MIDLAND, Texas, Feb. 17, 2015 (GLOBE NEWSWIRE) -- Diamondback Energy, Inc. (Nasdaq:FANG) ("Diamondback" or the "Company") today announced financial and operating results for the fourth quarter ended December 31, 2014.
HIGHLIGHTS
- Proved reserves as of December 31, 2014 increased 77% year over year to 112.8 MMboe (67% oil, 17% natural gas, 16% natural gas liquids), with a PV-10 value of approximately $2.3 billion as calculated below. Additions replaced 793% (626% organically) of 2014 production with drill bit finding and development costs ("F&D") of $11.09/boe as calculated below.
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Diamondback continues to report strong Lower Spraberry results:
- Diamondback completed a three-well pad targeting the Lower Spraberry on 660 foot inter-lateral spacing. The ST 4104LS, ST 4105LS and ST 4106LS have an average 5,214 foot lateral and were completed with an average of 23 stages. The three wells achieved an average peak 30-day 2-stream initial production ("IP") rate of 1,377 boe/d (92% oil) on electric submersible pump ("ESP") when normalized to a 7,500 foot lateral. This translates to 184 boe/d per 1,000 feet of lateral.
- Diamondback also completed its first Lower Spraberry 500 foot inter-lateral spacing test in Midland County. Early results are similar to wells on 660 foot inter-lateral spacing. The ST W 701LS has a 7,201 foot lateral and was completed with 31 stages while the ST W 702LS has a 7,291 foot lateral and 31 stages. The two wells have an average peak 30-day 2-stream IP rate of 1,340 boe/d (90% oil) on ESP when normalized to a 7,500 foot lateral, or 179 boe/d per 1,000 feet of lateral. As a reminder, Diamondback's Lower Spraberry inventory count reflects 660 foot inter-lateral spacing.
- The UL Mason Unit 2LS, Diamondback's second Lower Spraberry well in Andrews County, has a 7,619 foot lateral, completed with 33 stages, achieving an average peak 15-day 2-stream IP rate of 1,384 boe/d (91% oil) on ESP.
- The Estes B Unit 1602LS, Diamondback's first Lower Spraberry well in Dawson County, has an 8,289 foot lateral completed with 36 stages, achieving a peak 24 hour 2-stream IP rate of 1,067 boe/d (95% oil) on ESP, with an average peak 30 day 2-stream IP rate of 694 boe/d (93% oil).
- As a result of continued strong Lower Spraberry well results, Ryder Scott increased its estimate of Diamondback's PUD reserve levels on a two stream basis for 7,500 foot laterals in Midland County to 990 Mboe from 650 Mboe previously. The Company now believes the Lower Spraberry will average between 700 and 800 Mboe for 7,500 foot laterals across its identified inventory.
- As previously reported, Diamondback's Q4 2014 production increased 25% to 25.7 Mboe/d from 20.6 Mboe/d in Q3 2014. Full year 2014 production increased 166% over full year 2013 to 19.5 Mboe/d, above the 2014 guidance range of 17.0 to 19.0 Mboe/d.
"We are excited about the continued success of the Lower Spraberry with promising tests in Upton, Midland, Martin, Andrews and now Dawson Counties. As a result of the continued success, we have increased the Lower Spraberry estimated ultimate recoveries ("EUR") to almost one million barrels of oil equivalent in Midland County. At $50 oil, our Lower Spraberry wells in Midland County can generate a 50% rate of return at current costs and approximately 100% rate of return when including our mineral ownership," stated Travis Stice, Chief Executive Officer of Diamondback.
Mr. Stice added, "I'm pleased with our results in 2014 as our proved reserves grew by 77% and we replaced 793% (626% organically) of our 2014 production. Our F&D costs in 2014 were an attractive $11.09/boe. In 2014, our production volumes grew by 166% as compared to 2013. Lease operating expense ("LOE") increased during the quarter, reflecting the September acquisition of approximately 130 vertical wells with high LOE. Excluding the effects of acquisitions, LOE would have been $6.87/boe in 2014."
FINANCIAL HIGHLIGHTS
Fourth quarter 2014 income before income taxes was $156.2 million. During that same period the Company's net income after taxes and net income attributable to a non-controlling interest was $98.7 million as compared to $43.7 million in the third quarter of 2014.
