Attached files
| file | filename |
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| 8-K - 8-K - SILVERBOW RESOURCES, INC. | sfy_8k-07312014.htm |
COMPANY CONTACT: Paul Vincent Director – Finance & Investor Relations (281) 874-2700, (800) 777-2412 | FOR IMMEDIATE RELEASE |
SWIFT ENERGY ANNOUNCES: | |
24% INCREASE IN SECOND QUARTER 2014 PRODUCTION TO 3.45 MILLION BARRELS OF OIL EQUIVALENT;
24% INCREASE IN SECOND QUARTER 2014 ADJUSTED CASH FLOW TO $90.0 MILLION;
20% INCREASE IN SECOND QUARTER 2014 NET INCOME TO $8.0 MILLION, OR $0.18 PER DILUTED SHARE
HOUSTON, July 31, 2014 – Swift Energy Company (NYSE: SFY) announced second quarter 2014 results today including a 24% increase in production, a 24% increase in adjusted cash flow and a 20% increase in net income, when compared to the second quarter of 2013.
Swift Energy’s production increased 24% to 3.45 million barrels of oil equivalent (“MMBoe”) during the second quarter of 2014, when compared to second quarter 2013 production of 2.78 MMBoe, and a 17% increase over first quarter 2014 production of 2.94 MMBoe. This production growth was driven by the Company’s Eagle Ford properties in South Texas, where second quarter 2014 production from the Eagle Ford formation was approximately 26,600 barrels of oil equivalent per day, an increase of approximately 71% compared to second quarter 2013 levels.
The Company’s net income rose by 20% for the second quarter of 2014 to $8.0 million, or $0.18 per diluted share, an increase from the second quarter 2013 net income of $6.7 million, or $0.15 per diluted share, and increased 48% compared to net income of $5.4 million, or $0.12 per diluted share, in the first quarter of 2014.
Included in the determination of second quarter 2014 net income are the following non-recurring items: (i) a loss recorded for a quarter-end, non-cash fair value adjustment associated with the Company’s ongoing price risk management program, (ii) some one-time general and administrative transaction related costs associated with our previously announced Fasken joint venture and (iii) a larger than normal accrual estimate reduction in the quarter’s lease operating expenses. These non-recurring items partially offset each other this quarter and have been appropriately considered in the Company’s forward guidance.
1
Adjusted cash flow (cash flow before working capital changes, a non-GAAP measure - see page 8 for reconciliation to the GAAP measure) for the second quarter of 2014 increased 24% to $90.0 million, compared to $72.8 million for that measure in the second quarter of 2013.
“One of our goals for 2014 is to strategically grow our Eagle Ford production and balance our spending levels with our cash flows,” commented Terry Swift, CEO of Swift Energy. “Our recently closed joint venture transaction for our Eagle Ford Fasken acreage in Webb County has helped us accelerate a significant multi-year development program, achieve a reduction of balance sheet leverage and improve our liquidity position. We’ve also adjusted our oil and gas capital activity levels to be more closely aligned with our anticipated cash flow profile for the remainder of the year.
“The Fasken results provide an excellent example of how our current generation of drilling and completion design can improve field performance. In Fasken, we have grown our Eagle Ford dry gas gross production from 28.3 million cubic feet of gas per day (“MMcf/d”) in the 2nd quarter of 2013 to 103.8 MMcf/d for the 2nd quarter in 2014, a 367% increase. Our professionals applied advanced technology drilling and completion methods to increase our average lateral lengths and sand volumes by 40% and 80% respectively. We also reduced average drilling and completion costs by 40% and drilling times by 20% respectively. The performance results of these new designs have yielded 30 day and 90 day cumulative production increases of 100% and 85% respectively. With the expansion of our Fasken pipeline capacity, we expect to see our firm Fasken take away capacity grow from 75 MMcf/d to 160 MMcf/d in early 2015.
