), with the remaining revenue generated from sales of electricity and marketing activities.

The following is a description of our principal activities from which we generate revenue. Revenues are recognized when a customer obtains control of promised goods or services, in an amount that reflects the consideration we expect to receive in exchange for those goods or services.


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BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Oil, Natural Gas and NGLs

We recognize revenue from the sale of our oil, natural gas and NGLs production when delivery has occurred and control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our NGL contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the amount that we have a right to invoice once we are able to adequately estimate the consideration (i.e., when market prices are known). Our contracts with customers typically require payment within 30 days following invoicing.

Electricity Sales

The electrical output of our cogeneration facilities that is not used in our operations is sold to the California market based on market pricing, which includes capacity payments. The majority of the portion sold from three of our cogeneration facilities is sold under long-term contracts to two California utility companies, based on the market pricing. Revenue is recognized over time when obligations under the terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the electricity. Revenue is measured as the amount of consideration we expect to receive based on average index pricing with payment due the month following delivery. Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on seasonality, which is consistent with how we earn the capacity payment. Capacity payments are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the case of capacity payments. We report electricity revenue as electricity sales on our consolidated statements of operations.

Marketing Revenue

Marketing revenue primarily includes our activities associated with transporting and marketing third-party volumes. These sales are made under the same agreements with the same purchaser as our natural gas sales discussed above. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Revenues are presented excluding costs incurred prior to transferring control of these volumes to the customer, or the costs to purchase these volumes when we are acting as the principal. The revenues and expenses related to the sale and purchase of third-party volumes are presented separately as marketing revenue and marketing expenses on the consolidated statement of operations.

Disaggregated Revenue

As a result of adoption of this standard, we are now required to disclose the following information regarding revenue from contracts with customers on a disaggregated basis.

 
Three Months Ended
March 31,
 
2019
 
2018
 
(in thousands)
Oil sales
$
123,450

 
$
117,902

Natural gas sales
6,715

 
6,563

Natural gas liquids sales
937

 
1,159

Electricity sales
9,729

 
5,453

Marketing revenues
830

 
785

Revenues from contracts with customers
141,661

 
131,862

Gains (losses) on oil derivatives
(65,239
)
 
(34,644
)
Other revenues
117

 
66

Total revenues and other
$
76,539

 
$
97,284


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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 our interim unaudited consolidated financial statements and related notes presented in this Quarterly Report on form 10-Q, as well as our audited consolidated financial statements and related notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2018 (the "Annual Report") filed with the Securities and Exchange Commission ("SEC"). When we use the terms “we,” “us,” “our,” the “Company” or similar words in this report, we are referring to Berry Corp. and its subsidiary, Berry LLC.
Our Company
We are a western United States independent upstream energy company with a focus on conventional, long-lived oil reserves in the San Joaquin basin of California. Our long-lived, high-margin asset base is uniquely positioned to support our objectives of generating top-tier corporate-level returns and positive levered free cash flow through commodity price cycles. We target onshore, low-cost, low-risk, oil-rich reservoirs in the San Joaquin basin of California and, to a lesser extent, our Rockies assets including low-cost, oil-rich reservoirs in the Uinta basin of Utah and low geologic risk natural gas resource plays in the Piceance basin in Colorado. Successful execution of 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 continue returning capital to our stockholders.
How We Plan and Evaluate Operations
We use Levered Free Cash Flow to plan our capital allocation for maintenance and internal growth opportunities as well as hedging needs. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends.
We use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA; (b) operating expenses; (c) environmental, health & safety (“EH&S”) results; (d) general and administrative expenses; and (e) production.
Adjusted EBITDA
Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business. We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items.
Operating expenses
We define operating expenses as lease operating expenses, electricity generation expenses, transportation expenses, and marketing expenses, offset by the third-party revenues generated by electricity, transportation and marketing activities, as well as the effect of derivative settlements (received or paid) for gas purchases. Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Taxes other than income taxes are excluded from operating expenses. The electricity, transportation and marketing activity related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the economics of development projects and the efficiency of our hydrocarbon recovery. Additionally, we strive to minimize the variability of our fuel gas costs for our steam operations, and we significantly increased our gas hedges in the second quarter of 2019. 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.


