OREANDA-NEWS. August 02, 2016. Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today announces its second quarter 2016 financial and operating results.

Richard Carty, President and Chief Executive Officer, commented, "Our operations team continues to exceed expectations and is focused on increasing efficiencies and reducing costs. The second quarter marked the fourth consecutive quarter of asset outperformance in the Rockies since the full field implementation of RMI in the third quarter of 2015, demonstrating a repeated pattern of higher production volumes and lower LOE.  Our efficiency mandates have yielded a 41% decrease in second quarter LOE from a year ago, and a 39% decrease in second quarter G&A from the prior year.  The second quarter also marked an important milestone of two million work-hours completed without a lost time injury, a commendable record for our health, safety, and environmental initiatives.  While the operating assets continue to perform, our balance sheet and access to capital remain a major headwind. In an effort to enhance the liquidity position of the Company, in the first and second quarter of 2016 we targeted divestitures of both our RMI and MidCon assets. Although we received strong economic bids for both of these asset packages, conditions included in the bid proposals require that the Company improve its liquidity and its balance sheet. As a result, we have suspended the divestiture efforts to focus on other liquidity enhancing and debt restructuring options. To assist in evaluating all alternatives, we have retained (as previously announced) Perella Weinberg Partners as restructuring advisors and Davis Polk & Wardwell as legal advisors."

Mr. Carty further commented, “Lastly, I want to express our gratitude to Tony Buchanon, Executive Vice President and Chief Operating Officer, for his contributions in building a strong and capable operations team since 2013. Tony recently decided to step down from his position in order to pursue another opportunity in the industry. We wish him the very best. Our Board of Directors is confident that our experienced engineering and operations managers reporting to Dean Tinsley, Vice President, Rocky Mountain Asset Management, Kerry McCowen, Vice President, Rocky Mountain Operations, John Larson, Vice President, Mid-Continent Operations, and David Stewart, Vice President, Environmental, Health, Safety and Regulatory Compliance, and other talented Bonanza leaders will ensure that our company doesn’t miss a beat. In addition, Jeff Wojahn, a member of our Board and the former President of Encana Oil & Gas (USA) Inc., has graciously volunteered to serve as Senior Operations Advisor, to be done in his continued capacity as a director of the Company. Although our drilling and completion program is currently suspended while we address our balance sheet, Jeff’s significant experience in the Wattenberg Field will be extremely valuable as the Company prepares to resume more typical operational activity levels."


Second Quarter 2016 Results

For the second quarter of 2016, the Company reported average daily production of 23.2 MBoe per day, a 4% sequential decrease from the first quarter of 2016, and a 17% decrease from the second quarter of 2015. The reduction in production volumes is a result of suspended drilling and completion operations at the end of the first quarter. Product mix for the second quarter of 2016 was 56% oil, 19% NGLs, and 25% natural gas.

Net revenue for the second quarter of 2016 was \\$54.5 million, a 23% sequential increase from the first quarter of 2016 and a 40% decrease from the second quarter of 2015. Crude oil accounted for approximately 83% of total revenue. Differentials for the Company's Rocky Mountain oil production during the quarter averaged approximately \\$8.99 per Bbl. Average realized prices for the second quarter of 2016 are presented below.

Average Realized Prices
 Three Months Ended June 30, 2016
 Before Derivatives After Derivatives
Oil (per Bbl)38.21  41.51 
Gas (per Mcf)1.48  1.48 
NGL (per Bbl)11.53  11.53 
Boe (Per Boe)25.78  27.62 
      

LOE for the second quarter of 2016 was \\$10.7 million, or \\$5.08 per Boe, compared to \\$13.3 million, or \\$6.01 per Boe in the first quarter of 2016, and \\$18.2 million, or \\$7.12 per Boe in the second quarter of 2015. The Company continues to execute on cost saving metrics resulting in a 19% sequential decrease and a 41% year over year decrease in total LOE. Below is a breakout of the Company's regional LOE and gas plant and midstream operating expense for the second quarter of 2016.

Lease Operating Expense
 Three Months Ended June 30, 2016
 Rocky Mountain Mid-Continent Total Company
 (\\$M) (\\$/Boe) (\\$M) (\\$/Boe) (\\$M) (\\$/Boe)
LOE\\$8,657  \\$4.99  \\$2,080  \\$5.46  \\$10,737  \\$5.08 
Gas plant and midstream operating expense1,526  0.88  2,009  5.27  3,535  1.67 
Total\\$10,183  \\$5.87  \\$4,089  \\$10.73  \\$14,272  \\$6.75 
                        

General and administrative ("G&A") expense for the second quarter of 2016 was \\$13.2 million, or \\$6.26 per Boe. This compares to G&A expense of \\$21.6 million, or \\$8.47 per Boe in the second quarter of 2015 and \\$17.7 million, or \\$7.99 per Boe in the first quarter of 2016. On a sequential basis, total G&A expense has decreased by 25% and has decreased by 39% from the second quarter of 2015. Cash G&A expense, which excludes stock compensation, for the second quarter of 2016 was \\$10.9 million, or \\$5.13 per Boe. This compares to cash G&A expense, excluding severance charges, of \\$12.5 million, or \\$5.66 per Boe in the first quarter of 2016. The decrease in cash G&A is a result of the previously announced reduction in force which occurred at the end of the first quarter.

Depreciation, depletion and amortization ("DD&A") for second quarter of 2016 was \\$30.9 million, or \\$14.62 per Boe, a 23% sequential increase on a per unit basis from the first quarter of 2016 and a 47% decrease on a per unit basis from the second quarter 2015. The increase in total DD&A expense in the second quarter is primarily due to the resumption of DD&A expense for the Rocky Mountain Infrastructure ("RMI") assets, which were previously classified as held for sale and not depreciated pursuant to GAAP. Upon moving these assets back into Proved Properties on the balance sheet, DD&A expense was calculated and recorded for the three quarters during which the RMI assets were classified as held for sale. The Company's Arkansas ("MidCon") assets were also moved out of the held for sale classification. As the MidCon assets were impaired to market value while they were classified as held for sale, however, a DD&A catch-up is unnecessary for these assets.

As of the end of the second quarter, year to date 2016 total CAPEX was \\$17.5 million, of which \\$2.3 million was attributable to RMI. A downward adjustment of \\$3.1 million in CAPEX was recorded in the second quarter as a result of estimated costs which exceeded actual costs.

Reported GAAP net loss for the second quarter of 2016 was \\$49.5 million, or \\$1.00 per diluted share, compared to a net loss of \\$41.2 million, or \\$0.83 per diluted share, for the second quarter of 2015. Adjusted net loss for the second quarter of 2016 was \\$19.7 million, or \\$0.40 per diluted share, compared to an adjusted net loss of \\$6.9 million, or \\$0.14 per diluted share for the second quarter of 2015, and an adjusted net loss of \\$22.4 million, or \\$0.46 per diluted share for the first quarter of 2016. Adjusted EBITDAX for the second quarter of 2016 was \\$27.7 million, a 63% decrease compared to \\$74.0 million for the second quarter of 2015 and a 50% sequential increase from the first quarter of 2016.

Cash G&A, adjusted net income and adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures. Cash G&A is defined as GAAP G&A expense excluding the stock compensation portion of the expense. See Schedule 1 for general and administrative break-out of stock-based compensation.

The table below summarizes the Company's quarterly and year to date results as compared to guidance provided in the first quarter earnings release. Updated twelve month guidance is included in the Third Quarter Guidance and Update section of this release.

Guidance vs Actual Summary
 Three Months Ended June 30, 2016
 Guidance Actual
    
Production (MBoe/d)22.7 – 23.3 23.2 
    
 Twelve Months Ended
December 31, 2016		 Six Months Ended
June 30, 2016 
 Guidance Actual
LOE (\\$MM)\\$52 – \\$56 \\$24.0 
Midstream (\\$MM)\\$15 – \\$17 \\$7.3 
Cash G&A (\\$MM)*\\$40 – \\$44 \\$23.4 
Production taxes (% of pre-derivative realization)6% – 7% 7.5%
CAPEX (\\$MM)\\$35 – \\$45 \\$17.5 
    
* Cash G&A guidance is a non-GAAP measure that is exclusive of the Company's stock based compensation and one-time severance charges of \\$2.2 million in the first quarter of 2016. The Company does not guide to GAAP G&A expense as it has less certainty to the stock based compensation portion of GAAP G&A.

Operations Update

Rocky Mountain Region – Wattenberg

Production from the Rocky Mountain region during the second quarter of 2016, averaged 19.1 MBoe/d, or 82% of total Company volumes. The production was comprised of 56% crude oil, 20% NGLs, and 24% natural gas. Rocky Mountain average daily sales volumes decreased sequentially by 4% from the first quarter of 2016 and decreased 16% compared to the second quarter of 2015 due to suspended drilling and completion activity.

The Company did not drill or complete any wells during the second quarter as it idled its development program at the end of the first quarter. At the end of the second quarter, the Company had six drilled uncompleted wells, consisting of four standard reach and two extended reach laterals. The Company does not have any current plans to restart drilling or completion activity in the second half of 2016.

Mid-Continent Region – Cotton Valley

The Mid-Continent region contributed 4.2 MBoe/d, or 18% of total Company net sales volumes for the second quarter of 2016, and was comprised of 54% crude oil, 16% NGLs, and 30% natural gas. Sales volumes decreased sequentially by 6% from the first quarter of 2016 and decreased 21% compared to the second quarter of 2015 as a result of suspended drilling and completions activity.

Financial and Risk Management Update

Debt and Liquidity

The Company has a \\$1.0 billion revolving credit facility, which was redetermined in May of 2016 to an approved borrowing base and commitment amount of \\$200 million. As of June 30, 2016, the Company had borrowings under its credit facility of \\$273.3 million and cash totaling \\$170.2 million. Upon redetermination of the Company's credit facility, its borrowings exceeded its borrowing base by \\$88 million. The Company has elected to pay this deficiency in six monthly installments as allowed under the terms of the credit facility agreement. During the quarter the Company paid off its remaining \\$12.0 million letter of credit and made its first credit facility deficiency payment of \\$14.7 million. The Company has subsequently paid its second deficiency payment of \\$14.7 million in July and has four remaining payments to be made on a monthly basis to remedy its credit facility deficiency. The Company's next redetermination is expected to happen in the fourth quarter of 2016.  As of June 30, 2016, the Company was in compliance with all financial covenants under its credit facility, with a senior secured debt to TTM EBITDAX ratio of 1.5x, an interest coverage ratio of 3.2x, and a current ratio of 2.7x.

In addition to the credit facility, Bonanza Creek has two outstanding issues of unsecured high-yield bonds which consist of \\$500 million of 6.75% senior notes due in 2021 and \\$300 million of 5.75% senior notes due in 2023. The Company is subject to certain covenants under the respective indentures governing the senior notes that, among other things, limit its ability to incur additional indebtedness. Specifically, the incurrence by the Company (or any of the guarantors under the indentures) of additional indebtedness and letters of credit under the revolving credit facility in an aggregate principal amount at any one time outstanding is not to exceed the greater of (a) \\$300.0 million or (b) 35% of the Company's Adjusted Consolidated Net Tangible Assets (“ACNTA”) determined as of the date of the incurrence of such indebtedness. ACNTA is defined as the Company's PV-10 value plus capitalized costs for unproved properties plus consolidated net working capital and other tangible assets.  At June 30, 2016, 35% of the Company’s ACNTA was equal to approximately \\$380 million.

While the Company currently has sufficient cash on hand to make its upcoming bond interest payment, it has made the election to not pay the interest payment for its \\$300 million 5.75% senior unsecured notes, which was due on August 1, 2016. By not paying the interest due, the Company has entered into a 30-day grace period during which it retains the right to pay the interest due to the holders of its 5.75% notes and thereby remain within compliance of the bond indenture. The 30-day grace period also applies to any potential cross-default under the Company's credit facility with respect to the bond interest payment.

Asset Sale Processes - RMI and Mid-Continent

During the second quarter of 2016, the Company re-launched a marketing effort to divest its RMI assets. The Company engaged a third party advisor to assist in locating a purchaser for these assets by performing a widely marketed process. While the Company received economically strong bids for the assets, they all contained significant conditions that required the Company to remedy its debt burden and its limited access to capital. With regard to the MidCon assets, the Company also performed a widely marketed process to divest the assets with the assistance of a third party advisor. Bids received for these assets also contained significant going concern representations resulting from the Company's liquidity constraints. Upon reviewing these bids, given the significant conditions and, in the absence of improvement to the Company's balance sheet, the unlikely sale for either package, the Company's management and board have decided to suspend these asset sale processes and focus efforts on alternative methods to reduce debt and increase liquidity.

Please review the Company's quarterly report on Form 10-Q filed with the Securities Exchange Commission on August 1, 2016 for further information regarding the Company's debt and liquidity.

Commodity Derivatives Positions

The following table summarizes the Company’s crude oil and natural gas commodity derivative positions as of June 30, 2016 and settling quarterly:

Settlement Period Volume (Bbls/d) Contract Type Swap Price
3Q 2016 2,704 Fixed Price Swap \\$51.78 
4Q 2016 2,303 Fixed Price Swap \\$52.83 
       
Settlement Period Volume (Bbls/d) Contract Type Floor Price
3Q 2016 4,733 Floor (Long Put) \\$51.01 
4Q 2016 4,031 Floor (Long Put) \\$51.01 

Third Quarter Guidance and Update

The Company is providing updated cost and CAPEX guidance for the remainder of 2016 that reflects a lower cost structure that the Company implemented during the first half of the year. As a result of efficiency gains in its operations and service cost reductions, the Company has reduced the midpoint of its full year guidance for LOE and Midstream expense by 15% and 6%, respectively. The Company attributes approximately 80% of the cost savings to efficiency gains that it expects to be repeatable irrespective of service costs. The Company has also reduced its full year CAPEX guidance midpoint by 25% due to reductions in previous well costs estimates. The table below provides updated guidance for the third quarter and full year of 2016.

Guidance Summary   
 Three Months Ended  September 30, 2016 Twelve Months Ended  December 31, 2016
    
Production (MBoe/d)19.6 – 20.2 19.7 – 21.7
LOE (\\$MM)  \\$44 – \\$48
Midstream expense (\\$MM)  \\$14 – \\$16
Cash G&A (\\$/Boe)*  \\$40 – \\$44
Production taxes (% of pre-derivative realization)  6% – 7%
Total CAPEX  \\$25 – \\$35
* Cash G&A guidance is a non-GAAP measure that is exclusive of the Company's stock based compensation and one-time severance charges of \\$2.2 million in the first quarter of 2016. The Company does not guide to GAAP G&A expense as it has less certainty to the stock based compensation portion of GAAP G&A.

Conference Call Information
The Company will not be hosting a conference call to discuss its second quarter results.

About Bonanza Creek Energy, Inc.

Bonanza Creek Energy, Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. The Company’s assets and operations are concentrated primarily in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations, and in southern Arkansas, focused on oily Cotton Valley sands. The Company’s common shares are listed for trading on the NYSE under the symbol: “BCEI.” For more information about the Company, please visit www.bonanzacrk.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These statements include updated 2016 guidance; drilling expectations; timing of future redeterminations of the Company's borrowing base under its revolving credit facility and anticipated efficiency gains. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, that may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including the following: changes in natural gas, oil and NGL prices; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; ability to acquire adequate supplies of water; risks related to derivative instruments; access to adequate gathering systems and pipeline take-away capacity; and pipeline and refining capacity constraints. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. We refer you to the discussion of risk factors in our Annual Report on Form 10-K for the year ended December 31, 2015, filed on February 29, 2016, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Schedule 1: Statement of Operations
(in thousands, expect for per share amounts, unaudited)
    
 Three Months Ended June 30, Six Months Ended June 30,
 2016 2015 2016 2015
Operating net revenues:       
Oil and gas sales\\$54,530  \\$90,422  \\$98,704  \\$163,498 
Operating expenses:       
Lease operating expense10,737  18,169  24,035  35,142 
Gas plant and midstream operating expense3,535  2,726  7,324  5,017 
Severance and ad valorem taxes4,277  4,148  7,431  10,644 
Exploration677  5,748  943  6,246 
Depreciation, depletion and amortization30,927  69,925  57,306  128,929 
Impairment of oil and gas properties—  —  10,000  — 
Abandonment and impairment of unproved properties9,875  14,527  16,781  19,996 
General and administrative (including \\$2,380, \\$4,359, \\$5,384 and \\$7,787, respectively, of stock-based compensation)13,235  21,602  30,920  38,474 
Total operating expenses73,263  136,845  154,740  244,448 
Loss from operations(18,733) (46,423) (56,036) (80,950)
Other income (expense):       
Derivative gain (loss)(12,923) (5,478) (13,930) 13,378 
Interest expense(16,527) (14,468) (31,074) (28,706)
Gain on termination fee—  —  6,000  — 
Other gain (loss)(1,294) 198  (1,674) 148 
Total other income (expense)(30,744) (19,748) (40,678) (15,180)
Loss from operations before taxes(49,477) (66,171) (96,714) (96,130)
Income tax benefit—  25,007  —  36,544 
Net loss\\$(49,477) \\$(41,164) (96,714) \\$(59,586)
        
Basic net loss per common share\\$(1.00) \\$(0.83) \\$(1.97) \\$(1.25)
        
Diluted net loss per common share\\$(1.00) \\$(0.83) \\$(1.97) \\$(1.25)
        
Basic weighted-average common shares outstanding49,277  48,923  49,204  46,734 
        
Diluted weighted-average common shares outstanding49,277  48,923  49,204  46,734 
The Company follows the two-class method when computing the basic and diluted loss per share, which allocates earnings between common shareholders and participating securities. Please refer to Note 10 – Earnings per Share in the Form 10-Q, for a detailed calculation.
 
Schedule 2: Statement of Cash Flows
(in thousands, unaudited)
    
 Three Months Ended June 30, Six Months Ended June 30,
 2016 2015 2016 2015
Cash flows from operating activities:       
Net loss\\$(49,477) \\$(41,164) \\$(96,714) \\$(59,586)
Adjustments to reconcile net loss to net cash provided by operating activities:       
Depreciation, depletion and amortization30,927  69,925  57,306  128,929 
Deferred income tax benefit—  (25,007) —  (36,544)
Impairment of oil and gas properties—  —  10,000  — 
Abandonment and impairment of unproved properties9,875  14,527  16,781  19,996 
Dry hole expense734  5,680  966  5,680 
Stock-based compensation2,380  4,359  5,384  7,787 
Amortization of deferred financing costs and debt premium1,671  703  2,279  1,226 
Accretion of contractual obligation for land acquisition—  349  —  698 
Derivative (gain) loss12,923  5,478  13,930  (13,378)
Derivative cash settlements3,893  15,189  11,401  50,655 
Other4  (16) (112) (43)
Changes in current assets and liabilities:       
Accounts receivable371  2,021  23,415  18,319 
Prepaid expenses and other assets274  525  (1,348) (1,348)
Accounts payable and accrued liabilities(25,316) (21,073) (28,457) (23,054)
Settlement of asset retirement obligations(34) (234) (75) (519)
Net cash provided by (used in) operating activities(11,775) 31,262  14,756  98,818 
Cash flows from investing activities:       
Acquisition of oil and gas properties(284) (532) (816) (11,914)
Payments of contractual obligation(12,000) —  (12,000) — 
Exploration and development of oil and gas properties(7,881) (128,694) (42,753) (283,106)
Increase in restricted cash(2) —  (2,535) — 
Additions to property and equipment - non oil and gas(8) 841  39  (649)
Net cash used in investing activities(20,175) (128,385) (58,065) (295,669)
Cash flows from financing activities:       
Proceeds from credit facility—  43,000  209,000  87,000 
Payments to credit facility(14,667) —  (14,667) (77,000)
Proceeds from sale of common stock—  —  —  209,300 
Offering costs related to sale of common stock—  (115) —  (6,607)
Offering costs related to sale of Senior Notes—  (74) —  (93)
Payment of employee tax withholdings in exchange for the return of common stock(44) (321) (273) (2,448)
Deferred restructuring charges(1,684) —  (1,684) — 
Deferred financing costs(83) (541) (237) (545)
Net cash provided by (used in) financing activities(16,478) 41,949  192,139  209,607 
Net change in cash and cash equivalents(48,428) (55,174) 148,830  12,756 
Cash and cash equivalents:       
Beginning of period218,599  70,514  21,341  2,584 
End of period\\$170,171  \\$15,340  \\$170,171  \\$15,340 
                
Schedule 3: Condensed Balance Sheet
(in thousands, unaudited)
    
 June 30, December 31,
 2016 2015
ASSETS   
Current assets\\$221,685  \\$120,074 
Oil and gas properties and natural gas plant held for sale, net of accumulated depreciation, depletion and amortization of \\$636,917 in 2015—  214,922 
Total property and equipment, net1,071,501  922,344 
Other noncurrent assets4,980  2,301 
Total Assets\\$1,298,166  \\$1,259,641 
    
LIABILITIES AND STOCKHOLDERS’ EQUITY   
Current liabilities\\$1,147,269  \\$135,973 
Long-term debt—  871,666 
Other long-term liabilities33,093  42,595 
Total Liabilities1,180,362  1,050,234 
    
Stockholders’ Equity117,804  209,407 
Total Liabilities and Stockholders’ Equity\\$1,298,166  \\$1,259,641 
 
Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)
    
 Three Months Ended June 30, Six Months Ended June 30,
 2016 2015 2016 2015
Wellhead Volumes and Prices       
        
Crude Oil and Condensate Sales Volumes (Bbl/d)       
Rocky Mountains10,715  14,079  11,190  13,877 
Mid-Continent2,270  2,768  2,353  2,827 
Total12,985  16,847  13,543  16,704 
        
Crude Oil and Condensate Realized Prices (\\$/Bbl)       
Rocky Mountains\\$36.74  \\$48.72  \\$30.70  \\$43.60 
Mid-Continent\\$45.18  \\$55.93  \\$40.41  \\$51.60 
Composite (before derivatives)\\$38.21  \\$49.90  \\$32.39  \\$44.96 
Composite (after derivatives)\\$41.51  \\$59.37  \\$37.01  \\$61.26 
        
Natural Gas Liquids Sales Volumes (Bbl/d)       
Rocky Mountains3,772  3,696  3,594  3,579 
Mid-Continent675  1,020  697  1,007 
Total4,447  4,716  4,291  4,586 
        
Natural Gas Liquids Realized Prices (\\$/Bbl)       
Rocky Mountains\\$10.59  \\$16.21  \\$11.80  \\$14.99 
Mid-Continent\\$16.75  \\$16.56  \\$14.48  \\$16.16 
Composite (before derivatives)\\$11.53  \\$16.28  \\$12.23  \\$15.25 
Composite (after derivatives)\\$11.53  \\$16.28  \\$12.23  \\$15.25 
        
Natural Gas Sales Volumes (Mcf/d)       
Rocky Mountains27,450  29,782  28,044  29,299 
Mid-Continent7,444  9,075  7,648  9,612 
Total34,894  38,857  35,692  38,911 
        
Natural Gas Realized Prices (\\$/Mcf)       
Rocky Mountains\\$1.34  \\$1.65  \\$1.27  \\$1.80 
Mid-Continent\\$2.01  \\$2.99  \\$2.05  \\$3.10 
Composite (before derivatives)\\$1.48  \\$1.96  \\$1.44  \\$2.12 
Composite (after derivatives)\\$1.48  \\$2.15  \\$1.44  \\$2.31 
        
Crude Oil Equivalent Sales Volumes (Boe/d)       
Rocky Mountains19,062  22,739  19,458  22,339 
Mid-Continent4,186  5,300  4,325  5,436 
Total23,248  28,039  23,783  27,775 
        
Crude Oil Equivalent Sales Prices (\\$/Boe)       
Rocky Mountains\\$24.68  \\$34.96  \\$21.66  \\$31.84 
Mid-Continent\\$30.78  \\$37.50  \\$27.94  \\$35.32 
Composite (before derivatives)\\$25.78  \\$35.44  \\$22.80  \\$32.52 
Composite (after derivatives)\\$27.62  \\$41.39  \\$25.44  \\$42.60 
        
Total Sales Volumes (MBoe)2,115.5  2,551.5  4,328.7  5,027.3 
            
Schedule 5: Per unit operating margins
(unaudited)
    
 Three Months Ended June 30, Six Months Ended June 30,
  2016   2015  Percent Change  2016  2015 Percent Change
Production           
Oil (MBbl)1,181.7  1,533.0  (23)% 2,465.0  3,023.5  (18)%
Gas (MMcf)3,175.3  3,535.9  (10)% 6,496.0  7,042.8  (8)%
NGL (MBbl)404.7  429.2  (6)% 781.0  830.0  (6)%
Equivalent (MBoe)2,115.5  2,551.5  (17)% 4,328.7  5,027.3  (14)%
            
Realized pricing (before derivatives)          
Oil (\\$/Bbl)\\$38.21  \\$49.90  (23)% \\$32.38  \\$44.96  (28)%
Gas (\\$/Mcf)\\$1.48  \\$1.96  (24)% 1.44  2.12  (32)%
NGL (\\$/Bbl)\\$11.53  \\$16.28  (29)% 12.23  15.25  (20)%
Equivalent (\\$/Boe)\\$25.78  \\$35.44  (27)% \\$22.80  \\$32.52  (30)%
            
Per Unit Costs (\\$/Boe)           
Realized price (before derivatives)\\$25.78  \\$35.44  (27)% \\$22.80  32.52  (30)%
LOE5.08  7.12  (29)% \\$5.55  \\$6.99  (21)%
Gas plant and midstream operating expense1.67  1.07  56% \\$1.69  \\$1.00  69%
Severance and Ad Valorem2.02  1.63  24% \\$1.72  \\$2.12  (19)%
Cash General and Administrative 5.13   6.76  (24)% \\$5.90  \\$6.10  (3)%
Total cash operating costs\\$13.90  \\$16.58  (16)% \\$14.86  \\$16.21  (8)%
Cash operating margin (before derivatives)\\$11.88  \\$18.86  (37)% \\$7.94  \\$16.31  (51)%
Derivative Cash Settlements1.84  5.95  (69)% \\$2.64  10.08  (74)%
Cash operating margin (after derivatives)\\$13.72  \\$24.81  (45)% \\$10.58  26.39  (60)%
            
Non-cash items           
Depreciation Depletion and Amortization14.62  27.41  (47)% \\$13.24  \\$25.65  (48)%
Non-cash General and Administrative\\$1.13  \\$1.71  (34)% \\$1.24  \\$1.55  (20)%
            
Schedule 6: Adjusted Net Income (Loss)
(in thousands, except per share amounts, unaudited)
     
Adjusted net income is a supplemental non-GAAP financial measure that is used by management to present  recurring profitability by excluding items which are non-recurring in nature or items which are not easily estimable. Management believes adjusted net income provides external users of the Company's consolidated financial statements such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. The Company defines adjusted net income as net income after adjusting first for (1) the impact of certain non-cash items, including unrealized gains and losses on unsettled derivative instruments, impairment of oil and gas properties, other similar non-cash charges and one-time transactions and then (2) the non-cash and one time items’ impact on taxes based on an applicable rate that approximates the Company's effective tax rate in each period. Adjusted net income is not a measure of net income as determined by GAAP.
     
The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of adjusted net income (loss).
     
  Three Months Ended June 30, Six Months Ended June 30,
  2016 2015 2016 2015
Net loss \\$(49,477) \\$(41,164) \\$(96,714) \\$(59,586)
Adjustments to net loss:        
Derivative (gain) loss 12,923  5,478  13,930  (13,378)
Derivative cash settlements 3,893  15,189  11,401  50,655 
Impairment of proved properties —  —  10,000  — 
Abandonment and impairment of unproved properties 9,875  14,527  16,781  19,996 
Exploratory dry hole 734  5,680  966  5,680 
Stock-based compensation 2,380  4,359  5,384  7,787 
Cash severance costs (1) —  —  2,162  — 
Gain on termination fee (2) —  —  (6,000) — 
Derivative Conversion Payment (3) —  10,472  —  10,472 
Total adjustments before taxes 29,805  55,705  54,624  81,212 
Income tax effect —% 38.5% —% 38.5%
Total adjustments after taxes \\$29,805  \\$34,259  \\$54,624  \\$49,945 
         
Adjusted net loss \\$(19,672) \\$(6,905) \\$(42,090) \\$(9,641)
Adjusted net loss per diluted share \\$(0.40) \\$(0.14) \\$(0.86) \\$(0.21)
         
Diluted weighted-average common shares outstanding 49,277  48,923  49,204  46,734 
         
(1)  Included as a portion of general and administrative expense on the consolidated statement of operations.
(2)  Gain resulting from termination fee on unsuccessful RMI transaction during the first quarter of 2016.
(3) Conversion payment is included as a portion of Derivative cash settlements on the statement of cash flows and results from hedge restructuring in the second quarter of 2015 from 3-way collars to 2-way collars.
Schedule 7: Adjusted EBITDAX
(in thousands, unaudited)
     
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management to provide a metric of the Company's ability to internally generate funds for exploration and development of oil and gas properties and service debt. The metric excludes items which are non-recurring in nature and/or items which are not reasonably estimable. Management believes adjusted EBITDAX provides and external users of the Company’s consolidated financial statements, such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. The Company defines Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash and non-recurring charges. Adjusted EBITDAX is not a measure of net income or cash flows as determined by GAAP.
     
The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.
     
  Three Months Ended June 30, Six Months Ended June 30,
  2016 2015 2016 2015
Net loss \\$(49,477) \\$(41,164) \\$(96,714) \\$(59,586)
Exploration 677  5,748  943  6,246 
Depreciation, depletion and amortization 30,927  69,925  57,306  128,929 
Impairment of proved properties —  —  10,000  — 
Abandonment and impairment of unproved properties 9,875  14,527  16,781  19,996 
Stock-based compensation 2,380  4,359  5,384  7,787 
Cash severance costs (1) —  —  2,162  — 
Gain on termination fee (2) —  —  (6,000) — 
Derivative conversion payment (3) —  10,472  —  10,472 
Interest expense 16,527  14,468  31,074  28,706 
Derivative (gain) loss 12,923  5,478  13,930  (13,378)
Derivative cash settlements 3,893  15,189  11,401  50,655 
Income tax benefit —  (25,007) —  (36,544)
Adjusted EBITDAX \\$27,725  \\$73,995  \\$46,267  \\$143,283 
         
(1)  Included as a portion of general and administrative expense on the consolidated statement of operations.
(2)  Gain resulting from termination fee on unsuccessful RMI transaction during the first quarter of 2016.
(3) Conversion payment is included as a portion of Derivative cash settlements on the statement of cash flows and results from hedge restructuring in the second quarter of 2015 from 3-way collars to 2-way collars.