MIDLAND, Texas, March 18, 2019 /PRNewswire/ -- Legacy Reserves Inc. ("Legacy") (NASDAQ: LGCY) today announced the 2018 fourth quarter and year-end results. These results are subject to the completion of audited financial statements to be filed within our forthcoming Form 10-K.
Highlights since the third quarter 2018 include:
- Generated quarterly oil production of 18,630 Bbls/d and record annual oil production of 18,162 bbls/d which represents a 32% year-over-year increase;
- Brought 7 Permian horizontal wells online late in the quarter, including:
- One 4-well pad of 10,000' Wolfcamp B wells in Martin County, each of which achieved average peak rates of nearly 1,100 bbls/d prior to installation of artificial lift equipment; and
- Three 7,500'-8,000' wells in Lea County in the 1st, 2nd and 3rd Bone Spring formations, which achieved average peak rates of nearly 1,000 bbls/d;
- Drilled our first two horizontal Wolfcamp wells in Lea County with first production expected Q1 2019;
- Commenced drilling a 6-well pad in Northern Midland County consisting of 7,500' laterals across four horizons;
- Completed three Permian land swaps, enhancing drilling prospects and adding drilling locations in Lea County, NM and Martin and Midland Counties, TX:
- Increased net lateral footage by 62,000'; and
- Increased average lateral lengths 17% to approximately 7,500' for the 106 gross drilling locations comprising the 4 affected prospect areas;
- Completed 6 divestitures of 554 non-core, low-value wells generating approximately $19 million of proceeds;
- Extinguished $16.7 million of debt through equity exchanges, including exchanges after year end, at an average implied conversion price of $2.76 per share; and
- Generated net income of $78.0 million and Adjusted EBITDA of $55.7 million for the fourth quarter.
Dan Westcott, Legacy's Chief Executive Officer, commented, "The team continues to execute on our goals to efficiently develop our significant Permian horizontal resource, high-grade our assets by divesting non-core properties, and enhance our near-term drilling prospects by trading our small tracts. We're proud of our recent well results in Martin County and look forward to executing in new areas across Midland and Howard Counties later this year. I am proud of the Legacy team and their ability to post strong results despite our challenged financial situation."
Robert Norris, Legacy's Chief Financial Officer, commented, "Through 2018, Legacy completed a corporate reorganization, improved our total leverage metrics, participated in value-accretive acreage trades, and sold non-core assets in an effort to improve our leverage profile and access to capital markets. We continue that effort with our announced $135 million 2019 capital budget, which is a meaningful reduction in activity, designed to drill within cash flow. We look forward to working with our stakeholders and advisors to address our capital structure and determine the best path forward for Legacy."
The following information represents estimates of our proved reserves as of December 31, 2018 which have been prepared in compliance with the SEC rules using an average WTI price, as posted by Plains Marketing L.P., of $65.56 per Bbl for oil and an average natural gas price, as posted by Platts Gas Daily, of $3.10 per MMBtu.
2019 Capital Program By Category
We serve as operator of more than 90% of our anticipated capital program, and accordingly, maintain significant control of the capital program budget and may deviate materially from the figures above based on market conditions, credit conditions, or otherwise.
Credit Agreement Update and Strategic Alternatives
Legacy continues to diligently work with the lenders under its revolving credit facility (the "Facility") for the execution of a maturity extension under the Facility.
As previously announced, Legacy is evaluating and exploring potential strategic alternatives. These alternatives include, among others, a sale or other business combination transaction, sales of assets, financing transactions, or some combination of these.
In association with his promotion to Chief Executive Officer, Dan Westcott, has been appointed to the Board of Directors effective immediately. In an effort to enhance the Company's governance practices, Cary Brown, a former Chief Executive Officer of Legacy's predecessor entity, has elected to resign as a director of the Board coincident with Mr. Westcott's appointment. Mr. Brown stated, "Legacy has been a blessing in my life since its inception. I pray for their success through this difficult backdrop and trust the management team and Board will keep fighting for the Company's best interests."
Annual Financial and Operating Results - 2018 Compared to 2017
- Production increased 6% to an annual record of 47,564 Boe/d in 2018 from 44,967 Boe/d in 2017 primarily due to additional oil production from our Permian Basin horizontal drilling operations and higher realized ethane recoveries associated with our Piceance assets for portions of 2018. This was partially offset by natural production declines and individually immaterial divestitures completed in 2018 and 2017.
- Average realized price, excluding net cash settlements from commodity derivatives, increased 20% to $31.96 per Boe in 2018 from $26.58 per Boe in 2017. Average realized oil price increased 19% to $56.64 in 2018 from $47.59 in 2017. This increase was primarily driven by an increase in the average West Texas Intermediate ("WTI") crude oil price of $14.43 per Bbl and partially offset by widening realized regional differentials. Average realized natural gas price decreased 5% to $2.59 per Mcf in 2018 from $2.74 per Mcf in 2017. This decrease was primarily driven by widening realized regional differentials partially offset by an increase in the average NYMEX pricing. Finally, our average realized NGL price increased 3% to $0.67 per gallon in 2018 from $0.65 per gallon in 2017.
- Production expenses, excluding ad valorem taxes, increased 10% to $191.3 million in 2018 from $173.6 million in 2017 primarily due to increased workover and repair activity across all operating regions, increased well count due to our Permian horizontal drilling program, partially offset by general cost reduction efforts. On an average cost per Boe basis, production expenses increased to $11.02 per Boe in 2018 from $10.58 per Boe in 2017, driven primarily by increased well count, working interests, and general cost inflations.
- Non-cash impairment expense totaled $68.0 million in 2018 primarily driven by the further decline in oil and natural gas futures prices in early 2018 as well as increased expenses and well performance during 2018.
- General and administrative expenses, excluding transaction-related expenses and unit-based Long-Term Incentive Plan ("LTIP") compensation expense increased to $39.0 million in 2018 compared to $34.0 million in 2017 primarily due to reduced overhead income which is recognized as a reduction in general and administrative expenses. The reduction is related to dispositions of oil and natural gas properties and as such, lower recovery results in an increase in our expenses. The remaining increase was due to general cost increases.
- Cash settlements paid on our commodity derivatives during 2018 were $11.7 million as compared to cash receipts of $24.2 million in 2017. The decrease in cash settlements is a result of fluctuating commodity prices and reduced nominal volumes hedged.
- Total development capital expenditures increased to $229.5 million in 2018 from $176.8 million in 2017. The 2018 activity was comprised mainly of the drilling and completion of horizontal Permian wells.
Financial and Operating Results - Fourth Quarter 2018 Compared to Fourth Quarter 2017
- Production decreased 3% to 47,543 Boe/d from 49,185 Boe/d primarily due to additional natural production declines in our Piceance assets as well as immaterial asset sales. This was partially offset by increased oil production from our Permian Basin horizontal drilling program.
- Average realized price, excluding net cash settlements from commodity derivatives, remained relatively flat at $30.38 per Boe in 2018 compared to $30.30 per Boe in 2017. Average realized oil price decreased 7% to $48.69 per Bbl in 2018 from $52.30 per Bbl in 2017. This decrease of $3.61 was primarily attributable to widening regional differentials as the average WTI crude oil price increased by $4.70. Average realized natural gas prices increased 6% to $2.92 per Mcf in 2018 from $2.76 per Mcf in 2017. This increase of $0.16 was primarily attributable to an increase in the average Henry Hub gas price. Finally, our average realized NGL price decreased 5% to $0.72 per gallon in 2018 from $0.76 per gallon in 2017.
- Production expenses, excluding ad valorem taxes, increased 16% to $49.4 million in 2018 from $42.6 million in 2017. Production expenses increased primarily due to increased workover and repair activity across all operating regions and increased well count due to our Permian horizontal drilling program, partially offset by general cost reduction efforts. On a per Boe basis, production expenses increased to $11.30 from $9.41 or 20% driven primarily by increased well work activities, decreased low cost oil production, increased competition in the market place and general cost inflations.
- Non-cash impairment expense totaled $13.6 million in 2018 primarily driven by the write-off of unproved properties acquired since 2010 as well as declining oil and natural gas futures prices, increased costs and well performance.
- General and administrative expenses, excluding acquisition costs and LTIP compensation expense, increased to $11.7 million in 2018 from $9.9 million in 2017 primarily due to reduced overhead income which is recognized as a reduction in general and administrative expenses. The reduction is related to dispositions of oil and natural gas properties and as such, lower recovery results in an increase in our expenses. The remaining increase was due to general cost increases.
- Cash settlements paid on our commodity derivatives were $7.7 million during 2018 compared to receipts of $6.4 million in 2017. The decrease in cash settlements is a result of fluctuating commodity prices and reduced nominal volumes hedged.
- Total development capital expenditures were $58 million in the fourth quarter of 2018.
Commodity Derivative Contracts
The following tables summarize, for the periods indicated, our oil and natural gas derivatives in place as of March 13, 2019 covering the period from January 1, 2019 through December 31, 2019. We use derivatives, including swaps, enhanced swaps and three-way collars, as our mechanism for offsetting the cash flow effects of changes in commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to reduce the effects on cash flow of the floating prices we are paid by purchasers of our oil and natural gas. These transactions are mostly settled based upon the monthly average closing price of front-month NYMEX WTI oil and the price on the last trading day of front-month NYMEX Henry Hub natural gas.
Natural Gas Swaps:
We have entered into regional crude oil differential swap contracts in which we have swapped the floating WTI-ARGUS (Midland) crude oil price for floating WTI-ARGUS (Cushing) less a fixed-price differential. As noted above, we receive a discount to the NYMEX WTI crude oil price at the point of sale. Due to refinery downtimes and limited takeaway capacity that has impacted the Permian Basin, the difference between the WTI-ARGUS (Midland) price, which is the price we receive on almost all of our Permian crude oil production, and the WTI-ARGUS (Cushing) price reached historic highs in late 2012 and early 2013 and again in late 2014. We entered into these differential swaps to negate a portion of this volatility. The following table summarizes the oil differential swap contracts currently in place as of March 13, 2019, covering the period from January 1, 2019 through December 31, 2019:
We have entered into regional crude oil differential enhanced swap contracts in which we have swapped the floating WTI-ARGUS (Midland) crude oil price for floating WTI-ARGUS (Cushing) crude oil price less a fixed-price differential combined with a short call option to enhance the price of the differential swap. The following table summarizes the oil differential contracts currently in place as of March 13, 2019, covering the period from January 1, 2019 through December 31, 2019:
We have also entered into regional natural gas differential swap contracts in which we have swapped the floating CIG natural gas price for a floating NYMEX Henry Hub price less a fixed differential. The following table summarizes these type of enhanced swap contracts currently in place as of March 13, 2019, covering the period from January 1, 2019 through December 31, 2019:
About Legacy Reserves Inc.
Legacy Reserves Inc. is an independent energy company engaged in the development, production and acquisition of oil and natural gas properties in the United States. Our current operations are focused on the horizontal development of unconventional plays in the Permian Basin and the cost-efficient management of shallow-decline oil and natural gas wells in the Permian Basin, East Texas, Rocky Mountain and Mid-Continent regions. Additional information is available at www.LegacyReserves.com .
Cautionary Statement Relevant to Forward-Looking information
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, including, without limitation, the evaluation of financial, transactional, and other strategic alternatives, statements regarding the expected future growth and dividends of the company, and plans and objectives of management for future operations. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Legacy expects, believes or anticipates will or may occur in the future are forward-looking statements. Words such as "anticipates," "expects," "intends," "plans," "targets," "projects," "believes," "seeks," "schedules," "estimated," and similar expressions are intended to identify such forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the control of Legacy, which could cause results to differ materially from those expected by management of Legacy. Such risks and uncertainties include, but are not limited to, the structure and timing of any financial, transactional or other strategic alternative and whether any such financial, transactional or other strategic alternative will be completed; whether Legacy will be able to receive an extension to the maturity of its revolving credit facility; realized oil and natural gas prices; production volumes, lease operating expenses, general and administrative costs and finding and development costs; future operating results; and the factors set forth under the heading "Risk Factors" in Legacy's and Legacy Reserves LP's filings with the U.S. Securities and Exchange Commission, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports of Form 8-K. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, Legacy undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Our consolidated, audited financial statements and related footnotes will be available in our annual 2018 Form 10-K which is expected to be filed no later than April 2, 2019.
Non-GAAP Financial Measures
This press release, the financial tables and other supplemental information include "Adjusted EBITDA" which is a non-generally accepted accounting principles ("non-GAAP") measure which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of this non-GAAP financial measure to its nearest comparable generally accepted accounting principles ("GAAP") measure.
Adjusted EBITDA is presented as management believes it provides additional information concerning the performance of our business and is used by investors and financial analysts to analyze and compare our current operating and financial performance relative to past performance. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because all companies may not calculate such measure in the same manner.
Certain factors impacting Adjusted EBITDA may be viewed as temporary, one-time in nature, or being offset by reserves from past performance or near-term future performance. Financial results are also driven by various factors that do not typically occur evenly throughout the year that are difficult to predict, including rig availability, weather, well performance, the timing of drilling and completions and near-term commodity price changes.
"Adjusted EBITDA" should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance.
Adjusted EBITDA is defined as net income (loss) plus:
- Interest expense;
- (Gain) loss on extinguishment of debt;
- Income tax expense (benefit);
- Depletion, depreciation, amortization and accretion;
- Impairment of long-lived assets;
- (Gain) loss on sale of partnership investment;
- Loss (gain) on disposal of assets;
- Equity in (income) loss of equity method investees;
- Unit-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods;
- Minimum payments received in excess of overriding royalty interest earned;
- Equity in EBITDA of equity method investee;
- Net (gains) losses on commodity derivatives;
- Net cash settlements received (paid) on commodity derivatives; and
- Transaction costs.
The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA:
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