Bonanza Creek Energy Announces First Quarter 2015  Financial and Operating Results

DENVER, May 7,  2015 – Bonanza Creek Energy, Inc. (NYSE: BCEI) today reported its first quarter 2015 financial and operating results. The Company previously announced it reached agreement with its gas processing providers in the Rocky Mountain region to realize operated sales volumes in three streams (oil, NGLs and natural gas) effective January 1, 2015. Unless noted, all references to barrel of oil equivalent (boe) volumes related to activities completed in the Rocky Mountain region during 2014 have incorporated 6:1 gas to liquids conversion of two-stream (oil and wet gas) volumes. 

Highlights from first quarter 2015 include:

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Richard Carty, President and Chief Executive Officer, commented on the Company’s financial and operating results, “We are pleased with the underlying performance of our asset base during the first quarter. Everyone in the energy sector is adjusting to a radically different commodity price environment and the Bonanza Creek team has ably adapted to meet the challenges that these conditions present to our business. Compared to 2014 levels, our recurring efficiency initiatives and external service cost reductions have yielded a reduction in well costs by approximately 20% in the Wattenberg Field.  Wells with 4,000 foot laterals completed with 25 frac stages are now projected to cost approximately $3.6 million, and 9,000 foot laterals target $5.9 million costs. As our cash operating costs of $15.83 per Boe demonstrate, our contiguous leasehold position is proving to be a critical benefit to us during this time of depressed oil prices, enabling capital efficiencies as a result of our ability to drill wells into de-risked areas, drill multiple wells on scalable pads and co-locate new wells with previously installed surface infrastructure. Consistent with our previously disclosed 2015 plan, we are now running two rigs in the Wattenberg and expect to hold this activity flat through the end of the year. Although we are not adjusting any elements of our guidance for the full year at this time, we expect average well costs in 2015 to be below the assumptions that underpinned our capital activity budget of $400-420 million when announced in early January.”

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First Quarter 2015 Financial Results

Net revenue for first quarter 2015 was $73.1 million, compared to $127.4 million for first quarter 2014. Crude oil and liquids accounted for approximately 89% of total revenue.

Average realized prices for first quarter 2015, before the effect of commodity derivatives, were $39.87 per Bbl of oil, $2.28 per Mcf of natural gas and $14.14 per Bbl of NGLs, compared to $89.11 per Bbl of oil, $5.99 per Mcf of natural gas and $54.53 per Bbl of NGLs for first quarter 2014.

Lease operating expense for first quarter 2015 was $19.3 million, or $7.78 per Boe, compared to $17.1 million, or $9.63 per Boe ($8.99 per Boe adjusted for estimated 3-stream volumes), for first quarter 2014.  

General and administrative expense (“G&A”) for first quarter 2015 was $16.9 million, or $6.81 per Boe, compared to $23.7 million, or $13.37 per Boe ($12.48 per Boe adjusted for estimated 3-stream volumes), for first quarter 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense)(2) was $13.4 million, or $5.43 per Boe for the first quarter of 2015 compared to $16.9 million, or $9.54 per Boe for first quarter 2014.  First quarter 2014 G&A was impacted by executive departure costs of approximately $7.5 million, of which $3.6 million was cash. Not including departure costs, cash G&A for the first quarter 2014 was $13.3 million, or $7.51 per Boe ($7.00 per Boe adjusted for estimated 3-stream volumes). 

Depreciation, depletion and amortization for first quarter 2015 was $59.0 million, or $23.83 per Boe, compared to $41.1 million, or $23.20 per Boe ($21.65 per Boe adjusted for estimated 3-stream volumes), for the first quarter 2014.  

Interest expense for first quarter 2015 was $14.2 million compared to $9.3 million for the first quarter 2014.  

Adjusted EBITDAX(2) for first quarter 2015 was $69.3 million, compared to $80.5 million for the first quarter 2014.  

