Exhibit 99.1
|
News Release |
|
For Immediate Release
May 8, 2014
Bonanza Creek Energy Announces First Quarter 2014 Operational and Financial Results and Super-Section Tests of Downspacing and Stacking Potential
DENVER, May 8, 2014 — Bonanza Creek Energy, Inc. (NYSE: BCEI) today reported its first quarter 2014 operating and financial results.
Key highlights from continuing operations(1) for the first quarter 2014, as compared to first quarter 2013, include:
· 60% increase in sales volumes to 19,701 Boe/d; 71% crude oil and liquids
· 63% increase in revenue to $127.4 million
· 20% increase in net income to $13.5 million, or $0.34 per share
· 14% increase in adjusted net income(2) to $18.4 million, or $0.46 per share
· 54% increase in adjusted EBITDAX(2) to $80.5 million
(1) Bonanza Creek began the divestiture process of its California properties in the second quarter 2012 and sold its remaining property, the Midway Sunset Field, on March 21, 2014. Under generally accepted accounting principles, the results of operations for the California properties are presented as “discontinued operations.”
(2) Non-GAAP measure, see attached Reconciliation Schedules
Operational highlights for the three pad, 15-well Super-Section include:
· Drilled and completed the Super-Section ahead of schedule
· 80-acre spacing results in the Niobrara B and C Benches substantiate stacking concept and potential for higher recoveries than individual wells; initial 30-day production rates for the five wells on the pad averaged 516 Boe/d
· 40-acre spacing results in the Niobrara B and C Benches demonstrate viability of downspacing and provide key learnings for future completion optimization; initial 30-day production rates for the five wells on the pad averaged 374 Boe/d
· Tracer data shows minimal frac communication between Codell wells spaced at 80 acres; additional testing planned
Marvin Chronister, Bonanza Creek’s Interim President and Chief Executive Officer, commented, “The first quarter demonstrated continued operational execution and increased visibility to the ultimate value of our assets. We reported production on plan despite the impact of severe cold weather, and we continue to see strong performance from three distinct resource layers in the Niobrara and Codell. The Super-Section results increase confidence in our 3P inventory — establishing that, in areas where the Codell is prospective, 20 wells per section is a minimum for development and up to 36 wells per section is achievable. We will continue to analyze the data and drill additional downspaced, multi-bench pads over the coming months and work to shape our capital programs for many years to come based on the lessons learned in 2014. Also during the course of the year, we will test the eastern boundaries of our assumed Codell potential, drill more medium and extended reach laterals and complete our first wells in the Niobrara A Bench and the North Park Basin.”
First Quarter 2014 Financial Results
Average realized prices for first quarter 2014, before the effect of commodity derivatives, were $89.11 per Bbl of oil, $5.99 per Mcf of natural gas and $54.53 per Bbl of NGLs, compared to $90.56 per Bbl of oil, $4.65 per Mcf of natural gas and $53.40 per Bbl of NGLs for first quarter 2013.
Net revenue for first quarter 2014 was $127.4 million, compared to $78.3 million for first quarter 2013. Crude oil and liquids revenue accounted for approximately 85% of total revenue.
Lease operating expense (“LOE”) for first quarter 2014 was $17.1 million, or $9.63 per Boe, compared to $11.1 million, or $10.05 per Boe, for first quarter 2013. The decrease in per unit LOE resulted primarily from increased sales volumes and growing production from the lower per unit operating cost attributable to horizontal wells. However, LOE was above plan in first quarter 2014 due primarily to the impact of severe cold weather in the Rocky Mountain region.
General and administrative expense (“G&A”) for first quarter 2014 was $23.7 million, or $13.37 per Boe, compared to $13.2 million, or $11.89 per Boe, for first quarter 2013. Cash G&A (non-GAAP) was $16.9 million, or $9.54 per Boe, compared to $8.8 million, or $7.93 per Boe, for the first quarter of 2013. 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.