Fourth quarter 2014 Adjusted EBITDA was $111.7 million and fourth quarter 2014 revenues were $131.6 million.
As of January 30, 2015, the Company had approximately $128 million drawn on its credit facility. As previously communicated, Diamondback's lenders under its revolving credit facility approved a borrowing base increase to $750 million. However, the Company elected to limit the lenders' aggregate commitment to $500 million.
During 2014, capital spent for drilling, completion and infrastructure was approximately $486.9 million. 2014 capital drove production growth that was 8% over the midpoint of guidance. Additionally, the Company spent $903.5 million on leasehold and mineral acquisitions.
RESERVES
Ryder Scott Company, L.P. prepared estimates of Diamondback's proved reserves as of December 31, 2014. Reference prices of $94.99 per barrel of oil, $4.35 per MMcf of natural gas and $44.84 per barrel of natural gas liquids were used in accordance with applicable rules of the Securities and Exchange Commission. Realized prices with applicable differentials were $87.15 per barrel of oil, $4.85 per MMcf of natural gas and $30.09 per barrel of natural gas liquids.
Proved reserves at year-end 2014 of 112.8 MMboe represent a 77% increase over year-end 2013 reserves.
Proved developed reserves increased by 122% to 66.5 MMboe as of December 31, 2014 reflecting the continued development of the Company's horizontal well inventory. Horizontal wells now represent 56% of Diamondback's proved developed reserves and 81% of the Company's proved undeveloped reserves. Crude oil represents 67% of Diamondback's total proved reserves.
Net proved reserve additions of 56.4 MMboe resulted in a reserve replacement ratio of 793% (defined as the sum of extensions, discoveries, revisions and purchases, divided by annual production). The organic reserve replacement ratio was 626% (defined as the sum of extensions, discoveries, and revisions, divided by annual production).
Purchases of reserves came primarily from two acquisitions, one located in southwest Martin County and the other predominantly in Glasscock and Midland Counties. The acquired reserves were proved developed producing reserves from 280 gross vertical wells and six gross non-operated horizontal wells. Significant extensions occurred primarily as a result of continued horizontal development of the Wolfcamp B horizon and the beginning of horizontal development of the Lower Spraberry shale. Approximately 56% of the extensions are classified as proved undeveloped. Revisions are primarily the result of downgrading 6.2 MMboe of reserves attributable to 73 vertical wells into the probable category as the Company continues to focus on horizontal development of its acreage.
| Oil (Bbl) | Gas (Mcf) | Liquids (Bbl) | BOE | |
| Proved Reserves at December 31, 2013 | 42,600,852 | 61,679,496 | 10,705,724 | 63,586,492 |
| Revisions of Previous Estimates | (6,784,560) | (17,726,552) | 649,476 | (9,089,509) |
| Extensions and Discoveries | 37,068,820 | 52,099,252 | 7,828,094 | 53,580,123 |
| Purchases of Reserves-In-Place | 8,186,053 | 19,898,649 | 360,536 | 11,863,030 |
| Production | (5,381,576) | (4,345,585) | (1,001,898) | (7,107,738) |
| Proved Reserves at December 31, 2014 | 75,689,589 | 111,605,260 | 18,541,932 | 112,832,397 |
Diamondback's exploration and development costs in 2014 were $561.9 million. F&D costs were $11.09/boe, with F&D costs defined as exploration and development costs divided by the sum of extensions, discoveries and revisions (with revisions excluding 6.2 MMboe of vertical PUD downgrades).
| Year ended December 31, | ||
| (in thousands) | 2014 | 2013 |
| Acquisition costs | ||
| Proved properties | $ 302,234 | $ 339,130 |
| Unproved properties | $ 601,188 | $ 279,402 |
| Development costs | $ 86,097 | $ 88,460 |
| Exploration costs | $ 475,756 | $ 242,929 |
| Capitalized asset retirement cost | $ 4,962 | $ 697 |
| Total | $ 1,470,237 | $ 950,618 |
FULL YEAR 2015 GUIDANCE
As previously announced, Diamondback forecasts 2015 production of 26.0 to 28.0 Mboe/d, including 4.2 to 4.5 Mboe/d attributable to subsidiary Viper Energy Partners LP ("Viper"). This range represents approximately 40% growth at the midpoint as compared to 2014 production.
