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Warren Resources Announces Third Quarter 2014 Financial and Operating Results

  • Total Revenue Increases 17% to $40.5 Million
  • Production Increases 116% to approximately 7.1 Bcfe
  • Lease Operating Expense and Taxes per Mcfe Declines 33%

NEW YORK, Nov. 4, 2014 (GLOBE NEWSWIRE) -- Warren Resources, Inc. (Nasdaq:WRES) today reported its third quarter 2014 financial and operating results. Warren reported net income of $3.7 million, or $0.05 per basic and diluted share, compared to net income of $14.7 million, or $0.20 per basic and diluted share for the third quarter of 2013.

The Company's financial results in the third quarter of 2014 were impacted by $3.7 million of unrealized gains on hedges, a $1.1 million positive accounting adjustment to G&A for lower litigation expenses than previously accrued for, and $4.1 million of one-time acquisition expenses related to the Marcellus acquisition. Results in the third quarter of 2013 were impacted by $1.0 million of unrealized losses on hedges and a $5.3 million gain resulting from an adjustment to recapture certain previously undercharged post production costs.

Warren's adjusted net income* for the third quarter of 2014 was $3.0 million, or $0.04 per diluted share, compared to adjusted net income of $10.4 million, or $0.14 per diluted share, for the third quarter of 2013.

In addition, Warren's EBITDA* for the third quarter of 2014 was $23.4 million, compared to EBITDA of $26.4 million for the third quarter of 2013.

Warren's cash flow from operations in the third quarter of 2014 was $19.0 million, compared to $25.7 million in the third quarter of 2013. The Company's discretionary cash flow* (excluding the impact of changes in working capital) in the third quarter of 2014 was $17.4 million, compared to $27.5 million for the third quarter of 2013.

In announcing the results, Philip A. Epstein, Chairman and Chief Executive Officer, commented, "We are pleased to announce our third quarter results, which benefitted from the integration of our Marcellus assets which we acquired in August, 2014. The Marcellus assets are outperforming expectations, which allows us to increase our full year 2014 natural gas guidance by 7%. The new employees who joined as part of the Marcellus acquisition have hit the ground running and are closely collaborating with their colleagues to drive growth at Warren. We plan to complete three Marcellus wells in the 4th quarter and will commence our Marcellus drilling program, which will include testing the Upper Marcellus, late fourth quarter 2014.

"While there has been significant volatility in energy commodity prices and capital markets, Warren has over $100 million of liquidity and will continue to focus on growth within cash flow. Warren is well positioned to ride-out market fluctuations while maintaining financial flexibility to execute on attractive growth opportunities. Following our large Marcellus acquisition, Warren adjusted its 2014 capital allocations by scaling back our Wyoming CBM drilling program from 50 to 33 wells, which allows us to further emphasize cash flow growth on high return assets and positions the Company for even stronger growth into 2015."

* Please refer to the section titled "Explanation and Reconciliation of Non-GAAP Financial Measures" at the end of this release for additional information on non-GAAP measures including adjusted net income, discretionary cash flow and EBITDA.

Third Quarter of 2014 Results

Warren's oil and gas revenues increased 13% to $39.2 million in the third quarter of 2014, compared to $34.7 million in the third quarter of 2013. This primarily resulted from a 116% increase in production volumes in the third quarter of 2014 compared to the third quarter of 2013.

Warren produced approximately 268,000 barrels of oil in the quarter ended September 30, 2014, compared to approximately 294,000 barrels of oil in the third quarter of 2013. Oil production in the third quarter of 2014 was negatively impacted by 58 days of infrastructure downtime in the North Wilmington Unit, or "NWU", which curtailed production by an average of approximately 290 Bbl/d in the quarter.

In the third quarter of 2014, Warren produced approximately 5.5 net billion cubic feet ("Bcf") of natural gas, compared to approximately 1.5 net Bcf of natural gas in the third quarter of 2013. The production growth is primarily attributable to the Company's recently acquired Marcellus assets.

