NEWS RELEASE
Vanguard Natural Resources Reports Second Quarter 2013 Results
HOUSTON-July 31, 2013--Vanguard Natural Resources, LLC (NASDAQ: VNR) ("Vanguard" or "the Company") today reported financial and operational results for the quarter ended June 30, 2013.
Mr. Scott W. Smith, President and CEO, commented, "This quarter we reached record levels of production as we continue to see the benefits of our acquisition efforts in 2012 and in the first quarter of 2013. We are excited about the early recompletion results we have seen on the Permian assets recently purchased from Range Resources and our 2013 capital program is on track to generate attractive returns for the Company. With over $850 million of liquidity available, we are well positioned to be very competitive in what we feel will be a very robust acquisition market in the second half of the year."
Mr. Richard A. Robert, EVP and CFO, added, “This was an eventful quarter from a capital markets perspective. Issuing a new publicly traded perpetual preferred unit (NASDAQ: VNRAP) was an important step in creating another source of financing to allow Vanguard to continue to execute its growth through acquisitions strategy. We are also pleased to announce an increase to our common unit distribution effective with our July 2013 distribution which will be paid in September. This reflects a continuation of our slow but steady approach to distribution growth.”
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| ($ in thousands, except per unit data) | ||||||||||||||||
| Production (BOE/d) | 36,477 | 12,338 | 34,809 | 12,953 | ||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 116,737 | $ | 66,441 | $ | 213,419 | $ | 149,158 | ||||||||
| Realized gain (loss) on commodity derivative contracts | $ | (2,588 | ) | $ | 2,165 | $ | 3,184 | $ | (1,074 | ) | ||||||
| Unrealized gain on commodity derivative contracts | $ | 61,183 | $ | 83,309 | $ | 26,136 | $ | 60,575 | ||||||||
| Operating expenses | $ | 36,473 | $ | 23,932 | $ | 69,989 | $ | 49,351 | ||||||||
| Selling, general and administrative expenses | $ | 6,900 | $ | 4,827 | $ | 13,449 | $ | 9,799 | ||||||||
| Depreciation, depletion, amortization, and accretion | $ | 42,911 | $ | 20,855 | $ | 81,604 | $ | 42,652 | ||||||||
| Net income available to common unitholders | $ | 81,149 | $ | 103,447 | $ | 54,126 | $ | 101,423 | ||||||||
Adjusted net income available to common unitholders (1) | $ | 19,102 | $ | 8,726 | $ | 35,990 | $ | 30,338 | ||||||||
Adjusted net income available to common unitholders, per common unit (1) | $ | 0.27 | $ | 0.17 | $ | 0.53 | $ | 0.58 | ||||||||
Adjusted EBITDA(1) | $ | 80,282 | $ | 44,450 | $ | 152,714 | $ | 97,689 | ||||||||
| Interest expense, including realized losses on interest rate derivative contracts | $ | 16,925 | $ | 10,396 | $ | 33,310 | $ | 16,301 | ||||||||
| Drilling, capital workover and recompletion expenditures | $ | 14,770 | $ | 15,147 | $ | 29,418 | $ | 23,360 | ||||||||
| Distributions to preferred unitholders | $ | 152 | $ | — | $ | 152 | $ | — | ||||||||
Distributable cash flow available to common unitholders (1) | $ | 48,435 | $ | 18,907 | $ | 89,834 | $ | 63,405 | ||||||||
Distributable cash flow available to common unitholders, per common unit (1) | $ | 0.65 | $ | 0.36 | $ | 1.25 | $ | 1.21 | ||||||||
Common unit distribution coverage (1) | 1.05x | 0.61x | 1.03x | 1.03x | ||||||||||||
| Weighted average common units outstanding | 71,218 | 52,031 | 68,021 | 52,259 | ||||||||||||
| (1) | Non-GAAP financial measures. Please see Adjusted Net Income, Adjusted EBITDA and Distributable Cash Flow tables at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure. |
1
Second Quarter 2013 Highlights:
| • | Adjusted EBITDA (a non-GAAP financial measure defined below) increased 81% to $80.3 million in the second quarter of 2013 from $44.5 million in the second quarter of 2012 and increased 11% from the $72.4 million recorded in the first quarter of 2013. |
| • | Distributable Cash Flow Available to Common Unitholders (a non-GAAP financial measure defined below) increased 156% to $48.4 million from the $18.9 million generated in the second quarter of 2012 and increased 17% from the $41.4 million generated in the first quarter of 2013. |
| • | We reported net income available to common unitholders for the quarter of $81.1 million or $1.14 per basic unit compared to a reported net income of $103.4 million or $1.99 per basic unit in the second quarter of 2012. The recent quarter includes net non-cash gains of $62.2 million that are adjustments to arrive at Adjusted Net Income available to common unitholders (a non-GAAP financial measure defined below). The second quarter of 2012 results included net non-cash gains of $94.7 million. |