First quarter 2015 earnings included non-cash mark-to-market losses on derivatives of $16.6 million before tax, or $0.37 per diluted share.

First quarter 2015 earnings also included non-cash, pre-tax charges of $5.5 million related to the impairment of unproved properties within the Wattenberg Field resulting from lease expiration during the quarter. 

Reported net loss for first quarter 2015 was $18.4 million, or $0.41 per diluted share, compared to net income of $13.5 million, or $0.34 per diluted share, for first quarter 2014.  Adjusted net loss(2) for first quarter 2015 was $2.7 million, or $0.06 per diluted share, compared to adjusted net income of $18.4 million, or $0.46 per diluted share for first quarter 2014.

Operations Update

During first quarter 2015, the Company achieved average sales volumes of 27.5 Mboe/d, comprised of 60% crude oil, 16% NGLs and 24% natural gas, increasing total sales volumes by 30% over estimated 3-stream volumes in the first quarter of 2014. Total capital costs incurred during the first quarter totaled $123.4 million which represents approximately 30% of the Company’s capital budget for 2015.

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Rocky Mountain Region – Wattenberg Horizontal Development

During first quarter 2015, the Rocky Mountain region sold 21.9 Mboe/d, or 80% of total Company volumes, with over 95% coming from horizontal wells. On a 3-stream basis, sales volumes were up 41% compared to the first quarter of 2014 and increased by 3% compared to the fourth quarter of 2014. Capital costs incurred for the region were $111.7 million for the quarter.

The Company spud 30 gross operated (23.4 net) horizontal wells and tied 30 gross operated (20.5 net) horizontal wells into sales during the quarter. Non-operated activity for the quarter included no spud activity but 2 gross (0.1 net) wells tied into sales. Compared to the Company’s budget for 2015, the pace of spud activity moved 5 gross (3.6 net) wells ahead of plan during March as field operating conditions were favorable and rig efficiencies improved. During the first quarter, we spud 9 gross (7.9 net) operated extended reach lateral wells. Utilizing fit-for-purpose rigs, batch drilling on multi-well pads has resulted in spud-to-rig release times of 10-11 days for 9,000 foot lateral wells compared to 15-17 days during 2014.

The number of wells tied into sales was in-line with the Company’s plan for the quarter. The pace of well tie-ins was weighted to activity during February and March as January accounted for 15% of the net wells that began flowback during the quarter. For the remainder of the year, the Company expects to tie-in approximately 18-23 gross (15-20 net) wells per quarter. 

The Company continues to be pleased with the growing set of extended production histories on catalyst wells drilled in 2014. We have 14 Niobrara B and C bench wells drilled on 40-acre spacing and completed with 28 frac stages. In aggregate, the cumulative production from these laterals is proximal to the cumulative production profile represented in our 354 Mboe (3-stream) target type curve. In the Codell, our first well to test thinner net pay (less than eight feet) is nearly one year old and is tracking to a 300 MBoe (3-stream) recovery. A second Codell well drilled into less than eight feet of net pay is in early stages of flowback.

Differentials to WTI in the Wattenberg Field have decreased to an average of $10 per Bbl during the first quarter compared to $12 per Bbl during the fourth quarter of 2014. The Company expects incremental improvement over the remainder of 2015 into the $9 to $10 per Bbl range. On May 1, 2015, the Company began shipping 12,500 Bbls/d (gross) on the Pony Express Pipeline.

On April 30,  2015, the company consolidated its Pronghorn and 70 Ranch gas gathering and compression systems in the Wattenberg Field into a  new, wholly-owned subsidiary, Rocky Mountain Infrastructure, LLC.  This midstream subsidiary will serve as an operating platform from which the Company intends to facilitate the development of surface infrastructure in concert with the demands of its upstream business.