"Another important 2014 goal is to more broadly apply our technical expertise to our existing inventory and enhance our multi-year oil and gas production growth opportunities in the Eagle Ford. We believe our drilling and completion design is a transferable, competitive advantage when exploiting the Eagle Ford shale. The two recent Whitehurst wells, which had an average initial production rate above 3,000 barrels of oil equivalent per day, mark the third distinct operational area where we have applied our current drilling and completion designs to the Eagle Ford and have observed significant improvement in performance as measured by higher initial production rates, larger estimated ultimate reserve recoveries and shallower declines of flowing casing pressure.
“Based on the results of our first half 2014 operational efforts, we are increasing our currently estimated production volumes for the year from a range of 31.5 – 32.3 thousand barrels of oil equivalent per day (“Mboe/d”) to a range of 32.6 – 33.2 Mboe/d. We also believe we can grow our 2015 production to a range of 34.5 – 36.2 Mboe/d and align our anticipated cash flows with our capital investments.”
Second Quarter Revenues and Expenses
Oil and gas sales revenues increased 12% to $158.2 million during the second quarter of 2014, when compared to the second quarter 2013 oil and gas sales revenues of $140.9 million, and a 6% increase over first quarter 2014 oil and gas sales revenues of $148.6 million. Total revenues for the second quarter of 2014 (including a pre-tax loss of $1.2 million for a quarter-end non-cash fair value adjustment associated with the Company’s ongoing price risk management program) increased 9% to $155.7 million when compared to $142.5 million in the second quarter of 2013, and increased 8% compared to $143.7 million in the first quarter 2014.
2
Depreciation, depletion and amortization expense (“DD&A”) of $20.93 per barrel of oil equivalent (“Boe”) in the second quarter of 2014 decreased 2% from $21.40 of DD&A per Boe in the comparable period in 2013 due to increased reserve levels, partially offset by a higher depletable base. On a sequential basis, DD&A per Boe was relatively flat with first quarter 2014 levels.
Lease operating costs, before severance and ad valorem taxes, were $6.36 per Boe in the second quarter 2014, an approximate 34% decrease when compared to $9.70 per Boe incurred in the same period of 2013. While cost savings initiatives are being realized, a portion of this quarter’s large per unit reduction was the result of certain previously estimated accrued lease operating expenses being greater than ultimately incurred, along with higher production volumes for the quarter. On a sequential basis, lease operating costs decreased 26% from $8.58 in the first quarter of 2014.
Transportation and processing expense in the second quarter of 2014 of $1.74 per Boe decreased slightly from $1.75 per Boe in the second quarter of 2013 due primarily to higher levels of natural gas production. On a sequential basis, transportation and processing expense decreased 3% from $1.80 in the first quarter of 2014.
Severance and ad valorem taxes decreased to $2.74 per Boe in the second quarter of 2014 from $3.78 per Boe in the second quarter of 2013 primarily due to a higher percentage of revenues associated with production in Texas, which carries a lower overall severance tax rate (due partially to certain qualified severance tax credits) than Louisiana. On a sequential basis, severance and ad valorem taxes decreased 12% from $3.13 in the first quarter 2014.
General and administrative expenses (which included approximately $1 million in one-time general and administrative transaction related costs associated with the Company’s previously announced Fasken joint venture) still decreased to $3.60 per Boe during the second quarter of 2014, down from $4.03 per Boe in the same period in 2013. Interest expense decreased to $5.41 per Boe in the second quarter of 2014 compared to $6.12 per Boe for the same period in 2013. On a sequential basis, general and administrative expenses decreased 1% from $3.65 per Boe in the first quarter of 2014, while interest expense decreased 14% from $6.27 in the first quarter of 2014.
Second Quarter Pricing
The Company realized an aggregate average price of $45.87 per Boe during second quarter, a decrease from the $50.71 per Boe average price received in the second quarter of 2013 and the $50.45 per BOE average price received in the first quarter of 2014.