| • | Adjusted Net Income available to common unitholders (a non-GAAP financial measure defined below) was $19.1 million in the second quarter of 2013, or $0.27 per basic unit, as compared to $8.7 million, or $0.17 per basic unit, in the second quarter of 2012. |
| • | Reported average production of 36,477 BOE per day in the second quarter of 2013, up 196% over 12,338 BOE per day produced in the second quarter of 2012 and a 10% increase over 33,122 BOE per day produced in the first quarter of 2013. On a BOE basis, crude oil, natural gas and natural gas liquids (“NGLs”) accounted for 24%, 66%, and 10% of our second quarter 2013 production, respectively. |
During the quarter we produced 13,176 MMcf of natural gas, an increase of 616% from the 1,839 MMcf of natural gas produced in the second quarter of 2012, 798 MBbls of oil, an increase of 16% from the 687 MBbls of oil produced in the second quarter of 2012, and 326 MBbls of NGLs, an increase of 153% from the 129 MBbls of NGLs produced in the second quarter of 2012.
Including the impact of our natural gas hedges in the second quarter of 2013, we realized an average price of $3.17 per Mcf on natural gas sales, compared to the unhedged realized average price of $2.73 per Mcf. Including the impact of our oil hedges, we realized an average price of $86.31 per barrel on crude oil sales, compared to the unhedged realized average price of $87.38 per barrel. Including the impact of our NGL hedges, we realized an average price of $34.23 per barrel, compared to the unhedged realized average price of $33.85 per barrel.
2013 Six Month Highlights:
| • | Adjusted EBITDA (a non-GAAP financial measure defined below) increased 56% to $152.7 million in the first half of 2013 from $97.7 million in the first half of 2012. |
| • | Distributable Cash Flow Available to Common Unitholders (a non-GAAP financial measure defined below) for the first six months of 2013 increased 42% to $89.8 million from the $63.4 million generated in the first half of 2012. |
| • | We reported net income available to common unitholders for the first six months of 2013 of $54.1 million or $0.80 per basic unit compared to a reported net income of $101.4 million or $1.94 per basic unit in the first half of 2012. The 2013 results include net non-cash gains of $18.9 million that are adjustments to arrive at Adjusted Net Income available to common unitholders (a non-GAAP financial measure defined below). Results for the first half of 2012 included net non-cash gains of $71.1 million. |
| • | Adjusted Net Income available to common unitholders (a non-GAAP financial measure defined below) was $36.0 million for the first six months of 2013, or $0.53 per basic unit, as compared to $30.3 million, or $0.58 per basic unit, in the comparable period of 2012. |
| • | Reported average production of 34,809 BOE per day in the first half of 2013, up 169% over 12,953 BOE per day produced in the first half of 2012. On a BOE basis, crude oil, natural gas and NGLs accounted for 24%, 67%, and 9% of our production for the first half of 2013 production, respectively. |
2
During the first six months of 2013, we produced 25,167 MMcf of natural gas, an increase of 490% from the 4,267 MMcf of natural gas produced in the first six months of 2012, 1,523 MBbls of oil, an increase of 10% from the 1,379 MBbls of oil produced in the first six months of 2012, and 583 MBbls of NGLs, an increase of 118% from the 267 MBbls of NGLs produced in the first six months of 2012.
Including the impact of our natural gas hedges in the first half of 2013, we realized an average price of $3.34 per Mcf on natural gas sales, compared to the unhedged realized average price of $2.52 per Mcf. Including the impact of our oil hedges, we realized an average price of $82.96 per barrel on crude oil sales, compared to the unhedged realized average price of $84.19 per barrel. Including the impact of our NGL hedges, we realized an average price of $37.41 per barrel, compared to the unhedged realized average price of $37.17 per barrel.
Capital Expenditures
Capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $14.8 million in the second quarter of 2013 compared to $15.1 million for the comparable quarter of 2012 and $14.6 million for the first quarter of 2013. The capital expenditures in the second quarter were approximately $5.3 million lower than our budget due to the acceleration of projects which resulted in higher capital spending during the first quarter of 2013.