Net income for first quarter 2014 was $13.5 million, or $0.34 per diluted share, compared to $11.3 million, or $0.28 per diluted share for first quarter 2013. Adjusted net income (non-GAAP) for first quarter 2014 was $18.4 million, or $0.46 per diluted share, compared to adjusted net income of $16.2 million, or $0.41 per diluted share for first quarter 2013.
Operations Update
During first quarter 2014, the Company achieved an average production rate of 19,701 Boe/d from continuing operations, comprised of 66% crude oil, 5% NGLs, and 29% natural gas, increasing total production by 60% over first quarter 2013. The Company reaffirms its 2014 production guidance of 23,000 to 25,000 Boe/d.
Rocky Mountain Region — Wattenberg Horizontal Development
The Rocky Mountain region contributed 14,099 Boe/d, or 72% of total Company net sales volumes for the quarter with approximately 95% coming from horizontal wells. Severe cold weather in January and February negatively impacted production for the quarter by approximately 700 Boe/d.
In fourth quarter 2013, the Company began drilling the 15 well Super-Section targeting the Niobrara B Bench, the Niobrara C Bench and the Codell. Completion operations began in January, while flowback commenced mid-February and meaningful production was realized during March. During the quarter, the Company spud 28 gross (22.9 net) operated wells and, not including the Super-Section, completed 3 gross (2.0 net) operated wells with the remaining wells in progress at March 31, 2014.
The Company’s analysis of the Super-Section is ongoing. Initial 30-day average production rates from the three pads drilled suggest that downspacing to 40 acres in the Niobrara is realistic and stacking arrangements between benches could be preferable to single zone development, increasing confidence in the Company’s 3P inventory and reserves assumptions. The west pad, testing 80-acre spaced Niobrara B bench wells staggered and stacked on top of Niobrara C and Codell wells produced a per well average rate of 448 Boe/d. The middle pad, testing 40-acre spacing Niobrara B bench wells staggered on top of 40-acre spaced Niobrara C bench wells produced a per well average rate of 374 Boe/d. The east pad, testing 80-acre spaced Niobrara B bench wells staggered on top of 80-acre spaced Niobrara C bench wells produced a per well average rate of 516 Boe/d. Management will present additional commentary and analysis on its conference call.
Two wells on the Super-Section experienced mechanical issues. The Codell well on the west pad had a casing failure that blocked 16 of the 18 frac stages. It is currently under evaluation for remedial work and did not contribute to the 448 Boe/d per well average for the pad. An 80-acre Niobrara B well on the east pad was unable to be fully cleaned out post frac resulting in six missing frac stages.
Year to date, the Company has drilled three extended reach laterals: one 7,500’ lateral in the Codell, and two 9,000’ laterals in the Niobrara B Bench and C Bench. The two 9,000’ lateral wells drilled in 2013 continue to track a 750 MBoe type curve.
Mid-Continent Cotton Valley Program
The Mid-Continent region contributed 5,602 Boe/d, or 28% of total Company net sales volumes for first quarter 2014, comprised of 53% crude oil, 18% natural gas liquids and 29% natural gas. Sales volumes increased by approximately 9% over first quarter 2013. Bonanza Creek spud 15 gross (10.8 net) wells during first quarter 2014, of which nine were spaced on 10 acres and six were spaced on five acres, and performed 23 recompletions. It tied eight gross (6.0 net) wells into sales during the quarter.
Financial and Risk Management Update
Liquidity
As of March 31, 2014, the Company had a $600 million revolving credit facility with an undrawn borrowing base of $450 million. The Company had a letter of credit totaling $36.0 million and cash totaling $131.3 million, resulting in total liquidity of $545.3 million.