In the second quarter of 2014, Swift Energy’s average crude oil prices decreased 1% to $101.67 per barrel from $103.15 per barrel realized in the same period in 2013, but increased 2% compared to the $99.38 per barrel realized in the first quarter of 2014. For the same period, average natural gas prices were $4.16 per thousand cubic feet (“Mcf”), up 8% from the $3.86 per Mcf average price realized a year earlier, but down 1% compared to the $4.20 per Mcf average price realized in the first quarter of 2014. Prices for NGLs averaged $33.93 per barrel in the 2014 second quarter, a 14% increase from second quarter 2013 NGL prices of $29.74 per barrel, but a decrease of 6% compared to $36.27 per barrel for the first quarter of 2014.
3
Second Quarter Drilling Activity
In the second quarter of 2014, Swift Energy drilled 11 operated development wells, all in the Company’s South Texas core Eagle Ford area. In McMullen County, 7 wells were drilled and 4 were drilled in Webb County in the Fasken area.
There are currently two operated rigs drilling in the Company’s South Texas core Eagle Ford area.
Operations Update:
South Texas Operations
In the Company’s South Texas core area, 9 operated wells were completed during the first quarter. In McMullen County, 6 Eagle Ford wells were completed and in Webb County, 3 Eagle Ford wells were completed.
Initial Production Test Rates of South Texas Horizontal Wells
Completed in Second Quarter 2014
(Operated and approximately 100% Working Interest)
Well Name | County/Formation Target | Oil (Bbls/d) | Natural Gas Liquids (Bbls/d) | Residual Natural Gas (MMcf/d) | Barrels of Oil Equivalent | Pressure (psi) | Choke Setting | |||||||
Whitehurst JV EF 3H | McMullen – Eagle Ford | 216 | 1,160 | 9.2 | 2,916 | 5,300 | 24/64” | |||||||
Whitehurst JV EF 4H | McMullen – Eagle Ford | 308 | 1,236 | 9.8 | 3,185 | 5,318 | 24/64” | |||||||
PCQ EF 17H | McMullen – Eagle Ford | 939 | 159 | 1.1 | 1,286 | 3,336 | 20/64” | |||||||
PCQ EF 18H | McMullen – Eagle Ford | 1,062 | 211 | 1.5 | 1,522 | 3,448 | 20/64” | |||||||
Fasken C 17H | Webb – Eagle Ford | -- | -- | 21.4 | 3,571 | 4,292 | 34/64” | |||||||
Fasken C 18H | Webb – Eagle Ford | -- | -- | 20.2 | 3,374 | 4,101 | 34/64” | |||||||
Fasken C 19H | Webb – Eagle Ford | -- | -- | 22.4 | 3,734 | 4,442 | 34/64” | |||||||
PCQ EF 20H | McMullen – Eagle Ford | 936 | 211 | 1.5 | 1,396 | 3,125 | 14/64” | |||||||
PCQ EF 21H | McMullen – Eagle Ford | 1,008 | 167 | 1.2 | 1,371 | 2,846 | 14/64” | |||||||
The Company placed 3 wells on production at its Fasken lease in Webb County during the quarter. The Company has now brought 7 consecutive wells online at Fasken that have exceeded 20 MMcf/d of gas in initial production. The Company is currently completing 4 more wells on this lease.
One well scheduled for completion during the quarter in McMullen County, the PCQ EF 19H, encountered mechanical difficulties and completion operations were suspended. This completion has been rescheduled for 2015.
4
Southeast Louisiana
In the Lake Washington field in Plaquemines Parish, LA, the Company continued its ongoing production optimization program, performing 10 recompletions and 3 production optimization projects during the quarter. The Company plans to conduct 10 additional well recompletions during the second half of 2014 at Lake Washington.
Central Louisiana
The Company continues to work with a prospective buyer for all of its Central Louisiana properties, but it is uncertain when or if this transaction will occur. The Company’s motivation for selling these assets was to reduce short-term debt and improve its liquidity profile, both of which were accomplished with the closing of the previously announced joint venture in its south Texas area. At this point, if no sale of these assets were to occur, the Company anticipates investing a limited amount of capital in 2015 in low risk projects to maintain the value of these assets, while evaluating future alternatives.