Diamondback expects a 2015 total capital spend of $400 to $450 million, consisting of $285 to $315 million for horizontal drilling and completions, $20 to $30 million for infrastructure and $20 to $30 million for non-operated activity and other expenditures. Capital spend also includes $75 million for expenditure related to 2014 activity (net of expenditures expected to be carried into 2016 from 2015).
During February 2015, the Company intends to release two horizontal rigs and its remaining vertical rig. Of the three remaining horizontal rigs, two will operate at Spanish Trail in Midland County where Viper owns the underlying minerals.
As previously disclosed, Diamondback expects to drill and complete 50 to 60 gross horizontal wells in 2015. The Company expects that service costs will recalibrate to the current commodity environment and anticipates costs for a 7,500 foot lateral horizontal well to range from $6.2 to $6.7 million. If the Company does not receive meaningful service cost reductions, it could defer completions.
As shown in the table below, 2015 LOE is expected to be in the range of $6.50 to $7.50 per boe while depreciation, depletion and amortization expense ("DD&A") is expected to range from $20.00 to $22.00 per boe. The Company projects cash general and administrative expense ("G&A") per boe to be between $1.00 and $2.00 per boe and non-cash equity-based compensation to be between $1.00 and $2.00 per boe. Production and ad valorem taxes as a percent of revenue are expected to be 7.1%.
| 2015 Guidance | ||
| Diamondback Energy Inc | Viper Energy Partners LP | |
| Total Net Production – MBoe/d | 26.0 – 28.0 | 4.2 – 4.5 |
| Unit costs ($/boe) | ||
| Lease Operating Expenses | $6.50 – $7.50 | $0.00 |
| G&A | ||
| Cash G&A | $1.00 – $2.00 | $1.00 – $2.00 |
| Non-Cash Equity-Based Compensation | $1.00 – $2.00 | $2.00 – $3.00 |
| DD&A | $20.00 – $22.00 | $20.00 – $22.00 |
| Production and Ad Valorem Taxes (% of Revenue) (a) | 7.1% | 7.5% |
| ($ - million) | ||
| Gross Horizontal Well Costs (b) | $6.2 – $6.7 | n/a |
| Horizontal Wells Drilled & Completed (net) | 50 – 60 (43 – 52) | n/a |
| Interest Expense (net of interest income) | $40.0 – $50.0 | n/a |
| Capital Budget ($ - million) | ||
| Horizontal Drilling and Completion | $285.0 – $315.0 | n/a |
| Infrastructure | $20.0 – $30.0 | n/a |
| Non-op and Other | $20.0 – $30.0 | n/a |
| 2015 Capital Budget | $325.0 – $375.0 | n/a |
| Net Carry In | $75.0 | n/a |
| 2015 Capital Spend | $400.0 – $450.0 | n/a |
| a - Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes. | ||
| b -Assumes a 7,500' average lateral length. | ||
CONFERENCE CALL
Diamondback and Viper will host a joint conference call and webcast for investors and analysts to discuss their results for the quarter on Wednesday, February 18, 2015 at 9:00 a.m. CT.
Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and utilize the confirmation code 75840964. A telephonic replay will be available for anyone unable to participate in the live call. To access the replay, call (855) 859-2056 (United States/Canada) or (404) 537-3406 (International) and enter confirmation code 75840964. The recording will be available from 12:00 p.m. CT on Wednesday, February 18, 2015 through Monday, February 23, 2015 at 10:59 p.m. CT. A live broadcast of the earnings conference call will also be available via the internet at www.diamondbackenergy.com under the "Investor Relations" section of the site. The webcast will be archived on the site.
About Diamondback Energy, Inc.
Diamondback is an independent oil and natural gas Company headquartered in Midland, Texas focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback's activities are primarily focused on the horizontal exploitation of multiple intervals within the Wolfcamp, Spraberry, Clearfork and Cline formations.