The average realized price per barrel of oil was $89.77 in the third quarter of 2014 compared to $99.96 in the third quarter of 2013. The average realized price per thousand cubic feet ("Mcf") of natural gas was $2.73 for the third quarter of 2014 compared to $3.41 for the third quarter of 2013. These realized commodity prices exclude the effect of derivatives and hedging activities.

The net gain on derivative financial instruments was $3.7 million during the three months ended September 30, 2014, comprised of a $3.7 million unrealized mark-to-market, non-cash gain on oil and gas commodity price derivatives.

Total operating expenses were $36.7 million during the third quarter of 2014, compared to $23.4 million during the third quarter of 2013. The increase was primarily due to $4.1 million of one-time acquisition expenses, increased operating activity and higher production volumes. Total operating expenses on a per barrel of oil equivalent ("Boe") basis were $30.83 per Boe in the third quarter of 2014, 27% lower than the $42.30 per Boe in the same period in 2013.

Interest expense increased to $3.8 million in the third quarter of 2014 compared to $0.8 million in the same period last year. The increase was primarily due to additional interest expense from the $300 million of 9% Senior Notes issued during the third quarter of 2014.

Impact of Purchase Price Accounting and Pro Forma Estimates

Warren closed on the acquisition of Marcellus assets from Citrus Energy on August 11th, 2014, with an economic effective date of July 1, 2014. Accordingly, due to U.S. GAAP accounting rules, approximately $7.8 million of income from operations the Marcellus assets generated during the period from July 1st through August 10th are not reflected in the Company's statement of operations in the third quarter. Pursuant to U.S. GAAP accounting it was recorded as an adjustment to the purchase price of the assets and the impact is reflected on the Company's balance sheet in oil and gas properties.

Similarly, Warren's net production in the third quarter does not include 3.6 Bcf generated by the Marcellus assets from July 1st through August 10th.

Operational Update

Marcellus, Pennsylvania

Warren's Marcellus assets have continued to perform strongly, with production from all producing wells outperforming their type curves. Net production in the Marcellus, including production volumes from July 1st through August 10th, averaged 81.1 MMcf/d in the third quarter, 28% better than projected.

Drilling activity in the Marcellus is expected to commence late in the fourth quarter, slightly later than previously anticipated, which will push the drilling of three planned wells into early 2015. Warren continues to expect the commencement of completion operations on three previously drilled wells and to initiate drilling on one additional well in the fourth quarter. Initial sales from the wells completed in the fourth quarter are expected to start in the first quarter of 2015.

With the capital budgeted for drilling three wells now shifted into 2015, capital expenditures in the Marcellus are projected to total $10.3 million for the full year 2014.

Going forward, Warren plans to maintain a one rig drilling program on average in the Marcellus, which is expected to drive continued production growth while maximizing capital efficiency.

Wilmington Field, California

In the Wilmington field, operations overcame headwinds related to infrastructure constraints and maintenance in the third quarter. Despite these challenges production held up well, with average net production for the third quarter of 2,912 barrels of oil per day ("BOPD").

In July, Warren repaired gathering and pipeline infrastructure in the NWU. This required production curtailments for approximately 58 days during repair work and the gradual restoration of full production following completion of the repairs. In keeping with Warren's focus on safety, the Company pursued a more cautious and measured approach to restore and increase production volumes. The repair work and subsequent restoration of production volumes to prior levels was slightly slower than previously projected, lowering net oil production in the third quarter by an estimated 17,000 Bbls, or an average of 290 BOPD. The gathering line has now been fully tested and there are no current production curtailments.

Further upgrades to the infrastructure in the NWU are planned to increase water injection beyond the current 20,000 Bbls per day and enable production volumes to grow more quickly. The planned upgrades to the facilities will be taken into account when designing the 2015 drilling program.

Warren drilled and completed a total of twelve new wells in the Wilmington field during the third quarter, six at the Wilmington Townlot Unit, or "WTU", and six at the NWU.

At the WTU, Warren drilled one Tar producer, two Ranger producers, two Ford producers and one Ford injector. The thirty day average initial production rate of the new Tar well was 162 BOPD and the two new Ranger wells had initial thirty day average rates of 36 BOPD and 17 BOPD, respectively. The second Ranger well has not yet seen uplift from injector support that is currently being drilled and is expected to come online in the fourth quarter. One of the new Ford wells had a thirty day average production rate of 84 BOPD. The second Ford well has not yet established a 30 day production rate.

At the NWU, Warren drilled three producers and three injectors in the Ranger formation. The three new Ranger producer wells had a thirty day average initial production rate of 42 BOPD. The initial production rates of these wells were impacted by a lack of water injection support due to the gathering and pipeline repairs in the third quarter. Production performance of the wells is expected to benefit from improved injection support going forward.

Subsequent to the end of the third quarter, Warren drilled one Ranger producer and one Ranger injector in the WTU. In the NWU, the Company has drilled one Ranger producer and two Ranger injectors subsequent to September 30th. The producer wells are expected to commence production in the fourth quarter.

Third quarter capital expenditures for the Wilmington Field were $25.7 million. These capital expenditures consisted of $23.8 million for drilling and development operations and $1.9 million for facilities improvements, infrastructure costs and other related items.

Warren modified its 2014 drilling plan in the Wilmington field to drill three additional wells and increase the mix of NWU wells. The initial 2014 drilling program planned for 22 wells (17 producers and 5 injectors) to be drilled in the WTU and 11 wells in the NWU (6 producers and 5 injectors). The revised plan removed 2 producers from the WTU program and added 5 additional wells to the NWU (2 producers and 3 injectors). The revision in the Wilmington drilling plan was primarily due to the reallocation of the rig originally planned to move to Leroy Pine, which had the additional benefit of reducing expenditures and downtime associated with moving the rig.

Leroy Pine Project, California

Completion and workover operations were conducted in the third quarter on two of the three wells previously drilled in 2013, the Leroy 1 and Leroy 2 wells. Initial pressure data and production rates from the wells were encouraging, but due to high water production, the wells did not achieve economic rates of return that Warren views as competitive with the other assets in its portfolio.

The Company is analyzing the data collected during drilling and completion operations, as well as the results of offset operators, to re-evaluate its completion methodology to lower water cuts. In the interim, Warren is reallocating its capital toward higher rate of return projects and reducing activity in the Leroy Pine Project until further evaluation is complete and other strategic initiatives are fully considered. As a result, Warren is cutting its Leroy Pine 2014 capital budget by $11.9 million to the $2.4 million of expenditures spent year-to-date.

Wyoming Coalbed Methane (CBM)

During the third quarter drilling activity accelerated in the Spyglass Hill Unit in the Atlantic Rim area of Wyoming. Warren drilled 26 wells (24 CBM producer wells and two injector wells) of which a total of 17 producers were completed. Through September 30, 2014, Warren has drilled a total 30 wells (28 producers and two injectors) and completed 17 producers in the Atlantic Rim in 2014.

Subsequent to the end of the quarter, the Company has drilled three producer wells and completed four producer wells.

Wyoming capital expenditures for drilling and completion operations in the third quarter totaled $14.2 million.

Warren has elected to defer drilling and completion of 17 planned CBM producer wells and four injector wells in the Atlantic Rim. As discussed in more detail below, the decision to defer development activity in Wyoming is a result of a re-evaluation of capital allocations following the Marcellus acquisition. As a result, Warren is cutting its Wyoming 2014 capital budget by $14.3 million to $24.6 million.

Capital Budget and Production Guidance Update

Following the acquisition of the Marcellus assets from Citrus Energy, Warren conducted an in-depth Company-wide portfolio review to re-evaluate the Company's capital allocations and ensure capital was being optimally invested towards the Company's highest rate-of-return opportunities. Generating growth while maintaining spending within cash flows and maximizing free cash flow generation for debt reduction are also key considerations in Warren's capital allocation decisions.

The information and tables below set forth Warren's updated forecast for 2014 development activity, capital expenditures and net production based on the information available at the time of this release. Please see the forward-looking statement at the end of this release for more discussion of the inherent limitations of this information.

2014 Development Plan Update

As a result of its portfolio review, Warren decided to defer some development activity in Wyoming into 2015 and reduce activity in Leroy Pine. With the rig at NWU no longer moving off to drill in Leroy Pine, the development plan for the Wilmington Field was revised to increase drilling activity at the NWU, thereby also minimizing downtime and rig move costs.

The table below sets forth Warren's revised 2014 development plans.

Operating Unit Producer
Wells*
Injector
Wells*
WTU, California 15 5
NWU, California 9 7
Leroy Pine, California** - -
Atlantic Rim, Wyoming 31 2
Marcellus, Pennsylvania** 1 -
* Gross wells (8/8 interest).
** Planned drilling activity only. Planned completion of 3 previously drilled wells in the Marcellus not included in the above schedule.

Capital Expenditure Guidance

The table below sets forth Warren's revised 2014 capital expenditure budget by operating area.

Operating Unit CapEx ($MM)
WTU, California $36.2
NWU, California 31.6
Leroy Pine, California 2.4
Atlantic Rim, Wyoming 24.6
Marcellus, Pennsylvania 10.3
Total Warren $105.1

Production Guidance

Due to the strong performance of the Marcellus assets, Warren is increasing natural gas production guidance for the full year ending December 31, 2014. The deferral of some development activity in Wyoming into 2015 is not expected to have an impact on 2014 production volumes. Oil guidance is being lowered primarily to account for reduced development activity in Leroy Pine and the impact of the longer than projected production curtailments in the NWU in the third quarter.

The table below sets forth Warren's forecast for full year 2014 net production based on the information available at the time of this release.

Full Year ending
December 31, 2014
Oil (MBbl) 1,100 – 1,120
Gas (MMcf)* 14,500 – 15,250
Oil Equivalent (MBoe)* 3,517 – 3,662

*FY14 Marcellus production guidance excludes approximately 3.6 net Bcf of natural gas volumes from July 1, 2014 through August 10, 2014 which were accounted for in the adjustment to the Marcellus assets' acquisition purchase price in 3Q14 in accordance with U.S. GAAP.

Debt and Liquidity

At September 30, 2014, Warren had approximately $1.8 million in cash and cash equivalents, with $120.7 million outstanding under its $225 million borrowing base and available borrowing capacity of $104.3 million, for total available liquidity of $106.1 million. Warren's next borrowing base redetermination will be in November.

Hedges

The Company's current hedges in place as of November 4, 2014 are as noted in the table below:

Type Benchmark Price Quantity Period
Oil Hedges
Oil Swap Brent $102.12 800 Bbl/d 10/01/14 - 12/31/14
Oil Swap NYMEX $101.67 300 Bbl/d 10/01/14 - 12/31/14
Natural Gas Hedges
Gas Swap NYMEX $3.79 7,000 MMBtu/d 10/01/14 -12/31/14
Gas Swap NYMEX $4.18 2,000 MMBtu/d 10/01/14 -12/31/14
Gas Swap NYMEX $4.27 3,000 MMBtu/d 10/01/14 -12/31/14
Gas Swap NYMEX $4.18 3,000 MMBtu/d 01/01/15 -12/31/15
Basis Swap* (WY) CIG to NYMEX $0.20 6,000 MMBtu/d 10/01/14 -12/31/14
*This represents a differential spread between NYMEX and CIG pricing.

Financial and Statistical Data Tables

Following are financial highlights for the comparative three and nine months ended September 30, 2014 and 2013. All production volumes and dollars are expressed on a net revenue interest basis.

Consolidated Statements of Operations
Three Months Ended Nine Months Ended
September 30, (unaudited) September 30, (unaudited)
2014 2013 2014 2013
(in thousands, except per share information)
Operating Revenues
Oil and gas sales $39,175 $34,682 $105,627 $96,237
Transportation revenue 1,338 -- 4,082 --
40,513 34,682 109,709 96,237
Operating Expenses
Lease operating expenses and taxes 13,337 9,257 32,046 27,384
Depreciation, depletion and amortization 15,844 10,987 36,733 34,368
Transportation expense 558 -- 1,674 --
Acquisition expenses 4,080 -- 4,080 --
General and administrative 2,898 3,124 10,731 11,371
Total operating expenses 36,717 23,368 85,264 73,123
Income from operations 3,796 11,314 24,445 23,114
Other income (expense)
Interest and other income 17 5,315 2,379 5,346
Interest expense (3,783) (760) (5,182) (2,234)
Gain (loss) on derivative financial instruments 3,699 (1,205) 1,038 491
Total other income (expense) (67) 3,350 (1,765) 3,603
Income before income taxes 3,729 14,664 22,680 26,717
Deferred income tax expense (benefit) 4 6 (10) 45
Net income 3,725 14,658 22,690 26,672
Less dividends and accretion on preferred shares 2 2 8 8
Net income applicable to common stockholders $3,723 $14,656 $22,682 $26,664
Earnings per share-Basic and Diluted $0.05 $0.20 $0.30 $0.37
Weighted average common shares outstanding – Basic 78,549 72,425 75,122 72,235
Weighted average common shares outstanding – Diluted 78,874 72,619 75,314 72,426
Production Volumes and Commodity Price Realizations
For the Three Months
Ended
For the Nine Months
Ended
September 30,
(unaudited)
September 30,
(unaudited)
2014 2013 2014 2013
Production:
Gas - MMcf 5,537 1,550 8,766 4,680
Oil - MBbls 268 294 825 812
Total Equivalents (MBoe) 1,191 552 2,286 1,592
Realized Prices (before hedges):
Gas ($/Mcf) $ 2.73 $ 3.41 $ 3.18 $ 3.40
Oil – ($/Bbl) 89.77 99.96 94.15 98.87
Total Equivalents ($/Boe) 32.90 62.78 46.20 60.44

Explanation and Reconciliation of Non-GAAP Financial Measures

The Company reports its financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP"). However, management believes certain non-GAAP measures provide useful information for investors because the Company utilizes non-GAAP measures internally to evaluate the performance of its operations, and many of those same measures are commonly used by industry analysts to evaluate a company's operations, as well as for comparison purposes to industry peers.

  • Adjusted net income, a non-GAAP measure, excludes from the calculation of net income, the impact of unrealized non-cash gains or losses related to the mark to market of hedging contracts, as well as other non-recurring items and other extraordinary items. Management views this measure as offering a more accurate picture of our current business operations because unrealized hedging gains and losses are accounting adjustments and have no cash impact on our operations. Additionally, by excluding non-recurring items, adjusted net income enables a better comparison of the ongoing prospects of the business to previous periods.
  • Discretionary cash flow, a non-GAAP measure, excludes the impact of changes in working capital from the calculation of cash flow from operations. Management views this measure as useful because it is widely accepted by the investment community as a means of measuring a company's ability to fund its capital expenditures, while at the same time excluding the fluctuations caused by changes in current assets and liabilities.
  • EBITDA (earnings before interest expenses, income taxes, depreciation and amortization) is a non-GAAP measure. Management views this measure as useful because it indicates the Company's ability to generate cash flow at a level that can sustain its operations and support its capital investment program. EBITDA is a commonly used measure by the Company and industry peers to evaluate and compare operational performance, as well as plan our capital expenditure programs. EBITDA is not a calculation based on GAAP, and, in measuring our Company's performance, should not be considered as an alternative to net income/(loss) applicable to common shareholders, which is the most directly comparable GAAP financial measure.
  • The PV-10 value represents a non-GAAP measure that differs from the standardized measure of discounted future net cash flows presented in Warren's Form 10-K, which includes the effect of future income taxes. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%. The PV-10 value represents the present value of future cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum. We use PV-10 value when assessing the potential return on investment related to our oil and gas properties. Although it is a non-GAAP measure, we believe that the presentation of the PV-10 value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure.

Investors should not consider these non-GAAP measures in isolation or as substitutes for income or loss from operations, cash flow from operations or any other measures for determining a Company's operating performance that is calculated in accordance with GAAP. In addition, because adjusted net income, discretionary cash flow and EBITDA are non-GAAP measures, they may not necessarily be comparable to similarly titled measures employed by other companies or research analysts, which may calculate these figures differently than we do, limiting their usefulness as comparative measures. A reconciliation of net income to adjusted net income, cash flows from operating activities to discretionary cash flow, and net income to EBITDA for the three and Nine months ended September 30, 2014 and 2013 is provided in tables below.

Adjusted Net Income

The following table reconciles net income applicable to common shares to adjusted income (in thousands):

For the Three Months
Ended
For the Nine Months
Ended
September 30, September 30,
2014 2013 2014 2013
(in thousands, except per share information)
Net income applicable to common shares $3,723 $14,656 $22,682 $26,664
Unrealized derivative (gains) losses (3,688) 1,024 (4,305) (1,348)
Severance expense -- 14 520 700
Litigation expense (gain) (1,100) -- -- --
Acquisition expense 4,080 -- 4,080 --
(Income) from post- production cost recapture -- (5,299) (2,211) (5,299)
Adjusted net income $3,015 $10,395 $20,766 $20,717
Adjusted net income per fully diluted share $0.04 $0.14 $0.28 $0.29

Discretionary Cash Flow

The following table reconciles net cash provided by operating activities to discretionary cash flow* (in thousands):

For the Three Months
Ended
For the Nine Months
Ended
September 30, September 30,
2014 2013 2014 2013
(in thousands, except per share information)
Net cash provided by operating activities $19,007 $25,695 $58,358 $58,107
Net changes in working capital (1,574) 1,794 (553) 3,680
Discretionary cash flow* $17,433 $27,489 $57,805 $61,787
Discretionary cash flow per fully diluted share $0.22 $0.38 $0.77 $0.85
*Cash flow from operations before changes in working capital

EBITDA

The following table reconciles net income to EBITDA (in thousands):

For the Three Months
Ended
For the Nine Months
Ended
September 30, September 30,
2014 2013 2014 2013
(in thousands)
Net income applicable to common shares $3,723 $14,656 $22,682 $26,664
Interest Expense 3,783 760 5,182 2,234
Income Tax Expense (Benefit) 4 6 (10) 45
DD&A 15,844 10,987 36,733 34,368
EBITDA $23,354 $26,409 $64,587 $63,311

About Warren Resources

Warren Resources, Inc. is an independent energy company engaged in the acquisition, exploration, development and production of domestic oil and natural gas reserves. Warren's activities are primarily focused on oil in the Wilmington field in the Los Angeles Basin in California, and natural gas in the Marcellus Shale in Pennsylvania and Washakie Basin in Wyoming.

Forward-Looking Statements

Portions of this press release contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. A number of factors may cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this release. Warren believes that its expectations are based on reasonable assumptions. No assurance, however, can be given that such expectations will prove to have been correct. Some factors that could cause actual results to differ materially from those in the forward-looking statements, include, but are not limited to: changes in oil and gas prices and hedging activities undertaken in relation thereto; changes in expected levels of oil and gas reserve estimates and production estimates; the inability to drill wells on a substantial portion of our acreage due to insufficient capital, market conditions or other factors; the timing and results of drilling and other development activities; any inability to hold substantial leases; governmental and environmental regulations and permitting requirements and delays; the availability of capital and credit market conditions; unsuccessful exploratory activities; unexpected cost increases; delays in completing production, treatment and transportation facilities; the availability and cost of obtaining equipment and technical personnel; operating hazards; risks associated with the availability of acceptable transportation arrangements; unanticipated operational problems; potential liability for remedial actions under existing or future environmental regulations; changes in tax, environmental and other laws applicable to our business as well as general domestic and international economic and political conditions; concentration of customers; inability to replace reserves as they are produced; climate change; computer security breaches; and factors that may affect our common stock including the numbers of shares subject to registration rights; stock price volatility; anti-takeover measures in our organizational documents; and any failure to make appropriate assumptions or estimates in the preparation of our financial statements or to maintain adequate internal control over financial reporting. All forward-looking statements are made only as of the date hereof and, unless legally required, the Company undertakes no obligation to update any such statements, whether as a result of new information, future events or otherwise. Further information on risks and uncertainties that may affect Warren's operations and financial performance, and the forward-looking statements made herein, is available in the Company's filings with the Securities and Exchange Commission (www.sec.gov), including its Annual Report on Form 10-K under the headings "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in other public filings and press releases.

CONTACT: Robert Ferer 212-697-9660

Source:Warren Resources, Inc.