Joint Venture Closing
On July 15, 2014, the Company announced it had closed a previously announced joint venture to develop its Fasken Eagle Ford acreage. At closing Swift Energy received approximately $147 million, composed of the initial $125 million cash consideration plus its partner’s share of capital costs, net of revenue, since the January 1, 2014 effective date of the transaction, which capital costs included its partner’s carry of a portion of Swift Energy’s field development costs for that same period. After closing, approximately $38 million remains of its partner’s original $50 million drilling carry obligation, which is expected to be fulfilled by calendar year 2016.
The net proceeds received by Swift Energy in this transaction have been used initially to reduce the amount of borrowings under the Company’s credit facility and ultimately a portion of the proceeds will be used to fund accelerated development of its Eagle Ford shale properties.
Price Risk Management
Swift Energy has entered into hedging transactions for the remainder of 2014 covering 7.8 Bcf of natural gas production and approximately 0.1 MMbbls of crude oil production. On an ongoing basis, details of Swift Energy’s complete price risk management activities can be found on the Company’s website (www.swiftenergy.com).
Earnings Conference Call
Swift Energy will conduct a live conference call today, July 31, at 10:00 a.m. EDT to discuss second quarter 2014 financial results and third quarter and full-year 2014 financial and operational guidance. To participate in this conference call, dial 973-339-3086 five to ten minutes before the scheduled start time and indicate your intention to participate in the Swift Energy conference call. A digital replay of the call will be available later on July 31 until August 6, by dialing 855-859-2056 and using Conference ID # 61082965. Additionally, the conference call will be available over the Internet by accessing the Company’s website at www.swiftenergy.com and by clicking on the event hyperlink. This webcast will be available online and archived at the Company’s website.
5
About Forward Looking Statements
This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The opinions, forecasts, projections, guidance or other statements contained herein, other than statements of historical fact, are forward-looking statements, including guidance estimates for the third quarter and second half of 2014. These statements are based upon assumptions that are subject to change and to risks, especially the uncertainty and costs of finding, replacing, developing and acquiring reserves, availability and cost of capital, labor, services, supplies and facility capacity, hurricanes or tropical storms disrupting operations, and, volatility in oil or gas prices, uncertainty and costs of finding, replacing, developing or acquiring reserves, and disruption of operations. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Certain risks and uncertainties inherent in the Company’s business are set forth in the filings of the Company with the Securities and Exchange Commission. Estimates of future financial or operating performance provided by the Company are based on existing market conditions and engineering and geologic information available at this time. Actual financial and operating performance may be higher or lower. Future performance is dependent upon oil and gas prices, exploratory and development drilling results, engineering and geologic information and changes in market conditions.
