HOUSTON, Feb. 23, 2017 (GLOBE NEWSWIRE) -- Carrizo Oil & Gas, Inc. (Nasdaq:CRZO) today announced the Company’s financial results for the fourth quarter of 2016 and provided an operational update, which includes the following highlights:
- Crude oil production of 28,727 Bbls/d, 15% above the fourth quarter of 2015
- Total production of 44,775 Boe/d, 11% above the fourth quarter of 2015
- Loss From Continuing Operations of $0.8 million, or $0.01 per diluted share, and Net Cash Provided by Operating Activities From Continuing Operations of $74.9 million
- Adjusted Net Income of $28.4 million, or $0.44 per diluted share, and Adjusted EBITDA of $118.1 million
- 291% reserve replacement from all sources at a finding, development, and acquisition (FD&A) cost of $13.65 per Boe
- 2017 drilling and completion capital expenditure guidance of $530-$550 million
- 2017 crude oil production growth target of 23%
- Three-year compound annual crude oil production growth target of more than 20%
- Increasing Eagle Ford Shale inventory by more than 10% based on additional successful downspacing pilots
Carrizo reported a fourth quarter of 2016 loss from continuing operations of $0.8 million, or $0.01 per basic and diluted share compared to a loss from continuing operations of $380.7 million, or $6.73 per basic and diluted share in the fourth quarter of 2015. The loss from continuing operations for the fourth quarter of 2016 includes certain items typically excluded from published estimates by the investment community. Adjusted net income, which excludes the impact of these items as described in the non-GAAP reconciliation tables included below, for the fourth quarter of 2016 was $28.4 million, or $0.44 per diluted share, respectively, compared to $18.5 million, or $0.32 per diluted share, respectively, in the fourth quarter of 2015.
For the fourth quarter of 2016, Adjusted EBITDA was $118.1 million, an increase of 5% from the prior year quarter due to higher production volumes and commodity prices. Adjusted EBITDA and the reconciliation to loss from continuing operations are presented in the non-GAAP reconciliation tables included below.
Production volumes during the fourth quarter of 2016 were 4,119 MBoe, or 44,775 Boe/d, an increase of 11% versus the fourth quarter of 2015. The year-over-year production growth was driven by continued strong results from the Company’s Eagle Ford Shale assets as well as a ramp up from its Delaware Basin assets. Oil production during the fourth quarter of 2016 averaged 28,727 Bbls/d, an increase of 15% versus the fourth quarter of 2015; natural gas and NGL production averaged 65,999 Mcf/d and 5,048 Bbls/d, respectively, during the fourth quarter of 2016. Fourth quarter of 2016 production exceeded the high end of Company guidance due primarily to stronger-than-expected performance from the Company’s Eagle Ford Shale and Delaware Basin assets.
Drilling and completion capital expenditures for the fourth quarter of 2016 were $92.0 million. More than 85% of the fourth quarter drilling and completion spending was in the Eagle Ford Shale, with the balance weighted towards the Delaware Basin and Niobrara Formation. Land and seismic expenditures during the quarter were $7.9 million, excluding the previously-announced acquisition from Sanchez Energy Corporation.
For 2017, Carrizo is providing initial drilling and completion capital expenditure guidance of $530-$550 million. This level of spending incorporates an assumed increase in oilfield service costs during the year and should allow the Company to run three rigs in the Eagle Ford as well as continue to develop its acreage in the Delaware Basin. During 2016, Carrizo adjusted its development plan for the Eagle Ford to incorporate even larger pads than it had in prior years, and the Company expects to continue utilizing larger pads going forward. While this is expected to result in a more efficient development of the Company's Eagle Ford assets, it is also likely to result in more uneven production growth on a quarterly basis. The Company's initial land and seismic capital expenditure guidance is $20 million.
Based on this level of activity, Carrizo is providing initial 2017 oil production guidance of 31,400-31,900 Bbls/d. Using the midpoint of this range, the Company’s 2017 oil production growth guidance is 23%. For natural gas and NGLs, Carrizo is providing initial 2017 guidance of 69-73 MMcf/d and 5,600-5,900 Bbls/d, respectively. For the first quarter of 2017, Carrizo expects oil production to be 27,700-28,100 Bbls/d, and natural gas and NGL production to be 72-76 MMcf/d and 4,700-4,900 Bbls/d, respectively. A full summary of Carrizo’s guidance is provided in the attached tables.
Carrizo is also providing guidance on its three-year plan, which is designed to generate strong, economical production growth while also improving the Company's balance sheet. Based on a three-rig program in the Eagle Ford, complemented by activity in the Company's other operating areas, Carrizo expects to deliver a three-year compound annual growth rate of more than 20% for its crude oil production. Based on the current commodity price strip, this plan is also expected to reduce the Company's leverage ratio over the period.
S.P. “Chip” Johnson, IV, Carrizo’s President and CEO, commented on the results, “We finished 2016 with another strong quarter operationally, with production again exceeding our forecast. During the commodity price downturn of the last couple of years our primary focus was on managing our balance sheet, while remaining in a strong operational position that would allow us to quickly re-accelerate production growth as prices improved. And I believe our team did a great job on both fronts. As a result, we recently elected to add a third full-time rig to our Eagle Ford Shale properties, which should drive a crude oil production growth rate for 2017 that is approximately twice the rate we grew last year.
“During 2016, Carrizo once again generated strong reserve growth. Our proved reserves grew by approximately 17% during the year, with the Eagle Ford Shale and Delaware Basin accounting for the majority of the reserve additions. This is despite the SEC crude oil price deck for the year being approximately 15% below the 2015 level.
“We have continued to expand our inventory of de-risked drilling locations in the Eagle Ford Shale. Additional stagger-stack pilots have performed well, so we are moving the stagger stack to development mode in two more areas. We also successfully tested an infill pilot on our LaSalle County acreage, where we saw good performance from the new well as well as a positive response from the offsetting parent wells. As a result of these initiatives, we are increasing our estimate of net de-risked drilling locations in the Eagle Ford Shale to more than 1,200, or 10-15 years of inventory at our current drilling pace.
