- Addition of approximately 7,400 Boe/day net production as of April 2013 (approximately 87% oil and 11% NGLs).
- Estimated reserve life index of approximately 13 years based on estimated proved reserves of approximately 35.0 MMBoe as of April 1, 2013.
- Differential for oil is $8.00 per barrel below WTI and lifting costs are approximately $18.00 per Boe.
- Control of midstream assets will enable integrated management of CO 2 compression, delivery and recycling as well as oil export via a wholly owned pipeline. These assets are strategically important, enhance the value of the acquired oil properties, and minimize reliance on third parties for CO 2 delivery and oil transportation.
- Whiting will continue to operate the assets post-closing through October 31, 2013, affording the Partnership the opportunity to transition and integrate its operation of the new assets.
- Immediately accretive to distributable cash flow (“DCF”) per unit. The Partnership expects second half 2013 total DCF to range between approximately $135 million and $145 million.
- The expected accretion to DCF per unit from this transaction will support the Partnership’s target annual distribution growth rate of 5% and strengthen DCF coverage ratio for the second half of 2013 and in future years.
- At closing, Whiting will novate to the Partnership oil derivative contracts, with a counterparty that is a participant in the Partnership’s current credit facility, consisting of swaps to NYMEX WTI crude oil at the following notional volumes and prices:
|Period||Swap Volume (Bbl/d)||Swap Price|
|4/1/13 – 12/31/13||6,100||$98.50|
|1/1/14 – 12/31/14||5,500||$94.75|
|1/1/15 – 12/31/15||5,000||$94.75|
|1/1/16 – 3/31/16||4,400||$93.50|
- The Partnership has a financing commitment to increase the borrowing base of its credit facility to $1.5 billion, with an elected commitment amount of $1.4 billion, at closing. The Partnership expects to fund the asset purchase price with borrowings under this amended credit facility.
- At closing, the Partnership expects to have a pro forma total leverage ratio, equal to total debt divided by the last twelve months pro forma Adjusted EBITDA, of approximately 4.0-to-1.
- To maximize financial flexibility, the Partnership’s amended credit facility will have a relaxed total leverage ratio covenant limitation for a period of five quarters following the transaction to allow for the gradual reduction of indebtedness from operating cash flow and opportunistic refinancing transactions. Specifically, the leverage ratio covenant limitation, defined as total debt divided by last twelve months pro forma Adjusted EBITDA, will be revised as follows
|Existing Total Leverage Covenant:||4.00x||4.00x||4.00x||4.00x||4.00x||4.00x|
|Amended Total Leverage Covenant:||4.75x||4.75x||4.75x||4.50x||4.25x||4.00x|
The following guidance is subject to all of the cautionary statements and limitations described below and under the caption "Cautionary Statement Regarding Forward-Looking Information." In addition, estimates for the Partnership's future production volumes are based on, among other things, assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of oil and gas are extremely complex and are subject to disruption due to transportation and processing availability, mechanical failure, human error, weather, and numerous other factors, including the inability to obtain expected supply of CO 2. The Partnership's estimates are based on certain other assumptions, such as well performance, which may actually prove to vary significantly from those assumed. Operating costs, which include major maintenance costs, vary in response to changes in prices of services and materials used in the operation of our properties and the amount of maintenance activity required. Operating costs, including taxes, utilities and service company costs, move directionally with increases and decreases in commodity prices, and we cannot fully predict such future commodity or operating costs. Similarly, interest rates and price differentials are set by the market and are not within our control. They can vary dramatically from time to time. Capital expenditures are based on our current expectations as to the level of capital expenditures that will be justified based upon the other assumptions set forth below as well as expectations about other operating and economic factors not set forth below. The guidance below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. Rather, the table simply sets forth our best estimate today for these matters based upon our current expectations about the future based upon both stated and unstated assumptions. Actual conditions and those assumptions may, and probably will, change over the course of the year.
|($ in 000s)||2H 2013 Guidance|
|Total Production (Mboe):||5,950||-||6,350|
|Oil Production (Mbbls)||3,350||-||3,550|
|NGL Production (Mbbls)||300||-||340|
|Gas Production (MMcfe)||13,800||-||14,760|
|December 2013 Exit Rate (boe/d)||34,700||-||36,100|
|Average Price Differential %:|
|WTI Oil Price Differential %||91||%||-||92||%|
|Brent Oil Price Differential % (1)||95||%||-||96||%|
|NGL Price Differential % (of WTI)||34||%||-||35||%|
|Gas Price Differential %||102||%||-||103||%|
|Operating Costs / BOE (2)(3)||$18.00||-||$20.00|
|Production / Property Taxes (% of oil/NGL/gas revenue)||7.25||%||-||7.75||%|
|G&A (Excl. Unit Based Compensation)||$19,000||-||$21,000|
|Cash Interest Expense (4)||$43,000||-||$45,000|
|Adjusted EBITDA (5)||$235,000||-||$245,000|
|Capital Expenditures (6):|
|(1)||Approximately 25% of oil production is expected to be sold based on Brent pricing.|
|(2)||Operating Costs include lease operating costs, processing fees, district expense and transportation expense. Expected transportation expense totals approximately $3.5 million in 2H 2013, largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs range per boe is approximately $17.42 - $19.42.|
|(3)||Operating Costs are based on flat $95 per barrel WTI crude oil, $100 per barrel Brent crude oil, and $4.00 per mcfe natural gas price levels for 2H 2013. Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices.|
|(4)||The Partnership typically borrows on a 1-month LIBOR basis, plus an applicable spread. Estimated cash interest expense assumes a 1-month LIBOR rate of 0.3%.|
|(5)||Assuming the high and low range of our guidance, Adjusted EBITDA is expected to range between $245 million and $235 million, and is comprised of estimated net income (before non-cash unit based compensation) between $64 million and $52 million, plus unrealized loss on commodity derivative instruments of $18 million, plus DD&A of $120 million, plus interest expense between $43 million (high end of Adjusted EBITDA) and $45 million (low end of Adjusted EBITDA). Estimated 2H 2013 net income is based on oil prices of $95 per barrel for WTI crude oil, $100 per barrel Brent crude oil, and $4.00 per mcfe for natural gas. Consequently, differences between actual and forecast prices could result in changes to unrealized gains or losses on commodity derivative instruments, DD&A, including potential impairments of long-lived assets, and ultimately, net income.|
|(6)||Total capital expenditures for 2H 2013 excludes capital expenditures for additional acquisitions as well as technology capital spending of approximately $1.5 million. Maintenance capital is defined as the estimated amount of investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately constant for the period.|