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Table of Contents

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.
Capital Expenditures
For the three months ended March 31, 2019, our capital expenditures were approximately $49 million, on an accrual basis excluding acquisitions. Approximately 87% of this total was directed to California oil operations.

Our 2019 anticipated capital expenditure budget is approximately $195 to $225 million, which represents an increase of approximately 42% over 2018 capital expenditures. Based on current commodity prices and a drilling success rate comparable to our historical performance, we believe we will be able to fund our 2019 capital development programs while producing positive Levered Free Cash Flow. Our 2019 capital program is focused on growing our oil production in California. We anticipate oil production will be approximately 86% of total production in 2019, compared to 82% in 2018. This change in product mix also factors in the divestiture of our non-core East Texas gas properties in late 2018. During 2019, we expect to:
• employ four drilling rigs in California throughout the year; and

• drill approximately 370 to 420 gross development wells, all of which we expect will be in California for oil production.

The table below sets forth the expected allocation of our 2019 capital expenditure budget by area as compared to the allocation of our 2018 capital expenditures.
 
Capital Expenditure by Area
 
2019 Budget
2018 Actual
 
 
(in millions)
California
$
185-212
$
126

Rockies
 
4-6
17

Corporate
 
6-7
5

Total
$
195-225
$
148


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.

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Table of Contents

2019 Guidance
The table below sets forth our 2019 Guidance for certain metrics.
 
 
2019 Guidance
 
Low
 
High
Average daily production (MBoe/d)
 
28
 
31
% Oil
 
~86%
Operating expenses ($/Boe)
 
$18.00
 
$19.50
Taxes, other than income taxes ($/Boe)
 
$4.25
 
$4.75
Adjusted General & Administrative Expenses ($/Boe)
 
$4.25
 
$4.75
Capital Expenditures (millions)
 
$195
 
$225
Business Environment, Market Conditions and Seasonality
The oil and gas industry is heavily influenced by commodity prices. While average oil prices were slightly lower for the three months ended March 31, 2019 compared to the three months ended December 31, 2018 and March 31, 2018, they did significantly fluctuate during each period. For instance, Brent crude oil contract prices ranged from $54.91 per Bbl at the beginning of the first quarter of 2019, to $68.39 per Bbl at the end of the first quarter. The Henry Hub spot price for natural gas also fluctuated during the three months ended March 31, 2019 between $2.54 per MMBtu and $4.25 per MMBtu. And, in California, the daily price we paid for fuel gas purchases (generally based on the Kern, Delivered index) was as low as $2.61 per MMbtu and as high as $17.59 per MMBtu during the first quarter of 2019. Our revenue, costs, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production and the prices we pay for our natural gas purchases which will continue to be affected by a variety of factors, as discussed in Risk Factors in our 10-K.
The following table presents the average Brent, WTI, Henry Hub and Kern, Delivered prices for the three months ended March 31, 2019, December 31, 2018 and March 31, 2018:
 
Three Months Ended
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
Brent oil ($/Bbl)
$
63.83

 
$
68.08

 
$
67.16

WTI oil ($/Bbl)
$
54.87

 
$
58.81

 
$
62.87

Henry Hub natural gas ($MMBtu)
$
2.92

 
$
3.64

 
$
3.00

Kern, Delivered natural gas ($MMBtu)
$
5.12

 
$
4.40

 
$
2.66

California oil prices are Brent-influenced as California refiners import nearly 70% of the state’s demand by waterborne supply, primarily from the Middle East and South America. 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 crude transportation options, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California.
Utah oil prices have historically traded at a discount to WTI as the local refineries are designed for Utah oil's unique characteristics and the remoteness of the assets makes access to other markets logistically challenging.
Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify pricing volatility.
Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. We purchase substantially more natural gas for our steamfloods and power generation, than we produce and sell. Consequently, higher gas prices have a negative impact on our operating costs. However, we mitigate a portion of this exposure by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. Additionally, we strive to minimize the variability of our fuel gas costs from our steam operations by hedging a portion of such gas purchases and have recently increased the amount of gas purchases we hedge. Also, the negative impact of higher gas prices is partially offset by higher gas sales for the gas we produce.

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Table of Contents

Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses, we also sell electricity produced by three of our cogeneration facilities under long-term contracts. The most significant input and cost of the cogeneration facilities is natural gas. We receive significantly more revenue from these cogeneration facilities in the summer months, June through September, due to negotiated capacity payments we receive.
Seasonal weather conditions can impact a portion of our drilling and production activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires and rain.
Summary By Area
The following table shows a summary by area of our selected historical financial information and operating data for the periods indicated.
 