“We have a deep inventory of high-quality, de-risked drilling locations not just in the Eagle Ford, but in our other areas as well. And we are confident that we will be able to continue to expand our drilling inventory through both organic efforts as well as additional acquisitions. Given this visibility, we're pleased to announce a three-year plan that is expected to deliver a compound annual growth rate of more than 20% for our crude oil production while also reducing our leverage over the period.”
2016 Proved Reserves
The Company’s proved reserves as of December 31, 2016 were 200.2 MMBoe, a 17% increase over year-end 2015, including a record 128.4 MMBbls of crude oil, a 17% increase over year-end 2015. The Company’s PV-10 value was $1.3 billion as of December 31, 2016.
The table below summarizes the Company’s year-end 2016 proved reserves and PV-10 by region as determined by the Company’s independent reservoir engineers, Ryder Scott Company, L.P., in accordance with Securities and Exchange Commission guidelines, using pricing for the twelve months ended December 31, 2016 based on the West Texas Intermediate benchmark crude oil price of $42.75/Bbl and the Henry Hub benchmark natural gas price of $2.49/MMBtu, before adjustment for differentials.
| Crude Oil | NGLs | Natural Gas | Total | PV-10 | ||||||||
| Region | (MMBbl) | (MMBbl) | (Bcf) | (MMBoe) | ($MM) | |||||||
| Eagle Ford | 120.9 | 20.5 | 125.4 | 162.3 | $1,187.8 | |||||||
| Delaware Basin | 4.9 | 2.7 | 24.8 | 11.7 | 37.4 | |||||||
| Niobrara | 2.1 | 0.3 | 2.0 | 2.7 | 24.5 | |||||||
| Marcellus | — | — | 130.9 | 21.8 | 43.5 | |||||||
| Utica | 0.5 | 0.4 | 4.4 | 1.7 | 10.2 | |||||||
| Total | 128.4 | 23.9 | 287.5 | 200.2 | $1,303.4 | |||||||
The table below summarizes the changes in the Company’s proved reserves during 2016.
| Crude Oil | NGLs | Natural Gas | Total | ||||||
| (MMBbl) | (MMBbl) | (Bcf) | (MMBoe) | ||||||
| Proved reserves - December 31, 2015 | 109.6 | 20.2 | 244.9 | 170.6 | |||||
| Revisions of previous estimates | (16.7 | ) | (3.2 | ) | 1.6 | (19.6 | ) | ||
| Extensions and discoveries | 40.1 | 8.6 | 59.3 | 58.6 | |||||
| Purchases of reserves in place | 4.8 | 0.1 | 7.3 | 6.1 | |||||
| Production | (9.4 | ) | (1.8 | ) | (25.6 | ) | (15.5 | ) | |
| Proved reserves - December 31, 2016 | 128.4 | 23.9 | 287.5 | 200.2 | |||||
| Proved developed - December 31, 2016 | 51.1 | 9.4 | 187.1 | 91.6 | |||||
The following table summarizes the Company’s costs incurred in oil and gas property acquisition, exploration, and development activities for the year ended December 31, 2016.
| Total | ||||
| ($MM) | ||||
| Property acquisition costs | ||||
| Proved properties | $90.7 | |||
| Unproved properties | 113.5 | |||
| Total property acquisition costs | 204.2 | |||
| Exploration costs | 37.5 | |||
| Development costs | 374.1 | |||
| Total costs incurred (1) | $615.8 | |||
_________
(1) Total costs incurred includes capitalized general and administrative expense and asset retirement obligations and excludes capitalized interest.
2016 highlights include:
- Total reserve replacement was 291% at an all-sources FD&A cost of $13.65 per Boe
- Drill-bit reserve replacement was 252% at an F&D cost of $10.55 per Boe
- Excluding negative price-related revisions of 6.7 MMBoe, drill-bit reserve replacement was 295% at an F&D cost of $9.01 per Boe
- Eagle Ford reserves increased to 162.3 MMBoe, a 13% increase from the 144.0 MMBoe at year-end 2015
- Crude oil represents 64% of total proved reserves and 86% of the total PV-10 value at December 31, 2016
- Proved developed reserves increased to 91.6 MMBoe at year-end 2016, a 21% increase from the 76.0 MMBoe at year-end 2015
- 46% of total proved reserves at December 31, 2016 are classified as proved developed, compared to 45% at year-end 2015
Operational Update
In the Eagle Ford Shale, Carrizo drilled 23 gross (22.9 net) operated wells during the fourth quarter and completed 14 gross (13.3 net) wells. Crude oil production from the play was approximately 25,100 Bbls/d for the quarter, up 16% versus the prior quarter. At the end of the quarter, Carrizo had 35 gross (33.4 net) operated Eagle Ford wells waiting on completion, equating to net crude oil production potential of more than 12,500 Bbls/d. The Company is currently operating three rigs in the Eagle Ford and expects to drill approximately 107 gross (92 net) operated wells and complete 99 gross (87 net) operated wells in the play during 2017.
Carrizo continues to test multiple initiatives aimed at determining the optimal development spacing on its acreage position, including the Company’s ongoing stagger-stack pilots and a recent infill test. The Company currently has nine stagger-stack pilots on production across its Core acreage position in the Eagle Ford Shale, with these pilots testing effective lateral spacing ranging from 200 ft. to 285 ft. At the RPG project, the Company has four pilots testing 250 ft. effective lateral spacing. Early results from these pilots have been encouraging with production meeting or exceeding production from nearby wells drilled at 330 ft. spacing. At Irvin Ranch, the Company has three pilots testing effective lateral spacing ranging from 200 ft. to 285 ft. Performance from these pilots continues to improve, and Carrizo believes that at a stagger stack development is optimal for this portion of the asset. The Company plans to conduct additional spacing pilots at Irvin Ranch before moving the rest of the potential locations into its de-risked inventory. Carrizo currently has three additional pilots in other core project areas that are currently being drilled and completed.
The Company’s first infill test, the Irvin Ranch 1H, was drilled between two wells that were completed in December 2011 and have produced more than 375 Mbo. The infill well was completed in late 2015, and has produced 75 Mbo to date from a 4,800 ft. lateral. At current well costs and projected EURs, the expected IRR for a similar well is over 80% at current commodity price levels. Additionally, Carrizo observed a positive production response from the parent wells offsetting the Irvin 1H, which produced approximately 15 Mbo of incremental oil after completion of the infill well.