Forward Looking Statements
This news release contains forward-looking statements within the meaning of the federal securities laws. All statements, other than historical facts, that address activities that Diamondback assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management's current beliefs, based on currently available information, as to the outcome and timing of future events. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of Diamondback. Information concerning these risks and other factors can be found in Diamondback's filings with the Securities and Exchange Commission, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the Securities and Exchange Commission's web site at http://www.sec.gov. Diamondback undertakes no obligation to update or revise any forward-looking statement.
| Diamondback Energy, Inc. | ||||
| Consolidated Statements of Operations | ||||
| (unaudited; in thousands, except per share data) | ||||
|
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||
| 2014 | 2013 | 2014 | 2013 | |
| Revenues: | ||||
| Oil and natural gas revenues | $ 131,583 | $ 75,908 | $ 495,718 | $ 208,002 |
| Operating Expenses: | ||||
| Lease operating expense | 23,168 | 5,790 | 55,384 | 21,157 |
| Production and ad valorem taxes | 9,288 | 4,604 | 32,638 | 12,899 |
| Gathering and transportation expense | 1,143 | 277 | 3,288 | 918 |
| Depreciation, depletion and amortization | 53,641 | 23,621 | 170,005 | 66,597 |
| General and administrative | 6,280 | 3,823 | 21,266 | 11,036 |
| Asset retirement obligation accretion expense | 164 | 67 | 467 | 201 |
| Total expenses | 93,684 | 38,182 | 283,048 | 112,808 |
| Income from operations | 37,899 | 37,726 | 212,670 | 95,194 |
| Other income | 569 | 30 | 677 | 1,077 |
| Net interest expense | (10,424) | (5,950) | (34,514) | (8,058) |
| Other expense | 0 | -- | (1,416) | -- |
| Non-cash gain (loss) on derivative instruments | 111,479 | 1,613 | 117,109 | 5,346 |
| Gain (loss) on derivative instruments, net | 16,637 | (1,604) | 10,430 | (7,218) |
| Total other income (expense) | 118,261 | (5,911) | 92,286 | (8,853) |
| Income before income taxes | 156,160 | 31,815 | 304,956 | 86,341 |
| Income tax provision | 56,243 | 11,691 | 108,985 | 31,754 |
| Net income | 99,917 | 20,124 | 195,971 | 54,587 |
| Less: Net income attributable to noncontrolling interest | 1,243 | -- | 2,216 | -- |
| Net income attributable to Diamondback Energy, Inc. | $ 98,674 | $ 20,124 | $ 193,755 | $ 54,587 |
| Basic earnings per common share(1) | $ 1.74 | $ 0.43 | $ 3.67 | $ 1.30 |
| Diluted earnings per common share(1) | $ 1.73 | $ 0.42 | $ 3.64 | $ 1.29 |
| Weighted average number of basic shares outstanding | 56,787 | 47,076 | 52,826 | 42,015 |
| Weighted average number of diluted shares outstanding | 57,045 | 47,412 | 53,297 | 42,255 |
| ¹The Company's earnings per common share amounts are calculated in accordance with Accounting Standards Codification 260, with an adjustment included for the awards issued by a consolidated subsidiary. | ||||
| Diamondback Energy, Inc. | ||||
| Selected Operating Data | ||||
| (unaudited; in thousands, except per BOE data) | ||||
|
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||
| 2014 | 2013 | 2014 | 2013 | |
| Production Data: | ||||
| Oil (MBbl) | 1,785 | 760 | 5,382 | 2,023 |
| Natural gas (MMcf) | 1,447 | 525 | 4,346 | 1,730 |
| Natural gas liquids (MBbls) | 341 | 112 | 1,002 | 361 |
| Oil Equivalents (1)(2) (MBOE) | 2,367 | 959 | 7,108 | 2,672 |
| Average daily production(2) (BOE/d) | 25,724 | 10,426 | 19,474 | 7,321 |
| % Oil | 75% | 79% | 76% | 76% |
| Average sales prices: | ||||
| Oil, realized ($/Bbl) | $ 66.01 | $ 91.33 | $ 83.48 | $ 93.32 |
| Natural gas realized ($/Mcf) | 3.91 | 3.56 | 4.15 | 3.61 |
| Natural gas liquids ($/Bbl) | 23.86 | 41.59 | 28.39 | 36.00 |