California
(San Joaquin and Ventura basins)
 
Rockies
(Uinta and Piceance basins)
 
Three Months Ended
 
Three Months Ended
 
March 31, 2019
 
March 31, 2018
 
March 31, 2019
 
March 31, 2018
($ in thousands, except prices)
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
111,896

 
$
105,544

 
$
19,206

 
$
18,715

Operating income(a)
$
37,357

 
$
47,258

 
$
4,779

 
$
3,445

Depreciation, depletion, and amortization (DD&A)
$
21,342

 
$
14,905

 
$
3,244

 
$
3,031

Average daily production (MBoe/d)
21.0

 
18.8

 
6.8

 
6.6

Production (oil% of total)
100
%
 
100
%
 
46
%
 
35
%
Realized sales prices:
 
 
 
 
 
 
 
Oil (per Bbl)
$
59.16

 
$
62.37

 
$
41.38

 
$
60.29

NGLs (per Bbl)
$

 
$

 
$
24.42

 
$
26.46

Gas (per Mcf)
$

 
$

 
$
3.77

 
$
2.58

Capital expenditures
$
42,509

 
$
15,301

 
$
5,313

 
$
378

__________
(a)
Operating income includes oil, natural gas and NGL sales, offset by operating expenses, general and administrative expenses, DD&A, and taxes, other than income taxes.


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Table of Contents

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.
 
Three Months Ended
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
Average daily production:(1)(5)
 
 
 
 
 
Oil (MBbl/d)
24.1

 
23.7

 
21.1

Natural Gas (MMcf/d)
19.5

 
22.1

 
27.6

NGL (MBbl/d)
0.4

 
0.6

 
0.5

Total (MBoe/d)(2)
27.8

 
28.0

 
26.2

Total Production:(5)
 
 
 
 
 
Oil (MBbl)
2,170

 
2,178

 
1,897

Natural gas (MMcf)
1,752

 
2,034

 
2,481

NGLs (MBbl)
38

 
54

 
45

Total (MBoe)(2)
2,501

 
2,571

 
2,356

Weighted-average realized sales prices:
 
 
 
 
 
Oil without hedges ($/Bbl)
$
56.88

 
$
61.48

 
$
62.14

Oil with hedges ($/Bbl)
$
62.03

 
$
64.36

 
$
52.74

Natural gas ($/Mcf)
$
3.83

 
$
3.86

 
$
2.64

NGL ($/Bbl)
$
24.35

 
$
20.39

 
$
25.56

Average Benchmark prices:
 
 
 
 
 
Oil (Bbl) – Brent
$
63.83

 
$
68.08

 
$
67.16

Oil (Bbl) – WTI
$
54.87

 
$
58.81

 
$
62.87

Natural gas (MMBtu) – Henry Hub
$
2.92

 
$
3.64

 
$
3.00

Average costs per Boe(3):
 
 
 
 
 
Lease operating expenses
$
23.16

 
$
19.96

 
$
18.80

Electricity generation expenses
3.10

 
2.63

 
1.94

Electricity sales(3)
(3.89
)
 
(3.70
)
 
(2.31
)
Transportation expenses
0.87

 
0.86

 
1.26

Transportation sales(3)
(0.05
)
 
(0.11
)
 

Marketing expenses
0.34

 
0.28

 
0.25

Marketing revenues(3)
(0.33
)
 
(0.21
)
 
(0.33
)
Derivatives settlements (received) paid for gas purchases(3)
(1.49
)
 
(0.94
)
 

Total operating expenses
$
21.71

 
$
18.77

 
$
19.61

General and administrative expenses(4)
$
5.73

 
$
6.27

 
$
5.09

Depreciation, depletion and amortization
$
9.83

 
$
9.43

 
$
7.82

Taxes, other than income taxes
$
3.23

 
$
3.04

 
$
3.50

__________
(1)
Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
(2)
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 quarter ended March 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $63.83 per Bbl and $2.92 per MMBtu, respectively, resulting in an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent basis.
(3)
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 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 relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses also includes the effect of derivative settlements (received or paid) for gas purchases.