Based on the results from these spacing initiatives, Carrizo is adding more than 120 net locations to its estimate of de-risked inventory in the Eagle Ford Shale. This brings the Company's current estimate of net de-risked locations on its acreage position to more than 1,200 locations.
In addition to conducting spacing optimization tests on its acreage, the Company has also been testing various completion optimization techniques. During 2016, the Company began testing tighter frac stage spacing in its Eagle Ford Shale wells, reducing the stage spacing to 200 ft. from 240 ft. To date, Carrizo has completed 28 wells with the tighter stage spacing, with the tighter stage-spaced wells outperforming the wider stage-spaced wells by approximately 10%. The wells with the tighter stage spacing also appear to minimize the frac interference between the new wells and the offsetting parent wells, which should further enhance the economics of the Company's development program. Based on the success from the 200 ft. stage-spaced wells, the Company is currently testing completions with even tighter stage spacing.
In the Delaware Basin, Carrizo drilled two operated wells during the fourth quarter, both located on the western side of its acreage position. Carrizo currently plans to complete these wells as part of its 2017 program. Crude oil production from the play was more than 1,200 Bbls/d for the quarter, up more than 65% versus the prior quarter. Carrizo currently plans to drill approximately 6 gross (4 net) operated wells and complete 6 gross (5 net) operated wells in the Delaware Basin during 2017.
The Company’s most recent operated completion in the Delaware Basin was the Fortress State 1H, which was brought online late in the third quarter. The well was drilled with an approximate 6,100 ft. lateral and completed with 27 frac stages. The well achieved a peak 30-day rate of 1,520 Boe/d (25% oil, 36% gas, 39% NGL) on a restricted choke. Carrizo operates the Fortress State 1H with a 93% working interest.
In the Niobrara Formation, Carrizo did not drill or complete any operated wells during the fourth quarter. Crude oil production from the play was more than 2,200 Bbls/d for the quarter, up more than 20% from the prior quarter as a result of the Company's completion activity during the third quarter of 2016. Carrizo is not currently budgeting any operated activity in the Niobrara during 2017. However, based on recent improvements in well-level economics, the Company will continue to evaluate resuming operated development activity later in 2017 or in 2018. Carrizo expects to continue participating in non-operated activity within its focus area during 2017.
In Appalachia, which encompasses the Company's Utica Shale and Marcellus Shale positions, Carrizo did not drill or complete any operated wells during the fourth quarter. Oil and condensate production from the Utica was more than 200 Bbls/d during the quarter, down from approximately 250 Bbls/d in the prior quarter due to the lack of activity. In the Marcellus, the Company's production was 35.8 MMcf/d, down from 40.9 MMcf/d in the prior quarter due to significant voluntary production curtailments during October given the extremely weak local market price environment. Carrizo expects to continue to vary its Marcellus production during 2017 based on local market pricing. Carrizo has currently allocated only a minimal amount of maintenance capital to Appalachia during 2017.
Hedging Activity
Carrizo currently has hedges in place for more than 25% of estimated crude oil production for 2017 (based on the midpoint of guidance). For the year, the Company has swaps covering approximately 8,200 Bbls/d of crude oil at an average fixed price of approximately $51.30/Bbl. Additionally, Carrizo has swaps covering 20,000 MMBtu/d for the year at an average fixed price of $3.30/MMBtu. (Please refer to the attached tables for details of the Company’s derivative contracts.)
Conference Call Details
The Company will hold a conference call to discuss 2016 fourth quarter financial results on Thursday, February 23, 2017 at 10:00 AM Central Standard Time. To participate in the call, please dial (888) 225-8168 (U.S. & Canada) or +1 (303) 223-4367 (Intl.) ten minutes before the call is scheduled to begin. A replay of the call will be available through Thursday, March 2, 2017 at 12:00 PM Central Standard Time at (800) 633-8284 (U.S. & Canada) or +1 (402) 977-9140 (Intl.). The reservation number for the replay is 21843646 for U.S., Canadian, and International callers.
A simultaneous webcast of the call may be accessed over the internet by visiting our website at http://www.carrizo.com, clicking on “Upcoming Events”, and then clicking on the “2016 Fourth Quarter and Year-end Conference Call” link. To listen, please go to the website in time to register and install any necessary software. The webcast will be archived for replay on the Carrizo website for 7 days.
Carrizo Oil & Gas, Inc. is a Houston-based energy company actively engaged in the exploration, development, and production of oil and gas from resource plays located in the United States. Our current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas, the Delaware Basin in West Texas, the Niobrara Formation in Colorado, the Utica Shale in Ohio, and the Marcellus Shale in Pennsylvania.
Statements in this release that are not historical facts, including but not limited to those related to capital requirements, capital expenditure and other spending plans, the three-year plan including effects thereof, economical basis of wells or inventory, rig program, effect of transactions offsetting hedge positions, production, average well returns, the estimated production results and financial performance of such properties, effects of transactions, targeted ratios and other metrics, the ability to acquire additional acreage, midstream infrastructure availability and capacity, timing, levels of and potential production, downspacing, crude oil production potential and growth, oil and gas prices, drilling and completion activities, drilling inventory, including timing thereof, resource potential, well costs, breakeven prices, production mix, development plans, growth, midstream matters, use of proceeds, hedging activity, the ability to maintain a sound financial position, the Company’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, results of the Company’s strategies, expected income tax rates and other statements that are not historical facts are forward-looking statements that are based on current expectations. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that these expectations will prove correct. Important factors that could cause actual results to differ materially from those in the forward-looking statements include assumptions regarding well costs, estimated recoveries, pricing and other factors affecting average well returns, the need to obtain board approval of expenditures in the three-year plan, results of wells and testing, failure of actual production to meet expectations, performance of rig operators, spacing test results, availability of gathering systems, costs of oilfield services, actions by governmental authorities, joint venture partners, industry partners, lenders and other third parties, actions by purchasers or sellers of properties, satisfaction of closing conditions and failure of the acquisition to close, purchase price adjustment, integration and effects of acquisitions, market and other conditions, risks regarding financing, capital needs, availability of well connects, capital needs and uses, commodity price changes, effects of the global economy on exploration activity, results of and dependence on exploratory drilling activities, operating risks, right-of-way and other land issues, availability of capital and equipment, weather, and other risks described in the Company’s Form 10-K for the year ended December 31, 2015 and its other filings with the U.S. Securities and Exchange Commission. There can be no assurance any transaction described in this press release will occur on the terms or timing described, or at all.