| Average price realized ($/BOE) | 55.60 | 79.14 | 69.74 | 77.84 |
| Oil, hedged(3) ($/Bbl) | 75.33 | 89.22 | 85.42 | 89.75 |
| Average price, hedged(3) ($/BOE) | 62.63 | 77.47 | 71.21 | 75.14 |
| Average costs per BOE: | ||||
| Lease operating expenses | $ 9.79 | $ 6.04 | $ 7.79 | $ 7.92 |
| Production and ad valorem taxes | 3.92 | 4.80 | 4.59 | 4.83 |
| Gathering and transportation expense | 0.48 | 0.29 | 0.46 | 0.34 |
| Interest expense | 4.40 | 6.20 | 4.86 | 3.02 |
| General and administrative | 2.65 | 3.99 | 2.99 | 4.13 |
| Depreciation, depletion, and amortization | 22.67 | 24.63 | 23.92 | 24.92 |
| Total | $ 43.92 | $ 45.95 | $ 44.61 | $ 45.16 |
| Components of general and administrative expense: | ||||
| General and administrative - cash component | $ 1.02 | $ 3.65 | $ 1.61 | $ 3.47 |
| General and administrative - Diamondback non-cash stock-based compensation | 1.17 | 0.34 | 1.08 | 0.66 |
| General and administrative - Viper non-cash unit-based compensation | 0.46 | -- | 0.30 | -- |
| (1) Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. | ||||
| (2) The volumes presented are based on actual results and are not calculated using the rounded numbers in the table above. | ||||
| (3) Hedged prices reflect the after effect of our commodity derivative transactions on our average sales prices. Our calculation of such after effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. | ||||
Non-GAAP Financial Measures
Adjusted net income is a non-GAAP financial measure equal to net income attributable to Diamondback Energy, Inc. plus non-cash (gain) loss on derivative instruments, net, (gain) loss on sale of assets, net and related income tax adjustments. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as net income plus non-cash (gain) loss on derivative instruments, net, interest expense, depreciation, depletion and amortization, non-cash stock-based compensation expense, capitalized stock-based compensation expense, asset retirement obligation accretion expense and income tax provision. Adjusted EBITDA is not a measure of net income (loss) as determined by United States' generally accepted accounting principles, or GAAP. Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate the Company's operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company adds the items listed above to net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of the Company's operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. The Company's computations of Adjusted EBITDA and adjusted net income may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts.
The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income.
| Diamondback Energy, Inc. | ||||
| Reconciliation of Adjusted EBITDA to Net Income | ||||
| (unaudited; in thousands) | ||||
|
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||
| 2014 | 2013 | 2014 | 2013 | |
| Net income | $ 99,917 | $ 20,124 | $ 195,971 | $ 54,587 |
| Non-cash (gain) loss on derivative instruments, net | (111,479) | (1,613) | (117,109) | (5,346) |
| Interest expense | 10,425 | 5,950 | 34,515 | 8,059 |
| Depreciation, depletion and amortization | 53,641 | 23,621 | 170,005 | 66,597 |
| Non-cash stock-based compensation expense | 4,108 | 619 | 14,253 | 2,724 |
| Capitalized stock-based compensation expense | (1,329) | (293) | (4,437) | (972) |
| Asset retirement obligation accretion expense | 164 | 67 | 467 | 201 |
| Income tax provision | 56,243 | 11,691 | 108,985 | 31,754 |
| Adjusted EBITDA | $ 111,690 | $ 60,166 | $ 402,650 | $ 157,604 |
| Diamondback Energy, Inc. | ||||
| Adjusted Net Income | ||||
| (unaudited; in thousands, except per share data) | ||||
| Adjusted net income is a performance measure used by management to evaluate performance, prior to non-cash (gain) loss on derivatives, net, (gain) loss on sale of assets, net and related income tax adjustments. | ||||