6
SWIFT ENERGY COMPANY
SUMMARY FINANCIAL INFORMATION
(Unaudited)
SUMMARY FINANCIAL INFORMATION
(Unaudited)
(In Thousands Except Per Share and Price Amounts)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
2014 | 2013 | Percent Change | 2014 | 2013 | Percent Change | |||||||||||||
Revenues: | ||||||||||||||||||
Oil & Gas Sales | $ | 158,214 | $ | 140,892 | 12 | % | $ | 306,772 | $ | 287,369 | 7 | % | ||||||
Other | (2,493) | 1,574 | (7,370) | 1,334 | ||||||||||||||
Total Revenue | $ | 155,721 | $ | 142,466 | 9 | % | $ | 299,402 | $ | 288,703 | 4 | % | ||||||
Net Income | $ | 8,038 | $ | 6,722 | 20 | % | $ | 13,451 | $ | 13,931 | (3) | % | ||||||
Basic EPS | $ | 0.18 | $ | 0.15 | 20 | % | $ | 0.31 | $ | 0.32 | (3) | % | ||||||
Diluted EPS | $ | 0.18 | $ | 0.15 | 20 | % | $ | 0.30 | $ | 0.32 | (6) | % | ||||||
Net Cash Provided By Operating Activities | $ | 100,604 | $ | 87,308 | 15 | % | $ | 170,303 | $ | 149,531 | 15 | % | ||||||
Cash Flow Before Working Capital Changes(1) (non-GAAP measure) | $ | 89,955 | $ | 72,795 | 24 | % | $ | 163,525 | $ | 145,427 | 12 | % | ||||||
Weighted Average Shares Outstanding (Basic) | 43,826 | 43,369 | (1) | % | 43,727 | 43,268 | (1) | % | ||||||||||
Weighted Average Shares Outstanding (Diluted) | 44,312 | 43,612 | (2) | % | 44,215 | 43,599 | (1) | % | ||||||||||
EBITDA (non-GAAP measure) | $ | 105,928 | $ | 88,952 | 19 | % | $ | 199,109 | $ | 179,235 | 11 | % | ||||||
Production (MMBoe) | 3.45 | 2.78 | 24 | % | 6.39 | 5.60 | 14 | % | ||||||||||
Realized Price ($/Boe) | $ | 45.87 | $ | 50.71 | (10) | % | $ | 47.98 | $ | 51.34 | (7) | % | ||||||
(1) | See reconciliation on page 8. Management believes that the non-GAAP measures EBITDA and cash flow before working capital changes are useful information to investors because they are widely used by professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. Many investors use the published research of these analysts in making their investment decisions. |
7
SWIFT ENERGY COMPANY
RECONCILIATION OF GAAP(a) TO NON-GAAP MEASURES
(Unaudited)
(In Thousands)
Three Months Ended | ||||||||||
June 30, 2014 | June 30, 2013 | Percent Change | ||||||||
CASH FLOW RECONCILIATIONS: | ||||||||||
Net Cash Provided by Operating Activities | $100,604 | $87,308 | 15 | % | ||||||
Increases and Decreases In: | ||||||||||
Accounts Receivable | (4,467) | (5,792) | ||||||||
Accounts Payable and Accrued Liabilities | 2,033 | (520) | ||||||||
Income Taxes Payable | 150 | 178 | ||||||||
Accrued Interest | (8,365) | (8,379) | ||||||||
Cash Flow Before Working Capital Changes | $89,955 | $72,795 | 24 | % | ||||||
INCOME TO EBITDA RECONCILIATIONS: | ||||||||||
Net Income | $8,038 | $6,722 | 20 | % | ||||||
Provision for Income Taxes | 5,621 | 4,293 | ||||||||
Interest Expense, Net | 18,649 | 17,000 | ||||||||
Depreciation, Depletion & Amortization & ARO (b) | 73,620 | 60,937 | ||||||||
EBITDA | $105,928 | $88,952 | 19 | % | ||||||
Six Months Ended | ||||||||||
June 30, 2014 | June 30, 2013 | Percent Change | ||||||||
CASH FLOW RECONCILIATIONS: | ||||||||||
Net Cash Provided by Operating Activities | $170,303 | $149,531 | 15 | % | ||||||