Commodity Derivatives Positions
The following table summarizes the Company’s crude oil and natural gas commodity derivative positions as of May 1, 2014 and settling quarterly thereafter:
|
Settlement |
|
Swap |
|
Fixed |
|
Collar |
|
Average |
|
Average |
|
Average |
|
|
Period |
|
Volume |
|
Price |
|
Volume |
|
Short Floor |
|
Floor |
|
Ceiling |
|
|
Oil |
|
Bbl/d |
|
$ |
|
Bbl/d |
|
$ |
|
$ |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2 2014 |
|
4,126 |
|
96.20 |
|
4,846 |
|
|
|
86.55 |
|
96.72 |
|
|
Q3 2014 |
|
3,870 |
|
93.04 |
|
4,326 |
|
|
|
86.16 |
|
96.57 |
|
|
Q4 2014 |
|
4,370 |
|
93.47 |
|
4,326 |
|
|
|
86.16 |
|
96.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2-Q4 2014 |
|
|
|
|
|
2,000 |
|
65.00 |
|
87.68 |
|
99.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2015 |
|
2,000 |
|
92.22 |
|
5,500 |
|
67.27 |
|
83.75 |
|
95.19 |
|
|
Q2-Q4 2015 |
|
1,000 |
|
90.40 |
|
4,500 |
|
66.67 |
|
83.33 |
|
94.12 |
|
|
Gas |
|
MMBtu/d |
|
$ |
|
MMBtu/d |
|
$ |
|
$ |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q2-Q4 2014 |
|
|
|
|
|
30,000 |
|
3.63 |
|
4.21 |
|
4.81 |
|
|
FY 2015 |
|
|
|
|
|
15,000 |
|
3.50 |
|
4.00 |
|
4.75 |
|
Conference Call Information
Bonanza Creek will host a conference call on Friday, May 9, 2014 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time). To access the live interactive call, please dial (866) 318-8611 or (617) 399-5130 and use the passcode 14653373. 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 oil shale, and in southern Arkansas, focused on the 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 statements regarding the Company’s capital program and drilling and development program. 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; and access to adequate gathering systems and pipeline take-away capacity. 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, 2013 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
Vice President — Finance & Treasurer
720-440-6172
Mr. James Masters
Investor Relations Manager
720-440-6121
Schedule 1: Condensed Statement of Operations
(in thousands, expect for per share data, unaudited)
|
|
|
Three Months Ended |
| ||||
|
|
|
March 31 |
| ||||
|
|
|
2014 |
|
2013 |
| ||
|
NET REVENUES |
|
|
|
|
| ||
|
Oil and gas sales |
|
$ |
127,395 |
|
$ |
78,307 |
|
|
OPERATING EXPENSES |
|
|
|
|
| ||
|
Lease operating |
|
17,082 |
|
11,131 |
| ||
|
Severance and ad valorem taxes |
|
10,749 |
|
4,812 |
| ||
|
Exploration |
|
1,083 |
|
562 |
| ||
|
Depreciation, depletion and amortization |
|
41,132 |
|
23,363 |
| ||
|
General and administrative (including $6,797 and $4,378 in 2014 and 2013, respectively, of stock-based compensation) |
|
23,714 |
|
13,166 |
| ||
|
Total operating expenses |
|
93,760 |
|
53,034 |
| ||
|
INCOME FROM OPERATIONS |
|
33,635 |
|
25,273 |
| ||
|
OTHER INCOME (EXPENSE) |
|
|
|
|
| ||
|
Derivative loss |
|
(8,778 |
) |
(5,116 |
) | ||
|
Interest expense |
|
(9,335 |
) |
(1,963 |
) | ||
|
Other income |
|
51 |
|
137 |
| ||
|
Total other expense |
|
(18,062 |
) |
(6,942 |
) | ||
|
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES |
|
15,573 |
|
18,331 |
| ||
|
Income tax expense |
|
(5,996 |
) |
(7,058 |
) | ||
|
INCOME FROM CONTINUING OPERATIONS |
|
$ |
9,577 |
|
$ |
11,273 |
|
|
DISCONTINUED OPERATIONS |
|
|
|
|
| ||
|
Loss from operations associated with oil and gas properties held for sale |
|
(85 |
) |
(27 |
) | ||
|
Gain on sale of oil and gas properties |
|
6,514 |
|
— |
| ||
|
Income tax (expense) benefit |
|
(2,475 |
) |
10 |
| ||
|
Gain (loss) from discontinued operations |
|
3,954 |
|
(17 |
) | ||
|
NET INCOME |
|
$ |
13,531 |
|
$ |
11,256 |
|
|
DILUTED INCOME PER SHARE |
|
|
|
|
| ||
|
Income from continuing operations |
|
$ |
0.24 |
|
$ |
0.28 |
|
|
Income from discontinued operations |
|
$ |
0.10 |
|
$ |
— |
|
|
Net income per common share |
|
$ |
0.34 |
|
$ |
0.28 |
|
|
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK |
|
|
|
|
| ||
|
Basic |
|
39,605 |
|
39,254 |
| ||
|
Diluted |
|
39,762 |
|
39,285 |
| ||
* The Company follows the two-class method when computing the basic and diluted income (loss) per share, which allocates earnings between common shareholders and participating securities. Please refer to Note 13 – Earnings per Share in the Form 10-K, for a detailed calculation.