Excluding any potential future acquisitions, we currently anticipate an approximate capital budget for the remainder of the year of $30.0 – $35.0 million. The increase to our 2013 capital budget is primarily attributable to favorable results of our initial drilling program in the Woodford Shale in the first half of the year that we will expand for the remainder of 2013.
Recent Activities
Acquisition of Oil and Natural Gas Properties
On April 1, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties in the Permian Basin in southeast New Mexico and West Texas from Range Resources Corporation for an adjusted purchase price of $266.3 million. The purchase price was funded with borrowings under our reserve-based credit facility and is subject to customary post-closing adjustments to be determined based on an effective date of January 1, 2013. Based on internal reserve estimates as of June 30, 2013, the interests acquired have estimated total net proved reserves of 20.1 MMBOE, of which, 42% is natural gas, 26% is oil, 32% is natural gas liquids and 85% is proved developed.
Equity offerings
On June 4, 2013, we completed a public offering of 7,000,000 of our common units at a price of $28.35 per unit. Offers were made pursuant to a prospectus supplement to our shelf registration statement filed with the Securities and Exchange Commission (the "SEC") in January 2012. We received proceeds of approximately $190.9 million from this offering, after deducting underwriting discounts of $7.4 million and offering costs of $0.1 million. We used the net proceeds from this offering to repay indebtedness outstanding under our reserve-based credit facility. In July 2013, we received additional proceeds of $8.9 million from the sale of an additional 325,000 of our common units that were purchased by the underwriters to cover over-allotments.
On June 19, 2013, we completed a public offering of 2,520,000 7.875% Series A Cumulative Redeemable Perpetual Preferred Units representing preferred equity company interests ("Series A Preferred Units") at a price of $25.00 per unit. The total of 2,520,000 Series A Preferred Units includes 320,000 Series A Preferred Units purchased pursuant to the underwriters' over-allotment option. Offers were made pursuant to a prospectus supplement to a shelf registration statement filed with the SEC in January 2012. We received proceeds of approximately $60.9 million from this offering, after deducting discounts of $2.0 million and offering costs of $0.1 million. We used the net proceeds from this offering to repay indebtedness outstanding under our reserve-based credit facility.
3
Hedging Activities
We enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil and natural gas price volatility on our cash flow from operations. We have mitigated some of the volatility by implementing a hedging program for approximately 85% of our anticipated production of crude oil through 2015, approximately 85% of our natural gas production through June 30, 2017 and approximately 10% of our NGLs production through 2014. At June 30, 2013, the fair value of commodity derivative contracts was an asset of approximately $103.7 million, of which $38.6 million settles during the next twelve months. Currently, we use fixed-price swaps, basis swaps, swaptions, put spread options, put options sold, collars, three-way collars and range bonus accumulators to hedge oil, natural gas and NGL prices.
New commodity derivative contracts put in place during the three months ended June 30, 2013 are as follows:
| Year 2013 | Year 2014 | Year 2015 | Year 2016 | ||||||||||||
| Gas Positions: | |||||||||||||||
Fixed-Price Swaps (1) | |||||||||||||||
| Notional Volume (MMBtu) | 1,012,000 | 2,007,500 | 1,642,500 | 1,098,000 | |||||||||||
| Fixed Price ($/MMBtu) | $ | 4.10 | $ | 4.10 | $ | 4.12 | $ | 4.14 | |||||||
| Oil Positions: | |||||||||||||||
Fixed-Price Swaps | |||||||||||||||
| Notional Volume (MMBtu) | — | — | 365,000 | — | |||||||||||
| Fixed Price ($/MMBtu) | $ | — | $ | — | $ | 90.00 | $ | — | |||||||
Three-Way Collars (1) | |||||||||||||||
| Notional Volume (Bbl) | 18,400 | 200,600 | 182,500 | — | |||||||||||
| Floor Price ($/Bbl) | $ | 90.00 | $ | 90.00 | $ | 90.00 | $ | — | |||||||
| Ceiling Price ($/Bbl) | $ | 98.55 | $ | 96.91 | $ | 96.75 | $ | — | |||||||
| Put Sold ($/Bbl) | $ | 75.00 | $ | 75.00 | $ | 75.00 | $ | — | |||||||
| Basis Swaps | |||||||||||||||
| Midland-Cushing | |||||||||||||||
| Notional Volume (Bbls) | — | 182,500 | 365,000 | — | |||||||||||
| Fixed Price ($/Bbl) | $ | — | $ | (0.40 | ) | $ | (0.90 | ) | $ | — | |||||
| Range Bonus Accumulators | |||||||||||||||
| Notional Volume (Bbls) | — | 365,000 | — | — | |||||||||||
| Bonus ($/Bbl) | $ | — | $ | 7.10 | $ | — | $ | — | |||||||
| Range Ceiling ($/Bbl) | $ | — | $ | 98.50 | $ | — | $ | — | |||||||
| Range Floor ($/Bbl) | $ | — | $ | 70.00 | $ | — | $ | — | |||||||
| Put Options Sold | |||||||||||||||
| Notional Volume (Bbls) | — | — | 438,000 | 73,200 | |||||||||||
| Fixed Price ($/Bbl) | $ | — | $ | — | $ | 70.83 | $ | 75.00 | |||||||
| (1) | Year 2013 positions begin July 1, 2013. |
For a summary of all commodity and interest rate derivative contracts in place at June 30, 2013, please refer to our Quarterly Report on Form 10-Q which is expected to be filed on or about August 1, 2013.