Increases and Decreases In: | ||||||||||
Accounts Receivable | (2,132) | (601) | ||||||||
Accounts Payable and Accrued Liabilities | (4,852) | (3,605) | ||||||||
Income Taxes Payable | 150 | 178 | ||||||||
Accrued Interest | 56 | (76) | ||||||||
Cash Flow Before Working Capital Changes | $163,525 | $145,427 | 12 | % | ||||||
INCOME TO EBITDA RECONCILIATIONS: | ||||||||||
Net Income | $13,451 | $13,931 | (3 | )% | ||||||
Provision for Income Taxes | 11,869 | 8,670 | ||||||||
Interest Expense, Net | 37,098 | 33,802 | ||||||||
Depreciation, Depletion & Amortization & ARO (b) | 136,691 | 122,832 | ||||||||
EBITDA | $199,109 | $179,235 | 11 | % | ||||||
(a) | GAAP—Generally Accepted Accounting Principles |
(b) | Includes accretion of asset retirement obligation |
Note: Items may not total due to rounding
8
SWIFT ENERGY COMPANY
SUMMARY BALANCE SHEET INFORMATION
(Unaudited)
(In Thousands)
As of June 30, 2014 | As of December 31, 2013 | ||||||
Assets: | |||||||
Current Assets: | |||||||
Cash and Cash Equivalents | $564 | $3,277 | |||||
Other Current Assets | 94,477 | 83,471 | |||||
Total Current Assets | 95,041 | 86,748 | |||||
Oil and Gas Properties | 5,881,057 | 5,671,731 | |||||
Other Fixed Assets | 42,400 | 42,368 | |||||
Less-Accumulated DD&A | (3,308,992) | (3,174,453) | |||||
Total Properties | 2,614,465 | 2,539,646 | |||||
Other Assets | 15,030 | 17,199 | |||||
$2,724,536 | $2,643,593 | ||||||
Liabilities: | |||||||
Current Liabilities | $187,007 | $177,076 | |||||
Long-Term Debt | 1,178,301 | 1,142,368 | |||||
Deferred Income Taxes | 229,107 | 217,384 | |||||
Asset Retirement Obligation | 65,963 | 63,225 | |||||
Other Long-term Liabilities | 9,695 | 10,324 | |||||
Stockholders’ Equity | 1,054,463 | 1,033,216 | |||||
$2,724,536 | $2,643,593 | ||||||
Note: Items may not total due to rounding
9
SWIFT ENERGY COMPANY
SUMMARY INCOME STATEMENT INFORMATION
(Unaudited)
In Thousands Except Per Boe Amounts
Three Months Ended | Six Months Ended | |||||||||||||||||||||||||
June 30, 2014 | Per Boe | June 30, 2014 | Per Boe | |||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||
Oil & Gas Sales | $ | 158,214 | $ | 45.87 | $ | 306,772 | $47.98 | |||||||||||||||||||
Other Revenue | (2,493) | (7,370) | ||||||||||||||||||||||||
155,721 | 45.15 | 299,402 | 46.83 | |||||||||||||||||||||||
Costs and Expenses: | ||||||||||||||||||||||||||
General and Administrative, net | 12,412 | 3.60 | 23,151 | 3.62 | ||||||||||||||||||||||
Depreciation, Depletion & Amortization | 72,205 | 20.93 | 133,890 | 20.94 | ||||||||||||||||||||||
Accretion of Asset Retirement Obligation (ARO) | 1,415 | 0.41 | 2,801 | 0.44 | ||||||||||||||||||||||
Lease Operating Costs | 21,932 | 6.36 | 47,199 | 7.38 | ||||||||||||||||||||||
Transportation and Processing Expense | 6,013 | 1.74 | 11,305 | 1.77 | ||||||||||||||||||||||
Severance & Other Taxes | 9,436 | 2.74 | 18,638 | 2.92 | ||||||||||||||||||||||
Interest Expense, Net | 18,649 | 5.41 | 37,098 | 5.80 | ||||||||||||||||||||||
Total Costs & Expenses | 142,062 | 41.19 | 274,082 | 42.87 | ||||||||||||||||||||||
Income Before Income Taxes | 13,659 | 3.96 | 25,320 | 3.96 | ||||||||||||||||||||||