(Financial Highlights to Follow)
| CARRIZO OIL & GAS, INC. | ||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||
| (In thousands, except share and per share data) | ||||||||
| (Unaudited) | ||||||||
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| Assets | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $4,194 | $42,918 | ||||||
| Accounts receivable, net | 64,208 | 54,721 | ||||||
| Derivative assets | 1,237 | 131,100 | ||||||
| Other current assets | 3,349 | 3,443 | ||||||
| Total current assets | 72,988 | 232,182 | ||||||
| Property and equipment | ||||||||
| Oil and gas properties, full cost method | ||||||||
| Proved properties, net | 1,294,667 | 1,369,151 | ||||||
| Unproved properties, not being amortized | 240,961 | 335,452 | ||||||
| Other property and equipment, net | 10,132 | 12,258 | ||||||
| Total property and equipment, net | 1,545,760 | 1,716,861 | ||||||
| Deferred income taxes | — | 46,758 | ||||||
| Derivative assets | — | 1,115 | ||||||
| Other assets | 7,579 | 10,330 | ||||||
| Total Assets | $1,626,327 | $2,007,246 | ||||||
| Liabilities and Shareholders’ Equity | ||||||||
| Current liabilities | ||||||||
| Accounts payable | $55,631 | $74,065 | ||||||
| Revenues and royalties payable | 38,107 | 67,808 | ||||||
| Accrued capital expenditures | 36,594 | 39,225 | ||||||
| Accrued interest | 22,016 | 21,981 | ||||||
| Accrued lease operating expense | 12,377 | 11,588 | ||||||
| Liabilities of discontinued operations | — | 2,666 | ||||||
| Deferred income taxes | — | 46,758 | ||||||
| Derivative liabilities | 22,601 | — | ||||||
| Other current liabilities | 24,633 | 21,393 | ||||||
| Total current liabilities | 211,959 | 285,484 | ||||||
| Long-term debt | 1,325,418 | 1,236,017 | ||||||
| Liabilities of discontinued operations | — | 1,088 | ||||||
| Asset retirement obligations | 20,848 | 16,183 | ||||||
| Derivative liabilities | 27,528 | 12,648 | ||||||
| Other liabilities | 17,116 | 11,772 | ||||||
| Total liabilities | 1,602,869 | 1,563,192 | ||||||
| Commitments and contingencies | ||||||||
| Shareholders’ equity | ||||||||
| Common stock, $0.01 par value, 90,000,000 shares authorized; 65,132,499 issued and outstanding as of December 31, 2016 and 58,332,993 issued and outstanding as of December 31, 2015 | 651 | 583 | ||||||
| Additional paid-in capital | 1,665,891 | 1,411,081 | ||||||
| Accumulated deficit | (1,643,084 | ) | (967,610 | ) | ||||
| Total shareholders’ equity | 23,458 | 444,054 | ||||||
| Total Liabilities and Shareholders’ Equity | $1,626,327 | $2,007,246 | ||||||
| CARRIZO OIL & GAS, INC. | ||||||||||||||||
| CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||
| (In thousands, except per share data) | ||||||||||||||||
| (Unaudited) | ||||||||||||||||
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Revenues | ||||||||||||||||
| Crude oil | $123,315 | $86,542 | $378,073 | $376,094 | ||||||||||||
| Natural gas liquids | 7,309 | 4,006 | 22,428 | 15,608 | ||||||||||||
| Natural gas | 13,207 | 8,874 | 43,093 | 37,501 | ||||||||||||
| Total revenues | 143,831 | 99,422 | 443,594 | 429,203 | ||||||||||||
| Costs and Expenses | ||||||||||||||||
| Lease operating | 27,646 | 22,748 | 98,717 | 90,052 | ||||||||||||
| Production taxes | 6,106 | 4,370 | 19,046 | 17,683 | ||||||||||||
| Ad valorem taxes | 1,609 | 2,243 | 5,559 | 9,255 | ||||||||||||
| Depreciation, depletion and amortization | 53,470 | 65,577 | 213,962 | 300,035 | ||||||||||||
| General and administrative, net | 15,926 | 12,345 | 74,972 | 67,224 | ||||||||||||
| (Gain) loss on derivatives, net | 19,135 | (56,665 | ) | 49,073 | (99,261 | ) | ||||||||||
| Interest expense, net | 20,490 | 17,792 | 79,403 | 69,195 | ||||||||||||
| Impairment of proved oil and gas properties | — | 411,615 | 576,540 | 1,224,367 | ||||||||||||
| Loss on extinguishment of debt | — | — | — | 38,137 | ||||||||||||
| Other expense, net | 228 | 487 | 1,796 | 11,276 | ||||||||||||
| Total costs and expenses | 144,610 | 480,512 | 1,119,068 | 1,727,963 | ||||||||||||
| Loss From Continuing Operations Before Income Taxes | (779 | ) | (381,090 | ) | (675,474 | ) | (1,298,760 | ) | ||||||||
| Income tax benefit | — | 419 | — | 140,875 | ||||||||||||
| Loss From Continuing Operations | (779 | ) | (380,671 | ) | (675,474 | ) | (1,157,885 | ) | ||||||||
| Income From Discontinued Operations, Net of Income Taxes | — | 506 | — | 2,731 | ||||||||||||
| Net Loss | ($779 | ) | ($380,165 | ) | ($675,474 | ) | ($1,155,154 | ) | ||||||||
| Net Loss Per Common Share - Basic | ||||||||||||||||
| Loss from continuing operations | ($0.01 | ) | ($6.73 | ) | ($11.27 | ) | ($22.50 | ) | ||||||||
| Income from discontinued operations, net of income taxes | — | 0.01 | — | 0.05 | ||||||||||||
| Net loss | ($0.01 | ) | ($6.72 | ) | ($11.27 | ) | ($22.45 | ) | ||||||||
| Net Loss Per Common Share - Diluted | ||||||||||||||||
| Loss from continuing operations | ($0.01 | ) | ($6.73 | ) | ($11.27 | ) | ($22.50 | ) | ||||||||
| Income from discontinued operations, net of income taxes | — | 0.01 | — | 0.05 | ||||||||||||
| Net loss | ($0.01 | ) | ($6.72 | ) | ($11.27 | ) | ($22.45 | ) | ||||||||
| Weighted Average Common Shares Outstanding | ||||||||||||||||
| Basic | 63,587 | 56,544 | 59,932 | 51,457 | ||||||||||||