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Table of Contents

(4)
Includes non-recurring restructuring and other costs and non-cash stock compensation expense, in aggregate, of approximately $1.10 per Boe, $1.79 per Boe and $1.30 per Boe for the three months ended March 31, 2019, December 31, 2018 and March 31, 2018, respectively.
(5)
On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
The following table sets forth average daily production by operating area for the periods indicated:
 
Three Months Ended
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
Average daily production (MBoe/d)(1):
 
 
 
 
 
California
21.0

 
21.7

 
18.8

Rockies
6.8

 
5.8

 
6.6

East Texas(2)

 
0.5

 
0.8

Total average daily production
27.8

 
28.0

 
26.2

__________
(1)
Production represents volumes sold during the period.
(2)
On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
Average daily production volumes increased for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 due to production response from development capital spending throughout 2018 and early 2019, offset by natural decline and the sale of our East Texas properties in November 2018. Our first quarter 2019 California production increased 12% compared to the first quarter of 2018, as the substantial majority of our development capital was deployed throughout our California operations showing the strong ability of our California thermal properties to perform as expected.
Average daily production volumes decreased slightly for the three months ended March 31, 2019 as compared to the three months ended December 31, 2018 reflecting thermal response timing, natural decline and the impact of selling our East Texas assets in the fourth quarter of 2018, partially offset by the response from drilling activity in both California and Utah. Thermal development wells do not always initially start at peak rate as the time to heat the reservoir can vary reservoir by reservoir and project by project. Thermal results are better viewed over longer intervals as the 12% annual rate increase from the three months ended March 31, 2018 to the three months ended March 31, 2019 noted above.





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Table of Contents

Results of Operations
Three Months Ended March 31, 2019 compared to Three Months Ended December 31, 2018.
 
Three Months Ended
 
$ Change
 
% Change
 
March 31, 2019
 
December 31, 2018
 
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
Oil, natural gas and NGL sales
$
131,102

 
$
142,861

 
$
(11,759
)
 
(8
)%
Electricity sales
9,729

 
9,517

 
212

 
2
 %
Gain (losses) on oil derivatives
(65,239
)
 
127,160

 
(192,399
)
 
(151
)%
Marketing and other revenues
947

 
808

 
139

 
17
 %
Total revenues and other
76,539

 
280,346

 
(203,807
)
 
(73
)%
Expenses and other:
 
 
 
 
 
 
 
Lease operating expenses
57,928

 
51,308

 
6,620

 
13
 %
Electricity generation expenses
7,760

 
6,764

 
996

 
15
 %
Transportation expenses
2,173

 
2,220

 
(47
)
 
(2
)%
Marketing expenses
851

 
716

 
135

 
19
 %
General and administrative expenses
14,340

 
16,130

 
(1,790
)
 
(11
)%
Depreciation, depletion and amortization
24,585

 
24,253

 
332

 
1
 %
Taxes, other than income taxes
8,086

 
7,829

 
257

 
3
 %
(Gains) losses on natural gas derivatives
(2,115
)
 
(4,477
)
 
2,362

 
(53
)%
(Gains) losses on sale of assets and other, net
1,245

 
(3,269
)
 
4,514

 
(138
)%
Total expenses and other
114,853

 
101,474

 
13,379

 
13
 %
Other income (expenses):
 
 
 
 
 
 
 
Interest expense
(8,805
)
 
(8,820
)
 
15

 
 %
Other, net
154

 
108

 
46

 
43
 %
Reorganization items, net
(231
)
 
1,498

 
(1,729
)
 
(115
)%
Income (loss) before income taxes
(47,196
)
 
171,658

 
(218,854
)
 
(127
)%
Income tax expense (benefit)
(13,098
)
 
39,890

 
(52,988
)
 
(133
)%
Net income (loss)
$
(34,098
)
 
$
131,768

 
$
(165,866
)
 
(126
)%
Revenues and Other
Oil, natural gas and NGL sales decreased $12 million, or 8%, to approximately $131 million for the three months ended March 31, 2019 compared to the three months ended December 31, 2018. The large majority of this decrease reflects lower oil prices.
Electricity sales represent sales to utilities, which were comparable for the three months ended March 31, 2019 and December 31, 2018.
Losses on oil derivatives were approximately $65 million for the three months ended March 31, 2019 compared to a gain of approximately $127 million for the three months ended December 31, 2018. The changes are the result of the mark-to-market impact caused by increasing oil prices in the first quarter of 2019 relative to the fixed prices of our derivative contracts.
Marketing and other revenues increased 17% to approximately $0.9 million for the three months ended March 31, 2019, compared to the three months ended December 31, 2018 due to higher average prices. Marketing revenues in these periods primarily represented sales of third-party natural gas.
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 are used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.