Provision for Income Taxes | 5,621 | 1.63 | 11,869 | 1.86 | ||||||||||||||||||||||
Net Income | $ | 8,038 | $ | 2.33 | $ | 13,451 | $2.10 | |||||||||||||||||||
Additional Information: | ||||||||||||||||||||||||||
Total Capital Expenditures | $ | 110,152 | $ | 209,358 | ||||||||||||||||||||||
Capitalized General & Administrative | $ | 6,925 | $ | 14,051 | ||||||||||||||||||||||
Capitalized Interest Expense | $ | 1,203 | $ | 2,480 | ||||||||||||||||||||||
Deferred Income Tax | $ | 5,621 | $ | 11,869 | ||||||||||||||||||||||
Note: Items may not total due to rounding
10
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOW
(Unaudited)
(In Thousands)
Six Months Ended | |||||||
June 30, 2014 | June 30, 2013 | ||||||
Cash Flows From Operating Activities: | |||||||
Net Income | $13,451 | $13,931 | |||||
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities - | |||||||
Depreciation, Depletion, and Amortization | 133,890 | 119,578 | |||||
Accretion of Asset Retirement Obligation (ARO) | 2,801 | 3,254 | |||||
Deferred Income Taxes | 11,869 | 8,670 | |||||
Stock Based Compensation Expense | 3,953 | 6,018 | |||||
Other | (2,439) | (6,024) | |||||
Change in Assets and Liabilities - | |||||||
Decrease in Accounts Receivable | 2,132 | 601 | |||||
Increase/(Decrease) in Accounts Payable and Accrued Liabilities | 4,852 | 3,605 | |||||
Decrease in Income Taxes Payable | (150) | (178) | |||||
Increase in Accrued Interest | (56) | 76 | |||||
Net Cash Provided by Operating Activities | 170,303 | 149,531 | |||||
Cash Flows From Investing Activities: | |||||||
Additions to Property and Equipment | (208,979) | (265,317) | |||||
Proceeds from the Sale of Property and Equipment | 35 | 6,841 | |||||
Net Cash Used in Investing Activities | (208,944) | (258,476) | |||||
Cash Flows From Financing Activities: | |||||||
Net Proceeds From Bank Borrowings | 36,000 | 120,600 | |||||
Net Proceeds From Issuance of Common Stock | 824 | 946 | |||||
Purchase of Treasury Shares | (896) | (1,433) | |||||
Net Cash Provided by (Used in) Financing Activities | 35,298 | 120,113 | |||||
Net Increase/(Decrease) in Cash and Cash Equivalents | (2,713) | 11,168 | |||||
Cash and Cash Equivalents at the Beginning of the Period | 3,277 | 170 | |||||
Cash and Cash Equivalents at the End of the Period | $564 | $11,338 | |||||
11
SWIFT ENERGY COMPANY
OPERATIONAL INFORMATION
QUARTERLY COMPARISON -- SEQUENTIAL & YEAR-OVER-YEAR
(Unaudited)
Three Months Ended | Three Months Ended | ||||||||||||||||
June 30, 2014 | March 31, 2014 | Percent Change | June 30, 2013 | Percent Change | |||||||||||||
Production : | |||||||||||||||||
Oil & Natural Gas Equivalent (MBoe) | 3,449 | 2,944 | 17 | % | 2,778 | 24 | % | ||||||||||
Natural Gas (Bcf) | 12.75 | 9.21 | 38 | % | 7.91 | 61 | % | ||||||||||
Crude Oil (MBbl) | 890 | 931 | (4 | )% | 911 | (2 | )% | ||||||||||
NGL (MBbl) | 434 | 478 | (9 | )% | 549 | (21 | )% | ||||||||||
Average Prices: | |||||||||||||||||
Combined Oil & Natural Gas ($/Boe) | $45.87 | $50.45 | (9 | )% | $50.71 | (10 | )% | ||||||||||
Natural Gas ($/Mcf) | $4.16 | $4.20 | (1 | )% | $3.86 | 8 | % | ||||||||||