| Diluted | 63,587 | 56,544 | 59,932 | 51,457 | ||||||||||||
| CARRIZO OIL & GAS, INC. | |||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||||||
| (In thousands) | |||||||||||||||
| (Unaudited) | |||||||||||||||
| Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Cash Flows From Operating Activities | |||||||||||||||
| Net loss | ($779 | ) | ($380,165 | ) | ($675,474 | ) | ($1,155,154 | ) | |||||||
| Income from discontinued operations, net of income taxes | — | (506 | ) | — | (2,731 | ) | |||||||||
| Adjustments to reconcile loss from continuing operations to net cash provided by operating activities from continuing operations | |||||||||||||||
| Depreciation, depletion and amortization | 53,470 | 65,577 | 213,962 | 300,035 | |||||||||||
| Impairment of proved oil and gas properties | — | 411,615 | 576,540 | 1,224,367 | |||||||||||
| (Gain) loss on derivatives, net | 19,135 | (56,665 | ) | 49,073 | (99,261 | ) | |||||||||
| Cash received for derivative settlements, net | 20,549 | 52,387 | 119,369 | 194,296 | |||||||||||
| Loss on extinguishment of debt | — | — | — | 38,137 | |||||||||||
| Stock-based compensation expense, net | 5,252 | 5,526 | 36,086 | 14,729 | |||||||||||
| Deferred income taxes | — | (337 | ) | — | (140,875 | ) | |||||||||
| Non-cash interest expense, net | 1,067 | 725 | 4,172 | 4,289 | |||||||||||
| Other, net | 1,326 | 1,155 | 3,753 | 5,709 | |||||||||||
| Changes in components of working capital and other assets and liabilities- | |||||||||||||||
| Accounts receivable | (14,604 | ) | 2,386 | (12,836 | ) | 29,781 | |||||||||
| Accounts payable | (9,836 | ) | 5,498 | (30,130 | ) | (12,617 | ) | ||||||||
| Accrued liabilities | 16 | (11,903 | ) | (7,938 | ) | (17,517 | ) | ||||||||
| Other assets and liabilities, net | (675 | ) | (777 | ) | (3,809 | ) | (4,453 | ) | |||||||
| Net cash provided by operating activities from continuing operations | 74,921 | 94,516 | 272,768 | 378,735 | |||||||||||
| Net cash used in operating activities from discontinued operations | — | (121 | ) | — | (1,368 | ) | |||||||||
| Net cash provided by operating activities | 74,921 | 94,395 | 272,768 | 377,367 | |||||||||||
| Cash Flows From Investing Activities | |||||||||||||||
| Capital expenditures - oil and gas properties | (134,684 | ) | (134,336 | ) | (480,929 | ) | (675,952 | ) | |||||||
| Acquisitions of oil and gas properties | (153,521 | ) | (1,817 | ) | (153,521 | ) | (1,817 | ) | |||||||
| Proceeds from sales of oil and gas properties, net | 233 | 113 | 15,564 | 8,047 | |||||||||||
| Other, net | (285 | ) | 1,736 | (946 | ) | (3,654 | ) | ||||||||
| Net cash used in investing activities from continuing operations | (288,257 | ) | (134,304 | ) | (619,832 | ) | (673,376 | ) | |||||||
| Net cash used in investing activities from discontinued operations | — | (553 | ) | — | (2,678 | ) | |||||||||
| Net cash used in investing activities | (288,257 | ) | (134,857 | ) | (619,832 | ) | (676,054 | ) | |||||||
| Cash Flows From Financing Activities | |||||||||||||||
| Issuance of senior notes | — | — | — | 650,000 | |||||||||||
| Tender and redemption of senior notes | — | — | — | (626,681 | ) | ||||||||||
| Payment of deferred purchase payment | — | — | — | (150,000 | ) | ||||||||||
| Borrowings under credit agreement | 260,175 | 81,339 | 770,291 | 1,126,860 | |||||||||||
| Repayments of borrowings under credit agreement | (269,175 | ) | (237,829 | ) | (683,291 | ) | (1,126,860 | ) | |||||||
| Payments of debt issuance costs | (180 | ) | (755 | ) | (1,330 | ) | (12,420 | ) | |||||||
| Sale of common stock, net of offering costs | 223,739 | 238,842 | 223,739 | 470,158 | |||||||||||
| Proceeds from stock options exercised | — | — | — | 46 | |||||||||||
| Other, net | (264 | ) | (221 | ) | (1,069 | ) | (336 | ) | |||||||
| Net cash provided by financing activities from continuing operations | 214,295 | 81,376 | 308,340 | 330,767 | |||||||||||
| Net cash provided by financing activities from discontinued operations | — | — | — | — | |||||||||||
| Net cash provided by financing activities | 214,295 | 81,376 | 308,340 | 330,767 | |||||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 959 | 40,914 | (38,724 | ) | 32,080 | ||||||||||
| Cash and Cash Equivalents, Beginning of Period | 3,235 | 2,004 | 42,918 | 10,838 | |||||||||||
| Cash and Cash Equivalents, End of Period | $4,194 | $42,918 | $4,194 | $42,918 | |||||||||||
CARRIZO OIL & GAS, INC.
NON-GAAP FINANCIAL MEASURES
(Unaudited)
Reconciliation of Loss From Continuing Operations (GAAP) to Adjusted Net Income (Non-GAAP)
Adjusted net income is a non-GAAP financial measure which excludes certain items that are included in loss from continuing operations, the most directly comparable GAAP financial measure. Items excluded are those which the Company believes affect the comparability of operating results and typically excluded from published estimates by the investment community, including items whose timing and/or amount cannot be reasonably estimated or are non-recurring.
Adjusted net income is presented because management believes it provides useful additional information to investors for analysis of the Company’s fundamental business on a recurring basis. In addition, management believes that adjusted net income is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.