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Table of Contents

Operating expenses, as defined above, increased to $21.71 per Boe for the quarter ended March 31, 2019 from $18.77 per Boe for the quarter ended December 31, 2018, including $2.13 per Boe of higher fuel costs.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses increased by approximately $7 million, or 13%, to approximately $58 million for the three months ended March 31, 2019, compared to the three months ended December 31, 2018.

Lease operating expenses were impacted by unseasonably higher fuel prices related to our California steam operations, which increased unhedged fuel expense $4 million, for the three months ended March 31, 2019 compared to the three months ended December 31, 2018. The fuel gas price for the 2019 period was $4.94/MMBtu compared to $4.15/MMBtu in 2018. Additionally, we had an increase in facility, well, and lease maintenance costs in 2019 compared to 2018.
Electricity generation expenses increased approximately $1 million or 15% to $8 million for the three months ended March 31, 2019 compared to the three months ended December 31, 2018, primarily related to an increase in the price of natural gas.
Transportation expenses were approximately $2 million for the three months ended March 31, 2019 and the three months ended December 31, 2018.
Marketing expenses increased 19% to $0.9 million for the three months ended March 31, 2019 compared to the three months ended December 31, 2018, primarily due to an increase in natural gas costs.
General and administrative expenses decreased by approximately $2 million, or 11%, to approximately $14 million for the three months ended March 31, 2019 compared to the three months ended December 31, 2018. The improvement was largely because the fourth quarter was impacted by higher stock compensation associated with performance shares meeting target thresholds. Adjusted general and administrative expenses, which exclude non-recurring restructuring and other costs and non-cash stock compensation costs, were $11.6 million or $4.63/Boe for the first quarter 2019 compared to $11.5 million or $4.49/Boe for the fourth quarter 2018. Adjusted general and administrative expenses is a non-GAAP financial measure defined as general and administrative expenses adjusted for non-recurring restructuring and other costs and non-cash stock compensation expense. Please see “—Non-GAAP Financial Measure” for a reconciliation to the GAAP financial measure of general and administrative expenses.
DD&A was approximately $25 million for the three months ended March 31, 2019, which is comparable to the three months ended December 31, 2018.
Gains on natural gas derivatives of $2 million for the three months ended March 31, 2019, mostly represented the gains on settled derivative contracts. The $4 million gain on natural gas derivatives for the three months ended December 31, 2018 consisted of gains on settled contracts and mark-to-market valuation gains.
Taxes, Other Than Income Taxes
 
Three Months Ended
 
$ Change
 
% Change
 
March 31, 2019
 
December 31, 2018
 
 
(in thousands)
 
 
Severance taxes
$
703

 
$
1,463

 
$
(760
)
 
(52
)%
Ad valorem and property taxes
3,145

 
3,833

 
(688
)
 
(18
)%
Greenhouse gas allowances
4,238

 
2,533

 
1,705

 
67
 %
Total taxes other than income taxes
$
8,086

 
$
7,829

 
$
257

 
3
 %
 
 
 
 
 
 
 
 
Taxes, other than income taxes ($/Boe)
$
3.23

 
$
3.04

 
 
 
 

Taxes, other than income taxes increased in the three months ended March 31, 2019 by $0.3 million or 3%, compared to the three months ended December 31, 2018 due to increased greenhouse gas allowances offset by lower severance taxes and ad valorem and property taxes. Greenhouse gas costs increased as a result of fewer free allowances from the state of California and higher spot prices for those allowances purchased, both increased the average unit cost of emissions incurred. Ad valorem and property taxes declined in the first quarter of 2019 due to lower supplemental assessments than the fourth quarter 2018. Severance tax refunds received during the first quarter 2019, related to prior periods, decreased the related expense compared to the fourth quarter of 2018.