Crude Oil ($/Bbl) | $101.67 | $99.38 | 2 | % | $103.15 | (1 | )% | ||||||||||
NGL ($/Bbl) | $33.93 | $36.27 | (6 | )% | $29.74 | 14 | % | ||||||||||
12
SWIFT ENERGY COMPANY
THIRD QUARTER AND FULL YEAR 2014
GUIDANCE ESTIMATES
Actual For Second Quarter 2014 | Guidance For Third Quarter 2014 | Guidance For Full Year 2014 | ||||||||||
Production Volumes (MMBoe) | 3.45 | 2.79 | - | 2.84 | 11.9 | - | 12.1 | |||||
Production Mix: | ||||||||||||
Natural Gas (Bcf) | 12.75 | 9.08 | - | 9.24 | 40.4 | - | 41.1 | |||||
Crude Oil (MMBbl) | 0.89 | 0.88 | - | 0.90 | 3.49 | - | 3.55 | |||||
Natural Gas Liquids (MMBbl) | 0.43 | 0.39 | - | 0.41 | 1.68 | - | 1.70 | |||||
Product Pricing (Note 1): | ||||||||||||
Natural Gas (per Mcf) | ||||||||||||
NYMEX Differential (Note 2) | ($0.50) | ($0.25) | - | ($0.50) | ($0.30) | - | ($0.55) | |||||
Crude Oil (per Bbl) | ||||||||||||
NYMEX differential (Note 3) | ($1.32) | ($5.00) | - | --- | ($4.00) | - | $1.00 | |||||
NGL (per Bbl) | ||||||||||||
Percent of NYMEX Crude | 33% | 25% | - | 30% | 30% | - | 35% | |||||
Oil & Gas Production Costs: | ||||||||||||
Lease Operating Costs (per Boe) | $6.36 | $8.90 | - | $9.15 | $8.15 | - | $8.40 | |||||
Transportation and Processing (per Boe) | $1.74 | $2.30 | $2.40 | $2.05 | $2.15 | |||||||
Severance & Ad Valorem Taxes (as % of Revenue dollars) | 6.0% | 7.0% | - | 8.0% | 7.0% | - | 8.0% | |||||
Other Costs: | ||||||||||||
G&A per Boe | $3.60 | $3.60 | - | $3.85 | $3.60 | - | $3.80 | |||||
Interest Expense per Boe | $5.41 | $6.45 | - | $6.60 | $6.10 | - | $6.25 | |||||
DD&A per Boe | $20.93 | $23.00 | - | $23.25 | $22.00 | - | $22.25 | |||||
Supplemental Information: | ||||||||||||
Capital Expenditures (in Thousands) | ||||||||||||
Operations | $102,024 | $96,700 | - | $105,300 | $341,500 | - | $362,000 | |||||
Capitalized G&A | $6,925 | $7,000 | - | $8,000 | $28,000 | - | $31,000 | |||||
Capitalized Interest | $1,203 | $1,300 | - | $1,700 | $5,500 | - | $7,000 | |||||
Total Capital Expenditures | $110,152 | $105,000 | - | $115,000 | $375,000 | - | $400,000 | |||||
Acquisitions/(Dispositions), net | --- | ($144,000) | - | ($146,000) | ($144,000) | - | ($146,000) | |||||
Basic Weighted Average Shares | 43,826 | 43,800 | - | 43,900 | 43,800 | - | 43,900 | |||||
Diluted Weighted Average Shares | 44,312 | 44,300 | - | 44,400 | 44,300 | - | 44,400 | |||||
Effective Tax Rate | 41.2% | 39.0% | - | 42.0% | 39.0% | - | 42.0% | |||||
Deferred Tax Percentage | 100% | 98% | - | 100% | 98% | - | 100% | |||||
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Note 1: | Swift Energy maintains all its current price risk management instruments (hedge positions) on its Hedge Activity page on the Swift Energy website (www.swiftenergy.com). |
Note 2: | Average of monthly closing Henry Hub NYMEX futures price for the respective contract months, included in the period, which best benchmarks the 30-day price received for natural gas sales. |
Note 3: | Average of daily WTI NYMEX futures price during the calendar period reflected, which best benchmarks the daily price received for the majority of crude oil sales. |
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