Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 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)

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

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

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

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


Shares of common stock outstanding as of July 31, 2019                     80,973,285



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)
 
June 30, 2019
 
December 31, 2018
 
(in thousands, except share amounts)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
227

 
$
68,680

Accounts receivable, net of allowance for doubtful accounts of $1,377 at June 30, 2019 and $950 at December 31, 2018
54,871

 
57,379

Derivative instruments
29,945

 
88,596

Other current assets
22,250

 
14,367

Total current assets
107,293

 
229,022

Noncurrent assets:
 
 
 
Oil and natural gas properties
1,581,035

 
1,461,993

Accumulated depletion and amortization
(163,948
)
 
(123,217
)
Total oil and natural gas properties, net
1,417,087

 
1,338,776

Other property and equipment
129,190

 
119,710

Accumulated depreciation
(20,273
)
 
(15,778
)
Total other property and equipment, net
108,917

 
103,932

Derivative instruments
8,282

 
3,289

Other non-current assets
15,162

 
17,244

Total assets
$
1,656,741

 
$
1,692,263

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
127,110

 
$
144,118

Derivative instruments
7,409

 

Total current liabilities
134,519

 
144,118

Noncurrent liabilities:
 
 
 
Long-term debt
397,315

 
391,786

Derivative instruments
206

 

Deferred income taxes
44,946

 
45,835

Asset retirement obligation
102,291

 
89,176

Other noncurrent liabilities
25,148

 
14,902

Commitments and Contingencies - Note 4

 


Equity:
 
 
 
Common stock ($.001 par value; 750,000,000 shares authorized; and 80,973,285 and 81,202,437 shares outstanding, at June 30, 2019 and December 31, 2018, respectively)
85

 
82

Additional paid-in-capital
897,322

 
914,540

Treasury stock, at cost, (3,648,823 shares at June 30, 2019 and 448,661 shares at December 31, 2018)
(39,225
)
 
(24,218
)
Retained earnings
94,134

 
116,042

Total equity
952,316

 
1,006,446

Total liabilities and equity
$
1,656,741

 
$
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
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
 
(in thousands, except per share amounts)
Revenues and other:
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
136,908

 
$
137,385

 
$
268,010

 
$
263,010

Electricity sales
5,364

 
5,971

 
15,093

 
11,423

Gains (losses) on oil derivatives
27,276

 
(78,143
)
 
(37,963
)
 
(112,787
)
Marketing revenues
414

 
518

 
1,244

 
1,302

Other revenues
104

 
251

 
221

 
317

Total revenues and other
170,066

 
65,982

 
246,605

 
163,265

Expenses and other:
 
 
 
 
 
 
 
Lease operating expenses
47,879

 
41,517

 
105,807

 
85,819

Electricity generation expenses
3,164

 
3,135

 
10,924

 
7,725

Transportation expenses
1,694

 
2,343

 
3,867

 
5,321

Marketing expenses
421

 
407

 
1,272

 
987

General and administrative expenses
16,158

 
12,482

 
30,498

 
24,466

Depreciation, depletion, and amortization
23,654

 
21,859

 
48,240

 
40,288

Taxes, other than income taxes
11,348

 
8,715

 
19,434

 
16,972

Losses on natural gas derivatives
9,449

 

 
7,334

 

Other operating expenses
3,119

 
123

 
4,364

 
123

Total expenses and other
116,886

 
90,581

 
231,740

 
181,701

Other income (expenses):
 
 
 
 
 
 
 
Interest expense
(8,961
)
 
(9,155
)
 
(17,766
)
 
(16,951
)
Other, net

 
(239
)
 
155

 
(212
)
Total other income (expenses)
(8,961
)
 
(9,394
)
 
(17,611
)
 
(17,163
)
Reorganization items, net
(26
)
 
456

 
(257
)
 
9,411

Income (loss) before income taxes
44,193

 
(33,537
)
 
(3,003
)
 
(26,188
)
Income tax expense (benefit)
12,221

 
(5,476
)
 
(877
)
 
(4,537
)
Net income (loss)
31,972

 
(28,061
)
 
(2,126
)
 
(21,651
)
Series A preferred stock dividends

 
(5,650
)
 

 
(11,301
)
Net income (loss) attributable to common stockholders
$
31,972

 
$
(33,711
)
 
$
(2,126
)
 
$
(32,952
)
 
 
 
 
 
 
 
 
Net income (loss) per share attributable to common stockholders:
 
 
 
 
 
 
 
Basic
$
0.39

 
$
(0.94
)
 
$
(0.03
)
 
$
(0.89
)
Diluted
$
0.39

 
$
(0.94
)
 
$
(0.03
)
 
$
(0.89
)


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)

 
Six-Month Period Ended June 30, 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

Stock based compensation

 

 
1,278

 

 

 
$
1,278

Shares withheld for payment of taxes on equity awards

 

 
(176
)
 

 

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

 

 
(5,651
)
 

 

 
$
(5,651
)
Purchase of rights to common stock

 

 

 
(20,006
)
 

 
$
(20,006
)
Net income (loss)

 

 

 

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


$
33


$
536,188


$
(20,006
)

$
(42,719
)

$
808,496

 
Six-Month Period Ended June 30, 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

Shares withheld for payment of taxes on equity awards and other

 

 
(675
)
 

 

 
(675
)
Stock based compensation

 

 
2,497

 

 

 
2,497

Purchases of treasury stock

 

 

 
(10,897
)
 

 
(10,897
)
Dividends declared on common stock, $0.12/share

 

 

 

 
(9,710
)
 
(9,710
)
Net income (loss)

 

 

 

 
31,972

 
31,972

June 30, 2019
$


$
85


$
897,322


$
(39,225
)

$
94,134


$
952,316

__________
(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)
 
Six Months Ended
June 30,
 
2019
 
2018
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(2,126
)
 
$
(21,651
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
Depreciation, depletion and amortization
48,240

 
40,288

Amortization of debt issuance costs
2,517

 
2,651

Stock-based compensation expense
3,918

 
2,320

Deferred income taxes
(877
)
 
(4,537
)
Increase (decrease) in allowance for doubtful accounts
427

 
(20
)
Other operating expenses
395

 
123

Reorganization expenses, net (non-cash)

 
(10,763
)
Derivative activities:
 
 
 
Total losses
45,297

 
112,787

Cash settlements on derivatives
11,578

 
(46,110
)
Cash payments on early-terminated derivatives

 
(126,949
)
Changes in assets and liabilities:
 
 
 
Decrease (increase) in accounts receivable
2,108

 
(2,120
)
(Increase) in other assets
(13,021
)
 
(1,859
)
(Decrease) increase in accounts payable and accrued expenses
(8,319
)
 
8,421

(Decrease) in other liabilities
336

 
(2,129
)
Net cash provided by (used in) operating activities
90,473

 
(49,548
)
 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures:
 
 
 
Development of oil and natural gas properties
(95,538
)
 
(37,609
)
Purchases of other property and equipment
(9,190
)
 
(7,760
)
Acquisition of properties
(2,689
)
 

Proceeds from sale of property and equipment and other
38

 
3,022

Net cash (used in) investing activities
(107,379
)
 
(42,347
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Borrowings under RBL credit facility
123,400

 
96,800

Repayments on RBL credit facility
(118,200
)
 
(409,800
)
Proceeds from issuance of senior unsecured notes

 
400,000

Dividends paid on common stock
(19,662
)
 

Purchase of treasury stock
(36,139
)
 
(20,006
)
Shares withheld for payment of taxes on equity awards and other
(946
)
 
(176
)
Dividends paid on Series A Preferred Stock

 
(11,301
)
Debt issuance costs

 
(9,050
)
Net cash (used in) provided by financing activities
(51,547
)
 
46,467

Net decrease in cash, cash equivalents and restricted cash
(68,453
)
 
(45,428
)
Cash, cash equivalents and restricted cash:
 
 
 
Beginning
68,680

 
68,738

Ending
$
227

 
$
23,310


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 as of June 30, 2019. 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 February 2016, the FASB issued rules requiring lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers which is for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We expect the adoption of these rules to increase other assets and other liabilities on our balance sheet and do not expect a material impact on our consolidated results of operations.

5

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

Note 2 - Debt
The following table summarizes our outstanding debt:
 
June 30, 2019
 
December 31, 2018
 
Interest Rate
 
Maturity
 
Security
 
(in thousands)
 
 
 
 
 
 
RBL Facility
$
5,200

 
$

 
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
405,200

 
400,000

 
 
 
 
 
 
Less: Debt Issuance Costs
(7,885
)
 
(8,214
)
 
 
 
 
 
 
Long-Term Debt, net
$
397,315

 
$
391,786

 
 
 
 
 
 

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At June 30, 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 $13 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 June 30, 2019 and December 31, 2018, debt issuance costs, net of amortization, for the 2026 Senior Unsecured Notes were both $8 million.
For the three months ended June 30, 2019 and June 30, 2018, the amortization expense for the RBL Facility and 2026 Senior Unsecured Notes was approximately $1 million, which was included in "interest expense" in the condensed consolidated statements of operations. For the six months ended June 30, 2019 and June 30, 2018, these amounts were approximately $3 million, which 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 $388 million and $368 million at June 30, 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 June 30, 2019.
As of June 30, 2019, we had approximately $386 million of available borrowing capacity under the RBL Facility.
As of June 30, 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, interest and dividends, 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 June 30, 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 condensed consolidated statements of operations and (gains) losses on natural gas hedges are presented in the expenses and other section of the condensed consolidated statements of operations.
As of June 30, 2019, we had the following crude oil production and gas purchases hedges.
 
Q3 2019
 
Q4 2019
 
FY 2020
Sold Oil Calls Options (Brent):
 
 
 
 
 
Hedged volume (MBbls)
92

 
92

 

Weighted-average price ($/Bbl)
$
81.00

 
$
81.00

 
$

Purchased Oil Put Options (Brent):
 
 
 
 
 
  Hedged volume (MBbls)
460

 
460

 

  Weighted-average price ($/Bbl)
$
50.00

 
$
50.00

 
$

Fixed Price Oil Swaps (Brent):
 
 
 
 
 
  Hedged volume (MBbls)
1,472

 
1,380

 
4,392

  Weighted-average price ($/Bbl)
$
72.64

 
$
72.21

 
$
65.70

Fixed Price Oil Swaps (WTI):
 
 
 
 
 
  Hedged volume (MBbls)
92

 
92

 
121

  Weighted-average price ($/Bbl)
$
61.75

 
$
61.75

 
$
61.75

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

 
46

 

  Weighted-average price ($/Bbl)
$
(1.29
)
 
$
(1.29
)
 
$

Fixed Price Gas Purchase Swaps (Kern, Delivered):
 
 
 
 
 
  Hedged volume (MMBtu)
4,600,000

 
4,295,000

 
13,725,000

  Weighted-average price ($/MMBtu)
$
2.91

 
$
2.95

 
$
2.98

Fixed Price Gas Purchase Swaps (SoCal Citygate):
 
 
 
 
 
  Hedged volume (MMBtu)
460,000

 
460,000

 
1,525,000

  Weighted-average price ($/MMBtu)
$
3.80

 
$
3.80

 
$
3.80


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 purchased puts 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 have mitigated the exposure to a substantial portion of these premium payments by entering into offsetting put positions. We paid approximately $4 million and $19 million of the deferred premiums during the three and six months ended June 30, 2019, which is partially offset by premiums received during the six months ended June 30, 2019. The remaining deferred premiums of approximately $2 million are reflected in the mark-to-market valuation and will be payable through the first quarter of 2020.

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

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.
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 June 30, 2019 and December 31, 2018:
 
June 30, 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
 
$
39,116

 
$
(9,172
)
 
$
29,945

  Commodity Contracts
Non-current assets
 
9,301

 
(1,020
)
 
8,282

Liabilities:
 
 
 
 
 
 
 
  Commodity Contracts
Current liabilities
 
(16,581
)
 
9,172

 
(7,409
)
  Commodity Contracts
Non-current liabilities
 
(1,226
)
 
1,020

 
(206
)
Total derivatives
 
 
$
30,611

 
$

 
$
30,611


 
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 June 30, 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 June 30, 2019, we are not aware of material indemnity claims pending or threatened against us.
During the six months ended June 30, 2019, we entered into agreements to replace our Bakersfield, California office lease for approximately $11 million in aggregate over 8 years beginning August 2019. The annual costs under our current office lease, which ends in 2019, are similar to the costs under the new leases.
Note 5 - Equity
Cash Dividends
Our board of directors approved $0.12 per share quarterly cash dividends on our common stock for the first, second and third quarters of 2019. We paid the second quarter dividend in July 2019 and declared the third quarter dividend in July 2019, which is payable in October 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 market conditions for our common stock they authorized initial 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 June 30, 2019, we repurchased 1,000,000 shares at an average price of $10.90 per share for $11 million, which is reflected as treasury stock. For the six months ended June 30, 2019, we repurchased 3,200,162 shares at an average price of $11.02 per share for $35 million, which is reflected as treasury stock. The Company has repurchased a total of 3,648,823 shares under the stock repurchase program for $39 million as of June 30, 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 - 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.

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

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 Financial Statements
Other current assets reported on the condensed consolidated balance sheets included the following:  
 
June 30, 2019
 
December 31, 2018
 
(in thousands)
Prepaid expenses
$
7,382

 
$
4,656

Materials and supplies
10,909

 
5,461

Inventories
3,717

 
4,012

Other
243

 
238

Total
$
22,250

 
$
14,367

The major classes of inventory were not material and therefore not stated separately. Other non-current assets at June 30, 2019 and December 31, 2018, included approximately $13 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:
 
June 30, 2019
 
December 31, 2018
 
(in thousands)
Accounts payable-trade
$
20,693

 
$
13,564

Accrued expenses
52,070

 
66,417

Royalties payable
16,160

 
26,189

Taxes other than income tax liability
8,526

 
10,766

Accrued interest
10,516

 
10,500

Dividends payable
10,112

 
9,992

Asset retirement obligation - current portion
8,927

 
6,372

Other
106

 
318

Accounts payable and accrued expenses - total
$
127,110

 
$
144,118


The increase in the long-term portion of the asset retirement obligation largely reflected an increase in the change in estimate of $18 million, $2 million in new wells, and accretion expense of $3 million. The change in estimate was a result of California's new idle well regulations effective in the second quarter. This accelerated the timing of abandonment of certain wells. These increases were partially offset by liabilities settled during the period of $8 million and an increase to the current portion of the asset retirement obligation of $3 million.
Other non-current liabilities at June 30, 2019 and December 31, 2018 included approximately $25 million and $15 million of greenhouse gas liability, respectively.
Supplemental Information on the Statement of Operations
Other operating expenses mainly consist of excess abandonment costs, as well as gain (loss) on sale of assets.

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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:
 
Six Months Ended
June 30,
 
2019
 
2018
 
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
 
 
(Increase) decrease in accrued liabilities related to purchases of property and equipment
$
3,938

 
$
8,614

Supplemental Disclosures of Cash Payments (Receipts):
 
 
 
  Interest, net of amounts capitalized
$
15,272

 
$
3,298

  Reorganization items, net
$

 
$
1,352

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:
 
Six Months Ended
June 30,
 
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
$
227

 
$
3,600

Restricted cash

 
19,710

Cash, cash equivalents and restricted cash
$
227

 
$
23,310

Restricted cash was associated with cash reserved to settle claims with general unsecured creditors. Cash and cash equivalents consist 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, which is approximately 82 million shares in 2019. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, are considered common shares outstanding and are included in the computation of net income (loss) per share. Our initial capitalization included the issuance of 32,920,000 shares of common stock and another 7,080,000 shares reserved to settle claims of unsecured creditors, all of which were included in our computation of net income (loss) per share until the claims were settled and the shares issued. 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 and six months ended June 30, 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 the diluted EPS calculation for the three and six months ended June 30, 2018 as their effect was anti-dilutive under

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

the "if converted" method. The RSUs are not a participating security as the dividends are forfeitable. We included 164,000 incremental RSU shares in the diluted EPS calculation for the three months ended June 30, 2019. No incremental RSU shares were included in the diluted EPS calculation for the six months ended June 30, 2019 and the three and six months ended June 30, 2018, as their effect was anti-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
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
 
(in thousands except per share amounts)
Basic EPS calculation

 

 

 

Net income (loss)
$
31,972

 
$
(28,061
)
 
$
(2,126
)
 
(21,651
)
less: Series A Preferred Stock dividends and conversion to common stock

 
(5,650
)
 

 
(11,301
)
Net income (loss) attributable to common stockholders
$
31,972

 
$
(33,711
)
 
$
(2,126
)
 
$
(32,952
)
Weighted-average shares of common stock outstanding
81,519

 
35,873

 
82,061

 
37,224

Basic earnings (loss) per share(2)
$
0.39

 
$
(0.94
)
 
$
(0.03
)
 
$
(0.89
)
Diluted EPS calculation

 

 
 
 
 
Net income (loss)
$
31,972

 
$
(28,061
)
 
$
(2,126
)
 
$
(21,651
)
less: Series A Preferred Stock dividends and conversion to common stock

 
(5,650
)
 

 
(11,301
)
Net income (loss) attributable to common stockholders
$
31,972

 
$
(33,711
)
 
$
(2,126
)
 
$
(32,952
)
Weighted-average shares of common stock outstanding
81,519

 
35,873

 
82,061

 
37,224

Dilutive effect of potentially dilutive securities(1)
164

 

 

 

Weighted-average common shares outstanding - diluted
81,683

 
35,873

 
82,061

 
37,224

Diluted earnings (loss) per share(2)
$
0.39

 
$
(0.94
)
 
$
(0.03
)
 
$
(0.89
)
__________
(1)
No potentially dilutive securities were included in computing earnings (loss) per share for the six months ended June 30, 2019 and the three and six months ended June 30, 2018, because the effect of inclusion would have been anti-dilutive.

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 condensed consolidated statements 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
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
 
(in thousands)
Oil sales
$
132,165

 
$
130,464

 
$
255,616

 
$
248,367

Natural gas sales
4,086

 
5,400

 
10,800

 
11,963

Natural gas liquids sales
657

 
1,521

 
1,594

 
2,680

Electricity sales
5,364

 
5,971

 
15,093

 
11,423

Marketing revenues
414

 
518

 
1,244

 
1,302

Revenues from contracts with customers
142,686

 
143,874

 
284,347

 
275,735

Gains (losses) on oil derivatives
27,276

 
(78,143
)
 
(37,963
)
 
(112,787
)
Other revenues
104

 
251

 
221

 
317

Total revenues and other
$
170,066

 
$
65,982

 
$
246,605

 
$
163,265


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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 low risk, long-lived, oil reserves in conventional reservoirs. Most of our assets are 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, consistent and predictable 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) cash 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
As of the three and six months ended June 30, 2019, our capital expenditures for 2019 were approximately $57 million and $106 million, respectively, on an accrual basis excluding acquisitions. For the three and six months ended June 30, 2019, approximately 92% and 90%, respectively, 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 at least 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. Our 2019 capital program was front-end loaded resulting in more wells drilled in the first half of the year than the amount we expect to drill in the second half. Consistent with our plan, we drilled 210 wells in the first six months of 2019, of which we expect 133 wells will generate growth in the last half of the year as they come online or realize the full effects of steam injection. During 2019, we expect to:
• employ up to four drilling rigs in California throughout the year; and

• drill approximately 370 to 400 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
$
185-209
$
126

Rockies
 
4-9
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. Average oil prices were higher for the three months ended June 30, 2019 compared to the three months ended March 31, 2019 and lower than the three months ended June 30, 2018, and they fluctuated during each period. For instance, Brent crude oil contract prices ranged from $74.57 per Bbl to $59.97 per Bbl during the second quarter of 2019. In California, the daily price we paid for fuel gas purchases (generally based on the Kern Delivered Index) was as low as $0.99 per MMBtu and as high as $2.85 per MMBtu during the second 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 Annual Report.
The following table presents the average Brent, WTI, and Kern, Delivered prices for the three months ended June 30, 2019, March 31, 2019 and June 30, 2018 and for the six months ended June 30, 2019 and June 30, 2018:
 
Three Months Ended
 
Six Months Ended
 
June 30, 2019
 
March 31, 2019
 
June 30, 2018
 
June 30, 2019
 
June 30, 2018
Brent oil ($/Bbl)
$
68.47

 
$
63.83

 
$
74.97

 
$
66.17

 
$
71.16

WTI oil ($/Bbl)
$
59.86

 
$
54.87

 
$
67.85

 
$
57.38

 
$
65.42

Kern, Delivered natural gas ($/MMBtu)
$
2.07

 
$
5.03

 
$
2.23

 
$
3.54

 
$
2.44

California oil prices are Brent-influenced as California refiners import approximately 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 for 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. We are currently negotiating terms of a new power purchase agreement for our 18 MW cogeneration facility for which the current agreement expires in October 2019.

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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
 
June 30, 2019
 
March 31, 2019
 
June 30, 2018
 
June 30, 2019
 
March 31, 2019
 
June 30, 2018
($ in thousands, except prices)
 
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
120,917

 
$
111,896

 
$
117,288

 
$
15,991

 
$
19,206

 
$
20,097

Operating income(a)
$
47,809

 
$
37,357

 
$
60,014

 
$
954

 
$
4,779

 
$
4,858

Depreciation, depletion, and amortization (DD&A)
$
20,460

 
$
21,342

 
$
18,001

 
$
3,194

 
$
3,244

 
$
3,140

Average daily production (MBoe/d)
20.8

 
21.0

 
18.8

 
6.6

 
6.8

 
7.7

Production (oil % of total)
100
%
 
100
%
 
100
%
 
41
%
 
46
%
 
30
%
Realized sales prices:
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
63.91

 
$
59.16

 
$
68.72

 
$
44.92

 
$
41.38

 
$
61.64

NGLs (per Bbl)
$

 
$

 
$

 
$
16.86

 
$
24.42

 
$
24.38

Gas (per Mcf)
$

 
$

 
$

 
$
2.16

 
$
3.77

 
$
2.12

Capital expenditures
$
52,374

 
$
42,509

 
$
34,537

 
$
1,443

 
$
5,313

 
$
3,735

__________
(a)
Operating income comprises 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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Production, Prices and Costs
The following table sets forth information regarding average daily production, total production, average prices and average costs for each of the periods indicated.
 
Three Months Ended
 
June 30, 2019
 
March 31, 2019
 
June 30, 2018
Average daily production:(1)(5)
 
 
 
 
 
Oil (MBbl/d)
23.5

 
24.1

 
21.1

Natural Gas (MMcf/d)
20.8

 
19.5

 
28.0

NGL (MBbl/d)
0.4

 
0.4

 
0.7

Total (MBoe/d)(2)
27.4

 
27.8

 
26.5

Total Production:(5)
 
 
 
 
 
Oil (MBbl)
2,142

 
2,170

 
1,920

Natural gas (MMcf)
1,894

 
1,752

 
2,551

NGLs (MBbl)
39

 
38

 
62

Total (MBoe)(2)
2,497

 
2,501

 
2,408

Weighted-average realized sales prices:
 
 
 
 
 
Oil without hedges ($/Bbl)
$
61.69

 
$
56.88

 
$
67.93

Oil with hedges ($/Bbl)
$
61.82

 
$
62.03

 
$
53.22

Natural gas ($/Mcf)
$
2.16

 
$
3.83

 
$
2.12

NGL ($/Bbl)
$
16.86

 
$
24.35

 
$
24.38

Average Benchmark prices:
 
 
 
 
 
Oil (Bbl) – Brent
$
68.47

 
$
63.83

 
$
74.97

Oil (Bbl) – WTI
$
59.86

 
$
54.87

 
$
67.85

Gas (MMBtu) – Kern, Delivered(6)
$
2.07

 
$
5.03

 
$
2.23

Average costs per Boe:(3)
 
 
 
 
 
Lease operating expenses
$
19.18

 
$
23.16

 
$
17.24

Electricity generation expenses
1.27

 
3.10

 
1.30

Electricity sales(3)
(2.15
)
 
(3.89
)
 
(2.48
)
Transportation expenses
0.68

 
0.87

 
0.97

Transportation sales(3)
(0.04
)
 
(0.05
)
 
(0.09
)
Marketing expenses
0.17

 
0.34

 
0.17

Marketing revenues(3)
(0.17
)
 
(0.33
)
 
(0.22
)
Derivatives settlements (received) paid for gas purchases(3)
1.44

 
(1.49
)
 

Total operating expenses
$
20.38

 
$
21.71

 
$
16.89

General and administrative expenses(4)
$
6.47

 
$
5.73

 
$
5.18

Depreciation, depletion and amortization
$
9.47

 
$
9.83

 
$
9.08

Taxes, other than income taxes
$
4.54

 
$
3.23

 
$
3.62

__________
(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 three months ended June 30, 2019, the average prices of Brent oil and Henry Hub natural gas were $68.47 per Bbl and $2.57 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 revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales 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 include the effect of derivative settlements (received or paid) for gas purchases.

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Table of Contents

(4)
Includes restructuring and other non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.55 per Boe, $1.10 per Boe and $1.24 per Boe for the three months ended June 30, 2019, March 31, 2019 and June 30, 2018, respectively.
(5)
On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
(6)
Kern Delivered Index is the relevant index used for gas purchases in California.

The following table sets forth average daily production by operating area for the periods indicated:
 
Three Months Ended
 
June 30, 2019
 
March 31, 2019
 
June 30, 2018
Average daily production (MBoe/d):(1)
 
 
 
 
 
California
20.8

 
21.0

 
18.8

Rockies
6.6

 
6.8

 
6.9

East Texas(2)

 

 
0.8

Total average daily production
27.4

 
27.8

 
26.5

__________
(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, including sales of inventory, was lower for the three months ended June 30, 2019 due to inventory sales in the three months ended March 31, 2019, as actual production was flat quarter over quarter.
Average daily production volumes increased for the three months ended June 30, 2019 as compared to the three months ended June 30, 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 three months ended June 30, 2019 California production increased 11% compared to the three months ended June 30, 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.




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Table of Contents

The following table sets forth information regarding total production, average daily production, average prices and average costs for each of the periods indicated.
 
Six Months Ended
 
June 30, 2019
 
June 30, 2018
Average daily production:(1)(5)
 
 
 
Oil (MBbl/d)
23.8

 
21.1

Natural Gas (MMcf/d)
20.1

 
27.8

NGL (MBbl/d)
0.4

 
0.6

Total (MBoe/d)(2)
27.6

 
26.3

Total Production:(5)
 
 
 
Oil (MBbl)
4,313

 
3,818

Natural gas (MMcf)
3,646

 
5,032

NGLs (MBbl)
77

 
108

Total (MBoe)(2)
4,998

 
4,764

Weighted-average realized sales prices:
 
 
 
Oil without hedges ($/Bbl)
$
59.27

 
$
65.06

Oil with hedges ($/Bbl)
$
61.92

 
$
52.98

Natural gas ($/Mcf)
$
2.96

 
$
2.38

NGL ($/Bbl)
$
20.59

 
$
24.88

Average Benchmark prices:
 
 
 
Oil (Bbl) – Brent
$
66.17

 
$
71.16

Oil (Bbl) – WTI
$
57.38

 
$
65.42

Gas (MMBtu) – Kern, Delivered(6)
$
3.54

 
$
2.44

Average costs per Boe:(3)
 
 
 
Lease operating expenses
$
21.17

 
$
18.01

Electricity generation expenses
2.19

 
1.62

Electricity sales(3)
(3.02
)
 
(2.40
)
Transportation expenses
0.77

 
1.12

Transportation sales(3)
(0.04
)
 
(0.05
)
Marketing expenses
0.25

 
0.21

Marketing revenues(3)
(0.25
)
 
(0.27
)
Derivatives settlements (received) paid for gas purchases(3)
(0.03
)
 

Total operating expenses
$
21.04

 
$
18.24

General and administrative expenses(4)
$
6.10

 
$
5.14

Depreciation, depletion and amortization
$
9.65

 
$
8.46

Taxes, other than income taxes
$
3.89

 
$
3.56

__________
(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 six months ended June 30, 2019, the average prices of Brent oil and Henry Hub natural gas were $66.17 per Bbl and $2.74 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 are 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.
(4)
Includes restructuring and other non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.33 per Boe and $1.28 per Boe for the six months ended June 30, 2019 and June 30, 2018, respectively.
(5)
On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.

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(6)
Kern Delivered Index is the relevant index used for gas purchases in California.
The following table sets forth average daily production by operating area for the periods indicated:
 
Six Months Ended
 
June 30, 2019
 
June 30, 2018
Average daily production (MBoe/d):(1)
 
 
 
California
20.9

 
18.8

Rockies
6.7

 
6.7

East Texas(2)

 
0.8

Total average daily production
27.6

 
26.3

__________
(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 six months ended June 30, 2019 compared to the six months ended June 30, 2018 due to production response from development capital spending throughout 2018 and 2019, offset by natural decline and the sale of our East Texas properties in November 2018. For the six months ended June 30, 2019 California production increased 11% compared to the six months ended June 30, 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.





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Table of Contents

Results of Operations
Three Months Ended June 30, 2019 compared to Three Months Ended March 31, 2019.
 
Three Months Ended
 
$ Change
 
% Change
 
June 30, 2019
 
March 31, 2019
 
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
Oil, natural gas and NGL sales
$
136,908

 
$
131,102

 
$
5,806

 
4
 %
Electricity sales
5,364

 
9,729

 
(4,365
)
 
(45
)%
Gain (losses) on oil derivatives
27,276

 
(65,239
)
 
92,515

 
n/a

Marketing and other revenues
518

 
947

 
(429
)
 
(45
)%
Total revenues and other
170,066

 
76,539

 
93,527

 
122
 %
Expenses and other:
 
 
 
 
 
 
 
Lease operating expenses
47,879

 
57,928

 
(10,049
)
 
(17
)%
Electricity generation expenses
3,164

 
7,760

 
(4,596
)
 
(59
)%
Transportation expenses
1,694

 
2,173

 
(479
)
 
(22
)%
Marketing expenses
421

 
851

 
(430
)
 
(51
)%
General and administrative expenses
16,158

 
14,340

 
1,818

 
13
 %
Depreciation, depletion and amortization
23,654

 
24,585

 
(931
)
 
(4
)%
Taxes, other than income taxes
11,348

 
8,086

 
3,262

 
40
 %
(Gains) losses on natural gas derivatives
9,449

 
(2,115
)
 
11,564

 
n/a

Other operating expenses
3,119

 
1,245

 
1,874

 
151
 %
Total expenses and other
116,886

 
114,853

 
2,033

 
2
 %
Other income (expenses):
 
 
 
 
 
 
 
Interest expense
(8,961
)
 
(8,805
)
 
(156
)
 
2
 %
Other, net

 
154

 
(154
)
 
(100
)%
Reorganization items, net
(26
)
 
(231
)
 
205

 
(89
)%
Income (loss) before income taxes
44,193

 
(47,196
)
 
91,389

 
n/a

Income tax expense (benefit)
12,221

 
(13,098
)
 
25,319

 
n/a

Net income (loss)
$
31,972

 
$
(34,098
)
 
$
66,070

 
n/a

Revenues and Other
Oil, natural gas and NGL sales increased $6 million, or 4%, to approximately $137 million for the three months ended June 30, 2019 compared to the three months ended March 31, 2019. This increase reflected higher oil prices that were partially offset by lower gas prices and oil volumes including the impact of selling more Utah oil inventory in the first quarter.
Electricity sales represent sales to utilities, and decreased $4 million, or 45%, to approximately $5 million for the three months ended June 30, 2019 compared to the three months ended March 31, 2019. The decrease reflected lower unit sales prices and volumes due to increased facility downtime for scheduled maintenance during the second quarter of 2019 and lower seasonal prices compared to the first quarter as expected.
Gains on oil derivatives were approximately $27 million for the three months ended June 30, 2019 compared to losses of approximately $65 million for the three months ended March 31, 2019. Gains for the second quarter of 2019 mostly resulted from the mark-to-market effect caused by decreasing oil prices relative to the fixed prices of our derivative contracts.
Marketing and other revenues decreased 45% to approximately $0.5 million for the three months ended June 30, 2019, compared to the three months ended March 31, 2019 mostly due to lower average gas prices. Marketing revenues in these periods represented sales of natural gas purchased from third-parties.
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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Operating expenses, as defined above in "How We Plan and Evaluate Operations", decreased to $20.38 per Boe for the three months ended June 30, 2019 from $21.71 per Boe for the three months ended March 31, 2019. This decrease was largely driven by fuel costs that were lower by $6.86 per Boe partially offset by settled gas hedge losses which increased by $2.93 per Boe.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $10 million, or 17%, to approximately $48 million for the three months ended June 30, 2019, compared to the three months ended March 31, 2019.

Lease operating expenses were $19.18 per Boe for the three months ended June 30, 2019 compared to $23.16 per Boe for the three months ended March 31, 2019. Fuel prices related to our California steam operations recovered from unseasonably high prices during the three months ended March 31, 2019. The average fuel cost for the second quarter of 2019 decreased 58% to $2.03/MMBtu compared to $4.87/MMBtu for the first quarter of 2019. The decrease in fuel costs was partially offset by increases in facility, well, and lease maintenance costs during the second quarter of 2019. These fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Electricity generation expenses decreased approximately $5 million or 59% to $3 million for the three months ended June 30, 2019 compared to the three months ended March 31, 2019. The decrease reflected lower seasonal fuel costs and volumes due to increased downtime for scheduled maintenance during the second quarter of 2019. These fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Losses on natural gas derivatives of $9 million for the three months ended June 30, 2019, consisted of losses on settled derivative contracts and mark-to-market valuation losses. The $2 million gain on natural gas derivatives for the three months ended March 31, 2019 resulted from gains on settled contracts that were partially offset by mark-to-market valuation losses. Additionally, we increased our gas purchase hedge positions during the second quarter of 2019 to stabilize our fuel costs.
Transportation expenses were flat for the three months ended June 30, 2019 and March 31, 2019.
Marketing expenses were flat for the three months ended June 30, 2019 and March 31, 2019. Marketing expenses in these periods represented the cost of natural gas purchased from third-parties.
General and administrative expenses increased by approximately $2 million, or 13%, to approximately $16 million for the three months ended June 30, 2019 compared to the three months ended March 31, 2019. The second quarter was affected by higher non-cash stock compensation associated with the annual grant of stock awards in March. For the three months ended June 30, 2019 and March 31, 2019, general and administrative expenses included restructuring and other non-recurring costs of approximately $1.5 million and $1.3 million, respectively, and non-cash stock compensation costs of approximately $2.4 million and $1.4 million, respectively.
Adjusted general and administrative expenses, which exclude restructuring and other non-recurring costs and non-cash stock compensation costs, were $12.3 million or $4.92/Boe for the second quarter 2019 compared to $11.6 million or $4.63/Boe for the first quarter 2019. This increase was primarily due to organizational growth and system enhancements. Adjusted general and administrative expenses is a non-GAAP financial measure defined as general and administrative expenses adjusted for restructuring and other non-recurring 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 $24 million for the three months ended June 30, 2019, and was comparable to the three months ended March 31, 2019.

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Table of Contents

Taxes, Other Than Income Taxes
 
Three Months Ended
 
$ Change
 
% Change