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Table of Contents

Gains on Sale of Assets and Other, Net
Gains on sales of assets and other, net decreased in the three months ended March 31, 2019 by $4.5 million compared to the three months ended December 31, 2018 due to the gain on the sale of our East Texas properties in the fourth quarter 2018.
Reorganization items
Reorganization items, net consisted of approximately $0.2 million of expenses for the three months ended March 31, 2019, compared to income of $1 million from resolution of pre-emergence liabilities and claims for the three months ended December 31, 2018. The first quarter 2019 expenses were primarily related to the remaining bankruptcy-related legal and professional fees.
Income Tax Expense (Benefit)
Our effective tax rate was 27.8% for the three months ended March 31, 2019 and 23.2% for the three months ended December 31, 2018. The increase in the effective tax rate was primarily due to the release of our valuation allowance on deferred tax assets in 2018.

Three Months Ended March 31, 2019 compared to Three Months Ended March 31, 2018.
 
Three Months Ended
March 31,
 
$ Change
 
% Change
 
2019
 
2018
 
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
Oil, natural gas and NGL sales
$
131,102

 
$
125,624

 
$
5,478

 
4
 %
Electricity sales
9,729

 
5,453

 
4,276

 
78
 %
Gain (losses) on oil derivatives
(65,239
)
 
(34,644
)
 
(30,595
)
 
88
 %
Marketing and other revenues
947

 
851

 
96

 
11
 %
Total revenues and other
76,539

 
97,284

 
(20,745
)
 
(21
)%
Expenses and other:
 
 
 
 
 
 
 
Lease operating expenses
57,928

 
44,303

 
13,625

 
31
 %
Electricity generation expenses
7,760

 
4,590

 
3,170

 
69
 %
Transportation expenses
2,173

 
2,978

 
(805
)
 
(27
)%
Marketing expenses
851

 
580

 
271

 
47
 %
General and administrative expenses
14,340

 
11,985

 
2,355

 
20
 %
Depreciation, depletion and amortization
24,585

 
18,429

 
6,156

 
33
 %
Taxes, other than income taxes
8,086

 
8,256

 
(170
)
 
(2
)%
(Gains) losses on natural gas derivatives
(2,115
)
 

 
(2,115
)
 
(100
)%
(Gains) losses on sale of assets and other, net
1,245

 

 
1,245

 
100
 %
Total expenses and other
114,853

 
91,121

 
23,732

 
26
 %
Other income (expenses):
 
 
 
 
 
 
 
Interest expense
(8,805
)
 
(7,796
)
 
(1,009
)
 
13
 %
Other, net
154

 
27

 
127

 
470
 %
Reorganization items, net
(231
)
 
8,955

 
(9,186
)
 
(103
)%
Income (loss) before income taxes
(47,196
)
 
7,349

 
(54,545
)
 
(742
)%
Income tax expense (benefit)
(13,098
)
 
939

 
(14,037
)
 
(1,495
)%
Net income (loss)
(34,098
)
 
6,410

 
(40,508
)
 
(632
)%
Series A preferred stock dividends

 
(5,650
)
 
5,650

 
(100
)%
Net income (loss) available to common stockholders
$
(34,098
)
 
$
760

 
$
(34,858
)
 