Mid-Continent Region – Cotton Valley Development

The Mid-Continent region contributed 5.6 Mboe/d, or 20% of total Company net sales volumes for first quarter 2015, comprised of 52% crude oil, 18%  NGLs and 30% natural gas. Sales volumes were flat compared to the first quarter of 2014, but decreased by 15% compared to the fourth quarter of 2014. Capital costs incurred for the region were $10.2 million for the quarter.

During the first quarter 2015, Bonanza Creek spud 9 gross (7.0 net) Cotton Valley wells, tied 5 gross (3.3 net) wells into sales and performed 17 gross (15.7 net) recompletions. 

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Sales volumes were down compared to the fourth quarter of 2014 due to a 50% cut in the number of recompletions executed. In addition, sales volumes in the fourth quarter benefited from several recompletions that produced at higher than average initial rates and then experienced steeper than average declines into the first quarter. For the remainder of 2015, the Company expects to maintain a similar pace of drilling and recompletions as performed in the first quarter. 

Financial and Risk Management Update

Debt and Liquidity

As of March 31, 2015, Bonanza Creek had a  $1.0 billion revolving credit facility with an undrawn borrowing base of $600 million.  The Company elected to limit bank commitments to $500 million while reserving the option to access the full $600 million, at the Company’s request. The Company had a letter of credit totaling $24.0 million and cash totaling $70.5 million, resulting in total liquidity of $646.5 million. The Company expects to report the results of its Spring 2015 bank redetermination in mid-May. Net debt to trailing 12-month EBITDAX equaled 2.2x. 

Commodity Derivatives Positions

The following table summarizes the Company’s crude oil and natural gas commodity derivative positions as of May 1, 2015 and settling quarterly:

 

Conference Call Information

Bonanza Creek will host a conference call on Friday, May 8,  2015 at 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time). To access the live interactive call, please dial (877)  299-4454 or (617) 597-5447 and use the passcode 74944642. This call is being webcast and can be accessed at Bonanza Creek’s website www.bonanzacrk.com for one year after the event.

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 Mountains 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.

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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 statements regarding projected well costs and impact on the Company’s 2015 capital budget, anticipated tie-in, drilling and recompletion activity, differentials to WTI and timing of release of the Company’s spring 2015 bank redetermination. 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, 2014, filed on February 27,  2015, 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.

For further information, please contact:

Mr. Ryan Zorn
Senior Vice President – Finance & Treasurer
720-440-6172

 

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Schedule 1: Statement of Operations
(in thousands, expect for per share data, unaudited)

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Schedule 2: Statement of Cash Flows
(in thousands, unaudited)

 

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Schedule 3: Condensed Balance Sheet
(in thousands, unaudited)

 

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Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)

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Schedule 5: Adjusted Net Income

(in thousands, except per share amounts, unaudited)

 

Adjusted Net Income is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted Net Income as net income after adjusting first for (1) the impact of certain non-cash items, including changes in unrealized gains and losses on unsettled derivative instruments, impairment of oil and gas properties, and other similar non-cash charges, and then (2) the non-cash items’ impact on taxes based on a tax rate of 38.5%, which approximates our effective tax rate. Adjusted Net Income is not a measure of net income as determined by GAAP.

The following table provides a reconciliation of Net (Loss) Income (GAAP) to Adjusted Net (Loss) Income (non-GAAP):

 

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Schedule 6: Adjusted EBITDAX

(in thousands, except per share amounts, unaudited)

 

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash charges. Adjusted EBITDAX is not a measure of net income or cash flows as determined by GAAP.

The following table presents a reconciliation of GAAP financial measures of Net (Loss) Income to the non-GAAP financial measure of Adjusted EBITDAX.

 

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Schedule 7:  Estimated 2014 Rocky Mountain 3-Stream Sales Volumes

 

The following estimates are based on internal BCEI calculations which convert previously reported 2-stream sales volumes in the Rocky Mountain region to 3-stream commodity mix.  No assurances can be provided to the accuracy of these figures as they are based on a variety of assumptions related, but not limited, to wet gas shrink and NGL yields. 

 

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