North American natural gas giant Encana Corp. saw its gas production drop 12% from a year ago, as it turned off the spigot in its wide ranging gas-rich plays. Liquids output, however, is roaring and expected to double by the end of the year.
Liquids-rich onshore plays from a stable of better-known assets, including the San Juan Basin, and an emerging portfolio of unconventionals will “almost double” domestic liquids production this year, Encana Corp. U.S. chief Jeff Wojahn said during a conference call with analysts last week.
U.S. oil and natural gas liquids production reached 19,500 b/d in 1Q2013, well ahead of year-ago output of 10,100 b/d and ahead of 4Q2012’s 12,600 b/d. Liquids output in Canada also moved higher to 24,000 b/d, versus 19,200 b/d a year ago, and up from 23,600 b/d in the final months of last year.
“We achieved tremendous growth from our liquids programs,” Wojahn said during the conference call. “Total average production was approximately 90% higher than the first quarter of 2012.”
Annualized liquids production is forecast to “almost double year/year in the division,” he told analysts. Total liquids production is expected to increase to 70,000-75,000 b/d by the end of 2013 from 37,000 b/d at the end of 2012, with growth driven by several Canadian plays, including the Peace River Arch and Bighorn.
In the United States, more liquids growth is anticipated from the Jonah, Piceance and Denver-Julesburg (DJ) Basin. The projected growth only includes minimal volumes from the portfolio of emerging plays, which include the Tuscaloosa Marine Shale (TMS) and the newly reemerging San Juan Basin.
“We made the progress of advancing most of our emerging liquids plays during the first quarter, and we are now in a position to confirm the commerciality of our San Juan Basin play.” The San Juan Basin long has been a target for exploration and production companies, but it lately has taken on new life with unconventional drilling techniques.
“Our San Juan wells have consistently performed at or above our type curve, and we view the play as having low capital risk,” Wojahn explained. “Estimated ultimate recovery ranges are approximately 200,000-700,000 boe. We drilled two net wells during the quarter for a total of 16 wells drilled to date. Our last five wells delivered 30-day initial production rates of 150-700 boe/d, with roughly 80% of the production producing from oil.”
The basin’s well costs now are averaging $5-6 million each, and Encana has identified 150-300 “comparable quality gross well locations…in the core area, with the potential for significantly more locations across the rest of our acreage position.”
In the DJ Basin, Encana has “identified up to 500 locations…for both the formations on our land and have secured the necessary infrastructure capacity to execute our 2013 program,” said Wojahn. “We expect the DJ Basin to contribute an average 8,200 b/d of liquids for the year, an increase of approximately 5,000 b/d over 2012 volumes.”
Meanwhile, the TMS still resides on Encana’s “emerging” resource list, but it made “significant strides toward commerciality over the last quarter, as well performance continues to be strong and well cost are trending down.” He cited Goodrich Petroleum Corp.’s Crosby 12H-1 well, in which Encana holds a 25% stake. The TMS well delivered initial 30-day production rates “higher than 1,200 boe/d and continues to perform above type curve expectations.
U.S. natural gas output fell year/year to 2.877 Bcf/d from 3.272 Bcf/d; it was also lower than 4Q2012 output of 2.981 Bcf/d. Canadian output also fell from a year ago to 1.42 Bcf/d from 1.493 Bcf/d, but it was higher than in 4Q2012, when production hit 1.408 Bcf/d.
The Piceance Basin reported the highest U.S. gas results for the period, with 459 MMcf/d, but output was down from the year-ago results of 488 MMcf/d and from the final quarter, when 475 MMcf/d was produced. In the Haynesville Shale, which Encana recently re-entered with one rig, gas output totaled 420 MMcf/d, compared with 545 MMcf/d in the year-ago period. Canadian gas plays were led by the Cutbank Ridge, with output of 482 MMcf/d, up from 476 MMcf/d in 1Q2012.
“While we are adding diversity to our commodity and cash flow mix, Encana’s primary business is natural gas, and we will succeed over the long term by striving to improve capital efficiency and lower costs across our portfolio of assets,” said interim CEO Clayton Woitas. “Our focus remains on reducing costs and increasing our profitability…Until our emerging plays are proven to be commercial, we are taking a conservative approach to forecasting volume growth. That being said, we have taken some positive strides in the development of our emerging plays this quarter.”
Encana reported a net loss of $431 million (minus 59 cents/share) in 1Q2013, compared with year-ago net gains of $12 million (2 cents). Operating profits were down 25% to $179 million (24 cents/share) from $240 million (33 cents), but they still beat Wall Street’s consensus estimate. Revenue fell to $1.06 billion from $1.8 billion. The losses primarily were attributed to hedging bets and a loss on foreign currency exchange.
Encana had hedged about 1.52 Bcf/d of expected April-to-December 2013 output as of March 31 at prices of $4.39/Mcf. It hedged 1.5 Bcf/d of 2014 production at $4.19, and 825 MMcf/d of 2015 output at $4.37. In addition, Encana has hedged 15,000 b/d of expected April-December 2013 oil production at a WTI equivalent price of $98.08/bbl, and 5,800 b/d of expected 2014 oil production at $93.80.
The board’s selection committee also is interviewing a “short list of external and internal candidates” to take over as CEO, and the search is expected to be completed by the end of June, said Woitas. Once the new CEO is in place, board Chairman David O’Brien, who has been in place for 11 years, plans to step aside and Woitas would take over as chairman. CEO Randy Eresman resigned in January.
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