Schedule 2: Condensed Statement of Cash Flows
(in thousands, unaudited)
|
|
|
Three Months Ended |
| ||||
|
|
|
March 31, |
| ||||
|
|
|
2014 |
|
2013 |
| ||
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
| ||
|
Net income |
|
$ |
13,531 |
|
$ |
11,256 |
|
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
| ||
|
Depreciation, depletion and amortization |
|
41,199 |
|
23,467 |
| ||
|
Deferred income taxes |
|
8,471 |
|
7,048 |
| ||
|
Stock-based compensation |
|
6,797 |
|
4,378 |
| ||
|
Amortization of deferred financing costs |
|
562 |
|
219 |
| ||
|
Amortization of premium on senior notes |
|
(307 |
) |
— |
| ||
|
Accretion of contractual obligation for land acquisition |
|
190 |
|
190 |
| ||
|
Derivative loss |
|
8,778 |
|
5,116 |
| ||
|
Gain on sale of oil and gas properties |
|
(6,514 |
) |
— |
| ||
|
Other |
|
(2 |
) |
73 |
| ||
|
Changes in current assets and liabilities |
|
|
|
|
| ||
|
Accounts receivable |
|
(12,721 |
) |
(6,912 |
) | ||
|
Prepaid expenses and other assets |
|
(2,637 |
) |
81 |
| ||
|
Accounts payable and accrued liabilities |
|
20,337 |
|
(5,068 |
) | ||
|
Settlement of asset retirement obligations |
|
— |
|
(49 |
) | ||
|
Net cash provided by operating activities |
|
77,684 |
|
39,799 |
| ||
|
|
|
|
|
|
| ||
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
| ||
|
Acquisition of oil and gas properties |
|
(1,202 |
) |
(934 |
) | ||
|
Proceeds from sale of oil and gas properties |
|
6,000 |
|
— |
| ||
|
Exploration and development of oil and gas properties |
|
(123,835 |
) |
(64,334 |
) | ||
|
Natural gas plant capital expenditures |
|
(194 |
) |
(3,275 |
) | ||
|
Derivative cash settlements |
|
(2,227 |
) |
(1,507 |
) | ||
|
Additions to property and equipment - non oil and gas |
|
(838 |
) |
(1,386 |
) | ||
|
Net cash (used) in investing activities |
|
(122,296 |
) |
(71,436 |
) | ||
|
|
|
|
|
|
| ||
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
| ||
|
Proceeds from credit facility |
|
— |
|
33,500 |
| ||
|
Offering costs related to sale of senior subordinated notes |
|
(140 |
) |
— |
| ||
|
Payment of employee tax withholdings in exchange for the return of common stock |
|
(4,461 |
) |
(2,908 |
) | ||
|
Deferred financing costs |
|
(26 |
) |
(52 |
) | ||
|
Net cash (used in) provided by financing activities |
|
(4,627 |
) |
30,540 |
| ||
|
Net change in cash and cash equivalents |
|
(49,239 |
) |
(1,097 |
) | ||
|
|
|
|
|
|
| ||
|
Cash and cash equivalents, beginning of period |
|
180,582 |
|
4,267 |
| ||
|
Cash and cash equivalents, end of period |
|
$ |
131,343 |
|
$ |
3,170 |
|
Schedule 3: Condensed Balance Sheet