| The following table presents a reconciliation of adjusted net income to net income: | ||||
|
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||
| 2014 | 2013 | 2014 | 2013 | |
| Net income attributable to Diamondback Energy, Inc. | $ 98,674 | $ 20,124 | $ 193,755 | $ 54,587 |
| Plus: | ||||
| Non-cash (gain) loss on derivative instruments, net | (111,479) | (1,613) | (117,109) | (5,346) |
| (Gain) loss on sale of assets, net | (9) | -- | 1,396 | -- |
| Income tax adjustment for above items | 40,154 | 593 | 41,353 | 1,966 |
| Adjusted net income | $ 27,340 | $ 19,104 | $ 119,395 | $ 51,207 |
| Adjusted net income per common share: | ||||
| Basic | $ 0.48 | $ 0.41 | $ 2.26 | $ 1.22 |
| Diluted | $ 0.48 | $ 0.40 | $ 2.24 | $ 1.21 |
| Weighted average common shares outstanding: | ||||
| Basic | 56,787 | 47,076 | 52,826 | 42,015 |
| Diluted | 57,045 | 47,412 | 53,297 | 42,255 |
|
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||
| 2014 | 2013 | 2014 | 2013 | |
| Net income | $ 99,917 | $ 20,124 | $ 195,971 | $ 54,587 |
| Depreciation, depletion and amortization | 53,641 | 23,621 | 170,005 | 66,597 |
| Deferred income tax provision | 60,225 | 11,500 | 108,985 | 31,563 |
| Excess tax benefit | (749) | (749) | 0 | (749) |
| Accretion expense | 164 | 67 | 467 | 201 |
| Non-cash stock based compensation, net | 4,429 | 326 | 9,816 | 1,752 |
| Non-cash (gain) loss on derivative instruments, net | (111,479) | (1,613) | (117,109) | (5,346) |
| Non-cash interest expense | 620 | 492 | 2,125 | 1,018 |
| Other non-cash operating items | (9) | (8) | 1,396 | (39) |
| Discretionary cash flow | 106,759 | 53,760 | 371,656 | 149,584 |
| Changes in working capital accounts | (2,365) | (11,911) | (15,267) | 6,193 |
| Net cash provided by operating activities | $ 104,394 | $ 41,849 | $ 356,389 | $ 155,777 |
| Discretionary cash flow per share: | ||||
| Basic | $ 1.88 | $ 1.14 | $ 7.04 | $ 3.56 |
| Diluted | $ 1.87 | $ 1.13 | $ 6.97 | $ 3.54 |
| Weighted average common shares outstanding: | ||||
| Basic | 56,787 | 47,076 | 52,826 | 42,015 |
| Diluted | 57,045 | 47,412 | 53,297 | 42,255 |
| Diamondback Energy, Inc. | ||
| Derivatives Information | ||
| (unaudited) | ||
| The table below provides data regarding the details of Diamondback's current price swap contracts through 2015. | ||
| Average Bbls | Average | |
| Oil Swaps | Per Day | Price per Bbl |
| 2015 | ||
| First Quarter-LLS | 6,344 | $ 95.57 |
| First Quarter-WTI | 5,000 | $ 84.10 |
| First Quarter-Brent | 1,000 | $ 88.83 |
| Second Quarter-LLS | 3,330 | $ 91.89 |
| Second Quarter-WTI | 5,000 | $ 84.10 |
| Second Quarter-Brent | 2,000 | $ 88.78 |
| Third Quarter-LLS | 3,000 | $ 90.99 |
| Third Quarter-WTI | 5,000 | $ 84.10 |
| Third Quarter-Brent | 2,000 | $ 88.78 |
| Fourth Quarter-LLS | 3,000 | $ 90.99 |
| Fourth Quarter-WTI | 5,000 | $ 84.10 |
| Fourth Quarter-Brent | 2,000 | $ 88.78 |
| 2015 Average | 10,660 | $ 88.14 |
PV-10
PV-10 is the Company's estimate of the present value of the future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." The Company believes PV-10 to be an important measure for evaluating the relative significance of its oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, the Company believes the use of a pre-tax measure is valuable for evaluating the Company. The Company believes that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.
The following table reconciles PV-10 to the Company's standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.
| (in thousands) | 31-Dec-14 |
| PV-10 | $ 2,322,914 |
| Less income taxes: | |
| Undiscounted future income taxes | ($ 672,380) |
| 10% discount factor | $ 394,689 |
| Future discounted income taxes | ($ 277,691) |
| Standardized measure of discounted future net cash flows | $ 2,045,224 |