(4,587
)%

22

Table of Contents

Revenues and Other
Oil, natural gas and NGL sales increased $5 million, or 4% to approximately $131 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018. The large majority of this increase reflects increased oil volumes, partially offset by lower oil prices.
Electricity sales represent sales to utilities and increased by approximately $4 million, or 78%, to approximately $10 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018. The increase was primarily due to higher sales prices, due to the link of sales price and higher natural gas pricing, in the three months ended March 31, 2019, than the three months ended March 31, 2018.
Losses on oil derivatives were $65 million, net of realized gains of $11 million, for the three months ended March 31, 2019 and $35 million, net of realized gains $18 million, for the three months ended March 31, 2018. The increased loss was primarily due to improved commodity prices relative to the fixed prices of our derivative contracts.
Marketing and other revenues increased over 11% to approximately $0.9 million for the three months ended March 31, 2019, compared to the three months ended March 31, 2018 due to higher average prices. Marketing revenues in these periods primarily represented sales of third-party natural gas.
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, as well as gas purchase hedge settlements, are viewed and used internally in calculating operating expenses which are used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.
Operating expenses, as defined above, increased to $21.71 per Boe for the quarter ended March 31, 2019 from $19.61 per Boe for the quarter ended March 31, 2018, including higher fuel costs of $5.38 per Boe, partially offset by gains on natural gas derivative settlements in 2019.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses increased by approximately $14 million, or 31%, to approximately $58 million for the three months ended March 31, 2019, compared to the three months ended March 31, 2018.
The increase in lease operating expenses was primarily due to unhedged higher fuel prices that increased fuel expense approximately $11 million for the three months ended March 31, 2019 from the three months ended March 31, 2018. The fuel gas price for the 2019 period was $4.94/MMBtu compared to $2.78/MMBbtu in 2018. Additionally, we had an increase in facility, well, and lease maintenance costs.
Electricity generation expenses increased approximately $3 million or 69% to $8 million for the three months ended March 31, 2019 and the three months ended March 31, 2018, primarily due to an increase in the price of natural gas.
Transportation expenses decreased by less than $1 million to approximately $2 million for the three months ended March 31, 2019, compared to the three months ended March 31, 2018, mainly due to lower volumes shipped.
Marketing expenses increased $0.3 million or 47% to $1.0 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, primarily due to higher natural gas costs.
General and administrative expenses increased by approximately $2 million, or 20%, to approximately $14 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018. For the three months ended March 31, 2019 and March 31, 2018, general and administrative expenses included non-recurring restructuring and other costs of approximately $1.3 million and $2.0 million, respectively, and non-cash stock compensation costs of approximately $1.4 million and $1.0 million, respectively. Adjusted general and administrative expenses, which exclude non-recurring restructuring and other costs and non-cash stock compensation costs, were $11.6 million or $4.63/Boe for the first quarter 2019 compared to $8.9 million or $3.79/Boe for the first quarter 2018. The increases in both general and administrative expenses and adjusted general and administrative expenses were primarily due to increased costs associated with supporting the company's growth and public company status.
DD&A increased by approximately $6 million, or 33%, to approximately $25 million, for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, primarily due to the increased production and higher depreciation and depletion rates for 2019.

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Table of Contents

Gains on natural gas derivatives of $2 million for the three months ended March 31, 2019 include $4 million of realized gains on settlements partially offset by mark-to-market losses.
Taxes, Other Than Income Taxes
 
Three Months Ended
March 31,
 
$ Change
% Change
 
2019
 
2018
 
 
(in thousands)
 
Severance taxes
$
703

 
$
2,764

 
$
(2,061
)
(75
)%
Ad valorem and property taxes
3,145

 
3,417

 
(272
)
(8
)%
Greenhouse gas allowances
4,238

 
2,075

 
2,163

104
 %
Total taxes other than income taxes
$
8,086

 
$
8,256

 
$
(170
)
(2
)%
 
 
 
 
 
 
 
Taxes, other than income taxes ($/Boe)
$
3.23

 
$
3.50

 
 
 

Taxes, other than income taxes decreased in the three months ended March 31, 2019 by $0.2 million or 2%, compared to the three months ended March 31, 2018 due to lower severance taxes and ad valorem and property taxes, partially offset by higher greenhouse gas cost allowances. Severance tax refunds received during the first quarter 2019, related to prior periods, decreased the related expense compared to the same period last year. Ad valorem and property taxes decreased due to lower supplemental assessments than in the first quarter 2018. Greenhouse gas costs increased as a result of fewer free allowances from the state of California and higher spot prices for those allowances purchased, both of which increased the average unit cost of emissions incurred.
Gains on Sale of Assets and Other, Net
Gains on sales of assets and other, net included purchase price adjustments in the three months ended March 31, 2019.
Interest Expense
Interest expense increased in the three months ended March 31, 2019 by approximately $1 million or 13%, compared to the three months ended March 31, 2018, due to three months of the interest on the 2026 Notes in the first quarter 2019 versus one and a half months in the first quarter 2018.
Reorganization items
Reorganization items, net consisted of approximately $0.2 million in expense for the three months ended March 31, 2019, compared to $9 million of income from the return of undistributed funds reserved for settlement of claims of general unsecured creditors for the three months ended March 31, 2018. The first quarter 2019 expenses were primarily related to the remaining bankruptcy-related legal and professional fees.
Income Tax Expense (Benefit)
Our effective tax rate was 27.8% for the three months ended March 31, 2019 and 12.8% for the three months ended March 31, 2018. The increase in the effective tax rate compared with the same period in 2018 was primarily due to the release of our valuation allowance on deferred tax assets in 2018 due to earnings.
Non-GAAP Financial Measures