4
Liquidity Update
At June 30, 2013, we had indebtedness under our reserve-based credit facility totaling $450.0 million with a borrowing base of $1.3 billion, which provided for $848.3 million in undrawn capacity, after consideration of a $1.7 million reduction in availability for letters of credit. On April 17, 2013, we entered into the Fourth Amendment to the Third Amended and Restated Credit Agreement, which provided for, among others, (a) the extension of the maturity date to April 16, 2018, (b) the increase of our borrowing base from $1.2 billion to $1.3 billion and (c) increased hedging flexibility. However, under the amended agreement, we are only committed to and paying for a borrowing utilization of $1.2 billion, but we have the flexibility to request the additional $100.0 million of availability if needed in the future.
As of July 31, 2013, there were $420.0 million of outstanding borrowings and $878.3 million of borrowing capacity under the reserve-based credit facility, after consideration of a $1.7 million reduction in availability for letters of credit. We also have approximately $15.0 million in available cash.
Cash Distributions
On July 31, 2013, our board of directors approved an increase to our monthly cash distribution from $0.2050 to $0.2075 per common unit ($2.46 to $2.49 on an annualized basis) effective with our July distribution expected to be paid on September 13, 2013.
On July 18, 2013, our board of directors declared a cash distribution for our common unitholders attributable to the month of June 2013 of $0.2050 per common unit ($2.46 on an annualized basis) expected to be paid on August 14, 2013 to Vanguard unitholders of record on August 1, 2013.
Also on July 18, 2013, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per preferred unit expected to be paid on August 15, 2013 to Vanguard preferred unitholders of record on August 8, 2013. The initial distribution on the Series A Preferred Units was paid on July 15, 2013 amounting to $0.1422 per unit. This initial distribution rate was prorated from the date of offering, June 19, 2013 through July 15, 2013.
Conference Call Information
Vanguard will host a conference call on Thursday (August 1, 2013) to discuss its second quarter 2013 financial results, at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial (877) 941-2332 or (480) 629-9773
for international callers and ask for the “Vanguard Natural Resources Earnings Call.” The conference call will also be broadcast live via the Internet and can be accessed through the Investor Relations section of Vanguard's corporate website, http://www.vnrllc.com.
A telephonic replay of the conference call will be available until September 1, 2013 and may be accessed by calling (303) 590-3030 and using the pass code 4631199#. A webcast archive will be available on the Investor Relations page at www.vnrllc.com shortly after the call and will be accessible for approximately 30 days. For more information, please contact Lisa Godfrey at (832) 327-2234 or email at investorrelations@vnrllc.com.
About Vanguard Natural Resources, LLC
Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition, production and development of oil and natural gas properties. Vanguard's assets consist primarily of producing and non-producing oil and natural gas reserves located in the Arkoma Basin in Arkansas and Oklahoma, the Permian Basin in West Texas and New Mexico, the Big Horn Basin in Wyoming and Montana, the Piceance Basin in Colorado, South Texas, the Williston Basin in North Dakota and Montana, the Wind River Basin in Wyoming, the Powder River Basin in Wyoming, and Mississippi. More information on Vanguard can be found at www.vnrllc.com.