Adjusted net income should not be considered in isolation or as a substitute for loss from continuing operations or any other measure of a company’s financial performance or profitability presented in accordance with GAAP. A reconciliation of the differences between loss from continuing operations and adjusted net income is presented below. Because adjusted net income excludes some, but not all, items that affect loss from continuing operations and may vary among companies, our calculation of adjusted net income may not be comparable to similarly titled measures of other companies.
Reconciliation of Diluted Weighted Average Common Shares Outstanding (GAAP) to Adjusted Diluted Weighted Average Common Shares Outstanding (Non-GAAP)
Adjusted diluted weighted average common shares outstanding (“Adjusted Diluted WASO”) is a non-GAAP financial measure which includes the effect of potentially dilutive instruments that, under certain circumstances described below, are excluded from diluted weighted average common shares outstanding (“Diluted WASO”), the most directly comparable GAAP financial measure. When a loss from continuing operations exists, all potentially dilutive instruments are anti-dilutive to the loss from continuing operations per common share and therefore excluded from the computation of Diluted WASO. The effect of potentially dilutive instruments are included in the computation of Adjusted Diluted WASO for purposes of computing diluted adjusted net income per common share.
| Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands, except per share data) | |||||||||||||||
| Loss From Continuing Operations (GAAP) | ($779 | ) | ($380,671 | ) | ($675,474 | ) | ($1,157,885 | ) | |||||||
| Income tax benefit | — | 419 | — | 140,875 | |||||||||||
| Loss From Continuing Operations Before Income Taxes | (779 | ) | (381,090 | ) | (675,474 | ) | (1,298,760 | ) | |||||||
| (Gain) loss on derivatives, net | 19,135 | (56,665 | ) | 49,073 | (99,261 | ) | |||||||||
| Cash received for derivative settlements, net | 20,549 | 52,387 | 119,369 | 194,296 | |||||||||||
| Non-cash general and administrative expense, net | 5,025 | 2,018 | 36,009 | 15,794 | |||||||||||
| Impairment of proved oil and gas properties | — | 411,615 | 576,540 | 1,224,367 | |||||||||||
| Loss on extinguishment of debt | — | — | — | 38,137 | |||||||||||
| Other expense, net | 228 | 487 | 618 | 11,276 | |||||||||||
| Adjusted income before income taxes | 44,158 | 28,752 | 106,135 | 85,849 | |||||||||||
| Adjusted income tax expense (1) | (15,720 | ) | (10,263 | ) | (37,784 | ) | (30,648 | ) | |||||||
| Adjusted Net Income (Non-GAAP) | $28,438 | $18,489 | $68,351 | $55,201 | |||||||||||
| Loss From Continuing Operations Per Common Share - Diluted (GAAP) | ($0.01 | ) | ($6.73 | ) | ($11.27 | ) | ($22.50 | ) | |||||||
| Effect of change from diluted WASO to adjusted diluted WASO | — | (0.07 | ) | (0.12 | ) | (0.27 | ) | ||||||||
| Income tax benefit | — | 0.01 | — | 2.70 | |||||||||||
| Loss From Continuing Operations Before Income Taxes | (0.01 | ) | (6.67 | ) | (11.15 | ) | (24.93 | ) | |||||||
| (Gain) loss on derivatives, net | 0.30 | (0.99 | ) | 0.81 | (1.90 | ) | |||||||||
| Cash received for derivative settlements, net | 0.32 | 0.91 | 1.97 | 3.73 | |||||||||||
| Non-cash general and administrative expense, net | 0.08 | 0.03 | 0.60 | 0.30 | |||||||||||
| Impairment of proved oil and gas properties | — | 7.21 | 9.51 | 23.50 | |||||||||||
| Loss on extinguishment of debt | — | — | — | 0.73 | |||||||||||
| Other expense, net | — | 0.01 | 0.01 | 0.22 | |||||||||||
| Adjusted income before income taxes | 0.69 | 0.50 | 1.75 | 1.65 | |||||||||||
| Adjusted income tax expense (1) | (0.25 | ) | (0.18 | ) | (0.62 | ) | (0.59 | ) | |||||||
| Adjusted Net Income Per Common Share - Diluted (Non-GAAP) | $0.44 | $ | 0.32 | $ | 1.13 | $ | 1.06 | ||||||||
| Diluted WASO (GAAP) | 63,587 | 56,544 | 59,932 | 51,457 | |||||||||||
| Effect of potentially dilutive instruments | 717 | 550 | 668 | 648 | |||||||||||
| Adjusted Diluted WASO (Non-GAAP) | 64,304 | 57,094 | 60,600 | 52,105 | |||||||||||
___________
(1) Adjusted income tax expense is calculated by applying the Company’s effective income tax rates applicable to the adjusted income before income taxes which were 35.6% and 35.7% for the years ended December 31, 2016 and 2015, respectively.
CARRIZO OIL & GAS, INC.
NON-GAAP FINANCIAL MEASURES
(Unaudited)
Reconciliation of Loss From Continuing Operations (GAAP) to Adjusted EBITDA (Non-GAAP) to Net Cash Provided by Operating Activities From Continuing Operations (GAAP)
Adjusted EBITDA is a non-GAAP financial measure which excludes certain items that are included in loss from continuing operations, the most directly comparable GAAP financial measure. Items excluded are interest expense, depreciation, depletion and amortization and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or items that are non-recurring.
Adjusted EBITDA is presented because management believes it provides useful additional information to investors and analysts, for analysis of the Company’s financial and operating performance on a recurring basis and the Company's ability to internally generate funds for exploration and development, and to service debt. In addition, management believes that adjusted EBITDA is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.
Adjusted EBITDA should not be considered in isolation or as a substitute for loss from continuing operations, net cash provided by operating activities from continuing operations, or any other measure of a company's profitability, or liquidity measures presented in accordance with GAAP. A reconciliation of loss from continuing operations to adjusted EBITDA to net cash provided by operating activities from continuing operations is presented below. Because adjusted EBITDA excludes some, but not all, items that affect loss from continuing operations, our calculations of adjusted EBITDA may not be comparable to similarly titled measures of other companies.
Reconciliation of Net Cash Provided by Operating Activities From Continuing Operations (GAAP) to Discretionary Cash Flows (Non-GAAP)
Discretionary cash flows is a non-GAAP financial measure which excludes certain items that are included in net cash provided by operating activities from continuing operations, the most directly comparable GAAP financial measure. Items excluded are changes in components of working capital and other items that the Company believes affect the comparability of operating cash flows such as items that are non-recurring.
Discretionary cash flows is presented because management believes it provides useful additional information to investors for analysis of the Company’s ability to generate cash to internally fund exploration and development, and to service debt. In addition, management believes that discretionary cash flows is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.
Discretionary cash flows should not be considered in isolation or as a substitute for net cash provided by operating activities from continuing operations or any other measure of a company’s cash flows or liquidity presented in accordance with GAAP. A reconciliation of net cash provided by operating activities from continuing operations to discretionary cash flows is presented below. Because discretionary cash flows excludes some, but not all, items that affect net cash provided by operating activities from continuing operations and may vary among companies, our calculation of discretionary cash flows may not be comparable to similarly titled measures of other companies.
| Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands) | |||||||||||||||
| Loss From Continuing Operations (GAAP) | ($779 | ) | ($380,671 | ) | ($675,474 | ) | ($1,157,885 | ) | |||||||
| Income tax benefit | — | 419 | — | 140,875 | |||||||||||
| Loss From Continuing Operations Before Income Taxes | (779 | ) | (381,090 | ) | (675,474 | ) | (1,298,760 | ) | |||||||
| Depreciation, depletion and amortization | 53,470 | 65,577 | 213,962 | 300,035 | |||||||||||
| Interest expense, net | 20,490 | 17,792 | 79,403 | 69,195 | |||||||||||
| (Gain) loss on derivatives, net | 19,135 | (56,665 | ) | 49,073 | (99,261 | ) | |||||||||
| Cash received for derivative settlements, net | 20,549 | 52,387 | 119,369 | 194,296 | |||||||||||
| Non-cash general and administrative expense, net | 5,025 | 2,018 | 36,009 | 15,794 | |||||||||||
| Impairment of proved oil and gas properties | — | 411,615 | 576,540 | 1,224,367 | |||||||||||
| Loss on extinguishment of debt | — | — | — | 38,137 | |||||||||||
| Other expense, net | 228 | 487 | 618 | 11,276 | |||||||||||
| Adjusted EBITDA (Non-GAAP) | $118,118 | $112,121 | $399,500 | $455,079 | |||||||||||
| Interest expense, net | (20,490 | ) | (17,792 | ) | (79,403 | ) | (69,195 | ) | |||||||
| Non-cash interest expense, net | 1,067 | 725 | 4,172 | 4,289 | |||||||||||
| Other cash and non-cash adjustments, net | 999 | 26 | 2,986 | (4,658 | ) | ||||||||||
| Discretionary Cash Flows (Non-GAAP) | $99,694 | $95,080 | $327,255 | $385,515 | |||||||||||
| Changes in components of working capital and other | (24,773 | ) | (564 | ) | (54,487 | ) | (6,780 | ) | |||||||
| Net Cash Provided By Operating Activities From Continuing Operations (GAAP) | $74,921 | $94,516 | $272,768 | $378,735 | |||||||||||
CARRIZO OIL & GAS, INC.
NON-GAAP FINANCIAL MEASURES
(Unaudited)
Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)
PV-10 is a non-GAAP financial measure which excludes the present value of future income taxes discounted at 10% per annum, which is included in the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure.
PV-10 is presented because management believes it provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, management believes that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of the Company’s proved reserves to other oil and gas companies.
PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP. A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented below.
| As of December 31, 2016 | ||||
| (in millions) | ||||
| Standardized measure of discounted future net cash flows (GAAP) | $1,303.4 | |||
| Add: present value of future income taxes discounted at 10% per annum (1) | — | |||
| PV-10 (Non-GAAP) | $1,303.4 | |||
____________
(1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company's proved oil and gas reserves as of December 31, 2016.
Reserve Replacement (Non-GAAP)
Reserve replacement is a non-GAAP metric commonly used by the Company, as well as analysts and investors, to evaluate the Company’s ability to replenish annual production and grow its proved reserves. Total reserve replacement and drill-bit reserve replacement can be computed from information provided in this press release.
Total reserve replacement is defined as the sum of proved reserve extensions and discoveries, revisions of previous estimates and purchases of reserves in place divided by production for the corresponding period. Drill-bit reserve replacement is defined as the sum of proved reserve extensions and discoveries and revisions of previous estimates divided by production for the corresponding period. Drill-bit reserve replacement excluding price-related revisions is defined as the sum of proved reserve extensions and discoveries and revisions of previous estimates other than price-related revisions divided by production for the corresponding period. These definitions of reserve replacement may differ significantly from definitions used by other companies to compute similar measures. As a result, reserve replacement as defined above may not be comparable to similar measures provided by other companies.
Reserve replacement is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. Reserve replacement does not distinguish between changes in reserve quantities that are producing and those that will require additional time and capital to begin producing. In addition, since reserve replacement does not take into consideration the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.
Finding and Development Costs (Non-GAAP)
Finding and development ("F&D") costs are non-GAAP metrics commonly used by the Company, as well as analysts and investors, to measure and evaluate the Company’s cost of adding proved reserves. The all sources finding, development, and acquisition (“FD&A”) cost and drill-bit F&D cost can be computed from information provided in this press release.
All sources FD&A cost is defined as the sum of exploration costs, development costs and property acquisition costs divided by the sum of proved reserve extensions and discoveries, revisions of previous estimates and purchases of reserves in place. Drill-bit F&D cost is defined as the sum of exploration costs and development costs divided by the sum of proved reserve extensions and discoveries and revisions of previous estimates. Drill-bit F&D cost excluding price-related revisions is defined as the sum of exploration costs and development costs divided by the sum of proved reserve extensions and discoveries and revisions of previous estimates other than price-related revisions. These definitions of all sources FD&A costs and drill-bit F&D costs may differ significantly from definitions used by other companies to compute similar measures. As a result, the all sources FD&A costs and drill-bit F&D costs defined above may not be comparable to similar measures provided by other companies.
Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, development costs may be recorded in periods after the periods in which the related reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases or decreases in reserves independent of the related cost of such increases.
| CARRIZO OIL & GAS, INC. | ||||||||||||||||
| PRODUCTION VOLUMES AND REALIZED PRICES | ||||||||||||||||
| (Unaudited) | ||||||||||||||||
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Total production volumes - | ||||||||||||||||
| Crude oil (MBbls) | 2,643 | 2,295 | 9,423 | 8,415 | ||||||||||||
| NGLs (MBbls) | 464 | 371 | 1,788 | 1,352 | ||||||||||||
| Natural gas (MMcf) | 6,072 | 6,174 | 25,574 | 21,812 | ||||||||||||
| Total barrels of oil equivalent (MBoe) | 4,119 | 3,695 | 15,473 | 13,402 | ||||||||||||
| Daily production volumes by product - | ||||||||||||||||
| Crude oil (Bbls/d) | 28,727 | 24,942 | 25,745 | 23,054 | ||||||||||||
| NGLs (Bbls/d) | 5,048 | 4,032 | 4,885 | 3,705 | ||||||||||||
| Natural gas (Mcf/d) | 65,999 | 67,110 | 69,873 | 59,758 | ||||||||||||
| Total barrels of oil equivalent (Boe/d) | 44,775 | 40,159 | 42,276 | 36,719 | ||||||||||||
| Daily production volumes by region (Boe/d) - | ||||||||||||||||
| Eagle Ford | 32,339 | 29,058 | 30,664 | 26,377 | ||||||||||||
| Delaware Basin | 2,469 | 250 | 1,115 | 104 | ||||||||||||
| Niobrara | 3,190 | 2,642 | 2,931 | 2,957 | ||||||||||||
| Marcellus | 5,965 | 6,934 | 6,329 | 5,850 | ||||||||||||
| Utica and other | 812 | 1,275 | 1,237 | 1,431 | ||||||||||||
| Total barrels of oil equivalent (Boe/d) | 44,775 | 40,159 | 42,276 | 36,719 | ||||||||||||
| Realized prices - | ||||||||||||||||
| Crude oil ($ per Bbl) | $46.66 | $37.71 | $40.12 | $44.69 | ||||||||||||
| Crude oil ($ per Bbl) - including cash received/paid for derivative settlements, net | $54.43 | $58.11 | $52.80 | $65.67 | ||||||||||||
| NGLs ($ per Bbl) | $15.75 | $10.80 | $12.54 | $11.54 | ||||||||||||
| Natural gas ($ per Mcf) | $2.18 | $1.44 | $1.69 | $1.72 | ||||||||||||
| Natural gas ($ per Mcf) - including cash received/paid for derivative settlements, net | $2.18 | $2.34 | $1.68 | $2.53 | ||||||||||||
| CARRIZO OIL & GAS, INC. | ||||||||||
| COMMODITY DERIVATIVE CONTRACTS - AS OF FEBRUARY 21, 2017 | ||||||||||
| (Unaudited) | ||||||||||
| Crude Oil Derivative Contracts | ||||||||||
| Weighted Average | Weighted Average | |||||||||
| Volume | Floor Price | Ceiling Price | ||||||||
| Period | Type of Contract | (in Bbls/d) | ($/Bbl) | ($/Bbl) | ||||||
| Q1 2017 | Fixed Price Swaps | 12,000 | $50.13 | |||||||
| Q2 2017 | Fixed Price Swaps | 12,000 | $50.13 | |||||||
| Q3 2017 | Fixed Price Swaps | 6,000 | $54.15 | |||||||
| Q4 2017 | Fixed Price Swaps | 3,000 | $55.01 | |||||||
| FY 2018 | Net Sold Call Options | 3,388 | $63.98 | |||||||
| FY 2019 | Net Sold Call Options | 3,875 | $65.98 | |||||||
| FY 2020 | Net Sold Call Options | 4,575 | $67.95 | |||||||
| Natural Gas Derivative Contracts | ||||||||||
| Weighted Average | Weighted Average | |||||||||
| Volume | Floor Price | Ceiling Price | ||||||||
| Period | Type of Contract | (in MMBtu/d) | ($/MMBtu) | ($/MMBtu) | ||||||
| FY 2017 | Fixed Price Swaps | 20,000 | $3.30 | |||||||
| Sold Call Options | 33,000 | $3.00 | ||||||||
| FY 2018 | Sold Call Options | 33,000 | $3.25 | |||||||
| FY 2019 | Sold Call Options | 33,000 | $3.25 | |||||||
| FY 2020 | Sold Call Options | 33,000 | $3.50 | |||||||
| CARRIZO OIL & GAS, INC. | |||||
| FIRST QUARTER AND FULL YEAR 2017 GUIDANCE SUMMARY | |||||
| First Quarter 2017 | Full Year 2017 | ||||
| Daily Production Volumes - | |||||
| Crude oil (Bbls/d) | 27,700 - 28,100 | 31,400 - 31,900 | |||
| NGLs (Bbls/d) | 4,700 - 4,900 | 5,600 - 5,900 | |||
| Natural gas (Mcf/d) | 72,000 - 76,000 | 69,000 - 73,000 | |||
| Total (Boe/d) | 44,400 - 45,667 | 48,500 - 49,967 | |||
| Unhedged Commodity Price Realizations - | |||||
| Crude oil (% of NYMEX oil) | 93.0% - 95.0% | N/A | |||
| NGLs (% of NYMEX oil) | 31.0% - 33.0% | N/A | |||
| Natural gas (% of NYMEX gas) | 68.0% - 73.0% | N/A | |||
| Cash received for derivative settlements, net (in millions) | $0.0 - $2.0 | N/A | |||
| Costs and Expenses - | |||||
| Lease operating ($/Boe) | $6.75 - $7.25 | $6.75 - $7.50 | |||
| Production taxes (% of total revenues) | 4.25% - 4.50% | 4.25% - 4.75% | |||
| Ad valorem taxes (in millions) | $2.7 - $3.2 | $11.0 - $13.0 | |||
| Cash general and administrative, net (in millions) | $16.5 - $20.5 | $47.0 - $51.0 | |||
| DD&A ($/Boe) | $12.75 - $13.75 | $13.50 - $14.50 | |||
| Interest expense, net (in millions) | $20.5 - $21.5 | N/A | |||
| Capitalized Items - | |||||
| Drilling and completion capital expenditures (in millions) | N/A | $530.0 - $550.0 | |||
| Capitalized interest (in millions) | $3.5 - $4.0 | N/A | |||