(in thousands, unaudited)
|
|
|
March 31, |
|
December 31, |
| ||
|
|
|
2014 |
|
2013 |
| ||
|
Assets |
|
|
|
|
| ||
|
Current assets |
|
$ |
227,481 |
|
$ |
264,174 |
|
|
Total property and equipment, net |
|
1,379,200 |
|
1,267,609 |
| ||
|
Other assets |
|
13,463 |
|
14,152 |
| ||
|
Oil and gas properties held for sale, less accumulated depreciation, depletion, and amortization |
|
— |
|
|
| ||
|
Total Assets |
|
$ |
1,620,144 |
|
$ |
1,545,935 |
|
|
|
|
|
|
|
| ||
|
Liabilities and Stockholders’ Equity |
|
|
|
|
| ||
|
Current liabilities |
|
220,462 |
|
175,226 |
| ||
|
Long-term debt |
|
530,763 |
|
530,880 |
| ||
|
Deferred taxes |
|
161,152 |
|
152,681 |
| ||
|
Other long-term liabilities |
|
35,872 |
|
31,120 |
| ||
|
Total Liabilities |
|
$ |
948,249 |
|
$ |
889,907 |
|
|
|
|
|
|
|
| ||
|
Stockholders’ Equity |
|
671,895 |
|
656,028 |
| ||
|
Total Liabilities and Stockholders’ Equity |
|
$ |
1,620,144 |
|
$ |
1,545,935 |
|
Schedule 4: Volumes and Realized Prices
(unaudited)
|
|
|
Three Months Ended |
| ||||
|
|
|
March 31, |
| ||||
|
|
|
2014 |
|
2013 |
| ||
|
Wellhead Volumes and Prices |
|
|
|
|
| ||
|
Crude Oil and Condensate Sales Volumes (Bbl/d) |
|
|
|
|
| ||
|
Rocky Mountains |
|
9,987 |
|
5,107 |
| ||
|
Mid-Continent |
|
2,949 |
|
2,951 |
| ||
|
Total |
|
12,936 |
|
8,058 |
| ||
|
|
|
|
|
|
| ||
|
Crude Oil and Condensate Realized Prices ($/Bbl) |
|
|
|
|
| ||
|
Rocky Mountains |
|
$ |
86.72 |
|
$ |
86.30 |
|
|
Mid-Continent |
|
97.21 |
|
97.93 |
| ||
|
Composite (before derivatives) |
|
$ |
89.11 |
|
$ |
90.56 |
|
|
Composite (after derivatives) |
|
$ |
87.65 |
|
$ |
88.28 |
|
|
|
|
|
|
|
| ||
|
Natural Gas Liquids Sales Volumes (Bbl/d) |
|
|
|
|
| ||
|
Rocky Mountains |
|
39 |
|
— |
| ||
|
Mid-Continent |
|
1,006 |
|
830 |
| ||
|
Total |
|
1,045 |
|
830 |
| ||
|
|
|
|
|
|
| ||
|
Natural Gas Liquids Realized Prices ($/Bbl) |
|
|
|
|
| ||
|
Rocky Mountains |
|
$ |
27.12 |
|
$ |
— |
|
|
Mid-Continent |
|
55.59 |
|
53.40 |
| ||
|
Composite (before derivatives) |
|
$ |
54.53 |
|
$ |
53.40 |
|
|
Composite (after derivatives) |
|
$ |
54.53 |
|
$ |
53.40 |
|
|
|
|
|
|
|
| ||
|
Natural Gas Sales Volumes (Mcf/d) |
|
|
|
|
| ||
|
Rocky Mountains |
|
24,438 |
|
12,341 |
| ||
|
Mid-Continent |
|
9,887 |
|
8,171 |
| ||
|
Total |
|
34,325 |
|
20,512 |
| ||
|
|
|
|
|
|
| ||
|
Natural Gas Realized Prices ($/Mcf) |
|
|
|
|
| ||
|
Rocky Mountains |
|
$ |
6.27 |
|
$ |
5.40 |
|
|
Mid-Continent |
|
5.31 |
|
3.52 |
| ||
|
Composite (before derivatives) |
|
$ |
5.99 |
|
$ |
4.65 |
|
|
Composite (after derivatives) |
|
$ |
5.82 |
|
$ |
4.73 |