5
Forward-Looking Statements
This press release includes "forward-looking statements" within the meaning of the federal securities laws. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include but are not limited to statements about the acquisition announced in this press release. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for oil, natural gas and NGLs, our ability to replace reserves and efficiently develop our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company's reports filed with the Securities and Exchange Commission. Please see "Risk Factors" in the Company's public filings.
Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to publicly correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
VANGUARD NATURAL RESOURCES, LLC
Operating Statistics
(Unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2013(a) | 2012(a) | 2013(a) | 2012(a)(b) | |||||||||||||
| Average realized prices, excluding hedges: | ||||||||||||||||
| Oil (Price/Bbl) | $ | 87.38 | $ | 81.69 | $ | 84.19 | $ | 87.39 | ||||||||
| Natural Gas (Price/Mcf) | $ | 2.73 | $ | 2.49 | $ | 2.52 | $ | 3.45 | ||||||||
| NGLs (Price/Bbl) | $ | 33.85 | $ | 44.47 | $ | 37.17 | $ | 52.00 | ||||||||
Average realized prices, including hedges (c): | ||||||||||||||||
| Oil (Price/Bbl) | $ | 86.31 | $ | 82.67 | $ | 82.96 | $ | 84.67 | ||||||||
| Natural Gas (Price/Mcf) | $ | 3.17 | $ | 5.32 | $ | 3.34 | $ | 5.71 | ||||||||
| NGLs (Price/Bbl) | $ | 34.23 | $ | 44.47 | $ | 37.41 | $ | 52.00 | ||||||||
| Total production volumes: | ||||||||||||||||
| Oil (MBbls) | 798 | 687 | 1,523 | 1,379 | ||||||||||||
| Natural Gas (MMcf) | 13,176 | 1,839 | 25,167 | 4,267 | ||||||||||||
| NGLs (MBbls) | 326 | 129 | 583 | 267 | ||||||||||||
| Combined (MBOE) | 3,319 | 1,123 | 6,300 | 2,358 | ||||||||||||
| Average daily production volumes: | ||||||||||||||||
| Oil (Bbls/day) | 8,765 | 7,549 | 8,414 | 7,578 | ||||||||||||
| Natural Gas (Mcf/day) | 144,795 | 20,203 | 139,043 | 23,443 | ||||||||||||
| NGLs (Bbls/day) | 3,579 | 1,422 | 3,220 | 1,469 | ||||||||||||
| Combined (BOE/day) | 36,477 | 12,338 | 34,809 | 12,953 | ||||||||||||
| (a) | During 2013 and 2012, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included with ours from the closing date of the acquisition forward. |
| (b) | On March 30, 2012, we divested oil and natural gas properties in the Appalachian Basin. As such, there are no operating results from these properties included in our operating results from the closing date of the divestiture forward. |
| (c) | Excludes amortization of premiums paid and amortization on derivative contracts acquired. |
Proved Reserves
Total proved oil and natural gas reserves at June 30, 2013 were 175.7 million barrels of oil equivalent, consisting of 588.2 billion cubic feet of natural gas, 47.8 million barrels of crude oil and 29.8 million barrels of natural gas liquids. Natural gas, crude oil and natural gas liquids accounted for 56%, 27%, and 17%, respectively, of our total proved reserves. Of these total estimated proved reserves, approximately 77% were classified as proved developed.
6
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Revenues: | ||||||||||||||||
| Oil, natural gas and NGLs sales | $ | 116,737 | $ | 66,441 | $ | 213,419 | $ | 149,158 | ||||||||
| Realized gain (loss) on commodity derivative contracts | (2,588 | ) | 2,165 | 3,184 | (1,074 | ) | ||||||||||
| Unrealized gain on commodity derivative contracts | 61,183 | 83,309 | 26,136 | 60,575 | ||||||||||||
| Total revenues | 175,332 | 151,915 | 242,739 | 208,659 | ||||||||||||
| Costs and expenses: | ||||||||||||||||
| Production: | ||||||||||||||||
| Lease operating expenses | 26,509 | 16,681 | 50,682 | 35,240 | ||||||||||||
| Production and other taxes | 9,964 | 7,251 | 19,307 | 14,111 | ||||||||||||
| Depreciation, depletion, amortization, and accretion | 42,911 | 20,855 | 81,604 | 42,652 | ||||||||||||
| Selling, general and administrative expenses | 6,900 | 4,827 | 13,449 | 9,799 | ||||||||||||
| Total costs and expenses | 86,284 | 49,614 | 165,042 | 101,802 | ||||||||||||
| Income from operations | 89,048 | 102,301 | 77,697 | 106,857 | ||||||||||||
| Other income (expense): | ||||||||||||||||
| Interest expense | (15,963 | ) | (9,830 | ) | (31,401 | ) | (15,159 | ) | ||||||||
| Realized loss on interest rate derivative contracts | (962 | ) | (566 | ) | (1,909 | ) | (1,142 | ) | ||||||||
| Unrealized gain (loss) on interest rate derivative contracts | 3,374 | (2,623 | ) | 4,036 | (3,044 | ) | ||||||||||
| Gain on acquisition of oil and natural gas properties, net | 5,827 | 14,126 | 5,827 | 13,796 | ||||||||||||
| Other | (23 | ) | 39 | 28 | 115 | |||||||||||
| Total other income (expense) | (7,747 | ) | 1,146 | (23,419 | ) | (5,434 | ) | |||||||||
| Net income | $ | 81,301 | $ | 103,447 | $ | 54,278 | $ | 101,423 | ||||||||
| Distributions to Preferred unitholders | (152 | ) | — | (152 | ) | — | ||||||||||
Net income available to Common and Class B unitholders | $ | 81,149 | $ | 103,447 | $ | 54,126 | $ | 101,423 | ||||||||
| Net income per Common and Class B units – basic | $ | 1.14 | $ | 1.99 | $ | 0.80 | $ | 1.94 | ||||||||
| Net income per Common and Class B units – diluted | $ | 1.14 | $ | 1.98 | $ | 0.80 | $ | 1.94 | ||||||||
| Weighted average common units outstanding: | ||||||||||||||||
| Common units – basic | 70,798 | 51,611 | 67,601 | 51,839 | ||||||||||||
| Common units – diluted | 70,798 | 51,781 | 67,601 | 51,892 | ||||||||||||
| Class B units – basic & diluted | 420 | 420 | 420 | 420 | ||||||||||||
7
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
| June 30, 2013 | December 31, 2012 | |||||||
| (Unaudited) | ||||||||
| Assets | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | 24,611 | $ | 11,563 | ||||
| Trade accounts receivable, net | 72,270 | 51,880 | ||||||
| Derivative assets | 41,674 | 46,690 | ||||||
| Other current assets | 3,957 | 3,858 | ||||||
| Total current assets | 142,512 | 113,991 | ||||||
| Oil and natural gas properties, at cost | 2,476,504 | 2,126,268 | ||||||
| Accumulated depletion, amortization and impairment | (629,643 | ) | (550,032 | ) | ||||
| Oil and natural gas properties evaluated, net – full cost method | 1,846,861 | 1,576,236 | ||||||
| Other assets | ||||||||
| Goodwill | 420,955 | 420,955 | ||||||
| Derivative assets | 65,303 | 53,240 | ||||||
| Other assets | 34,117 | 35,712 | ||||||
| Total assets | $ | 2,509,748 | $ | 2,200,134 | ||||
| Liabilities and members’ equity | ||||||||
| Current liabilities | ||||||||
| Accounts payable: | ||||||||
| Trade | $ | 5,682 | $ | 8,417 | ||||
| Affiliates | 266 | 32 | ||||||
| Accrued liabilities: | ||||||||
| Lease operating | 14,069 | 7,884 | ||||||
| Development capital | 12,496 | 4,754 | ||||||
| Interest | 11,627 | 11,573 | ||||||
| Production and other taxes | 18,100 | 12,852 | ||||||
| Derivative liabilities | 5,378 | 5,366 | ||||||
| Oil and natural gas revenue payable | 12,031 | 8,226 | ||||||
| Distribution payable | 16,072 | 11,919 | ||||||
| Other | 12,022 | 8,479 | ||||||
| Total current liabilities | 107,743 | 79,502 | ||||||
| Long-term debt | 997,752 | 1,247,631 | ||||||
| Derivative liabilities | 4,394 | 11,996 | ||||||
| Asset retirement obligations, net of current portion | 70,452 | 60,096 | ||||||
| Other long-term liabilities | 1,345 | 3,445 | ||||||
| Total liabilities | 1,181,686 | 1,402,670 | ||||||
| Commitments and contingencies | ||||||||
| Members’ equity | ||||||||
| Preferred units, 2,520,000 units issued and outstanding at June 30, 2013 | 60,880 | — | ||||||
| Common units, 77,090,911 units issued and outstanding at June 30, 2013 and 58,706,282 at December 31, 2012 | 1,264,656 | 794,426 | ||||||
| Class B units, 420,000 issued and outstanding at June 30, 2013 and December 31, 2012 | 2,526 | 3,038 | ||||||
| Total members’ equity | 1,328,062 | 797,464 | ||||||
| Total liabilities and members’ equity | $ | 2,509,748 | $ | 2,200,134 | ||||
8
Adjusted EBITDA
We present Adjusted EBITDA in addition to our reported net income in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income plus the following adjustments:
| • | Net interest expense, including write-off of deferred financing fees and realized gains and losses on interest rate derivative contracts; |
| • | Depreciation, depletion and amortization (including accretion of asset retirement obligations); |
| • | Amortization of premiums paid on derivative contracts; |
| • | Amortization of value on derivative contracts acquired; |
| • | Unrealized gains on other commodity and interest rate derivative contracts; |
| • | Gains on acquisition of oil and natural gas properties, net; |
| • | Taxes; |
| • | Compensation related items, which include unit-based compensation expense and unrealized fair value of phantom units granted to officers; and |
| • | Material transaction costs incurred on acquisitions. |
Adjusted EBITDA is a significant performance metric used by management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.
Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
Distributable Cash Flow Available to Common Unitholders
We present Distributable Cash Flow Available to Common Unitholders in addition to our reported net income in accordance with GAAP. Distributable Cash Flow Available to Common Unitholders is a non-GAAP financial measure that is defined as net income plus the following adjustments:
| • | Depreciation, depletion, amortization and accretion; |
| • | Amortization of premiums paid on derivative contracts; |
| • | Amortization of value on derivative contracts acquired; |
| • | Unrealized gains on commodity and interest rate derivative contracts; |
| • | Gains on acquisition of oil and natural gas properties, net; |
9
| • | Taxes; |
| • | Compensation related items, which include unit-based compensation expense and unrealized fair value on phantom units granted to officers; and |
| • | Material transaction costs incurred on acquisitions; |
Less:
•Drilling, capital workover and recompletion expenditures;
•Distributions to Preferred unitholders;
Plus:
•Proceeds from the sale of leasehold interests.
Distributable Cash Flow Available to Common Unitholders is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors) the cash distributions we could pay our common unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our monthly distribution rate to our common unitholders. While Distributable Cash Flow Available to Common Unitholders is measured on a quarterly basis for reporting purposes, management must consider the timing and size of its planned capital expenditures in determining the sustainability of its monthly distribution to common unitholders. Capital expenditures are typically not spent evenly throughout the year due to a variety of factors including weather, rig availability, and the commodity price environment. As a result, there will be some volatility in Distributable Cash Flow Available to Common Unitholders measured on a quarterly basis. Distributable Cash Flow Available to Common Unitholders is not intended to be a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.
10
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) to Adjusted EBITDA (a) and
Distributable Cash Flow Available to Common Unitholders
(Unaudited)
(in thousands, except per unit amounts)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Net income | $ | 81,301 | $ | 103,447 | $ | 54,278 | $ | 101,423 | ||||||||
| Plus: | ||||||||||||||||
| Interest expense, including realized losses on interest rate derivative contracts | 16,925 | 10,396 | 33,310 | 16,301 | ||||||||||||
| Depreciation, depletion, amortization and accretion | 42,911 | 20,855 | 81,604 | 42,652 | ||||||||||||
| Amortization of premiums paid on derivative contracts | 55 | 3,725 | 109 | 6,959 | ||||||||||||
| Amortization of value on derivative contracts acquired | 7,504 | — | 15,428 | — | ||||||||||||
| Unrealized gains on commodity and interest rate derivative contracts | (64,557 | ) | (80,686 | ) | (30,172 | ) | (57,531 | ) | ||||||||
| Gain on acquisition of oil and natural gas properties, net | (5,827 | ) | (14,126 | ) | (5,827 | ) | (13,796 | ) | ||||||||
| Taxes | 76 | (67 | ) | (241 | ) | (137 | ) | |||||||||
| Compensation related items | 1,775 | 906 | 3,503 | 1,818 | ||||||||||||
| Material transaction costs incurred on acquisitions | 119 | — | 722 | — | ||||||||||||
| Adjusted EBITDA | $ | 80,282 | $ | 44,450 | $ | 152,714 | $ | 97,689 | ||||||||
| Less: | ||||||||||||||||
| Interest expense, net | (16,925 | ) | (10,396 | ) | (33,310 | ) | (16,301 | ) | ||||||||
| Drilling, capital workover and recompletion expenditures | (14,770 | ) | (15,147 | ) | (29,418 | ) | (23,360 | ) | ||||||||
| Distributions to Preferred unitholders | (152 | ) | — | (152 | ) | — | ||||||||||
| Proceeds from sale of leasehold interests | — | — | — | 5,377 | ||||||||||||
| Distributable cash flow available to common unitholders | $ | 48,435 | $ | 18,907 | $ | 89,834 | $ | 63,405 | ||||||||
| Distributable cash flow per common unit | $ | 0.65 | $ | 0.36 | $ | 1.25 | $ | 1.21 | ||||||||
| Common unit distribution coverage | 1.05x | 0.61x | 1.03x | 1.03x | ||||||||||||
(a) Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
Adjusted Net Income Available to Common Unitholders
We present Adjusted Net Income Available to Common Unitholders in addition to our reported net income available to common unitholders in accordance with GAAP. Adjusted Net Income Available to Common Unitholders is a non-GAAP financial measure that is defined as net income available to common unitholders plus the following adjustments:
| • | Unrealized gains on commodity derivative contracts; |
| • | Unrealized gains and losses on interest rate derivative contracts; |
11
| • | Unrealized fair value on phantom units granted to officers; |
| • | Amortization of value on derivative contracts acquired; |
| • | Gains on acquisition of oil and natural gas properties, net; and |
| • | Material transaction costs incurred on acquisitions. |
This information is provided because management believes exclusion of the impact of these items will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the significant fluctuations that commodity price volatility has on our results, particularly as it relates to unrealized changes in the fair value of our derivative contracts. Adjusted Net Income Available to Common Unitholders is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income Available to Common Unitholders to
Adjusted Net Income Available to Common Unitholders
(in thousands, except per unit data)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Net income available to common unitholders | $ | 81,149 | $ | 103,447 | $ | 54,126 | $ | 101,423 | |||||||
| Plus (less): | |||||||||||||||
Unrealized gain on commodity derivative contracts | (61,183 | ) | (83,309 | ) | (26,136 | ) | (60,575 | ) | |||||||
| Unrealized (gain) loss on interest rate derivative contracts | (3,374 | ) | 2,623 | (4,036 | ) | 3,044 | |||||||||
| Unrealized fair value on phantom units granted to officers | 714 | 91 | 1,713 | 242 | |||||||||||
| Amortization of value on derivative contracts acquired | 7,504 | — | 15,428 | — | |||||||||||
Gain on acquisition of oil and natural gas properties, net | (5,827 | ) | (14,126 | ) | (5,827 | ) | (13,796 | ) | |||||||
| Material transaction costs incurred on acquisitions | 119 | — | 722 | — | |||||||||||
| Adjusted net income available to common unitholders | $ | 19,102 | $ | 8,726 | $ | 35,990 | $ | 30,338 | |||||||
| Net income available to common unitholders, per common unit | $ | 1.14 | $ | 1.99 | $ | 0.80 | $ | 1.94 | |||||||
| Plus (less): | |||||||||||||||
Unrealized gain on commodity derivative contracts | (0.86 | ) | (1.60 | ) | (0.38 | ) | (1.16 | ) | |||||||
| Unrealized (gain) loss on interest rate derivative contracts | (0.05 | ) | 0.05 | (0.06 | ) | 0.06 | |||||||||
| Unrealized fair value on phantom units granted to officers | 0.01 | — | 0.02 | — | |||||||||||
| Amortization of value on derivative contracts acquired | 0.11 | — | 0.23 | — | |||||||||||
Gain on acquisition of oil and natural gas properties, net | (0.08 | ) | (0.27 | ) | (0.09 | ) | (0.26 | ) | |||||||
| Material transaction costs incurred on acquisitions | — | — | 0.01 | — | |||||||||||
| Adjusted net income available to common unitholders, per common unit | $ | 0.27 | $ | 0.17 | $ | 0.53 | $ | 0.58 | |||||||
SOURCE: Vanguard Natural Resources, LLC
CONTACT: Vanguard Natural Resources, LLC
Investor Relations
Lisa Godfrey, 832-327-2234
investorrelations@vnrllc.com
###
12