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

24

Table of Contents

We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends.
Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. Levered Free Cash Flow is used by management as a primary metric to plan capital allocation for maintenance and internal growth opportunities, as well as hedging needs. It also serves as a measure for assessing our financial performance and our ability to generate excess cash from operations to service debt and pay dividends.
Adjusted Net Income (Loss) excludes the impact of unusual, out-of-period and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items and the income tax expense or benefit of these adjustments using our effective tax rate.
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 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.

25

Table of Contents

The following tables present reconciliations of the non-GAAP financial measures 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, as applicable, for each of the periods indicated.
 
Three Months Ended
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
 
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)
$
(34,098
)
 
$
131,768

 
$
6,410

Add (Subtract):
 
 
 
 
 
Interest expense
8,805

 
8,820

 
7,796

Income tax expense (benefit)
(13,098
)
 
39,890

 
939

Depreciation, depletion and amortization
24,585

 
24,253

 
18,429

Derivative losses (gains)
63,124

 
(131,637
)
 
34,644

Net cash received (paid) for scheduled derivative settlements
14,904

 
8,679

 
(17,849
)
(Gain) loss on sale of assets and other
1,245

 
(3,269
)
 

Stock compensation expense
1,475

 
3,249

 
1,042

Non-recurring restructuring and other costs
1,329

 
1,414

 
2,047

Reorganization items, net
231

 
(1,498
)
 
(8,955
)
Adjusted EBITDA
$
68,502

 
$
81,669

 
$
44,503


 
Three Months Ended
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
 
(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(1)
$
19,111

 
$
95,767

 
$
27,592

Add (Subtract):
 
 
 
 
 
Cash interest payments
14,000

 
562

 
2,654

Cash income tax payments

 
(1,901
)
 

Cash reorganization item (receipts) payments

 
(174
)
 
468

Non-recurring restructuring and other costs
1,329

 
1,414

 
2,047

Other changes in operating assets and liabilities
34,063

 
(13,998
)
 
11,742

Adjusted EBITDA
$
68,502

 
$
81,669

 
$
44,503

Subtract:
 
 
 
 
 
Capital expenditures - accrual basis
(49,099
)
 
(53,326
)
 
(15,732
)
Interest expense
(8,805
)
 
(8,820
)
 
(7,796
)
Cash dividends declared
(10,072
)
 
(9,992
)
 
(5,650
)
Levered Free Cash Flow(2)
$
526

 
$
9,531

 
$
15,325

__________
(1)
The three months ended March 31, 2019 included $37 million of annual or semi-annual payments that occur in the first quarter each year such as semi-annual interest and certain annual royalty payments and other accrued liabilities.
(2)
Levered Free Cash Flow includes cash received for scheduled derivative settlements of $15 million in the three months ended March 31, 2019 and $9 million in the three months ended December 31, 2018 and cash paid for scheduled derivatives settlements of $18 million for the three months ended March 31, 2018.

26

Table of Contents

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).
 
Three Months Ended
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
 
(in thousands)
Adjusted Net Income (Loss) reconciliation to net income (loss)
Net income (loss)
$
(34,098
)
 
$
131,768

 
$
6,410

Add (Subtract):
 
 
 
 
 
(Gains) losses on oil and natural gas derivatives
63,124

 
(131,637
)
 
34,644

Net cash received (paid) for scheduled derivative settlements
14,904

 
8,679

 
(17,849
)
(Gains) losses on sale of assets and other, net
1,245

 
(3,269
)
 

Non-recurring restructuring and other costs
1,329

 
1,414

 
2,047

Reorganization items, net
231

 
(1,498
)
 
(8,955
)
Total additions, net
80,833

 
(126,311
)
 
9,887

Income tax (expense) benefit of adjustments at effective tax rate
(22,471
)
 
29,352

 
(1,263
)
Adjusted Net Income (Loss)
$
24,264

 
$
34,809

 
$
15,034


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.
 
Three Months Ended
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
 
(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
G&A expenses
$
14,340

 
$
16,130

 
$
11,985

Subtract: