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Chaparral Energy Announces Second Quarter 2019 Financial and Operational Results

OKLAHOMA CITY, Aug. 07, 2019 (GLOBE NEWSWIRE) -- Chaparral Energy, Inc. (CHAP) announced today its second quarter 2019 financial and operational results. The company will hold its quarterly earnings call Thursday, August 8, at 9 a.m. Central.

Recent Highlights

  • Achieved second quarter 2019 total production of 28.3 thousand barrels of oil equivalent per day (MBoe/d), 1.5 MBoe/d above midpoint and 0.8 MBoe/d above high end of guidance and a 36% increase from the first quarter of 2019
  • Increased STACK production to 23.8 MBoe/d in the second quarter, 1.5 MBoe/d above midpoint and 0.8 MBoe/d above high end of guidance and a 50% increase from the first quarter of 2019
  • Reported net loss of $45.2 million for the second quarter of 2019, or $0.99 per share, which included a $63.6 million non-cash ceiling test impairment charge, partially offset by a $17.6 million non-cash derivative gain
  • Grew second quarter 2019 adjusted EBITDA, as defined below, to $43.7 million, an increase of 54% compared to the previous quarter
  • Decreased total company and STACK lease operating expense per Boe (LOE/Boe) to $5.19 and $3.90, respectively, a 21% decrease from the previous quarter for both
  • Lowered cash general and administrative expense per Boe (G&A/Boe), as defined below, to $2.52, which represents a 27% decrease from the previous quarter
  • Updated full year 2019 guidance, including a 5% reduction in total capital expenditures compared to the previous midpoint of the company’s guidance and decreases in LOE/Boe and cash G&A/Boe expense, while reaffirming its previously stated production range
  • Implemented proactive G&A cost reduction initiatives resulting in corporate workforce being reduced by 23% year to date and expected annualized G&A reductions of approximately 20% to 25% to better align G&A with current industry conditions
  • Continued drilling and completion execution improvements, with recent average Osage and Merge Miss well costs declining materially compared to the company’s 2018 average, ranging from $3.5 to $4.0 million in 2019
  • Finalized an agreement to sell the current corporate headquarters facilities; proceeds from the sale will be used to eliminate related debt of approximately $8.3 million and is expected to result in annual savings of approximately $1 million
  • Announced 120-day initial production (IP) results above oil type curve expectations from its 11-well cube style, co-development Foraker spacing test in Canadian County

“Since becoming a publicly traded company in 2017, we have consistently delivered operational results within or above our guidances ranges and this quarter is no exception,” said Chief Executive Officer Earl Reynolds. “We continue to demonstrate the considerable value of our differentiated acreage position through our outstanding operational execution. Our total company production increased to 28.3 MBoe/d, our adjusted EBITDA grew to $43.7 million and our operational expenses and capital costs per well continue to decline. Through the first half of this year we have been able to reduce our average well cost by approximately 15% to 20% compared to 2018 for our Merge Miss and Osage drilling program. Our ability to consistently execute, coupled with the operational efficiencies we continue to capture, including increases in drilling footage per day, more efficient frac designs and doubling the number of frac stages completed per day, have all contributed to our reduced well costs. These efficiencies allow us to drill and complete wells faster, drive down costs and reduce cycle times, which all positively impact well economics.”

“In addition, we continue to be very pleased with the outstanding drilling, completion and production results from our cube style, co-development Foraker spacing test, which we brought online in late March,” said Reynolds. “The average 120-day IP oil rates for both the Meramec and Woodford wells continue to outperform type curve at 148% and 101% respectively. I am extremely proud of our execution on this project and we are applying the learnings from this one-mile, full section development moving forward. We are reconfiguring our second half drilling schedule based on these results and plan to begin drilling the Greenback, which is a Canadian County Meramec full section development in close proximity to the Foraker, in the fourth quarter of this year.”

“For the full year of 2019, we are updating our corporate guidance. We continue to proactively take measures to reduce costs across our entire business. As a result of our G&A cost reduction initiatives, we are reducing our G&A per Boe guidance by 11% and as a result of our operational success are lowering our STACK LOE/Boe guidance by 4%. We are reaffirming our original full-year 2019 production estimates but lowering our capital expenditure guidance by approximately 5%. As we have discussed in the past, the overall timing of our production growth will be uneven from quarter to quarter due to the drilling of larger pads and full section developments. As such, we expect our third quarter total production guidance to be between 26.0 to 27.5 MBoe/d. While we continue to expect strong growth, the timing of completions and performance of our new wells will impact our quarter-to-quarter rates going forward,” said Reynolds. “We are proud of the differentiated STACK/Merge position we have built and how we have been able to execute operationally. We remain focused on generating strong adjusted EBITDA, which is driven by our operational execution, capital discipline and cost management, and maintaining a strong balance sheet. We are continuing to grow production and proactively taking additional steps that are allowing us to move progressively closer to achieving cash flow neutrality as we create long-term value for our shareholders.”

Operational Update
Chaparral’s STACK production for the second quarter of 2019 was 23.8 MBoe/d, while total company production was 28.3 MBoe/d, both of which are above the high end of the company’s second quarter 2019 guidance range. As expected, due to timing associated with production from the company’s multi-well spacing tests, total company and STACK production increased significantly on a quarter-over-quarter basis by 36% and 50%, respectively. On a year-over-year basis, STACK production increased 80%, while total company production increased 55%, excluding 2018 divestitures. Overall, total company production consisted of 34% oil, 29% natural gas liquids (NGLs) and 37% natural gas in the second quarter of 2019.

Chaparral completed the drilling of its 11-well cube style, co-development Foraker spacing test in Canadian County during the first quarter of 2019 and finalized completion of the wells early in the second quarter. The multi-well test was drilled from three pads into three distinct drilling targets, the Upper Meramec, Lower Meramec and Woodford. There were four wells drilled into the Upper Meramec, five wells in the Lower Meramec and two wells in the Woodford. The average lateral length of the Meramec and Woodford wells were 4,934 and 4,949 feet, respectively. To maximize completion efficiency, the wells were fracture stimulated in a manner which was designed to create the greatest amount of near wellbore complexity, while maintaining sufficient pressure boundaries to minimize inter-well frac communication.

The average 120-day IP rate for all 11 wells was 877 Boe/d, with 36% oil and 67% liquids. The nine Meramec wells had an average 120-day IP rate of 967 Boe/d, with 36% oil and 67% liquids. All nine Meramec wells are significantly outperforming the company’s oil type curve expectations with an average 120-day oil IP rate at 148% of type curve. The two Woodford wells had an average 120-day IP rate of 468 Boe/d, with 35% oil and 67% liquids. These Woodford wells are outperforming the company’s oil type curve expectations, with an average 120-day oil IP rate at 101% of type curve.

The company continues to see overall strong results from additional spacing tests. These tests are geologically driven, with some tests performing better than others. Given the performance of the Denali, Foraker and other recent tests, the company is now planning another Meramec full section development in Canadian County, with the drilling of the six to eight well Greenback project in the fourth quarter as it continues testing the number of wells per section to optimize long-term, full section development. The growth trajectory of Chaparral’s STACK/Merge production will continue to be impacted by spacing tests moving forward, with production dependent on how many wells are completed and brought online in any given quarter.

The company had 28 new gross operated STACK wells with first sales during the second quarter, three of which were part of its drilling joint venture. In addition, the full production impact of its 11-well cube style, co-development Foraker spacing test in Canadian County contributed materially to the increased production during the second quarter. Of its 28 wells with first sales, 14 were in Canadian County, 10 in Kingfisher County and four in Garfield County. Chaparral currently plans to operate three rigs for the remainder of 2019, with all capital in the second half of 2019 allocated to Canadian and Kingfisher counties.

Chaparral’s total oil and natural gas capital expenditures (CAPEX) during the second quarter were $75.7 million, of which $69.1 million was associated with the STACK. Of its STACK CAPEX, $64.7 million was related to drilling and completion (D&C) activities, which included $2.1 million of non-operated CAPEX. Additionally, $3.2 million was invested in acquisition activities and $1.8 million in workovers and other enhancement capital.

Capital Expenditures (in millions) Q2 2019
STACK Acquisitions1 $3.2
STACK D&C2 $64.7
STACK Enhancements $1.2
Total STACK $69.1
Other Enhancements $0.6
Corporate Allocations3 $6.0
Total CAPEX $75.7

   1Includes non-cash acreage trades of $0.6 million
   2Includes non-operated costs of $2.1 and $3.5 million of drilling joint venture
   3Includes capitalized G&A, capitalized interest and asset retirement obligations

Financial Summary
Chaparral reported a net loss of $45.2 million, or $0.99 per share, during the second quarter of 2019. This included a $63.6 million non-cash ceiling test impairment charge primarily due to a decrease in the prices used to estimate its reserves, partially offset by a $17.6 million non-cash gain in the fair value of hedge derivative instruments. Chaparral’s adjusted EBITDA for the second quarter was up 54% on a quarter-over-quarter basis to $43.7 million, primarily due to increased production. On a year-over-year basis, adjusted EBITDA was up 62% primarily due to higher production and lower operating costs. Total gross commodity sales for the second quarter of 2019 were $72.5 million, which included $51.0 million from oil, $11.0 million from NGLs and $10.5 million from natural gas. This represents a 36% quarter-over-quarter increase compared to $53.2 million in the first quarter of 2019 and an increase of 16% year-over-year compared to $62.3 million in the second quarter of 2018.

Chaparral’s average realized price for crude oil, excluding derivative settlements, increased to $58.41 per barrel in the second quarter of 2019, up 10% from the first quarter of 2019 and down 12% from the second quarter of 2018. Chaparral’s realized NGL price during the second quarter of 2019 was $14.72 per barrel, which represents a 19% quarter-over-quarter decrease and a 40% year-over-year decrease. The company’s realized natural gas price during the second quarter of 2019 was $1.83 per thousand cubic feet (Mcf), which represents a decrease of 27% compared to the first quarter of 2019 and a decrease of 9% compared to the second quarter of 2018.

Total company LOE for the second quarter of 2019 was $13.4 million, or $5.19 per Boe, which was down 21% compared to $6.56 per Boe in the first quarter of 2019 and down 38% compared to $8.36 per Boe in the second quarter of 2018. Chaparral’s STACK LOE/Boe for the second quarter of 2019 was $3.90 per Boe, which was down 21% from $4.96 in the previous quarter and down 26% from $5.30 in the second quarter of 2018. The decreases were driven primarily by the increase in production due to timing of new wells being brought online and reduced saltwater disposal costs along with efficiency improvements in the field operations.

To better align Chaparral’s G&A and overhead expenses with current industry conditions, the company recently implemented a workforce reduction. Since the beginning of 2019, the company has reduced its corporate workforce by 23% and implemented cost reduction initiatives that will result in estimated annualized G&A savings of 20% to 25%. The full impact of these reductions will be realized in 2020, with initial savings flowing through in the second half of 2019. Chaparral’s net G&A expense was $7.3 million, or $2.84 per Boe, during the second quarter of 2019, a reduction of 36% compared to the first quarter of 2019 and a reduction of 38% compared to the second quarter of 2018. Adjusted for non-cash compensation, Chaparral’s cash G&A expense per Boe in the second quarter of 2019 was $2.52, which is a 27% reduction compared to the first quarter of 2019 and a 31% decrease compared to the second quarter of 2018.

Balance Sheet and Liquidity
The company’s $325 million borrowing base was reaffirmed during its semi-annual spring redetermination, which closed on May 2, 2019. As of June 30, 2019, Chaparral had approximately $33 million in cash and cash equivalents and $85 million drawn under its $325 million borrowing base. The company’s balance sheet remains strong with no significant debt maturities due until 2022.

On August 5, Chaparral entered into an agreement to sell the building housing its headquarters. Proceeds from the sale of the building will be used to eliminate related debt of approximately $8.3 million and Chaparral estimates annualized savings of approximately $1 million will be achieved.

In the second quarter of 2019, the company had a non-cash ceiling test impairment of $63.6 million, primarily due to a decrease in the price used to estimate its reserves.

Updated Guidance
Chaparral expects capital expenditures in the second half of 2019 to be lower than the first half due to the reduction from four to three operated rigs, drilling and completion efficiencies per well, lower than anticipated non-operated activity and lower acquisition capital. The company is reducing full year 2019 CAPEX guidance to $260 to $285 million, which is a reduction from the midpoint of the initial guidance of approximately 5%. Chaparral is also lowering its guidance ranges for LOE/Boe to $4.90 to $5.40, STACK LOE/Boe to $3.60 to $4.10 and cash G&A/Boe to $2.50 to $3.00 per Boe as a result of cost reduction initiatives.

The company is also re-affirming its original production guidance range of 25.0 to 27.0 MBoe/d for the full year 2019. Chaparral expects third quarter 2019 total company production to be between 26.0 and 27.5 MBoe/d and total STACK production to between 21.5 and 23.0 MBoe/d. The decline from its second quarter actual production is primarily due to the impact of reducing operated activity from four rigs to three in late March and the associated timing of new operated development wells being placed online, going from 28 wells in the second quarter to an estimated 10 to 15 in the third quarter.

Full Year 2019 Guidance Updated 2019E Previous 2019E
Total Capital Expenditures (in millions) $260 - $285 $275 - $300
LOE/Boe $4.90 - $5.40 $5.00 - $5.50
STACK LOE/Boe $3.60 - $4.10 $3.75 - $4.25
Cash G&A/Boe $2.50 - $3.00 $2.85 - $3.35
Total Company Production (MBoe/d) 25.0 - 27.0 25.0 - 27.0
STACK Production (MBoe/d) 21.0 - 23.0 21.0 - 23.0

Earnings Call Information
Chaparral will hold its financial and operating results call on Thursday, August 8, at 9 a.m. Central. Interested parties may access the call toll-free at 877-790-7727 and ask for the Chaparral Energy conference call 10 minutes prior to the start time. The conference ID number is 1291065. A live webcast of the call will also be available through the Investor section of the company’s website. For those who cannot listen to the live call, a recording will be available shortly after the call’s conclusion at chaparralenergy.com/investors.

The company has also provided an updated investor presentation for the quarter, which along with its form 10-Q, will be available at chaparralenergy.com/investors, as well as the Securities and Exchange Commission’s website at sec.gov.

Statements made in this release contain “forward-looking statements.” These statements are based on certain assumptions and expectations made by Chaparral, which reflect management’s experience, estimates and perception of historical trends, current conditions, anticipated future developments, potential for reserves and drilling, completion of current and future acquisitions and growth, benefits of acquisitions, future competitive position and other factors believed to be appropriate. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices, the uncertain economic conditions in the United States and globally, the decline in the reserve values of our properties that may result in ceiling test write-downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, the impact of natural disasters on our present and future operations, the impact of government regulation and the operating hazards attendant to the oil and natural gas business. Initial production (IP) rates are discreet data points in each well’s productive history. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may decline over time and change as additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates or economic rates of return from such wells and should not be relied upon for such purpose. The ability of the company or the relevant operator to maintain expected levels of production from a well is subject to numerous risks and uncertainties, including those referenced and discussed above. In addition, methodology the company and other industry participants utilize to calculate peak IP rates may not be consistent and, as a result, the values reported may not be directly and meaningfully comparable. Please read “Risk Factors” in our annual reports, form 10-K or other public filings. We undertake no duty to update or revise these forward-looking statements. 

About Chaparral
Chaparral Energy (CHAP) is an independent oil and natural gas exploration and production company headquartered in Oklahoma City. Founded in 1988, Chaparral is a pure-play operator focused in Oklahoma’s highly economic STACK/Merge Play, where it has approximately 130,000 net acres primarily in Kingfisher, Canadian and Garfield counties. The company has approximately 221,000 net surface acres in the Mid-Continent region. For more information, visit chaparralenergy.com.

Investor Contact
Scott Pittman
Chief Financial Officer
405-426-6700
investor.relations@chaparralenergy.com

Consolidated Statement of Operations (unaudited)    
(in thousands, except share and per share data)
Three months ended Six Months Ended
Revenues: June 30, 2019 March 31, 2019 June 30, 2018 June 30, 2019 June 30, 2018
Net commodity sales 66,707   48,619   58,427   115,326   116,316  
Sublease revenue 1,198   1,198   1,198   2,396   2,396  
Total revenues 67,905   49,817   59,625   117,722   118,712  
Lease operating 13,371   12,294   15,009   25,665   29,552  
Production taxes 3,802   2,880   2,768   6,682   5,445  
Depreciation, depletion and
  amortization
30,282   23,715   20,407   53,997   41,513  
Loss on impairment of
  oil and gas assets
63,593   49,722     113,315    
Loss on impairment of
  other assets
6,407       6,407    
General and administrative 7,315   8,313   8,190   15,628   19,697  
Cost reduction initiatives     824     824  
Other 403   403   403   806   1,231  
Total costs and expenses 125,173   97,327   47,601   222,500   98,262  
Operating (loss) income (57,268 ) (47,510 ) 12,024   (104,778 ) 20,450  
Non-operating income (expense):          
Interest expense (5,571 ) (4,564 ) (1,739 ) (10,135 ) (3,110 )
Derivative gains (losses) 17,734   (51,016 ) (32.286 ) (33,282 ) (48,787 )
Gain (loss) on sale of assets 491   (1 ) 469   490   (575 )
Other income, net (302 ) 14   19   (288 ) 104  
Net non-operating income (expense) 12,352   (55,567 ) (33,537 ) (43,215 ) (52,368 )
Reorganization items, net (313 ) (463 ) (480 ) (776 ) (1,517 )
Loss before income taxes (45,229 ) (103,540 ) (21,993 ) (148,769 ) (33,435 )
Income tax expense          
Net (loss) (45,229 ) (103,540 ) (21,993 ) (148,769 ) (33,435 )
Earnings per share:          
Basic for Class A and
  Class B
(0.99 ) (2.28 ) (0.49 ) (3.27 ) (0.74 )
Diluted for Class A and  
  Class B
(0.99 ) (2.28 ) (0.49 ) (3.27 ) (0.74 )
Weighted average shares used to
compute earnings per share:
                           
Basic for Class A and Class B   45,641,797     45,456,214     45,338,650     45,549,518   45,241,513  
Diluted for Class A and Class B   45,641,797     45,456,214     45,338,650     45,549,518   45,241,513  


Consolidated Balance Sheets (Unaudited)      
(dollars in thousands, except share data) June 30, 2019 March 31, 2019 December 31, 2018
Assets      
Current assets:      
Cash and cash equivalents $ 32,648   $ 11,118   $ 37,446  
Accounts receivable, net   52,686     62,652     66,087  
Inventories, net   4,142     3,923     4,059  
Prepaid expenses   1,774     2,593     2,814  
Derivative instruments   4,524         24,025  
Total current assets   95,774     80,286     134,431  
Property and equipment, net   36,265     42,558     43,096  
Right of use assets from operating leases   9,005     12,064      
Oil and natural gas properties, using the full cost method:      
Proved   1,107,203     976,025     915,333  
Unevaluated (excluded from the amortization base)   426,738     484,021     466,616  
Accumulated depreciation, depletion, amortization and
  impairment
  (384,401 )   (292,679 )   (221,431 )
Total oil and natural gas properties   1,149,540     1,167,367     1,160,518  
Derivative instruments   221         2,199  
Other assets   411     389     425  
Total assets $ 1,291,216   $ 1,302,664   $ 1,340,669  
Liabilities and stockholders’ equity      
Current liabilities:      
Accounts payable and accrued liabilities $ 73,770   $ 97,404   $ 73,779  
Accrued payroll and benefits payable   7,807     6,420     10,976  
Accrued interest payable   12,207     5,934     13,359  
Revenue distribution payable   26,825     20,714     26,225  
Long-term debt and capital leases, classified as current   11,502     11,854     12,371  
Derivative instruments   4,802     10,874      
Total current liabilities   136,913     153,200     136,710  
Long-term debt and capital leases, less current maturities   382,295     326,198     295,100  
Derivative instruments   9,196     15,976     1,542  
Noncurrent operating lease obligations   2,075     2,307      
Deferred compensation   693     628     540  
Asset retirement obligations   22,300     22,248     22,090  
Commitments and contingencies (Note 10)      
Stockholders’ equity:      
Preferred stock          
Common stock   469     467     467  
Additional paid in capital   977,611     976,039     974,616  
Treasury stock   (6,107 )   (5,399 )   (4,936 )
Accumulated deficit   (234,229 )   (189,000 )   (85,460 )
Total stockholders' equity   737,744     782,107     884,687  
Total liabilities and stockholders' equity $ 1,291,216   $ 1,302,664   $ 1,340,669  


Consolidated Statements of Cash Flows (Unaudited)          
(in thousands) Three Months Ended
Six Months Ended
    June 30, 2019   March 31, 2019 June 30, 2018 June 30, 2019 June 30, 2018
Cash flows from operating activities          
Net (loss) income: $ (45,229 ) $ (103,540 ) $ (21,993 ) $ (148,769 ) $ (33,435 )
Adjustments to reconcile net
  (loss) income to net cash
  provided by operating activities
         
Depreciation, depletion and
  amortization
  30,282     23,715     20,407     53,997     41,513  
Loss on impairment of
  oil and gas assets
  63,593     49,722         113,315      
Loss on impairment of
  other assets
  6,407             6,407      
Derivative (gains) losses   (17,734 )   51,016     32,286     33,282     48,787  
(Gain) loss on sale of assets   (491 )   1     (469 )   (490 )   575  
Other   1,079     542     1,948     1,621     3,578  
Change in assets and
  liabilities
         
Accounts receivable   5,674     7,910     4,480     13,584     (7,660 )
Inventories   (167 )   207     6     40     (3,162 )
Prepaid expenses and
  other assets
  799     256     465     1,055     286  
Accounts payable and
  accrued liabilities
  (1,700 )   (16,689 )   5,607     (18,389 )   (4,221 )
Revenue distribution
  payable
  6,111     (5,511 )   5,092     600     7,243  
Deferred compensation   927     925     1,865     1,852     6,566  
  Net cash provided by
  operating activities
  49,551     8,554     49,694     58,105     60,070  
Cash flows from investing activities          
Expenditures for property, plant
  and equipment and oil and
  natural gas properties
  (82,390 )  

(64,044


)
  (76,334 )  

(146,434


)
  (176,275 )
Proceeds from asset
  dispositions
  857         6,518     857     6,591  
(Payments) proceeds from
  derivative instruments, net
  138     515     (5,525 )   653     (9,769 )
  Net cash used in
  investing activities
  (81,395 )   (63,529 )   (75,341 )   (144,924 )   (179,453 )
Cash flows from financing activities          
Proceeds from long-term debt   55,000     30,000     37,000     85,000     116,000  
Repayment of long-term debt   (172 )   (171 )   (243,245 )   (343 )   (243,391 )
Proceeds from senior notes           300,000         300,000  
Principal payments under
  capital lease obligations
  (746 )   (699 )   (668 )   (1,445 )   (1,329 )
Payment of debt issuance costs
  and other financing fees
      (20 )   (6,316 )   (20 )   (6,316 )
Treasury stock purchased   (708 )   (463 )   (4,872 )   (1,171 )   (4,872 )
Net cash provided by
  financing activities
  53,374     28,647     81,899     82,021     160,092  
Net increase (decrease)
  in cash, cash equivalents
  and restricted cash
  21,530     (26,328 )   56,252     (4,798 )   40,709  
Cash, cash equivalents and restricted cash at beginning of period   11,118     37,446     12,189     37,446     27,732  
Cash, cash equivalents and restricted cash at end of period $ 32,648   $ 11,118   $ 68,441   $ 32,648   $ 68,441  

Non-GAAP Financial Measures and Reconciliations
Adjusted EBITDA is a Non-GAAP financial measure and is described and reconciled to net income in the table “Adjusted EBITDA Reconciliation, NON-GAAP.”

Cash G&A is a non-GAAP financial measure and is described and reconciled to net income in the table “Cash G&A Reconciliation, NON-GAAP.”

Adjusted EBITDA Reconciliation, Non-GAAP
      Three Months Ended
Six Months Ended
(in thousands) June 30, 2019 March 31, 2019 June 30, 2018 June 30, 2019 June 30, 2018
Net loss income   (45,229 )   (103,540 )   (21,993 )   (148,769 )   (33,435 )
Interest expense   5,571     4,564     1,739     10,135     3,110  
Income tax expense                    
Depreciation, depletion and
  amortization
  30,282     23,715     20,407     53,997     41,513  
Loss on impairment of assets   63,593     49,722         113,315      
Loss on impairment of
  other assets
  6,407             6,407      
Non-cash change in fair
  value of derivative
  instruments
  (17,596 )   51,531     26,761     33,935     39,018  
Impact of derivative repricing           (1,680 )       (2,252 )
Loss on settlement of
  liabilities subject to
  compromise
                  48  
Interest income   (2 )       (1 )   (2 )   (2 )
Stock-based compensation
  expense
  852     802     1,671     1,654     6,294  
(Gain) loss on sale of assets   (491 )   1     (469 )   (490 )   575  
Restructuring, reorganization
  and other
  313     1,520     480     1,833     1,469  
Adjusted EBITDA $ 43,700   $ 28,315   $ 26,915   $ 72,015   $ 56,338  


Cash G&A Reconciliation, Non-GAAP
    Three Months Ended
Six Months Ended
(in thousands) June 30, 2019 March 31, 2019 June 30, 2018 June 30, 2019 June 30, 2018
General and administrative   7,315     8,313     8,190     15,628     19,697  
Less:          
Stock compensation, gross   1,228     1,419     2,335     2,647     7,915  
Capitalized stock
  compensation
  (399 )   (626 )   (664 )   (1,025 )   (1,621 )
Officer severance costs       1,058         1,058      
Plus:          
Cash-settled RSUs, net   5     22         27      
Cash G&A $ 6,491   $ 6,484   $ 6,519   $ 12,975   $ 13,403  
           
Production volumes (MBoe)   2,574     1,874     1,795     4,448     3,532  
           
Cash G&A per Boe $ 2.52   $ 3.46   $ 3.63   $ 2.92   $ 3.79