|
|
|
|
|
|
|
| ||
|
Crude Oil Equivalent Sales Volumes (Boe/d) |
|
|
|
|
| ||
|
Rocky Mountains |
|
14,099 |
|
7,176 |
| ||
|
Mid-Continent |
|
5,602 |
|
5,131 |
| ||
|
Total |
|
19,701 |
|
12,307 |
| ||
|
|
|
|
|
|
| ||
|
Crude Oil Equivalent Sales Prices ($/Boe) |
|
|
|
|
| ||
|
Rocky Mountains |
|
$ |
72.37 |
|
$ |
70.77 |
|
|
Mid-Continent |
|
70.52 |
|
70.48 |
| ||
|
Composite (before derivatives) |
|
$ |
71.85 |
|
$ |
70.64 |
|
|
Composite (after derivatives) |
|
$ |
70.59 |
|
$ |
69.29 |
|
|
|
|
|
|
|
| ||
|
Total Sales Volumes (MBoe) |
|
1,773.1 |
|
1,107.6 |
| ||
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, (2) cash dry hole charges related to a vertical well in the Wattenberg Field drilled to test the Lyons formation, and then (3) these 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 income (GAAP) to Adjusted Net Income (non-GAAP):
|
|
|
Three Months Ended |
| ||||
|
|
|
March 31, |
| ||||
|
|
|
2014 |
|
2013 |
| ||
|
Net Income |
|
$ |
13,531 |
|
$ |
11,256 |
|
|
Derivative loss |
|
8,778 |
|
5,116 |
| ||
|
Derivative cash settlements |
|
(2,227 |
) |
(1,507 |
) | ||
|
Gain on sale of oil and gas properties |
|
(6,514 |
) |
— |
| ||
|
Exploratory dry hole cost |
|
1,044 |
|
— |
| ||
|
Stock-based compensation |
|
6,797 |
|
4,378 |
| ||
|
Total adjustments before tax |
|
7,878 |
|
7,987 |
| ||
|
|
|
|
|
|
| ||
|
Adjustment of income tax effect |
|
3,033 |
|
3,075 |
| ||
|
Adjusted for income tax effects |
|
4,845 |
|
4,912 |
| ||
|
|
|
|
|
|
| ||
|
Adjusted net income |
|
$ |
18,376 |
|
$ |
16,168 |
|
|
Adjusted net income per diluted share |
|
$ |
0.46 |
|
$ |
0.41 |
|
|
|
|
|
|
|
| ||
|
Weighted Average Number of Shares |
|
39,762 |
|
39,285 |
| ||
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, exploration expenses and other similar non-cash charges. Adjusted EBITDAX is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.
The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measures of net income.
|
|
|
Three Months Ended |
| ||||
|
|
|
March 31, |
| ||||
|
|
|
2014 |
|
2013 |
| ||
|
Net Income |
|
$ |
13,531 |
|
$ |
11,256 |
|
|
Exploration |
|
1,083 |
|
619 |
| ||
|
Depreciation, depletion and amortization |
|
41,199 |
|
23,467 |
| ||
|
Stock-based compensation |
|
6,797 |
|
4,378 |
| ||
|
Gain on sale of oil and gas properties |
|
(6,514 |
) |
— |
| ||
|
Interest expense |
|
9,335 |
|
1,963 |
| ||
|
Derivative (gain) loss |
|
8,778 |
|
5,116 |
| ||
|
Derivative cash settlements |
|
(2,227 |
) |
(1,507 |
) | ||
|
Income tax expense |
|
8,471 |
|
7,048 |
| ||
|
Adjusted EBITDAX |
|
$ |
80,453 |
|
$ |
52,340 |
|